Exhibit 99.1

CONFIDENTIAL INFORMATION MEMORANDUM

Calpine Corporation

$7.6 billion New Exit Facility

consisting of

$1.0 billion First Lien Exit Revolving Facility

$6.3 billion First Lien Exit Term Loans

$300 million First Lien Bridge Facility

PUBLIC DOCUMENT

Special Notice Regarding Publicly Available Information

THE COMPANY HAS REPRESENTED THAT THE INFORMATION CONTAINED IN THIS CONFIDENTIAL INFORMATION MEMORANDUM IS EITHER PUBLICLY AVAILABLE OR DOES NOT CONSTITUTE MATERIAL NON-PUBLIC INFORMATION WITH RESPECT TO THE COMPANY, ITS SUBSIDIARIES AND AFFILIATES AND THEIR RESPECTIVE SECURITIES. THE RECIPIENT OF THIS CONFIDENTIAL INFORMATION MEMORANDUM HAS STATED THAT IT DOES NOT WISH TO RECEIVE MATERIAL NON-PUBLIC INFORMATION WITH RESPECT TO THE COMPANY, ITS SUBSIDIARIES AND AFFILIATES AND THEIR RESPECTIVE SECURITIES AND ACKNOWLEDGES THAT OTHER LENDERS HAVE RECEIVED OR WILL RECEIVE A SUPPLEMENTAL CONFIDENTIAL LENDERS PRESENTATION THAT CONTAINS ADDITIONAL INFORMATION WITH RESPECT TO THE COMPANY, ITS SUBSIDIARIES AND AFFILIATES AND THEIR RESPECTIVE SECURITIES THAT MAY BE MATERIAL. NEITHER THE COMPANY NOR THE ARRANGERS TAKE ANY RESPONSIBILITY FOR THE RECIPIENT’S DECISION TO LIMIT THE SCOPE OF THE INFORMATION IT HAS OBTAINED IN CONNECTION WITH ITS EVALUATION OF THE COMPANY AND THE FACILITY.

January 2008

Invitation to Participate

Re: Calpine Corporation

New Exit Facility

Goldman Sachs Credit Partners L.P. (“GSCP”), Credit Suisse Securities (USA), LLC, Deutsche Bank Securities Inc. and Morgan Stanley Senior Funding, Inc. (“Credit Suisse”, “Deutsche Bank” and “Morgan Stanley”, together with GSCP, the “Arrangers”) as Joint Lead Arrangers and Joint Bookrunners, on behalf of Calpine Corporation (“Calpine” or the “Company”), are pleased to invite your institution to become a lender in the $7.6 billion New Exit Facility (the “Facility”) for the Company.

The Arrangers have enclosed this Confidential Information Memorandum, which includes, among other information, a description of the Company and of the transaction.

Lender commitments will be accepted by the Arrangers until 5 p.m. (EST) on 18-January-2008. Your commitment letter should follow the format of the Form of Response and Mailing and Payment Instructions Form, as posted separately to SyndTrak, and should be sent by fax with an original to follow to:

Julian Nemirovsky
Goldman, Sachs & Co. One New York Plaza New York, NY 10004
Tel:	212-902-1483
Fax:	212-493-0488

You are specifically directed not to market or discuss this transaction, or distribute the Confidential Information Memorandum or any of its contents in the secondary market until you have received specific notice from the Arrangers that secondary marketing is permitted.

We look forward to working with you on this transaction.

Sincerely,

Goldman Sachs Credit Partners L.P.	Credit Suisse Securities (USA), LLC
Deutsche Bank Securities Inc.	Morgan Stanley Senior Funding, Inc.

January 2008

i

Notice to and Undertaking by Recipients

Re: Calpine Corporation

New Exit Facility

This Confidential Information Memorandum (the “Confidential Information Memorandum”) has been prepared solely for informational purposes from information supplied by or on behalf of Calpine Corporation (the “Company”), and is being furnished by Goldman Sachs Credit Partners L.P. (“GSCP”), Credit Suisse Securities (USA), LLC, Deutsche Bank Securities Inc. and Morgan Stanley Senior Funding, Inc. (“Credit Suisse”, “Deutsche Bank” and “Morgan Stanley”, together with GSCP, the “Arrangers”) to you solely in your capacity as a prospective lender (the “Recipient”) in considering the proposed New Exit Facility (the “Facility”).

ACCEPTANCE OF THIS CONFIDENTIAL INFORMATION MEMORANDUM CONSTITUTES AN AGREEMENT TO BE BOUND BY THE TERMS OF THIS NOTICE AND UNDERTAKING AND THE SPECIAL NOTICE SET FORTH ON THE COVER PAGE HEREOF (THE “SPECIAL NOTICE”). IF THE RECIPIENT IS NOT WILLING TO ACCEPT THE CONFIDENTIAL INFORMATION MEMORANDUM AND OTHER EVALUATION MATERIAL (AS DEFINED HEREIN) ON THE TERMS SET FORTH IN THIS NOTICE AND UNDERTAKING AND THE SPECIAL NOTICE, IT MUST RETURN THE CONFIDENTIAL INFORMATION MEMORANDUM AND ANY OTHER EVALUATION MATERIAL TO THE ARRANGERS IMMEDIATELY WITHOUT MAKING ANY COPIES THEREOF, EXTRACTS THEREFROM OR USE THEREOF.

I. Confidentiality

As used herein: (a) “Evaluation Material” refers to this Confidential Information Memorandum and any other information regarding the Company or the Facility furnished or communicated to the Recipient by or on behalf of the Company in connection with the Facility (whether prepared or communicated by the Arrangers or the Company, their respective advisors or otherwise) and (b) “Internal Evaluation Material” refers to all memoranda, notes, and other documents and analyses developed by the Recipient using any of the information specified under the definition of Evaluation Material.

The Recipient acknowledges that the Evaluation Material includes confidential, sensitive and proprietary information and agrees that it shall use reasonable precautions in accordance with its established procedures to keep the Evaluation Material confidential; provided however that (i) it may make any disclosure of such information to which the Company gives its prior written consent, (ii) any of such information may be disclosed to it, its affiliates and their respective partners, directors, officers, employees, agents, advisors and other representatives (collectively, “Representatives”) (it being understood that such Representatives shall be informed by it of the confidential nature of such information and shall be directed by the Recipient to treat such information in accordance with the terms of the Notice and Undertaking and the Special Notice) and (iii) it (and each Representative of the Recipient) may make any disclosure to any and all persons, without limitation of any kind, of the U.S. federal income tax treatment and U.S. federal income tax structure of the transaction and all materials of any kind (including opinions or other tax analyses) that are provided to the Recipient (or any Representatives of the Recipient) relating to such tax treatment and tax structure, except that (i) tax treatment and tax structures shall not include the identity of any existing or future party (or any affiliate) to the facility, and (ii) the foregoing proviso shall not apply to the extent reasonably necessary to comply with securities laws. The Recipient agrees to be responsible for any breach of the Notice and Undertaking or the Special Notice that results from the actions or omissions of its Representatives.

ii

The Recipient shall be permitted to disclose the Evaluation Material in the event that it is required by law or regulation or requested by any governmental agency or other regulatory authority (including any self-regulatory organization) or by subpoena or other similar judicial process. The Recipient agrees that it will notify the Arrangers, prior to (if possible) or as soon as practical in the event of any such disclosure (other than at the request of a regulatory authority in connection with routine regulatory examinations), unless such notification shall be prohibited by applicable law or legal process and will cooperate with the Arrangers or the Company in their or its efforts to maintain the confidential nature of the Evaluation Material.

The Recipient shall have no obligation hereunder with respect to any Evaluation Material to the extent that such information (i) is or becomes publicly available other than as a result of a disclosure by the Recipient or its Representatives in violation of this agreement, or (ii) was within the Recipient’s possession prior to its being furnished pursuant hereto or becomes available to the Recipient on a non-confidential basis from a source other than the Arrangers, the Company or their respective agents, provided that the source of such information was not known by the Recipient or its Representatives to be bound by a confidentiality agreement with or other contractual, legal or fiduciary obligation of confidentiality to the Company or any other party with respect to such information.

In the event that the Recipient of the Evaluation Material decides not to participate in the transaction described herein, all Evaluation Material shall remain confidential, and upon request of the Arrangers, such Recipient shall as soon as practicable return all Evaluation Material (other than Internal Evaluation Material) to the Arrangers or represent in writing to the Arrangers that the Recipient has destroyed all copies of the Evaluation Material (other than Internal Evaluation Material) unless prohibited from doing so by the Recipient’s internal policies and procedures.

II. Information

The Recipient acknowledges and agrees that (i) the Arrangers received the Evaluation Material from third party sources (including the Company) and it is provided to the Recipient for informational purposes, (ii) the Arrangers and their affiliates bear no responsibility (and shall not be liable) for the accuracy or completeness (or lack thereof) of the Evaluation Material or any information contained therein, (iii) no representation regarding the Evaluation Material is made by the Arrangers or any of their affiliates, (iv) neither the Arrangers nor any of their affiliates have made any independent verification as to the accuracy or completeness of the Evaluation Material, and (v) the Arrangers and their affiliates shall have no obligation to update or supplement any Evaluation Material or otherwise provide additional information.

The Evaluation Material has been prepared to assist interested parties in making their own evaluation of the Company and the Facility and does not purport to be all-inclusive or to contain all of the information that a prospective participant may consider material or desirable in making its decision to become a lender. Each Recipient of the information and data contained herein should take such steps as it deems necessary to assure that it has the information it considers material or desirable in making its decision to become a lender and should perform its own independent investigation and analysis of the Facility, the transactions contemplated thereby and the creditworthiness of the Company. The Recipient represents that it is sophisticated and experienced in extending credit to entities similar to the Company. The information and data contained herein are not a substitute for the Recipient’s independent evaluation and analysis and should not be considered as a recommendation by the Arrangers or any of their affiliates that any Recipient enters into the Facility.

The Evaluation Material may include certain forward-looking statements and projections provided by the Company. Any such statements and projections reflect various estimates and assumptions by the Company concerning anticipated results which may not prove to be correct. No representations or warranties are made by the Company or any of its affiliates as to the accuracy of any such statements or projections. Whether or not any such forward looking statements or projections are in fact achieved will depend upon future events some of which are not within the control of the Company. Accordingly, actual results may vary from the projected results and such variations may be material.

iii

Statements contained herein describing documents and agreements are summaries only and such summaries are qualified in their entirety by reference to such documents and agreements.

III. General

It is understood that unless and until a definitive agreement regarding the Facility among the parties thereto has been executed, the Recipient will be under no legal obligation of any kind whatsoever with respect to the Facility solely by virtue of this Notice and Undertaking except for the matters specifically agreed to herein and in the Special Notice including the confidentiality obligations provided herein, which are intended to be legally binding.

The Recipient agrees that money damages would not be a sufficient remedy for breach of this Notice and Undertaking or of the Special Notice, and that in addition to all other remedies available at law or in equity, the Company and the Arrangers shall be entitled to equitable relief, including injunction and specific performance, without proof of actual damages.

This Notice and Undertaking and the Special Notice together embody the entire understanding and agreement between the Recipient and the Arrangers with respect to the Evaluation Material and the Internal Evaluation Material and supersedes all prior understandings and agreements relating thereto. The terms and conditions of this Notice and Undertaking and the Special Notice shall apply until such time, if any, that the Recipient becomes a party to the definitive agreements regarding the Facility, and thereafter the provisions of such definitive agreements relating to confidentiality shall govern. If you do not enter into the Facility, the application of this Notice and Undertaking and the Special Notice shall terminate with respect to all Evaluation Material on the date falling two years after the date of the Confidential Information Memorandum.

This Notice and Undertaking and the Special Notice shall be governed by and construed in accordance with the law of the State of New York, without regard to principles of conflicts of law (other than Section 5-1401 of the New York General Obligation Law).

iv

Authorization Letter

January 8, 2008

Goldman Sachs Credit Partners L.P.

Credit Suisse Securities (USA), LLC

Deutsche Bank Securities Inc.

Morgan Stanley Senior Funding, Inc.

Re: New Exit Facility for Calpine Corporation

Ladies and Gentlemen:

We refer to the proposed $7.6 billion New Exit Facility (the “Facility”) for Calpine Corporation (“Calpine” or the “Company”) that you are arranging at our request, and the Confidential Information Memorandum forwarded herewith (the “Confidential Information Memorandum”). We have reviewed or participated in preparing the Confidential Information Memorandum and the information contained therein.

The Company has reviewed the information contained in the Confidential Information Memorandum and represents and warrants that as of the date hereof the information contained in the Confidential Information Memorandum does not, taken as a whole, contain any untrue statement of a material fact or taken as a whole omit to state a material fact necessary in order to make the statements contained therein, in light of the circumstances under which they were made, not materially misleading. Any management projections or forward-looking statements included in the Confidential Information Memorandum are based on assumptions and estimates developed by management of the Company in good faith and management believes such assumption and estimates to be reasonable as of the date of the Confidential Information Memorandum. Whether or not such projections or forward looking statements are in fact achieved will depend upon future events some of which are not within the control of the Company. Accordingly, actual results may vary from the projections and such variations may be material. The projections and forward looking statements included in the Confidential Information Memorandum should not be regarded as a representation by the Company or its management that the projected results will be achieved.

The Company represents and warrants that the information contained in the Confidential Information Memorandum is either publicly available information or not material information (although it may be sensitive and proprietary) with respect to the Company, its subsidiaries and affiliates and their respective securities for purposes of United States federal and state securities laws.

We request that you distribute the Confidential Information Memorandum to such financial institutions as you may deem appropriate to include in the Facility. We agree that we will rely on, and that you are authorized to rely on, the undertakings, acknowledgments and agreements contained in the Notice to and Undertaking by Recipients accompanying the Confidential Information Memorandum or otherwise acknowledged by recipients in connection with the Confidential Information Memorandum.

Yours sincerely,

/s/ Lisa Donahue

Senior Vice President and Chief Financial Officer, Calpine Corporation

v

Syndication Calendar

Dates
January 8	Lenders’ Call
	Time	: 10:00am EST
	Dial-in	: Domestic	888-461-2018
		: International	719-457-2711
	Passcode	: 2469534
	Replay	: Domestic	888-203-1112
		: International	719-457-0820
	Passcode	: 2469534
		*** must have passcode to dial-in***
Week of January 7	Amendment documentation posted to Syndtrak
Week of January 14	Comments due on amendment documentation
January 18	Amendment Signature pages due
January 31	Close and fund

vi

Table of Contents

I.      Executive Summary	1
A. Transaction Overview	1
B. Company Overview	2
C. The New Exit Facility	4
D. Collateral Overview	5
E. Operating and Construction Power Plants	7
F. Sources and Uses	10
G. Existing and Pro Forma Capitalization	11
H. Industry Overview	12
I. Restructuring Progress and Business Plan	14
J. Summary Financial Information	15
II.     Key Investment Considerations	17
A. Strong Asset and Collateral Coverage	17
B. Unencumbered Geysers	17
C. Key Restructuring Benefits Achieved through Reorganization	19
D. Strong Position in Key Deregulated Markets	19
E. Broad Geographic Footprint	20
F. Efficient, Reliable, and Flexible Generation Portfolio	21
G. Solid Environmental Position	22
H. New Management Team	23
III.   Summary Description of Key Terms of the New Exit Facility	24
IV.   Company Overview	25
A. Business Description	25
B. Asset Portfolio	27
C. Operating and Construction Power Plants	29
D. Calpine Portfolio Detail	33
E. Regional Highlights	33

vii

Table of Contents

F. West Assets	33
G. Texas Region Highlights	35
H. Southeast Region Highlights	36
I. Northeast and Midwest Region Highlights	38
J. Power and Commercial Operations	39
K. Management Overview	42
V.      Power Markets Overview	44
A. Electricity Industry Background	44
B. West Region	47
C. Texas Region	50
D. Southeast Region	52
E. Northeast and Midwest Region	55
VI.    Existing and Pro Forma Indebtedness	58
VII.  Financial Summary	61
A. Financial Assumptions	61
B. Forecast Financial Performance	62
VIII. Appendices	63
Appendix A: Certain Industry Terms	63

List of Figures

Figure 1:	Calpine Sources of Value	2
Figure 2:	Calpine Operating Asset Portfolio	3
Figure 3:	Existing DIP Facility vs. New Exit Facility	5
Figure 4:	Detailed Collateral Overview	7
Figure 5:	Debt at September 30, 2007 Pro Forma for the New Exit Facility	12
Figure 6:	Designated and Divested Assets and Projects	14
Figure 7:	Calpine Growth Projects	15

viii

Table of Contents

Figure 8:	Top 10 Renewable Generators	19
Figure 9:	Calpine Generation Capacity by Region	20
Figure 10:	Calpine’s Relative Fleet Characteristics	21
Figure 11:	Calpine Generation Capacity by Technology	22
Figure 12:	Calpine Operating Asset Portfolio	25
Figure 13:	Top Ten U.S. Merchants by Total Capacity	26
Figure 14:	Top Ten U.S. Merchants by Gas Fired Capacity	26
Figure 15:	Calpine Generation Capacity by Region	27
Figure 16:	Calpine Generation Capacity by Technology	28
Figure 17:	Top Ten U.S. Merchants by Renewable Generation	28
Figure 18:	Detailed Collateral Overview	32
Figure 19:	Texas Plants by Technology	36
Figure 20:	Calpine’s Southeast Plants by Region and Technology	37
Figure 21:	Northeast and Midwest Plants by Region and Technology	39
Figure 22:	Debt at September 30, 2007 Pro Forma for the New Exit Facility	58

List of Tables

Table 1:	Summary Structure of the New Exit Facility	5
Table 2:	Summary of Key Collateral Entities	6
Table 3:	The Geysers	7
Table 4:	CalGen	8
Table 5:	Calpine Eastern & Cogen	8
Table 6:	Unrestricted Holdings	8
Table 7:	Calpine Central	9
Table 8:	Calpine Development Holdings	9
Table 9:	CCFC Holdings	9
Table 10:	Other Projects	10

ix

Table of Contents

Table 11:	Sources and Uses of the New Exit Facility	10
Table 12:	Calpine Corporation Pre-Emergence Capital Structure	11
Table 13:	Calpine Corporation Pro Forma Post-Emergence Capital Structure	11
Table 14:	Calpine Forecast EBITDAR	16
Table 15:	The Geysers	29
Table 16:	CalGen	29
Table 17:	Calpine Eastern & Cogen	29
Table 18:	Unrestricted Holdings	30
Table 19:	Calpine Central	30
Table 20:	Calpine Development Holdings	30
Table 21:	CCFC Holdings	31
Table 22:	Other Projects	31
Table 23:	Plants under Development or Construction	32
Table 24:	Current and Pro Forma Calpine Corporation Debt at September 30, 2007	59
Table 25:	Current and Pro Forma CCFC and Project Finance Debt at September 30, 2007	60
Table 26:	Calpine Forecast EBITDAR	62

x

I. Executive Summary

Throughout this Confidential Information Memorandum, Calpine Corporation is referred to as “Calpine” or the “Company”. The Company’s fiscal year end is December 31, 2007.

A. Transaction Overview

On December 20, 2005, Calpine Corporation (“Calpine” or the “Company”) and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York in Manhattan (the “Bankruptcy Court”). Calpine and its subsidiaries’ Chapter 11 cases are being jointly administered under the caption “Calpine Corporation, et al., Case No.05-60200” pending before the Honorable Burton R. Lifland.

In February 2006, the Company received funding for a $2.0 billion debtor-in-possession credit facility (the “Original DIP Facility”). The financing included a $1.0 billion first lien senior secured revolving credit facility, a $400 million first lien senior secured term loan facility and a $600 million second lien term loan facility.

In March 2007, the Company refinanced the Original DIP Facility with the proceeds from a $5.0 billion debtor-in-possession credit facility (the “Existing DIP Facility”), which is comprised of a $1.0 billion first lien senior secured revolving facility (the “First Lien DIP Revolving Facility”) and a $4.0 billion first lien senior secured term loan (the “First Lien DIP Term Loan”). The Existing DIP Facility matures on the earlier of the effective date of the confirmed Plan of Reorganization or March 29, 2009. The Existing DIP Facility includes a provision that allows (but does not obligate) the Company to convert the Existing DIP Facility into an exit financing facility (the “Existing Exit Facility”) on the effective date of Calpine’s Chapter 11 Plan of Reorganization (the “POR”), subject to the satisfaction or waiver of the conditions precedent referred to therein.

On June 20, 2007, Calpine filed its POR and associated Disclosure Statement with the Bankruptcy Court. In connection with the POR, Goldman Sachs Credit Partners L.P., Credit Suisse Securities (USA), LLC, Credit Suisse, Deutsche Bank Trust Company Americas, Deutsche Bank Securities Inc., and Morgan Stanley Senior Funding, Inc. (collectively, the “Joint Lead Arrangers” or the “Joint Bookrunners”) entered into a commitment letter (the “June 20^th Commitment Letter”) to cause an amendment to the Existing DIP Facility to become effective (the “Amendment”), subject to the satisfaction or waiver of the conditions precedent referred to therein. The June 20^th Commitment Letter was amended and restated by the parties thereto on December 13, 2007 (as amended and restated, the “Commitment Letter”). The Commitment Letter provides that the Amendment to the Existing DIP Facility will modify the Existing Exit Facility, such that the aggregate senior secured amount available under the Existing Exit Facility will be increased from $5.0 billion up to $7.3 billion (the “First Lien Exit Facilities”), subject to the satisfaction or waiver of the conditions precedent referred to in the Commitment Letter and subject to reduction pursuant to the Commitment Letter. In addition, the Joint Lead Arrangers have committed to provide a First Lien Bridge Facility in the aggregate principal amount of $300 million, subject to the satisfaction or waiver of the conditions precedent referred to therein. The First Lien Exit Facilities and the First Lien Bridge Facility are referred to herein as the “New Exit Facility”. The manner in which the New Exit Facility will be implemented is as follows:

• An amendment to the $5.0 billion Existing DIP Facility modifying the terms of the Existing Exit Facility to reflect, among other things, the terms set forth in the “Summary Description of Key

Executive Summary 1

Terms of the New Exit Facility” section of this document and to permit the incurrence of the indebtedness under the Additional Exit Term Loan Facilities referred to below

• The provision of an additional $2.3 billion (subject to reduction pursuant to the Commitment Letter, and subject to increase pursuant to the Commitment Letter in the amount of certain repayments of the Existing DIP Facility occurring prior to the Closing Date) of senior secured facilities (the “Additional First Lien Exit Term Loan”) on the effective date of the POR

• The provision of an additional $300 million of a First Lien Bridge Facility on the effective date of the POR. The $2.3 billion Additional First Lien Exit Term Loan, together with the $300 million First Lien Bridge Facility, are referred to as the “Additional Exit Term Loan Facilities”

The proceeds of the $2.6 billion Additional Exit Term Loan Facilities, together with projected cash available for distribution and proceeds from contemplated refinancing of debt and/or proceeds from pending asset sales, will be used, on the effective date of the POR (i) to repay the existing second priority secured debt at Calpine (the “Existing Second Lien Debt”), (ii) to fund distributions under the POR to holders of administrative and other claims, (iii) to pay fees, costs, commissions and expenses in connection therewith, and (iv) for working capital and general corporate purposes.

Subsequent to June 20, 2007, amendments to the POR were filed on August 27, 2007, September 18, 2007, September 24, 2007, September 27, 2007, December 13, 2007 and December 19, 2007. Additional information on Calpine’s filing under the Bankruptcy Code, including access to Court documents, the POR and other general information, is available online at http://www.kccllc.net/calpine.

B. Company Overview

Calpine is a wholesale power company that operates and develops clean, reliable and cost-competitive power generation facilities in North America. The Company’s primary business is generating and selling electricity-related products and services to wholesale and industrial customers through the operation of its portfolio of generation assets. Calpine protects and enhances the value of its assets with sophisticated commercial risk management and asset optimization organizations, which optimize the dispatch and maintenance of the Company’s plants.

Figure 1: Calpine Sources of Value

Executive Summary 2

Calpine operates a fleet of power generation assets with 23,851 MW of generating capacity, making the Company one of the largest wholesale power producers in the country.

Figure 2: Calpine Operating Asset Portfolio

Note: Operating capacity excludes Goldendale, Aries, Parlin, Newark, Pryor, Acadia, Hillabee, Fremont, Washington Parish, Otay Mesa, Russell City and Greenfield. For classification of each of these assets please refer to Figure 6. Included in the operating capacity is the non-operational plant Philadelphia Water. Total generating capacity including Calpine’s net ownership in construction plants is 25,335 MW.

Calpine’s portfolio of plants is comprised of two fuel-efficient and clean power generation technologies: natural gas-fired combustion (primarily combined-cycle) and renewable geothermal facilities. The Company owns or leases a portfolio of 64 (61 operating and 3 under construction) natural gas-fired power plants in 18 U.S. states as well as 19 (17 active) geothermal facilities at The Geysers in northern California. Geothermal plants (such as The Geysers facilities) harness the earth’s naturally occurring steam to generate electricity. These low-variable-cost renewable energy plants have capacity factors approaching 100%, meaning they run during nearly all hours when not down for maintenance. The Geysers are one of the largest producing geothermal resources in the world. Calpine’s natural gas-fired portfolio is equipped with state-of-the-art power generation technologies and is recognized as one of the most environmentally friendly and fuel-efficient fleets in the United States.

Calpine is focused on maximizing value by leveraging its asset portfolio, geographic diversity and operational and commercial expertise to provide the optimal combination of products and services to its customers. To accomplish this goal, the Company’s Power and Commercial Operations work together to maximize power asset performance, optimize the management of the Company’s commodity exposure and seek rational growth and development opportunities.

Power Operations

Calpine’s Power Operations function manages the Company’s fleet of power generating assets and is focused on continuous improvement of its clean, safe, efficient and cost-effective operations. Its goals include maximizing the availability and reliability of Calpine’s existing fleet, by leveraging the Company’s institutional expertise to optimize operations.

Commercial Operations

The Commercial Operations function manages the gross margin of Calpine’s portfolio of physical and contractual assets and obligations. Commercial Operations is focused on the effective management of commodity risk exposures that impact Calpine’s financial performance and the optimal dispatch of the Company’s portfolio.

Executive Summary 3

The Commercial Operations function markets a full suite of products and services to meet its goals. These include management of commodity risk through trading structured products in bilateral and exchange-traded markets, origination of structured products for third-parties, fuel supply and power transmission arbitrage, identifying economic dispatch opportunities for the physical assets and engaging in real-time trading and marketing of energy products and ancillary services.

The Commercial Operations function oversees Calpine’s focused asset growth and development strategy. Calpine continually evaluates growth and development projects, focusing on opportunities that will enhance and stabilize cash flow and that are consistent with Calpine’s regional development strategies. Development opportunities are selected based on a variety of factors, including availability of medium to longer term power sales agreements, the regulatory environment, plant economics, technology alternatives, transmission interconnection capacity and compatibility with existing operations.

C. The New Exit Facility

After giving effect to the proposed Amendment, the New Exit Facility will be comprised of:

• The first lien facility, consisting of (i) up to $4.0 billion of first lien term loans (the “First Lien Exit Term Loan”) which are anticipated (among other things) to roll over from the first lien term loans outstanding under the Existing DIP Facility and (ii) the Additional First Lien Exit Term Loan of up to $2.3 billion (together with the First Lien Exit Term Loan, the “First Lien Exit Term Loans”);

• The $1.0 billion first lien revolving facility on substantially similar terms as available under the Existing Exit Facility subject to modifications per the “Summary Description of Key Terms of the New Exit Facility” and such other modifications as GSCP may agree to (the “First Lien Exit Revolving Facility” and, together with the First Lien Exit Term Loans, the “First Lien Exit Facilities”); and

• The First Lien Bridge Facility of up to $300 million (together with the First Lien Exit Facilities, the “New Exit Facility”).

The First Lien Bridge Facility is structured to allow Calpine to repay a portion of its secured debt without prepayment penalty. The facility has a maturity of 366 days, and is expected to be retired with proceeds from the sale of certain non-strategic assets and tax refunds as described below. Given the non-core nature of these assets, their sale will have no adverse impact on EBITDA or cash flow on an on-going basis, providing an opportunity to commence deleveraging within a few months of closing.

Source	Approx. Proceeds	Status	Description
Fremont Energy Center	$124.0	Signed agreement, with closing expected in mid February 2008	Partially constructed natural gas-fired electricity generating facility
Hillabee Energy Center	$122.5	Signed agreement, with closing expected in mid March 2008	Partially constructed natural gas-fired electricity generating facility
Tax Refunds	$90.0	$70mm due in April 2008 with remainder due December 2008	Refund of withholding tax previously paid
Potential Assets Sales	$200.0 plus	No agreement yet	Other natural-gas fired electricity generating assets

Reorganized Calpine Corporation will be the borrower (the “Borrower”) under the New Exit Facility. The First Lien Exit Revolving Facility and First Lien Exit Term Loans will mature as per the Existing Exit Facility (i.e. March 29, 2014 which is 7 years from the closing of the Existing DIP Facility) and the First Lien Bridge Facility will mature 366 days after the closing date.

Executive Summary 4

Table 1: Summary Structure of the New Exit Facility

($ in millions)

Tranche	Amount		Tenor	Amortization
First Lien Exit Revolving Facility	$	1,000	March 29, 2014	None
First Lien Exit Term Loans		6,300	March 29, 2014	1% per annum
First Lien Bridge Facility		300	366 days from closing	None
Total New Exit Facility	$	7,600

The key terms and provisions of the Existing Exit Facility that will be amended include: (i) adjustments to financial covenants allowing, among other things, for the incurrence of indebtedness under the Additional Exit Term Loan Facilities and First Lien Bridge Facility, (ii) revised permitted capital expenditure and investment baskets under the Facility, (iii) other changes to mandatory prepayments and negative covenants to, among other things, accommodate the First Lien Bridge Facility, and (iv) changes to allow greater operational flexibility in running the business and developing and financing projects, as well as enhancement of Calpine’s ability to manage commodity exposure going forward. Details of key terms and conditions are described in the “Summary Description of Key Terms of the New Exit Facility” section of this document.

The Existing DIP Facility and the Existing Exit Facility also provide the Company with an ability to borrow incremental term loans of up to $2 billion. This “accordion” feature will continue to be available to Calpine under the New Exit Facility. The proceeds from this accordion will be limited to repayment of certain scheduled project secured debt, secured lease obligations or preferred securities up to $1.1 billion. The proceeds may also be used to redeem certain other project secured debt, leases, or preferred securities as long as the accordion debt receives the benefit of the collateral that was secured by the replaced debt¹.

D. Collateral Overview

The New Exit Facility will benefit from guarantees of substantially all unrestricted domestic subsidiaries of Calpine (with exceptions noted in the New Exit Facility). The obligations of the Borrower and the guarantors under the New Exit Facility shall be entitled to the following lien status:

Figure 3: Existing DIP Facility vs. New Exit Facility

Existing DIP Facility	New Exit Facility
•        Existing DIP Facility is secured by first liens on all unencumbered assets and junior liens on all encumbered assets •        Existing DIP Facility benefits from super priority administrative expense claim at each debtor entity •        Collateral for the DIP does not prime the collateral of the secured corporate bonds	•        New Exit Facilities will be secured by first liens on substantially all assets (including equity in subsidiaries) of the Borrower and the guarantors to the extent permitted by existing contractual arrangements and requirements of law

¹ Under certain conditions, if the interest rate of the accordion loans is more than 50bps higher than the First Lien Exit Term Loans, then the First Lien Exit Term Loans will automatically adjust to the same rate.

Executive Summary 5

Under the terms of the New Exit Facility agreement, reorganized Calpine Corporation will be the Borrower, and each subsidiary of Calpine (with exceptions noted in the agreement for the New Exit Facility), not restricted by contractual obligation or requirements of law, will guarantee, on a secured basis, the obligations of the Borrower. The collateral for the New Exit Facility consists of a first priority lien on all assets (including equity in subsidiaries) of the Borrower and the guarantors to the extent permitted by existing contractual arrangements and requirements of law. As listed below, the security for repayment of loans under the New Exit Facility primarily consists of:

• The equity interests in each of the entities in the table below holding directly or indirectly 23,851¹ MW of assets

• A first lien on substantially all assets (including equity in subsidiaries) of the Borrower and the guarantors to the extent permitted by existing contractual arrangements

• Collateral includes direct first liens on the Geysers and CalGen assets and direct first liens on the equity of CCFC and Calpine Energy Services and, if available and permitted, liens on other projects

The following table provides a summary of the key collateral entities supporting the New Exit Facility. The equity of each entity, to the extent applicable law and the terms of the existing contractual agreements, if reinstated, permit, is pledged as collateral to the financing.

Table 2: Summary of Key Collateral Entities

($ in millions)

	Plants	Net MW1	Project Debt2		Debt / kW
Geysers	19	725	$	0	$	0
CalGen	13	9,480		0		0
Calpine Eastern and Cogen	6	371		177		477
Unrestricted Holdings	14	2,615		622		238
Calpine Central	5	3,024		363		120
Calpine Development Holdings	5	2,389		1,281		536
CCFC	6	3,616		1,079		298
Other Projects	12	1,631		502		308
Total	80	23,851	$	4,024	$	169

Note: Operating capacity excludes Goldendale, Aries, Parlin, Newark, Pryor, Acadia, Hillabee, Fremont and Washington Parish. For classification of each of these assets, please refer to Figure 6. Included in the operating capacity is the non-operational plant Philadelphia Water. In addition to the operating plants, Calpine has 3 development or construction plants, Otay Mesa, Russell City, and Greenfield, which are excluded herein. Construction plants are also included in the collateral package and total generating capacity including Calpine’s net ownership in construction plants is 25,335 MW.

¹ Net MW represents total net interest with peaking capacity.

² Project debt as of September 30, 2007 (includes capital leases but not operating leases). Megawatts and debt related to construction/development projects are not included.

The following diagram presents the existing DIP collateral matrix for illustrative purposes. The collateral for the New Exit Facility will consist of a first lien on substantially all assets (including equity in the subsidiaries) of the Borrower and the guarantors of the New Exit Facility to the extent permitted by existing contractual arrangements and requirements of law after emergence from the Chapter 11 cases.

¹ Total MWs of 25,335 includes 23,851 MW of operating capacity and 1,484 MW capacity of plants under construction.

Executive Summary 6

Figure 4: Detailed Collateral Overview

Note: Excludes Philadelphia Water, Hillabee, Fremont and Washington Parish. For classification of each of these assets please refer to Figure 6. Diagram is pro forma for the completed or pending sale of Goldendale, Aries, Parlin and Acadia. It is also pro forma for Newark and Pryor, which are under evaluation.

E. Operating and Construction Power Plants

The table below provides a comprehensive list of the generation facilities that Calpine currently owns and operates under the respective legal entities within Calpine Corporation. The operating plants exclude assets sold or transferred, in the process of being sold or transferred, or under evaluation since December 31, 2006 FYE (for example Goldendale, Aries, Parlin, Newark, Pryor and Acadia are excluded). Included in the operating plants is the non-operational plant Philadelphia Water, as well as RockGen which is no longer assumed to be divested. In addition, Calpine has three plants under construction, Otay Mesa, Russell City, and Greenfield, which are presented herein. Total operating capacity is 23,851 MW and combined with Calpine’s net ownership in construction plants, 1,484 MW, total generating capacity is 25,335 MW. The 25,335 MW operational and construction capacity excludes three partially constructed/completed plants, Hillabee, Fremont and Washington Parish, for which sales are pending or which are under evaluation or consideration for sale.

Table 3: The Geysers

	Type	Location	Operating	Capacity1	Calpine Ownership
Geysers (19 facilities, 17 active)	Geo	WECC	Baseload	725	100	%

¹ Average annual capacity in MWs.

Executive Summary 7

Table 4: CalGen

	Type	Location	Operating	Capacity1	Calpine Ownership
Baytown	CG	ERCOT	Intermediate - Cogen	830	100	%
Carville	CG	SERC	Intermediate - Cogen	501	100	%
Channel	CG	ERCOT	Intermediate - Cogen	593	100	%
Columbia	CG	SERC	Intermediate - Cogen	606	100	%
Corpus Christi	CG	ERCOT	Intermediate - Cogen	505	100	%
Decatur	CC	SERC	Intermediate	792	100	%
Delta	CC	WECC	Intermediate	840	100	%
Freestone	CC	ERCOT	Intermediate	1,036	100	%
Los Medanos	CG	WECC	Intermediate - Cogen	540	100	%
Morgan	CG	SERC	Intermediate - Cogen	807	100	%
Oneta	CC	SPP	Intermediate	1,134	100	%
Pastoria Energy Facility	CC	WECC	Intermediate	750	100	%
Zion	CT	PJM	Peaking	546	100	%
Total				9,480

Note: CG = Cogeneration, CC = Combined Cycle, CT = Combustion Turbine; Sub Region / Region: PJM / RFC.

¹ Average annual capacity, including peaking capability, in MWs.

Table 5: Calpine Eastern & Cogen

	Type	Location	Operating	Capacity1	Calpine Ownership
Bethpage	CC	NYPP	Intermediate	56	100	%
Bethpage 3	CC	NYPP	Intermediate	80	100	%
Bethpage Peaker	CT	NYPP	Peaking	48	100	%
Kennedy (KIAC)	CG	NYPP	Intermediate - Cogen	121	100	%
Philadelphia Water2	CT	PJM	Peaking	19	83	%
Stony Brook	CG	NYPP	Intermediate - Cogen	47	100	%
Total				371

Note: CG = Cogeneration, CC = Combined Cycle, CT = Combustion Turbine; Sub-Region / Region: NYPP / NPCC; PJM / RFC.

¹ Average annual capacity, including peaking capability, in MWs.

² Non-operating due to environmental compliance issues.

Table 6: Unrestricted Holdings

	Type	Location	Operating	Capacity1	Calpine Ownership
Auburndale	CG	FRCC	Intermediate - Cogen	150	100	%
Broad River	CT	SERC	Peaking	847	100	%
Gilroy Cogeneration Plant	CG	WECC	Intermediate - Cogen	128	100	%
South Point	CC	WECC	Intermediate	520	100	%
Gilroy Energy Center	CT	WECC	Peaking	135	100	%
Creed	CT	WECC	Peaking	47	100	%
Feather River	CT	WECC	Peaking	47	100	%
Goose Haven	CT	WECC	Peaking	47	100	%
King City Energy Center	CT	WECC	Peaking	45	100	%
Lambie Energy Center	CT	WECC	Peaking	47	100	%
Riverview Energy Center	CT	WECC	Peaking	47	100	%
RockGen Energy Center2	CT	MISO	Peaking	460	100	%
Wolfskill Energy Center	CT	WECC	Peaking	48	100	%
Yuba City Energy Center	CT	WECC	Peaking	47	100	%
Total				2,615

Note: CG = Cogeneration, CC = Combined Cycle, CT = Combustion Turbine.

¹ Average annual capacity, including peaking capability, in MWs.

² No longer considered to be divested.

Executive Summary 8

Table 7: Calpine Central

	Type	Location	Operating	Capacity1	Calpine Ownership
Hidalgo1	CC	ERCOT	Intermediate	376	79	%
Clear Lake	CG	ERCOT	Intermediate - Cogen	400	100	%
Texas City	CG	ERCOT	Intermediate - Cogen	453	100	%
Deer Park	CG	ERCOT	Intermediate - Cogen	1,019	100	%
Pasadena Power Plant	CC/CG	ERCOT	Intermediate / Inter. Cogen	776	100	%
Total				3,024

Note: CG = Cogeneration, CC = Combined Cycle.

¹ Average annual capacity, including peaking capability, in MWs. MW values reflect Calpine’s share of the total plant MWs for Hidalgo.

Table 8: Calpine Development Holdings

	Type	Location	Operating	Capacity1	Calpine Ownership
Freeport	CG	ERCOT	Intermediate - Cogen	236	100	%
Mankato	CC	MISO	Intermediate	324	100	%
Metcalf	CC	WECC	Intermediate	605	100	%
Riverside	CC	MISO	Intermediate	603	100	%
Rocky Mountain	CC	WECC	Intermediate	621	100	%
Russell City1 2	CC	WECC	Intermediate	388	65	%
Total				2,777

Note: For type: CG = Cogeneration, CC = Combined Cycle, Sub-Region / Region: MISO / MRO.

¹ Average annual capacity, including peaking capability, in MWs. MW values reflect Calpine’s share of the total plant MW for Russell City.

² Under construction.

Table 9: CCFC Holdings

	Type	Location	Operating	Capacity1	Calpine Ownership
Brazos Valley	CC	ERCOT	Intermediate	594	100	%
Hermiston	CC	WECC	Intermediate	616	100	%
Magic Valley	CC	ERCOT	Intermediate	692	100	%
Osprey	CC	FRCC	Intermediate	599	100	%
Sutter	CC	WECC	Intermediate	578	100	%
Westbrook	CC	NEPOOL	Intermediate	537	100	%
Total				3,616

Note: CC = Combined Cycle; Sub Region / Region: NEPOOL / NPCC.

¹ Average annual capacity, including peaking capability, in MWs.

Executive Summary 9

Table 10: Other Projects

	Type	Location	Operating	Capacity1	Calpine Ownership
Agnews	CG	WECC	Intermediate - Cogen	28	100	%
Auburndale Peaker	CT	FRCC	Peaking	116	100	%
Blue Spruce	CT	WECC	Peaking	285	100	%
Greenfield Energy Centre²	CC	Canada	Intermediate	503	50	%
Greenleaf I	CG	WECC	Intermediate - Cogen	50	100	%
Greenleaf II	CG	WECC	Intermediate - Cogen	49	100	%
Hog Bayou	CC	SERC	Intermediate	237	100	%
King City	CG	WECC	Intermediate - Cogen	120	100	%
Los Esteros	CT	WECC	Peaking	188	100	%
Otay Mesa²	CC	WECC	Intermediate	593	100	%
Pine Bluff	CG	SERC	Intermediate - Cogen	215	100	%
Pittsburg	CG	WECC	Intermediate - Cogen	64	100	%
Santa Rosa	CG	SERC	Intermediate - Cogen	250	100	%
Watsonville	CG	WECC	Intermediate - Cogen	29	100	%
Total				2,727

Note: CG = Cogeneration, CC = Combined Cycle, CT = Combustion Turbine.

¹ Average annual capacity, including peaking capability. MW values reflect Calpine’s share of Greenfield Energy Centre.

² Under construction.

F. Sources and Uses

Table 11: Sources and Uses of the New Exit Facility

($ in millions)

Sources			Uses
First Lien Exit Revolving Facility1	$	0	Rollover First Lien DIP Revolving Facility	$	0
First Lien Exit Term Loan		6,300	Rollover First Lien DIP Term Loan2		3,844
First Lien Bridge Facility		300	Repayment of Existing Second Lien3		3,964
Cash on Balance Sheet		1,349	Administrative and Other Claims4		141
Cash Returns/Refinancings		238	Estimated Transaction Expenses		166
			Professional Fees - Escrow		72
Total Sources	$	8,187	Total Uses	$	8,187

¹ $300 million of posted letters of credit expected at close of the transaction against the $1,000 million revolving credit portion of the New Credit Facilities.

² September 30, 2007 balance adjusted to reflect anticipated prepayment from proceeds of ULC bonds and scheduled amortization offset by interest expense accrual.

³ Repayment of second lien debt includes $3,672 million of second lien and $292 million of accrued interest and other second lien claims.

⁴ Includes all other claims that must be paid upon exit.

Executive Summary 10

G. Existing and Pro Forma Capitalization

Table 12: Calpine Corporation Pre-Emergence Capital Structure

($ in millions)

	September 30, 2007
	Outstanding Amount		x of 2007E EBITDAR1
Project Debt and CCFC	$	4,024	2.9	x
First Lien DIP Revolving Facility2		—	2.9
First Lien DIP Term Loan		3,980	5.8
Second Priority Senior Secured Notes		3,672	8.4
Unsecured Senior Notes		1,880	9.8
Convertible Unsecured Senior Notes3		1,824	11.1
Total Debt	$	15,380	11.1	x
Cash4		2,264	1.6
Total Net Debt	$	13,116	9.5	x

Table 13: Calpine Corporation Pro Forma Post-Emergence Capital Structure

($ in millions)

	September 30, 2007
	Outstanding Amount			x of 2007E EBITDAR1
Project Debt and CCFC	$	4,069	5	2.9	x
First Lien Exit Revolving Facility		—		2.9
First Lien Exit Term Loans		6,300		7.5
First Lien Bridge Facility		300		7.7
Total Debt	$	10,669		7.7	x
Pro Forma Cash6		915		0.7
Total Net Debt	$	9,754		7.0	x

Note:Does not include possible issuance of credit facility of up to $200 million of letters of credit facility at Calpine Development Holdings.

¹ Ratios based upon 2007E estimated accrual EBITDAR of $1,384 million.

² $300 million of posted letters of credit expected at close of the transaction against the $1,000 million revolving credit portion of the New Credit Facilities.

³ Post-emergence total debt assumes equitization of unsecured debt.

⁴ Cash includes $561 million of restricted cash.

⁵ Project debt includes $45mm of incremental debt due to contemplated refinancing of Metcalf and Blue Spruce.

⁶ Cash at September 30, 2007 is pro forma for the cash used in the transaction sources and uses.

Executive Summary 11

Figure 5: Debt at September 30, 2007 Pro Forma for the New Exit Facility

($ in millions)

¹ $300 million of posted letters of credit expected at close of the transaction against the $1,000 million revolving credit portion of the New Credit Facilities.

² Does not include possible issuance of credit facility of up to $200 million of letters of credit at Calpine Development Holdings. Pro forma for Metcalf and Blue Spruce refinancings.

³ Other Projects Project Debt includes DWR Monetization, Power Contract Financing, Gilroy Note, Blue Spruce Project Financing, Agnews Capital Leases and Other Miscellaneous.

H. Industry Overview

The regional supply and demand environment and the competitive position of Calpine’s regional generation technology and fuel mix are two of the key drivers of Calpine’s projected financial performance. Other key drivers include the natural gas price environment, which affects wholesale electricity prices and operating margins, and environmental regulations, which affect market prices as well as operating costs.

For much of the 1990s, utilities invested relatively sparingly in new generation capacity. As a result, by the late 1990s many regional markets were in need of new capacity to meet growing electricity demand. Prices rose due to capacity shortages and the emerging merchant power industry responded by constructing significant amounts of new capacity. Between 2000 and 2003, more than 175,000 MW of new generating capacity came on line in the United States. In most regions, these new capacity additions far outpaced the growth of demand, resulting in overbuilt markets with excess capacity. In the West, for example, approximately 24,000 MW of new generation was added during this period, while load only increased by approximately 8,000 MW. The significant increase in supply relative to demand has contributed to the financial distress encountered by Calpine and other merchant generators in the past few years.¹

This surge of generation investment has subsided since 2003. During 2005, only 17,000 MW of new supply were added nationwide. As a result, growing demand for electricity has begun to reduce the level of excess supply, leading to the current predictions of decreasing reserve margins for many regional markets through the end of the decade. Currently, however, most regional markets are still overbuilt. Calpine’s plants in California and Texas benefit from lower levels of excess capacity than the levels found in many other regional markets.

¹ Sources: WSCC Summary of Estimated Loads and Resources (issued May 2001); WECC Summary of Estimated Loads and Resources (Issued July 2004).

Executive Summary 12

Regional generation technology and fuel mix are the second key drivers of Calpine’s financial performance. In a competitive market, the price of electricity in any given hour is typically related to the operating costs of the marginal, or price-setting, generator. Assuming economic behavior by market participants, generating units are generally dispatched in order of their variable costs. Units with lower costs are dispatched first and higher-cost units are dispatched as load grows. As a result, the variable costs of the last (or marginal) unit needed to satisfy demand typically drives the regional power price.

Much of Calpine’s generating capacity is located in California and Texas, regional markets in which gas-fired units set prices during most hours. This has two important implications for Calpine. First, since gas prices are generally higher than most other input fuels, these regions generally see higher power prices than regions in which coal-fired units set prices. In California, this leads to higher margins for Calpine’s geothermal assets. Second, since Calpine’s combined-cycle facilities are often more efficient than other gas-fired units in California and Texas, Calpine captures positive margins when higher-cost gas-fired units owned by other parties set power prices (the margin between realized power prices and fuel costs is referred to as the “spark spread”) in both markets.

Momentum toward national carbon regulations has increased. Carbon regulations are expected to increase generation costs and therefore increase market power prices. Recent developments related to the advancement of carbon regulations include:

• Government’s recent acknowledgement of intent to act to curb global warming

• Intergovernmental Panel on Climate Change reports on impacts of climate change and costs of mitigation

• California newly passed legislation aimed at reducing greenhouse gas emissions prior to 2007

• Several new legislative proposals put forward in 2007 with target implementation dates between 2010 and 2012

Executive Summary 13

I. Restructuring Progress and Business Plan

Restructuring Progress

Since entering Chapter 11, Calpine’s Management has identified several areas for improvement and executed a comprehensive plan of implementation, as disclosed in Calpine’s amended POR filed on December 19, 2007. Presented below are selected significant accomplishments that Calpine has achieved during the reorganization process.

• Cost Management - $180 million of annualized cost savings were realized through

• Reduction of workforce of approximately 1,096 employees

• Closing of 19 non-core offices

• Simplification of organizational structure

• Contract Rationalization - As of June 1, 2007, the Debtors have rejected approximately 57 executory contracts and approximately 29 unexpired leases. The Debtors are also rejecting an additional 212 executory contracts through the POR

• Asset Rationalization - Comprehensive analysis to identify underperforming or non-core assets

• Initially identified 14 “Designated Projects” and other non-core or idle assets with marginal or negative cash flow

• Divested 9 plants to date and divestitures have yielded greater than expected proceeds

• Restructuring has reduced project debt by $684 million and reduced lease obligations as well

• Company will continue to evaluate holdings in all assets

Figure 6: Designated and Divested Assets and Projects

Divested Assets	Under Evaluation - Partially Completed/Constructed
Aries	Washington Parish
Dighton
Fox	Pending Sale - Partially Completed/Constructed
Valladolid III	Fremont
Goldendale	Hillabee
Power Systems Manufacturing
Thomassen Turbine Systems	Restructured / Actively Marketing for Sale
Parlin	Texas City
Acadia¹	Clear Lake
Under Evaluation	Restructured
Newark	Pine Bluff
Pryor	RockGen
	Santa Rosa
Turned Over	Hog Bayou
Rumford/Tiverton

Source: Calpine

¹ Sale completed on September 13, 2007. Net proceeds received were $104mm and debt relief is $85mm.

The positive effects of these initiatives have helped the Company significantly improve its financial performance.

Business Plan

Calpine’s Management, together with the Company’s advisors, has developed a long-term business plan (the “Business Plan”), that has refocused the Company on its core strengths and will allow Calpine to emerge from bankruptcy as a stronger, more profitable company. The Business Plan financial forecast was prepared using a bottom-up approach with input throughout the organization.

Executive Summary 14

The financial presentation focuses on Cash EBITDAR (earnings before interest, tax, depreciation, amortization, major maintenance expense and certain other adjustments, rent and reorganization items), and includes the equity interest¹ in Greenfield and Otay Mesa and minority interest in Russell City.

Growth Projects

• Commercial Operations oversees the growth and development of Calpine’s portfolio. Following are three projects that the Company is currently developing and constructing²

Figure 7: Calpine Growth Projects

Otay Mesa Energy Center	Russell City Energy Center	Greenfield Energy Centre
•       100% owned 593 MW combined-cycle plant located in southern San Diego County •       Output contracted under long-term PPA with SDG&E •       Construction financing in place •       Expected on line date: 1-May-2009	•       65% Calpine owned 600 MW combined-cycle plant located in Hayward, California (San Francisco area) •       Output contracted under long-term PPA with PG&E •       Buyback opportunity for 35% minority interest •       Expected on line date: 1-Jun-2010	•       50% Calpine owned 1,005 MW gas-fired facility located in Ontario, Canada •       Output contracted under long-term PPA with Ontario Power Authority •       Construction financing in place •       Expected on line date: July-2008

Note: Otay Mesa and Greenfield are accounted for using the equity method.

J. Summary Financial Information

The financial forecast presented herein is based upon Calpine’s November 2007 long-term business plan, as developed by Calpine management, together with the Company’s advisors. Projections for 2008 and 2009 rely on forward market prices as of June^, 29, 2007, while longer term projections were estimated based on analysis of Calpine’s power plants. The primary forecast drivers include:

• Forecast of conditions in each of Calpine’s regional markets, including supply and demand

• Regional supply forecasts and position of Calpine power plants on the regional dispatch curves

• New construction projects and impact on the regional load forecasts

• Characteristics of Calpine’s unique asset fleet, which drive unit specific revenues and costs

• Certain items that impact the forecast since April 2007 are listed below:

• Higher spark spreads in 2009 and higher long-term gas prices (at June 29, 2007)

• Benefits from new carbon regulations now expected in 2012

• Upward pressure on cost of new builds, which influence longer-term market pricing

• Renegotiated and received CPUC approval for the Southern California Edison contract

• Entered into contracts for power from Santa Rosa, Hog Bayou, The Geysers and Pastoria

• RockGen is no longer assumed to be divested

¹ Reporting for Otay Mesa changed in Q2 2007 from full consolidation to equity accounting due to terms of contractual arrangements with San Diego Gas & Electric, Co. Further details are included in Calpine’s recent SEC quarterly report.

² The cash flows from Otay Mesa, Russell City, and Greenfield Energy Center are included in the business plan cash flows.

Executive Summary 15

Table 14: Calpine Forecast EBITDAR

($ in millions)

	2008			2009			2010			2011			2012			2013
Total Revenue Receipts	$	7,201		$	7,577		$	7,813		$	8,413		$	9,177		$	9,758
Fuel Cost Disbursements		(4,623	)		(4,836	)		(4,969	)		(5,151	)		(5,138	)		(5,483	)
Gross Margin	$	2,578		$	2,741		$	2,844		$	3,261		$	4,039		$	4,275
Total Operating and SG&A Expenses		(896	)		(948	)		(1,067	)		(1,097	)		(1,603	)		(1,742	)
Consolidated EBITDAR	$	1,682		$	1,794		$	1,777		$	2,164		$	2,437		$	2,533
Minority Interest/Equity Investment EBITDAR Adj.		19			98			75			67			73			72
Cash EBITDAR	$	1,702		$	1,892		$	1,852		$	2,231		$	2,510		$	2,605
GAAP, Mark-to-Market, Working Cap., and Other Adjustments		(8	)		(203	)		(50	)		(111	)		(76	)		(67	)
Accrual EBITDAR	$	1,694		$	1,689		$	1,802		$	2,121		$	2,435		$	2,538
Net Income to Accrual EBITDAR Reconciliation	2008			2009			2010			2011			2012			2013
Net Income/(Loss)	$	73		$	191		$	327		$	638		$	1,038		$	1,235
Add Back:
Interest Expense net of Interest Income1		808			757			728			696			611			507
Depreciation and Amortization		461			474			484			492			492			492
Major Maintenance		174			92			125			138			127			132
Reorganization Items		46			—			—			—			—			—
Other2		132			175			138			157			167			172
Accrual EBITDAR	$	1,694		$	1,689		$	1,802		$	2,121		$	2,435		$	2,538

Note: Cash EBITDAR is after minority interest for Russell City and including income from equity investments in Otay Mesa and Greenfield. Reporting for Otay Mesa changed in Q2 2007 from full consolidation to equity accounting due to terms of contractual arrangements with San Diego Gas & Electric, Co. Further details are included in Calpine’s recent SEC quarterly report.

¹ Interest expense is computed on the basis of the 3-month LIBOR (annual average) forward curve as of December 27, 2007. To the extent that actual interest rates in the future differ from the rates depicted in the forward curve, Calpine’s realized interest expense will differ from the amounts presented in this forecast.

² Other includes Minority Interest Expense, Operating Lease Expense, GAAP and other adjustments.

Executive Summary 16

II. Key Investment Considerations

A. Strong Asset and Collateral Coverage

The collateral securing the New Exit Facility will consist of first priority lien on substantially all assets (including equity in subsidiaries) of the Borrower and the guarantors to the extent permitted by existing contractual arrangements. The assets supporting the New Exit Facility are a set of geographically diverse, highly efficient, primarily low-carbon gas-fired generating facilities consisting of 80 active plants with a total generating capacity of 23,851 MW and 3 construction plants with a total capacity of 1,484 MW, for a total of 25,335 MW. This total operating capacity also includes 19 geothermal power plants with a total generating capacity of 725 MW. Key collateral assets include:

• Direct Lien on the Geysers and Calgen

• Geysers – the nation’s largest geothermal operations consisting of 19 (17 active) units producing energy from an environmentally friendly resource. The facilities operate as a 725 MW baseload unit with average availability of 95% and benefit from a substantial spread between their fixed operating costs and California’s electricity prices

• CalGen – 13 power generation facilities with a combined capacity with peaking of 9,480 MW located in California, Texas, Washington, the Southeast, Oklahoma and Illinois

• Equity lien held by lower tier subsidiaries in CCFC and Calpine Energy Services

• CCFC – 6 gas-fired facilities with a combined capacity with peaking of 3,616 MW located in California, Florida, Maine, Oregon and Texas

• Value of remaining 45 plants with 11,514 MW of generation capacity captured through equity interests liens (to the extent applicable law and the terms of the existing contractual arrangements, if reinstated, permit)

• To the extent other projects are unencumbered, lenders will receive a direct lien at the entity level to the fullest extent permitted

B. Unencumbered Geysers

The New Exit Facility will have a direct, first priority lien on substantially all of the Geysers’ assets. As the largest geothermal portfolio in the world, the 725 MW Geysers portfolio is one of the most attractive assets within Calpine’s generation fleet:

Strong free cash flow generation. The Geysers facilities are baseload generating facilities that continue to benefit from attractive electricity prices in California, where natural gas is on the margin. Power generated at The Geysers facilities has historically been sold primarily through several short-term contracts with California utilities and the remainder to Calpine Energy Services, which in turn sells into the attractive California NP-15, a market that is highly correlated to gas prices during the majority of the year. In April 2007, Calpine entered into an agreement with the California utility, Southern California Edison (“SCE”), to provide 225 MW of geothermal energy to SCE. The agreement, which has already received approval by the California Public Utilities Commission and the federal court overseeing Calpine’s bankruptcy case, is for a period of 10 years and has replaced the existing contract.

Key Investment Considerations 17

Additionally, electrical generation at the Geysers facilities is low cost, as the Geysers facilities utilize turbines that are powered by steam extracted from geothermal fields. The Geysers’ cost structure provides for a significant competitive and economic advantage relative to fuel-fired plants. Additionally, through consolidation of its plant and steam field operations, Calpine has been able to maximize the operating performance and efficiency of the Geysers facilities, resulting in a highly competitive cost structure.

Long lived geothermal reserves. The production of steam at the Geysers steam fields began in 1960 with the startup of Pacific Gas & Electric Units 1&2 (24 MW). Production peaked in 1987 when the installed capacity at the Geysers steam fields reached approximately 2,000 MW. Production capacity at the Geysers facilities today is approximately 725 MW. The steam pressure and flow rate declines at the Geysers steam fields have been significantly reduced through the implementation of various resource management programs, including increased water injection. Power production is expected to remain viable over the next several decades.

High operational flexibility. Geothermal electric plants can operate 24 hours per day and thus provide baseload capacity. Geothermal power generation is not intermittent like other renewable sources such as solar and wind. Calpine is a recognized leader in the operation and maintenance of power plants. Since 1999, the Geysers facilities have shown superior performance with an average availability of 96% to 98%.

The Geysers facilities are comprised of 19 (17 active) units, thereby lowering the amount of plant specific risk to serve customers. This not only provides operational flexibility in dispatch but also in scheduling outages and utilization of the steam resource.

Largest supplier of baseload green power in California. California’s stated objective is to generate 20% of its electricity from renewable resources by 2010. The Geysers facilities are the largest supplier of renewable power on a baseload basis to the California market and are able to earn additional revenues through sales of Renewable Energy Credits (“RECs”)¹. Additionally, due to the exceptionally high capacity factor of the Geysers, Calpine ranks second in the U.S. in terms of 2005 renewable energy generation.

¹ Geothermal is considered a renewable energy (like wind, solar, and biomass generation), since the fuel supply is not depleted during electricity production.

Key Investment Considerations 18

Figure 8: Top 10 Renewable Generators

Source: Energy Velocity

Note: Includes wind, geothermal, solar, biomass, agricultural byproducts and refuse.

C. Key Restructuring Benefits Achieved through Reorganization

Calpine has a strong foundation in place, with high quality assets and an experienced workforce. Chapter 11 protection provided the Company with the ability to address its financial challenges without disrupting its ability to continue to provide reliable power to the markets in which it operates. Leveraging its Debtor-In-Possession status, Calpine has been able to:

• optimize capital structure through leverage reduction,

• identify and reject certain unprofitable contracts,

• complete the Company’s asset rationalization plans,

• realign its workforce, and

• implement cost reduction measures.

The New Exit Facility will provide the Company with liquidity and flexibility to run its business after emergence. In turn, Calpine’s customers can continue to rely on the Company’s power plants for the reliable generation of electricity and delivery of other energy services.

The POR, the latest amendment to which was filed on December 19, 2007, represents a significant milestone in the Company’s emergence from Chapter 11 with a restructured balance sheet and a clear path toward ensuring long-term viability for Calpine.

D. Strong Position in Key Deregulated Markets

Calpine owns 53 plants in two of the largest markets in the country that are characterized by significant constraints on the transmission of power from generators outside of their respective regions – the California region (41 plants) and Electric Reliability Council of Texas (“ERCOT”) (12 plants). These 53 plants comprise 12,714 MW of net capacity or approximately 54% of Calpine’s total net operating capacity. Specifically, 5,204 MW of net capacity resides in the California region and 7,510 MW of net capacity resides in ERCOT.

Key Investment Considerations 19

The California region is one of the largest and fastest growing power markets in the country and was among the first to deregulate wholesale generation. Despite transmission constraints into and within the region, the California Independent System Operator (“CAISO”) is considered to be one of the most liquid markets in the country due to its high volume of trading. Population growth rates in the region are expected to exceed the compounded annual population growth rate of the rest of the country by almost 1.0% from 2000 to 2025. ERCOT is also one of the nation’s largest and fastest growing power markets and represents approximately 85% of power demand in Texas. From 1994 through 2004, peak hourly demand in ERCOT grew by 3.0%, compounded annually, while US demand grew by 2.1%, compounded annually, over the same period. The structural and geographic characteristics of the ERCOT region represent a relatively unique isolation from both the eastern and western interconnections.

The strong economy and the slowdown in new generation build have had positive effects on reserve margins and spark spreads. In ERCOT, strategic moves by some companies to mothball or retire certain older, uneconomic facilities have improved the competitive dynamics. The California region has historically been characterized by tight supply/demand fundamentals. Older, less efficient gas-fired power generation facilities generally set market clearing prices during peak periods, and Calpine’s newer, more efficient gas-fired facilities compete favorably. Additionally, the state of California features complex regulatory process and stringent environmental regulations which create significant barriers to entry. This presents significant competitive advantage for the Calpine Geysers, which are strategically located near major load centers in California. Increasing green power demand by utilities, municipalities and other power customers in California also provides strong support for future energy and capacity sales from the Geysers facilities.

Gas is on the margin during most hours in both California and Texas. These regions generally see higher prices than regions in which coal-fired units set prices. Calpine’s more efficient combined-cycle facilities capture positive margins when higher-cost gas-fired units set power prices.

E. Broad Geographic Footprint

Currently, Calpine has operations throughout the U.S. where it owns or leases 80 plants.

Figure 9: Calpine Generation Capacity by Region

Calpine Generation Capacity by Region

	Region	# of Plants	Capacity¹ (MW)
	West	45	7,246
	California	41	5,204
	Colorado	2	906
	Arizona	1	520
	Oregon	1	616
	Texas	12	7,510
	Southeast	12	6,254
	SERC	8	4,255
	FRCC	3	865
	SPP	1	1,134
	Northeast and Midwest	11	2,841
	New England	1	537
	New York	5	352
	PJM	2	565
	Midwest	3	1,387
	Total	80	23,851

¹ Average annual capacity, including peaking capability, in MWs. Operating capacity excludes Goldendale, Aries, Parlin, Newark, Pryor, Acadia, Hillabee, Fremont, Washington Parish, Otay Mesa, Russell City and Greenfield. Included in the operating capacity is the non-operational plant Philadelphia Water. For classification of each of these assets please, refer to Figure 6. Total generating capacity with peaking capability including Calpine’s net ownership in construction plants is 25,335 MW.

Key Investment Considerations 20

This broad geographic footprint offers the Company exposure to different regional economies, which diversifies its portfolio and which particularly limits the Company’s reliance on a specific industry or customer. In addition, Calpine’s operations in different power markets limit its exposure to regulatory, fuel procurement, and spark-spread risks, specific to certain markets.

F. Efficient, Reliable, and Flexible Generation Portfolio

The majority of the Company’s natural gas-fired plants have been built since 1999 and as a consequence of the newer technology and good maintenance of the plants, the Company is able to operate more efficiently than many of its peers. This efficiency is evidenced by the Company’s lower–than–market heat rate, which generally provides it with a competitive advantage, especially in times of rising fuel prices.

Calpine has been successful in clustering its standardized, highly efficient power generation assets. Construction costs, supply chain activities such as inventory and warehousing costs, labor, and fuel procurement costs can all be reduced with this approach. Utilizing this approach in a sales contract allows Calpine to provide power to a customer from the most economical plant at a given period of time. In addition, the operation of plants can be coordinated when increasing or decreasing power output throughout the day to enhance overall system efficiency, thereby enhancing the heat rate advantage already enjoyed by the plants.

Calpine’s power plant portfolio is also characterized by exceptionally high reliability. Calpine’s fleet of power plants exhibits higher availability and lower outages than national average. Calpine’s fleet efficiency permits the Company to economically dispatch its assets when it is uneconomic for other similar assets to operate.

Figure 10: Calpine’s Relative Fleet Characteristics

Net Capacity Factor	Equiv. Forced Outage	Net Heat Rate (BTU/kWh)

Sources: Calpine combined cycle data (excludes cogens): NERC Generating Availability Data System (GADS). National combined cycle data: NCF and EFOR plant data from NERC; NHR plant data from Energy Velocity and PA Consulting Group

Key Investment Considerations 21

The choice to focus on highly efficient and clean technologies reduces the Company’s fuel consumption, a major expense when operating power plants. Additionally, by signing long-term power contracts with fixed heat-rate based pricing (a component of which is the gas index), the Company can reduce its exposure to the volatility associated with power and gas prices.

Figure 11: Calpine Generation Capacity by Technology

Calpine Generation Capacity by Technology

	Technology	# of Plants	Capacity1 (MW)
	Intermediate	20	10,755
	Intermediate (Cogeneration)	24	7,394
	Peaking2	17	4,977
	Baseload (Geothermal)	19	725
	Total	80	23,851

¹ Average annual capacity, including duct capability, in MWs. Operating capacity excludes Goldendale, Aries, Parlin, Newark, Pryor, Acadia, Hillabee, Fremont, Washington Parish, Otay Mesa, Russell City and Greenfield. Included in the operating capacity is the non-operational plant Philadelphia Water. For classification of each of these assets please, refer to Figure 6. Total generating capacity including Calpine’s net ownership in construction plants is 25,335 MW.

² Number of peaking plants excludes intermediate and intermediate (cogeneration) plants with peaking capacity. 4,977 MW Peaking includes peaking capacity of combined cycle facilities.

G. Solid Environmental Position

The recent push to implement new environmental regulations will have a significant impact on the power generation industry. While these regulations will force many generators to spend more on environmental capital investments, Calpine’s necessary environmental expenditures will be limited due to its relatively clean and environmentally friendly generation portfolio. As a result, the Company will benefit as increased variable costs at coal-fired, price-setting units push market prices up.

Greenhouse gas regulations are due to come into effect in the Northeast in 2009 and in California in 2012. Federal regulations are also in the works, and eleven new federal greenhouse gas proposals have target start dates ranging from 2010 to 2012. Pending carbon regulations have already had a negative impact on some coal-fired generation projects as regulators, financial institutions and investors have become wary of the high emissions costs coal-fired plants may incur as a result of these proposals.

Although many power generators will feel negative repercussions from greenhouse gas regulations, others will benefit, including efficient generators that will see higher energy prices more than offsetting higher emissions costs. The majority of Calpine’s gas-fired fleet falls into this category except for those plants holding long term contracts to sell power at fixed prices with no provision for adjustments in response to changes in future greenhouse gas costs.

Sulfur dioxide (“SO₂”), nitrogen dioxide (“NO_x”) and Mercury regulations will be implemented under the Clean Air Interstate Rule (“CAIR”) and the Clean Air Mercury Rule (“CAMR”). The NO_x and SO₂ programs are scheduled to begin in 2009 and 2010, respectively; the CAMR cap-and-trade program designed to limit mercury emissions will start in 2010.

Finally, Renewable Portfolio Standards (“RPS”) represents another new environmental initiative that will affect the industry moving forward. RPS mandates that utilities and other load serving entities purchase a portion of their power from renewable sources. This creates a premium for electricity generated at The Geysers.

Key Investment Considerations 22

H. New Management Team

The management team of Calpine is composed of highly capable professionals with extensive experience not only in the successful management of large companies, but also in the energy industry. CEO Robert P. May, who, over the past 30 years, has served in various senior management and executive positions along with fellow executives on Calpine’s new management team, has a proven track record of success and will continue to bring to the table expertise and experience drawn from working in leading corporations. Upon exit, the range of talent of Calpine’s new management team will enable the Company to thrive and take advantage of attractive growth opportunities within the burgeoning power markets. The members of Calpine’s management team possess an impressive breadth of knowledge to launch Calpine into a new period.

Key Investment Considerations 23

III. Summary Description of Key Terms of the New Exit Facility

To be posted separately to SyndTrak.

Summary Description of Key Terms of the New Exit Facility 24

IV. Company Overview

A. Business Description

Calpine is a wholesale power company that operates and develops clean, reliable and cost-competitive power generation facilities in the United States and Canada. The Company’s primary business is generating and selling electricity-related products and services to wholesale and industrial customers through the operation of its portfolio of generation assets. Calpine protects and enhances the value of its assets with sophisticated commercial risk management and asset optimization organizations, which optimize the dispatch and maintenance of the Company’s plants.

Calpine operates a fleet of power generation assets with 23,851 MW of generating capacity, making the Company one of the largest wholesale power producers in the country.

Figure 12: Calpine Operating Asset Portfolio

Note: Average annual capacity, including peaking capability, in MWs. Operating capacity excludes Goldendale, Aries, Parlin, Newark, Pryor, Acadia, Hillabee, Fremont, Washington Parish, Otay Mesa, Russell City and Greenfield. Included in the operating capacity is the non-operational plant Philadelphia Water. For classification of each of these assets please, refer to Figure 6. Total generating capacity including Calpine’s net ownership in construction plants is 25,335 MW.

Calpine’s portfolio of plants is comprised of two fuel-efficient and clean power generation technologies: natural gas-fired combustion (primarily combined-cycle) and renewable geothermal facilities. The Company either owns or leases a portfolio of 64 (61 operating and 3 under development or construction) natural gas-fired power plants throughout the U.S. as well as 19 geothermal facilities at the Geysers in northern California. Calpine’s natural gas-fired portfolio is equipped with state-of-the-art power generation technologies and is recognized as one of the most environmentally friendly and fuel-efficient fleets in the United States. Additionally, the Company’s renewable energy portfolio, the Geysers, is the largest producing geothermal resource in the world.

Company Overview 25

Figure 13: Top Ten U.S. Merchants by Total Capacity

(Capacity in MW)

Figure 14: Top Ten U.S. Merchants by Gas Fired Capacity

(Capacity in MW)

Note: Calpine’s average annual capacity, including peaking capability, in MWs. Operating capacity excludes Goldendale, Aries, Parlin, Newark, Pryor, Acadia, Hillabee, Fremont, Washington Parish, Otay Mesa, Russell City and Greenfield. Included in the operating capacity is the non-operational plant Philadelphia Water. For classification of each of these assets please, refer to Figure 6. Total generating capacity including Calpine’s net ownership in construction plants is 25,335 MW.

Calpine is focused on maximizing value by leveraging its asset portfolio, geographic diversity and operational and commercial expertise to provide the optimal combination of products and services to its customers. To accomplish this goal, the Company’s Power and Commercial Operations functions work together to maximize power asset performance, optimize the management of the Company’s commodity exposure and seek rational growth and development opportunities.

Company Overview 26

B. Asset Portfolio

Calpine is currently one of the leading producers of electricity in North America from clean natural gas-fired and renewable geothermal power generation facilities. Calpine’s fleet of modern combined-cycle natural gas-fired power plants is one of the power industry’s most fuel-efficient and low-carbon energy portfolios. Calpine is also one of the world’s largest producers of energy from renewable geothermal sources.

The Company has generating assets throughout North America, though its asset portfolio is concentrated in California and Texas – two of the United States’ largest competitive power markets. Calpine’s power generation facilities are well positioned in these regions, comprising more than 7% of the generating capacity in California and almost 10% of the generating capacity in Texas, or what is commonly referred to as ERCOT.

Outside of West and Texas, the Company operates approximately 9,095 MW of capacity, much of which is committed under long-term power sales contracts. The Company’s asset portfolio contains approximately 7,394 MW of cogeneration capacity, making Calpine a major cogeneration power producer in the United States.

Figure 15: Calpine Generation Capacity by Region

	Calpine Generation Capacity by Region
	Region	# of Plants	Capacity¹ (MW)
	West	45	7,246
	California	41	5,204
	Colorado	2	906
	Arizona	1	520
	Oregon	1	616
	Texas	12	7,510
	Southeast	12	6,254
	SERC	8	4,255
	FRCC	3	865
	SPP	1	1,134
	Northeast and Midwest	11	2,841
	New England	1	537
	New York	5	352
	PJM	2	565
	Midwest	3	1,387
	Total	80	23,851

¹ Average annual capacity, including peaking capability, in MWs. Operating capacity excludes Goldendale, Aries, Parlin, Newark, Pryor, Acadia, Hillabee, Fremont, Washington Parish, Otay Mesa, Russell City and Greenfield. Included in the operating capacity is the non-operational plant Philadelphia Water. For classification of each of these assets please, refer to Figure 6. Total generating capacity including Calpine’s net ownership in construction plants is 25,335 MW.

Calpine’s power plants operate at very low heat rates, consuming significantly less fuel to generate a megawatt-hour (“MWh”) of electricity than older boiler/steam turbine power plants. Calpine’s fleet efficiency provides it with a competitive advantage in certain markets, permitting the Company to economically dispatch its assets when it is uneconomic for other similar assets to operate. This fuel efficiency, combined with advanced emissions control technology, allows the Company to offer environmentally preferred, low-carbon energy products compared to older fossil fuel-fired power generating plants.

Company Overview 27

Calpine’s Geysers power generation operation in northern California is one of the world’s largest producing geothermal resources. Calpine acquired its first stake in the Geysers in 1988 through a minority interest in a 20 MW geothermal plant, representing Calpine’s first owned megawatt of geothermal power generation. By late 2006, Calpine’s geothermal generating capacity had grown to 725 MW in total.¹

Figure 16: Calpine Generation Capacity by Technology

Calpine Generation Capacity by Technology

	Technology	# of Plants	Capacity¹ (MW)
	Intermediate	20	10,755
	Intermediate (Cogeneration)	24	7,394
	Peaking²	17	4,977
	Baseload (Geothermal)	19	725
	Total	80	23,851

¹ Average annual capacity, including peaking capability, in MWs. Operating capacity excludes Goldendale, Aries, Parlin, Newark, Pryor, Acadia, Hillabee, Fremont, Washington Parish, Otay Mesa, Russell City and Greenfield. Included in the operating capacity is the non-operational plant Philadelphia Water. For classification of each of these assets please, refer to Figure 6. Total generating capacity including Calpine’s net ownership in construction plants is 25,335 MW.

² Number of peaking plants excludes intermediate and intermediate (cogeneration) plants with peaking capacity. 4,977 MW Peaking includes peaking capacity of combined cycle facilities.

Figure 17: Top Ten U.S. Merchants by Renewable Generation

Source: Energy Velocity

Note: Includes wind, geothermal, solar, biomass, agricultural byproducts and refuse.

With approximately 6 million MWh of energy generated annually at the Geysers, Calpine is the second largest producer of renewable energy in the U.S.

Since the development of renewable portfolio standards (“RPS”) in a number of states, including California, Calpine has realized a premium on the power sold from the Geysers and additional flexibility in its portfolio due to its ability to generate and market RECs.

Calpine’s operating assets are subject to certain risks and challenges due to the nature of power asset operations. These include operational risks such as failure of power generation equipment, transmission lines, pipelines or other equipment or processes, which may cause limited availability or unplanned outages. The Company manages its operational risks through continuous monitoring and routine and predictive maintenance on each of its assets.

¹ Although the 725 MW of average annual capacity is expected to decline over time due to natural resource depletion, this decline is expected to be offset by additional steam and thermal investments.

Company Overview 28

C. Operating and Construction Power Plants

The table below provides a comprehensive list of the generation facilities that Calpine currently owns and operates under the respective legal entities within Calpine Corporation. The operating plants exclude assets sold or transferred, in the process of being sold or transferred, or under evaluation since December 31, 2006 FYE (for example Goldendale, Aries, Parlin, Newark, Pryor and Acadia are excluded). Included in the operating plants is the non-operational plant Philadelphia Water. Also included in the operating plants is RockGen which is no longer assumed to be divested. In addition, Calpine has three plants under development or construction, Otay Mesa, Russell City, and Greenfield, which are presented herein. Total operating capacity is 23,851 MW and combined with Calpine’s net ownership in construction plants, total generating capacity is 25,335 MW. The total operational and construction capacity excludes three partially constructed / completed plants, Hillabee, Fremont and Washington Parish, for which sales are pending or which are under evaluation or consideration for sale.

Table 15: The Geysers

	Type	Location	Operating	Capacity1	Calpine Ownership
Geysers (19 facilities, 17 active)	Geo	WECC	Baseload	725	100	%

¹ Average annual capacity in MWs.

Table 16: CalGen

	Type	Location	Operating	Capacity1	Calpine Ownership
Baytown	CG	ERCOT	Intermediate - Cogen	830	100	%
Carville	CG	SERC	Intermediate - Cogen	501	100	%
Channel	CG	ERCOT	Intermediate - Cogen	593	100	%
Columbia	CG	SERC	Intermediate - Cogen	606	100	%
Corpus Christi	CG	ERCOT	Intermediate - Cogen	505	100	%
Decatur	CC	SERC	Intermediate	792	100	%
Delta	CC	WECC	Intermediate	840	100	%
Freestone	CC	ERCOT	Intermediate	1,036	100	%
Los Medanos	CG	WECC	Intermediate - Cogen	540	100	%
Morgan	CG	SERC	Intermediate - Cogen	807	100	%
Oneta	CC	SPP	Intermediate	1,134	100	%
Pastoria Energy Facility	CC	WECC	Intermediate	750	100	%
Zion	CT	PJM	Peaking	546	100	%
Total				9,480

Note: CG = Cogeneration, CC = Combined Cycle, CT = Combustion Turbine; Sub Region / Region: PJM / RFC.

¹ Average annual capacity, including peaking capability, in MWs.

Table 17: Calpine Eastern & Cogen

	Type	Location	Operating	Capacity1	Calpine Ownership
Bethpage	CC	NYPP	Intermediate	56	100	%
Bethpage 3	CC	NYPP	Intermediate	80	100	%
Bethpage Peaker	CT	NYPP	Peaking	48	100	%
Kennedy (KIAC)	CG	NYPP	Intermediate - Cogen	121	100	%
Philadelphia Water2	CT	PJM	Peaking	19	83	%
Stony Brook	CG	NYPP	Intermediate - Cogen	47	100	%
Total				371

Note: CG = Cogeneration, CC = Combined Cycle, CT = Combustion Turbine; Sub Region / Region: NYPP / NPCC; PJM / RFC.

¹ Average annual capacity, including peaking capability, in MWs. MW values reflect Calpine’s share of the total plant MW for Philadelphia Water.

² Non-operating due to environmental compliance issues.

Company Overview 29

Table 18: Unrestricted Holdings

	Type	Location	Operating	Capacity1	Calpine Ownership
Auburndale	CG	FRCC	Intermediate - Cogen	150	100	%
Broad River	CT	SERC	Peaking	847	100	%
Gilroy Cogeneration Plant	CG	WECC	Intermediate - Cogen	128	100	%
South Point	CC	WECC	Intermediate	520	100	%
Gilroy Energy Center	CT	WECC	Peaking	135	100	%
Creed	CT	WECC	Peaking	47	100	%
Feather River	CT	WECC	Peaking	47	100	%
Goose Haven	CT	WECC	Peaking	47	100	%
King City Energy Center	CT	WECC	Peaking	45	100	%
Lambie Energy Center	CT	WECC	Peaking	47	100	%
Riverview Energy Center	CT	WECC	Peaking	47	100	%
RockGen Energy Center²	CT	MISO	Peaking	460	100	%
Wolfskill Energy Center	CT	WECC	Peaking	48	100	%
Yuba City Energy Center	CT	WECC	Peaking	47	100	%
Total				2,615

Note: CG = Cogeneration, CC = Combined Cycle, CT = Combustion Turbine.

¹ Average annual capacity, including peaking capability, in MWs.

² No longer considered for divestiture.

Table 19: Calpine Central

	Type	Location	Operating	Capacity1	Calpine Ownership
Hidalgo¹	CC	ERCOT	Intermediate	376	79	%
Clear Lake	CG	ERCOT	Intermediate - Cogen	400	100	%
Texas City	CG	ERCOT	Intermediate - Cogen	453	100	%
Deer Park	CG	ERCOT	Intermediate - Cogen	1,019	100	%
Pasadena Power Plant	CC/CG	ERCOT	Intermediate / Inter. Cogen	776	100	%
Total				3,024

Note: CG = Cogeneration, CC = Combined Cycle, CT = Combustion Turbine.

¹ Average annual capacity, including peaking capability, in MWs. MW values reflect Calpine’s share of the total plant MW for Hidalgo.

Table 20: Calpine Development Holdings

	Type	Location	Operating	Capacity1	Calpine Ownership
Freeport	CG	ERCOT	Intermediate - Cogen	236	100	%
Mankato	CC	MISO	Intermediate	324	100	%
Metcalf	CC	WECC	Intermediate	605	100	%
Riverside	CC	MISO	Intermediate	603	100	%
Rocky Mountain	CC	WECC	Intermediate	621	100	%
Russell City¹ ²	CC	WECC	Intermediate	388	65	%
Total				2,777

Note: For type: CG = Cogeneration, CC = Combined Cycle, CT = Combustion Turbine; For region: MISO = MRO.

¹ Average annual capacity, including peaking capability, in MWs. MW values reflect Calpine’s share of the total plant MW for RussCompany Overviewell City.

² Under construction.

Company Overview 30

Table 21: CCFC Holdings

	Type	Location	Operating	Capacity1	Calpine Ownership
Brazos Valley	CC	ERCOT	Intermediate	594	100	%
Hermiston	CC	WECC	Intermediate	616	100	%
Magic Valley	CC	ERCOT	Intermediate	692	100	%
Osprey	CC	FRCC	Intermediate	599	100	%
Sutter	CC	WECC	Intermediate	578	100	%
Westbrook	CC	NEPOOL	Intermediate	537	100	%
Total				3,616

Note: CC = Combined Cycle; Sub Region / Region: NEPOOL / NPCC.

¹ Average annual capacity, including peaking capability, in MWs.

Table 22: Other Projects

	Type	Location	Operating	Capacity1	Calpine Ownership
Agnews	CG	WECC	Intermediate - Cogen	28	100	%
Auburndale Peaker	CT	FRCC	Peaking	116	100	%
Blue Spruce	CT	WECC	Peaking	285	100	%
Greenfield Energy Centre²	CC	Canada	Intermediate	503	50	%
Greenleaf I	CG	WECC	Intermediate - Cogen	50	100	%
Greenleaf II	CG	WECC	Intermediate - Cogen	49	100	%
Hog Bayou	CC	SERC	Intermediate	237	100	%
King City	CG	WECC	Intermediate - Cogen	120	100	%
Los Esteros	CT	WECC	Peaking	188	100	%
Otay Mesa²	CC	WECC	Intermediate	593	100	%
Pine Bluff	CG	SERC	Intermediate - Cogen	215	100	%
Pittsburg	CG	WECC	Intermediate - Cogen	64	100	%
Santa Rosa	CG	SERC	Intermediate - Cogen	250	100	%
Watsonville	CG	WECC	Intermediate - Cogen	29	100	%
Total				2,727

Note: CG = Cogeneration, CC = Combined Cycle, CT = Combustion Turbine

.¹ Average annual capacity, including peaking capability, in MWs. Reflect Calpine’s share of the total plant MW for Greenfield Energy Centre.

² Under construction.

Company Overview 31

The following diagram presents the existing DIP collateral matrix for illustrative purposes. The collateral for the New Exit Facility will consist of first lien on substantially all assets (including equity in subsidiaries) of the Borrower and the guarantors of New Exit Facility to the extent permitted by existing contractual arrangements and requirements of law after emergence from the Chapter 11 cases.

Figure 18: Detailed Collateral Overview

Note: Excludes Philadelphia Water, Hillabee, Fremont and Washington Parish. For classification of each of these assets please refer to Figure 6. Diagram is pro forma for the completed or planned sale of Goldendale, Aries, Parlin and Acadia. It is also pro forma for Newark and Pryor which are under evaluation.

Table 23: Plants under Development or Construction

Calpine is actively developing or constructing three projects:

	Location	Estimated Commercial Operations	Calpine Ownership		Total Capacity (MW)	Net Interest
Otay Mesa Energy Center	San Diego, CA	2009	100	%	593	593
Russell City	Hayward, CA	2010	65	%	600	388
Greenfield Energy Centre	Ontario, Canada	2008	50	%	1,005	503
Total					2,198	1,484

Company Overview 32

D. Calpine Portfolio Detail

Calpine currently divides its portfolio into four major regions—West, Texas, Southeast (including Oklahoma) and Northeast and Midwest.

E. Regional Highlights

West Region Highlights

Calpine’s assets in the West region contribute the largest share of projected gross margin and EBITDAR of the four Calpine regions.

• Assets: Calpine owns and operates 45 plants in the West region, with total capacity of 725 MW from geothermal units and 6,521 MW from gas-fired units. The California assets account for more than 7% of the state’s installed generation capacity.

• Supply and demand: California is less overbuilt than many other U.S. markets, and natural gas is the price-setting fuel majority of the time, particularly in seasons with low levels of hydroelectric generation. These factors contribute to higher projected power prices and spark spreads (holding other factors constant).

• Regulatory issues: California is moving toward a market structure that provides separate energy and capacity (or resource adequacy) payments, which is expected to benefit Calpine’s generating facilities. Additionally, California has implemented aggressive renewable energy standards and carbon emissions regulations, which create a premium for energy generated by Calpine’s geothermal assets.

F. West Assets

Plants

Calpine operates 45 plants in the West region with a total capacity of 7,246 MW, which includes 725 MW from baseload geothermal units, 5,189 MW baseload capacity from intermediate gas-fired units and 1,332 MW from peaking gas-fired units. Calpine’s West plant locations and technology types are illustrated below.

Geographic Mix1	Dispatch Mix1

Note: Numbers might not add up to 100% due to rounding.

¹ Average annual capacity, including peaking capability, in MWs. 1,332 MW Peaking, as shown in dispatch mix, includes peaking capacity of combined cycle facilities.

Company Overview 33

Calpine’s California assets are concentrated in the northern half of the state, with the exception of the Pastoria facility north of Los Angeles.

Geysers

Located 75 miles north of San Francisco, Calpine’s 19 operating geothermal facilities produce renewable energy and benefit from revenues over and above market electricity prices via the sale of RECs.¹

Operations at the Geysers began in 1960, when Pacific Gas & Electric completed construction of the first geothermal electric generating station run by a utility in the United States. Calpine’s involvement began in October of 1988, with the acquisition of a 5% interest in, and an operating contract for, the 20 MW Aidlin Power Plant. Subsequent acquisitions led to Calpine’s current majority position of 725 MW from 19 operating facilities (339 production wells and 48 injection wells), which make the Geysers the largest operating geothermal facility in the world.

The Geysers operational area encompasses 40 square miles in Lake and Sonoma Counties. This location (with access to five transmission lines) positions the Geysers to sell power into the Northern California market.

The Geysers are critical for transmission grid support, which attracts additional revenues from contracts to provide system support and capacity.

To partially offset the natural decline in generating capacity at the Geysers, as a result of steam field degradation, Calpine is considering importing additional water for injection into existing wells, drilling and constructing pipelines to untapped steam resources and repowering certain plants to improve performance. Calpine is also evaluating an opportunity to add 50 MW of capacity at the Geysers, which could come online as early as 2010/2011. The evaluation of this opportunity includes ensuring that this additional capacity does not have an offsetting negative impact on the existing Geyser Fleet.²

In addition, Calpine is currently evaluating the prospect of developing up to 480 MW of capacity at Glass Mountain between 2011 and 2017. Calpine controls 46,400 acres of leases at Glass Mountain and Medicine Lake, home to the largest undeveloped geothermal resource in the lower 48 states. Social and transmission hurdles would need to be overcome to develop this capacity. In addition, further testing, research and development is necessary to confirm the steam availability and production capability of this potential resource.³

The Geysers’ low variable costs and continual steam access drive its nominal capacity factors toward 100%, meaning plants run during nearly all hours unless they are down for maintenance. With one REC for every MWh of electricity generated, the Geysers operation creates approximately 6 million RECs each year, which can be sold to satisfy the renewable energy requirements or preferences of Load Serving Entities (“LSEs”) throughout the United States (Geysers RECs have been sold in California, Oregon, Texas, Louisiana, Ohio, Pennsylvania and Virginia). The proliferation of renewable energy standards suggests that demand for green energy will increase.

West Contracts

While market prices are significant drivers of projected earnings for Calpine, some of the uncertainty is reduced by the presence of contracts, which dictate the payments Calpine receives for energy and capacity sold from certain West region plants:

• Much of the capacity of the geothermal assets is subject to power sales contracts with the Sacramento Municipal Utility District (“SMUD”) (AAA / A2)⁴, Southern California Edison (“SCE”)

¹ Since all electricity produced in a region is carried by the same transmission and distribution network, consumers cannot technically buy the specific electricity created by an particular source, such as renewable generation. To track and compensate generators for the premium of renewable generation, RECs (also known as “green tags”) were designed. RECs enable market participants to make distinct payment for renewable electricity: one price for the energy itself, and one price for the green attributes.

² Note that the 50 MW expansion at the Geysers is not reflected in the Business Plan projections.

³ Note that the potential development of Glass Mountain is not reflected in the Business Plan projections.

⁴ S&P rating is Senior Secured. Moody’s rating is for Issuer.

Company Overview 34

(BBB+ / A3)¹ and PG&E (BBB+/ Baa3)². The PG&E and SMUD contracts obligate Calpine to sell electricity at a market index price, plus fixed adders for RECs (as well as resource adequacy under the PG&E contract). The SCE contract specifies a fixed price for the renewable component; however, it is index priced for the brown energy component.

• The bulk of the peaking assets are subject to tolling agreements with PG&E through 2011. Under these agreements, Calpine receives fixed and variable payments and converts gas into power for PG&E.

• Calpine’s Qualifying Facilities (“QFs”) are subject to contracts with PG&E, as well as steam sales agreements, in some cases, with nearby industrial customers.³

• The non-QF cogeneration facilities are subject to power and / or steam sales agreements with industrial companies.

Production from the balance of the facilities is not subject to specific contracts, although certain of the projected earnings are hedged via forward sales to various industry counterparts.

G. Texas Region Highlights

Calpine is the third largest generator in the Electric Reliability Council of Texas (“ERCOT”) and operates more than 25% of the installed capacity in the Houston zone. Calpine’s Texas fleet contributes the second-largest share of projected gross margin and EBITDAR of the four Calpine regions:

• Assets: Calpine operates 12 plants in the Texas region, with total capacity of 7,510 MW, all from gas-fired units, of which 4,062⁴ MW operate as cogeneration facilities that market steam in addition to electricity and are often required to run during uneconomic hours to maintain steam output for industrial customers.

• Regional supply and demand: ERCOT is one of the least overbuilt markets in the U.S., and natural gas is almost always the price-setting fuel. These factors contribute to higher projected spark spreads (holding other factors constant), although spark spreads are expected to decline due to lower gas prices. In addition, the recently announced construction of new coal plants could reduce prices and spark spreads on average toward the end of the projection period to the extent the projects are completed.

• Regulatory issues: ERCOT’s market structure and the number of participants foster competitive behavior at both the wholesale and retail levels. Calpine’s plants in the Houston area are subject to increasingly stringent nitrogen oxides (“NO_X”) emissions regulations.

Texas Assets

Plants

Calpine operates the largest, most efficient gas fired fleet in ERCOT. The Company’s 12 plants provide 7,510 MW of capacity, representing nearly 10% of ERCOT’s total installed generation supply and more than 25% of installed combined-cycle capacity. The Company’s combined-cycle fleet has the advantage of operational flexibility (units can ramp up or ramp down in response to fluctuating electricity demand), which enables Calpine to market ancillary services in addition to scheduled electricity. Calpine’s plant technologies are illustrated below. Over half of Calpine’s Texas fleet operates as cogeneration facilities.

¹ Both S&P and Moody’s are Issuer Credit Ratings.

² Both S&P and Moody’s are Issuer Credit Ratings.

³ To receive Qualifying Facility (“QF”) status under the 1978 Public Utility Regulatory Policies Act (PURPA), a generating facility must produce electricity and “another form of useful thermal energy through sequential use of energy” while also meeting other ownership, operational and efficiency criteria. Once a generator attains QF status, utilities are then required by the FERC to purchase the facility’s energy at avoided cost rates (which tend to be favorable to the QF so as to encourage further development of this type).

⁴ Intermediate cogeneration capacity.

Company Overview 35

Figure 19: Texas Plants by Technology

Note: Average annual capacity, including duct capability, in MWs. 869 MW Peaking includes peaking capacity of combined cycle facilities.

ERCOT geographically spans 75% of Texas, serves 20 million customers and is electrically isolated from the rest of the neighboring regional markets due to limited import capabilities. The ERCOT market consists of four market zones (North, South, West and Houston). Much of Calpine’s fleet is concentrated in the Houston zone, where prices and spark spreads are often higher than other ERCOT zones.

Texas Contracts

While market prices are significant drivers of projected earnings for Calpine, some of the associated uncertainty is reduced by the presence of contracts, which dictate the payments the Company receives for energy and capacity sold from certain plants: ¹

• The cogeneration facilities are subject to power and steam sales agreements with industrial companies such as Dow Chemical (A- / A3) ². Total steam generation contract obligations in Texas create must-run obligations for approximately 1,200 MW.

• Significant power sales agreements and financial swaps reduce the market price risk of the Magic Valley and Deer Park facilities.

Production from the balance of the facilities is not subject to specific contracts, although Calpine typically executes other hedges such as forward sales or other derivative transactions.

H. Southeast Region Highlights

Outside of the West and ERCOT, Calpine operates an additional 9,095 MW of capacity, 6,254 MW of which are classified as Calpine’s Southeast fleet. Calpine organizationally defines the “Southeast” as the markets of the Southeastern Electric Reliability Commission (“SERC”), the Florida Reliability Coordinating Council (“FRCC”), and the Southwest Power Pool (“SPP”), located to the north of ERCOT.

¹ The specific contracts listed reflect the material contracts that are physically served by the designated plants. Other hedging contracts that are not served by specific plants are treated as part of the Commercial Operations projections.

² Both S&P and Moody’s are Issuer Credit Ratings.

Company Overview 36

• Assets: Calpine operates 12 gas-fired plants in the Southeast region. 2,208¹ MW of the 6,254 MW is baseload from cogeneration facilities, which market steam in addition to electricity and are often required to run during uneconomic hours to maintain steam output. Approximately 2,600 MW of the non-cogeneration capacity is subject to long-term power sales agreements, which reduce Calpine’s exposure to merchant market dynamics.

• Regional supply and demand: Most regions of the Southeast are more overbuilt than California and ERCOT, and coal is often the price-setting fuel. These factors contribute to lower projected spark spreads (holding other factors constant). Market recovery in SERC and SPP, however, is anticipated to be a positive contributor to Calpine’s future EBITDAR growth.

• Regulatory issues: The Southeast markets tend to be dominated by incumbent vertically integrated utilities. Power is currently sold exclusively through bilateral arrangements with a limited number of counterparties.

Southeast Assets

Plants

Compared to Calpine’s California and Texas assets, which tend to be geographically clustered, Calpine’s 12 assets in the Southeast are spread across multiple market areas. The Southeast region spans three major markets:

• SERC spans an area of approximately 460,000 square miles over 13 states. Calpine’s key sub-regions within SERC are Entergy (“SERC-Entergy”), Southern (“SERC-Southern”), Tennessee Valley Authority (“SERC-TVA”) and the Virginia and Carolinas Regional Group (“SERC-VACAR”)².

• The FRCC region includes the majority of the State of Florida.

• SPP encompasses all or part of six states in the South-Central United States including Oklahoma.

All of Calpine’s Southeast plants are gas-fired. Calpine’s Southeast plant locations and technology types are illustrated below. Calpine operates assets in most markets of the Southeast.

Figure 20: Calpine’s Southeast Plants by Region and Technology

Geographic Mix	Dispatch Mix

Note: Average annual capacity, including peaking capability, in MWs. 1,560 MW Peaking, as shown in dispatch mix, includes peaking capacity of combined cycle facilities.

¹ Intermediate cogeneration capacity.

² Note that this discussion does not address Calpine’s plants in SERC-Southern.

Company Overview 37

Southeast Contracts

While market prices are one of the primary drivers of projected earnings for Calpine, a significant portion of the uncertainty in the Southeast is reduced by the presence of contracts, which dictate the payments Calpine receives for energy and capacity sold from certain plants:

• The cogeneration facilities are subject to power and / or steam sales agreements with industrial companies such as BP Amoco. Total steam contract obligations in the Southeast create must-run obligations for approximately 200 MW.

• Long-term power sales agreements reduce the market price risk of the Decatur and Osprey combined-cycle facilities and the Auburndale and Broad River peaking plants.

Calpine continues to pursue other opportunities to secure long-term contracts, which are viewed as preferable to pure merchant operations (contingent upon fair contract pricing).

I. Northeast and Midwest Region Highlights

Calpine operates 2,841 MW of plant capacity in its Northeast and Midwest fleet. Calpine organizationally defines this “region” as the markets of New York, New England, PJM, and the Midwest.

• Assets: Calpine owns and operates 11 gas-fired plants throughout these markets. 155¹ MW are cogeneration facilities, which market steam or thermal energy in addition to electricity. Approximately 1,100 MW of the non-cogeneration capacity is subject to long-term power sales agreements, which reduces Calpine’s exposure to merchant market dynamics.

• Regional supply and demand: Most regions are more overbuilt than California and ERCOT (with the exception of certain parts of New York) but less overbuilt than the Southeastern U.S. markets. Outside of the Northeast, coal is often the price-setting fuel. These factors contribute to lower projected spark spreads in most regions (holding other factors constant); however, long-term power sales contracts substantially mitigate the effects on Calpine.

• Regulatory issues: The Northeast and PJM markets are considered among the most developed markets of the U.S.

Northeast and Midwest

Plants

Calpine’s assets in this group are spread across multiple market areas. All plants are gas-fired. Most of Calpine’s Northeast capacity operates as intermediate capacity.

¹ Intermediate cogeneration capacity.

Company Overview 38

Figure 21: Northeast and Midwest Plants by Region and Technology

Geographic Mix	Dispatch Mix

Source: Calpine

Note: Average annual capacity, including peaking capability, in MWs. 1,216 MW Peaking, as shown in dispatch mix, includes peaking capacity of combined cycle facilities.

Northeast and Midwest Contracts

A significant portion of Calpine’s capacity in these markets is subject to long-term contracts, which dictate the payments Calpine receives for energy and capacity sold from certain plants:

• The Kennedy and Stony Brook cogeneration facilities are subject to power and thermal energy / steam sales agreements with the JFK airport and the State University of New York, respectively.

• Long-term power sales agreements reduce the market price risk of all facilities in PJM and the Midwest, as well as certain plants in New York. In many cases, these contracts were secured in advance of construction.

J. Power and Commercial Operations

Power Operations

Calpine’s Power Operations function manages the Company’s fleet of power generating assets and is focused on continuous improvement of its clean, safe, efficient and cost-effective operations. Its goals include maximizing the availability and reliability of Calpine’s existing fleet, by leveraging the Company’s institutional expertise to optimize operations.

Calpine is refocusing its Power Operations activities to strengthen its competitive position and address competitive challenges for its existing fleet. The Company has undertaken two key sets of initiatives under its Achieving Calpine Excellence (“ACE”) continuous improvement program, to accomplish these goals.

• The Performance Optimization Program (“POP”) is focused on enhancing the total efficiency of Calpine’s plants. POP primarily entails the implementation of best practices gathered from across the Company’s fleet to ensure that all plants are performing at their optimal level.

• The Calpine Engine Optimization (“CEO”) initiative is designed to reduce heat rates and increase the power output of Calpine’s gas turbine fleet through implementation of optimized parts and components.

Company Overview 39

Calpine also owns, leases or has purchase options for a number of potential new power plant sites or expansions of existing sites. Calpine management continues to evaluate the potential financial impact of these opportunities and, as such, they are not included in the Business Plan projections.

Power Operations function faces certain risks to achieving its financial projections. The ACE optimization initiatives have been successfully implemented in certain plants to date, although the financial results from these initiatives may vary as they are implemented at additional sites, based on individual plant performance. Implementation of these plant performance-enhancing initiatives is continuing across Calpine’s fleet.

Plant construction is subject to a number of risk factors, including delay of commercial operation due to construction difficulties or equipment failure during initial operation.

Commercial Operations

Commercial Operations manages the gross margin of Calpine’s portfolio of physical and contractual assets and obligations. Commercial Operations is focused on the effective management of commodity risk exposures that impact Calpine’s financial performance and the optimal dispatch of the Company’s portfolio.

Commercial Operations function oversees Calpine’s focused asset growth and development strategy. Calpine continually evaluates growth and development projects, focusing on opportunities that will enhance and stabilize cash flow and that are consistent with Calpine’s regional development strategies. Development opportunities are selected based on a variety of factors, including regulatory environment, plant economics, technology alternatives, transmission interconnection capacity and compatibility with existing operations.

Calpine is actively pursuing three contracted development and construction opportunities – Otay Mesa Energy Center (“Otay Mesa”), Russell City Energy Center (“Russell City”) and Greenfield Energy Centre (“Greenfield”). Otay Mesa is a 593 MW combined-cycle combustion turbine power project in the early stages of construction, located in southern San Diego County. Russell City is a 600 MW combined-cycle plant expected to be built in Hayward, California. Calpine will initially own 65% of Russell City, with an option to purchase the remaining 35% post-construction. Greenfield is a 1,005 MW gas-fired facility being constructed in Ontario, Canada. Calpine will own 50% of Greenfield. The financial impact of these development opportunities has been included in the Business Plan.

The Company’s significant natural gas-fired portfolio makes Calpine one of the single largest consumers of natural gas in North America. This creates natural risks and opportunities for the Company as it manages its fleet of power generation assets. During the past five years, there has been a fundamental shift upward in natural gas prices and an increase in near-term price volatility. Commercial Operations manages this dynamic by creating new products and services that take advantage of Calpine’s core knowledge of natural gas as well as its economies of scale in handling such large volumes of gas every year.

To effectively manage price risk, Commercial Operations is active in trading and marketing power, fuel, transmission (power) and transportation (fuel), fuel storage, emissions allowances and RECs in each of the Company’s core geographical regions. Trading and marketing staff work closely with operations staff to ensure plant operational characteristics are considered in the overall management of the portfolio.

Calpine’s Commercial Operations function goals are:

• Ensure the optimal dispatch of Calpine’s generating assets;

• Reduce the potential negative impact of commodity price risk on the value of Calpine’s assets and contracts;

Company Overview 40

• Create value by using the flexibility of Calpine’s physical assets, energy market competencies and infrastructure to provide energy market participants with energy supply and management products; and

• Generate incremental value through active portfolio management and energy marketing by leveraging Calpine’s information, infrastructure and intellectual capital as a major operator in its core markets.

Commercial Operations function markets a full suite of products and services to meet its goals. These include management of commodity risk through trading structured products in bilateral and exchange-traded markets, origination of structured products for third-parties, fuel supply and power transmission arbitrage, identifying economic dispatch opportunities for the physical assets and engaging in real-time trading and marketing of energy products and ancillary services.

Calpine faces certain risks that are inherent in the operation of a power asset fleet. Much of Calpine’s business is conducted in the wholesale gas and power commodity markets, which are subject to significant price volatility. Changes in demand for commodities due to short-term weather variations or longer-term economic trends, changes to competitive supply levels due to new plant construction and changes to market structure due to regulatory developments all contribute to uncertainty for Calpine. Calpine seeks to manage this risk by hedging its gas purchases and electricity sales using short- and long-term contracts.

Company Overview 41

K. Management Overview

Calpine’s management team has a long history of expertise in restructuring, energy and power.

Calpine Management Team

NAME	TITLE	AGE
Robert P. May	Chief Executive Officer	58
Lisa J. Donahue	Senior Vice President, Chief Financial Officer	43
Gregory L. Doody	Executive Vice President, General Counsel and Secretary	43
Michael Rogers	Senior Vice President, President of Power Operations	50
Gary M. Germeroth	Executive Vice President, Chief Risk Officer	49

Robert P. May

Chief Executive Officer

Robert P. May has served as Chief Executive Officer and a director of Calpine since December 2005. Prior to Calpine, Mr. May served as Interim President and Chief Executive Officer of Charter Communications, Inc. from January 2005 to August 2005. He served on the Board of Directors of HealthSouth Corporation from October 2002 to October 2005 and as its Chairman of the Board from July 2004 to October 2005. From March 2003 to May 2004, he served as HealthSouth’s Interim Chief Executive Officer, and from August 2003 to January 2004, he served as Interim President of its outpatient and diagnostic division. Since March 2001, Mr. May has been a private investor and principal of RPM Systems, which provides strategic business consulting services. From March 1999 to March 2001, Mr. May served on the Board of Directors and was Chief Executive of PNV Inc., a national telecommunications company. Mr. May was Chief Operating Officer and a director of Cablevisions Systems Corp., from October 1996 to February 1998. He held several senior executive positions with Federal Express Corporation, including President, Business Logistics Services, from 1973 to 1993. Mr. May was educated at Curry College and Boston College and attended Harvard Business School’s Program for Management Development. Mr. May also serves as a director of Charter Communications, Inc. and on the advisory board of Deutsche Bank America. Mr. May is a member of the Executive Committee.

Lisa J. Donahue

Senior Vice President, Chief Financial Officer

Lisa Donahue has served as Senior Vice President and Chief Financial Officer since November 2006. She is a Managing Director of AlixPartners and its affiliate AP Services. AP Services has been retained by Calpine in connection with its chapter 11 restructuring. Ms. Donahue, who has been associated with AlixPartners since February 1998, will remain a Managing Director of each of AlixPartners and AP Services while serving as Calpine’s Chief Financial Officer. Since joining AlixPartners, Ms. Donahue has also served as an executive officer of several public companies, including most recently as Chief Executive Officer of New World Pasta Company from June 2004 through December 2005, and as Chief Financial Officer and Chief Restructuring Officer of Exide Technologies from October 2001 through February 2003. Ms. Donahue joined AlixPartners from The Recovery Group, a Boston based consulting firm, which she joined in 1994, and prior to that she was a senior vice president with the Boston Financial & Equity Corporation, a specialty lending institution, since 1988. Ms. Donahue received a Bachelor of Arts degree in Finance and Accounting from Florida State University in 1988.

Company Overview 42

Gregory L. Doody

Executive Vice President, General Counsel and Secretary

Gregory L. Doody joined Calpine in July 2006 as Executive Vice President, General Counsel and Secretary. He oversees all of Calpine’s legal affairs. Prior to joining Calpine, Mr. Doody held different positions at HealthSouth Corporation from July 2003 through July 2006, including Executive Vice President, General Counsel and Secretary. From August 2000 through March 2004, Mr. Doody was a Partner at Balch & Bingham LLP, a regional law firm based in Birmingham, Alabama, while he also acted as Interim Corporate Counsel and Secretary of HealthSouth Corporation from September 2003 until March 2004. He earned a Bachelor of Science, Management degree from Tulane University in 1987 and a Juris Doctor degree from Emory University’s School of Law in 1994. He is a member of the Alabama State Bar, Birmingham Bar Association and the American Bar Association. Mr. Doody also is a member of the Executive Committee of The Federalist Society’s Corporations and Securities and Antitrust Practice Group.

Michael Rogers

Senior Vice President, President of Power Operations

Michael Rogers was promoted to Senior Vice President and President of Power Operations in December 2007 after serving two months as Interim Executive Vice President of Power Operations. From 2006 to 2007, Mr. Rogers acted as Senior Vice President of Calpine’s Western power operations. He also served as Chief Operating Officer of the Calpine Power Income Fund from 2005 until the Fund’s sale in 2007. Mr. Rogers has served in both operations and development since joining Calpine Corporation in 2001 as Business Development Director, Calpine c*Power. He became Vice President, Calpine Power Company, West and Canada Regions in 2002. Prior to joining Calpine, he held a number of managerial positions with Pacific Gas and Electric Company in California. He also served as a Trustee of the Calpine Power Income Fund. Mr. Rogers is a graduate of the University of California at Davis with a degree in Chemical Engineering.

Gary M. Germeroth

Executive Vice President, Chief Risk Officer

Gary M. Germeroth, was named Calpine’s Executive Vice President and Chief Risk Officer in June 2007 subsequent to serving as Calpine’s Interim Chief Risk Officer as part of Calpine’s restructuring efforts. Mr. Germeroth, in his role of leading Calpine’s Risk Management function, is responsible for maintaining oversight of Calpine’s risk management framework and assuring that the complex risks of the company are communicated and understood throughout the organization. Previous to Calpine, Gary Germeroth was a member of the Global Energy Practice of PA Consulting Group, one of Calpine’s primary restructuring consultants. Mr. Germeroth brings to Calpine more than 26 years of experience in energy strategy and risk management, having directed a variety of commercial strategy, enterprise risk management and corporate restructuring engagements. He has led efforts related to corporate governance, portfolio risk evaluation, operational risk management, strategic options analysis, management of portfolio capital requirements, organizational and business process design, transaction settlement and financial accounting. Prior to joining PA in 1999, Mr. Germeroth held controllership, risk control, and treasury positions at various entities in his energy career. He holds a Bachelor of Science degree in finance from the University of Denver.

Company Overview 43

V. Power Markets Overview

A. Electricity Industry Background

The electric power industry was traditionally dominated by vertically integrated regulated utilities, which sold power to customers at cost-based rates determined by regulatory processes. Market structure changes over the past several years have led to the development of competitive wholesale power markets, in which competitive bidding sets prices. Power plants may now be owned by entities other than the utilities (e.g., “merchant” generators such as Calpine). Merchant generators may sell electricity to utilities under specific power contracts, or they (and utilities) may buy and sell electricity in the wholesale market.¹ Power prices that utilities charge customers remain regulated in many regional markets, but prices in the wholesale electricity market are now largely unregulated. Consequently, Calpine’s financial performance is now affected by prices set by competitive forces.

The regional supply and demand environment and the competitive position of Calpine’s technology types are two of the key drivers of Calpine’s projected financial performance. Other key drivers include the natural gas price environment, which affects wholesale electricity prices and operating margins, and environmental regulations, which affect market prices as well as operating costs.

A summary of each of these drivers is included below, followed by additional details about each of Calpine’s regional markets.

Supply and Demand

Regional supply and demand conditions affect the pricing that results from wholesale market competition, and are consequently the first key driver of Calpine’s financial performance.

For much of the 1990s, utilities invested relatively sparingly in new generation capacity. As a result, by the late 1990s many regional markets were in need of new capacity to meet growing electricity demand. Prices rose due to capacity shortages and the emerging merchant power industry responded by constructing significant amounts of new capacity. Between 2000 and 2003, more than 175,000 MW of new generating capacity came on line in the United States. In most regions, these new capacity additions far outpaced the growth of demand, resulting in overbuilt markets (markets with excess capacity). In the West, for example, approximately 24,000 MW of new generation was added during this period, while load only increased by approximately 8,000 MW.²

The significant increase in supply relative to demand has contributed to the financial distress encountered by Calpine and other merchant generators in the past few years. Most of this new generation consisted of gas-fired combined-cycle plants,³ which tend to have higher variable costs in today’s natural gas price climate and generally cannot compete solely on the basis of price with nuclear and coal-fired capacity.

¹ In ERCOT, as in some other regional markets such as those in the Northeast, merchant generators now own most of the generation capacity. In certain other regional markets, such as the Rocky Mountain and Southeast regions, regulated utilities continue to own most of the generation capacity.

² Sources: WSCC Summary of Estimated Loads and Resources (issued May 2001); WECC Summary of Estimated Loads and Resources (Issued July 2004).

³ Natural gas-fired, combined-cycle (“CC”) units use a gas turbine to create electricity, then capture, or recycle, the waste heat to create steam, which is then used to create additional electricity through a steam turbine. CC units can operate as intermediate facilities, characterized by greater efficiency than peaking units and superior flexibility compared to baseload generators. While lacking the quick start ability of simple-cycle combustion turbines, CCs are able to respond to swings in demand by increasing or decreasing production levels. Some CCs are also cogeneration facilities, which produce and sell steam or thermal energy for industrial use in addition to electricity.

Power Markets Overview 44

This surge of generation investment has subsided since 2003. During 2005, only 17,000 MW of new supply were added nationwide. As a result, growing demand for electricity has begun to reduce the level of excess supply, leading to the current predictions of decreasing reserve margins for many regional markets through the end of the decade.¹ Currently, however, most regional markets are still overbuilt. Calpine’s plants in California and Texas benefit from lower levels of excess capacity than capacity in many other regional markets.

Generation Technology and Regional Fuel Mix

In a competitive market, the price of electricity in any given hour is typically related to the operating costs of the marginal, or price-setting, generator. Assuming economic behavior by market participants, generating units are generally dispatched in order of their variable costs (units with lower costs are dispatched first and higher-cost units are dispatched as load grows), so the variable costs of the last (or marginal) unit needed to satisfy demand typically drives the regional power price. This market dynamic makes regional generation technology and fuel mix the second key driver of Calpine’s financial performance.

Generation technologies are generally classified as baseload, intermediate or peaking:

• Baseload units are least expensive (fueled by cheaper fuels such as hydro, geothermal, coal or nuclear fuels) and are generally required to serve electricity demand during most hours.

• Intermediate units (such as combined-cycle plants fueled by gas) are more expensive and are generally required to serve electricity demand during on-peak or weekday daylight hours.

• Peaking units (such as simple-cycle combustion turbines fueled by gas or oil) are the most expensive units to dispatch and are generally only needed to serve load during periods of high demand.²

Much of Calpine’s generating capacity is located in California and Texas, regional markets in which gas-fired units set prices during most hours. This has two important implications for Calpine:

• Since gas prices are generally higher than most other input fuels, these regions generally see higher power prices than regions in which coal-fired units set prices. In California, this leads to higher margins for Calpine’s geothermal assets (to the extent the assets are not contracted at fixed prices).

• Since Calpine’s combined-cycle facilities are often more efficient than other gas-fired units in California and Texas, Calpine captures positive margins when higher-cost gas-fired units owned by other parties set power prices (the margin between realized power prices and fuel costs is referred to as the “spark spread”) in both markets.

Outside of the West and Texas regions, other generating technologies (such as coal-fired plants) tend to set prices more often, reducing average prices and spark spreads. These conditions (particularly in overbuilt markets) often make it difficult for gas-fired generation to compete.

In addition to earning margins from the sale of electricity, Calpine’s geothermal assets benefit from regulations that promote renewable or “green” energy sources. Regardless of the dominant technology types for the generation of electricity in California, the current shortage of renewable generation sources creates a premium for power from the geothermal facilities.

Natural Gas Prices

Since natural gas is often the price-setting fuel in Calpine’s major regional markets, natural gas prices are a third overarching driver of the Company’s financial performance. Holding other factors constant (namely, the supply and demand balance and the regional generation technology and fuel mix),

¹ “Reserve margins” are a measure of the balance between supply and demand in a regional electricity market. A reserve margin of 15% indicates that supply exceeds expected peak electricity demand by 15%. Holding other factors constant, lower reserve margins typically lead to higher power prices, since the less efficient (more expensive) capacity in the region is needed to satisfy electricity demand.

² Simple-cycle combustion turbines (“CTs”) are gas-fired units that are capable of generating electricity on very short notice but are also characterized by high operating costs. Due to their flexibility and high variable cost, CT peaking units are typically called upon only during hours of high demand, after less expensive units have already been dispatched.

Power Markets Overview 45

higher gas prices tend to increase Calpine’s margins when plants are dispatched.¹ This is because Calpine’s combined-cycle plants are more fuel-efficient than many other older gas-fired technologies, so units with higher operating costs often set power prices in California and Texas, creating positive margins for Calpine. However, high gas prices in the Southeast and Midwest markets can hurt our competitive position relative to coal-fired units and lead to low dispatch levels.

Gas price variability is widely acknowledged. Gas contracts for delivery beyond 2007 continue to trade at high prices, suggesting that a historically high natural gas price environment will persist for some time. Beyond the near-term, long-term gas forecasts suggest that prices will fall below recent levels but remain higher than historical averages.

Regulations

Environmental regulations force generators to incur costs to comply with limits on emissions of certain pollutants. Higher operating costs for fossil fuel-fired generators implicitly favor low-emissions generating technologies such as Calpine’s geothermal and gas-fired capacity. Unlike some of Calpine’s competitors, which operate significant coal-fired capacity and have announced major environmental capital expenditure programs, Calpine’s necessary environmental capital investments are limited. Further, to the extent that price-setting units experience higher variable costs due to environmental regulations, market prices tend to increase.

Calpine’s regional markets are, or will be, affected by several current and pending environmental regulations:

• Sulfur dioxide (“SO₂”) and nitrogen oxides (“NO_X”) emissions regulations under the Clean Air Interstate Rule (“CAIR”)²: CAIR regulations will impact Calpine’s Texas, Southeast, and Northeast assets. In markets with coal on the margin, these assets are likely to see a positive gross margin impact. Western assets are not regulated under the CAIR program.

• Mercury emissions regulations under the Clean Air Mercury Rule (“CAMR”), which primarily penalize coal-fired generators³: In markets where coal is on the margin (such as the Midwest and some portions of the East), Calpine assets are likely to see a positive gross margin impact. Calpine’s Texas and West assets are expected to see little impact due to CAMR, due to the high percentage of time gas is on the margin.

• Renewable Portfolio Standards (“RPS”): RPS mandates that utilities and other LSEs entities purchase a portion of their electricity from renewable sources. This creates a premium for power sold from the Geysers.

• Carbon (greenhouse gas) regulations: Until recently there were only a handful of greenhouse gas proposals put forth by federal legislators. However, significant events in 2006 and 2007 now point to greater acceptance and likely earlier regulation. These events include the following:

• Change of control in House and Senate;

• Bush Administration’s acknowledgement of intent to act to curb global warming;

• “An Inconvenient Truth” bolstered public awareness and support;

• Intergovernmental Panel on Climate Change reports;

• Multiple new proposed federal regulations on greenhouse gases; and

¹ Note that the positive relationship between gas prices and Calpine's margins ignores the effects of contracts and assumes today's historically high gas pricing climate. If gas prices were to decline to much lower levels (e.g., below $3 per MMBtu), this relationship may change.

² CAIR will cap NO_x and SO₂ emissions in 28 of the easternmost states starting in 2009. With the exception of Oneta in SPP, all Calpine Southeast and Northeast plants will be subject to CAIR.

³ CAMR will tighten mercury emissions limits in 2010 and again in 2018, ultimately reducing coal plant mercury emissions by almost 70%. CAMR could benefit Calpine by reducing the attractiveness of coal generation investments, and outdated existing coal-fired plants may ultimately be forced to make costly capital improvements or retire.

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• State action, including California passing two bills aimed at reducing greenhouse emissions, and, 16 other states passing or proposing their own greenhouse gas regulations.

The eleven new federal greenhouse gas proposals have target start dates ranging from 2010 to 2012. Many proposed state regulations have target start dates around the same time, including California which is seeking to begin regulating greenhouse gases in 2012.

Carbon dioxide emissions regulations will have varying impacts on different stakeholders within the industry. Coal-fired generation projects recently have been cancelled as regulators, financial institutions, and investors have become concerned about the high emissions costs that coal plants will incur when greenhouse gas regulations are enacted. Moreover, greenhouse gas regulations are also anticipated to increase the number of retirements of older and smaller coal, gas and oil fired generators that are not able to cover the higher emission costs. Customers will likely see an increase in electricity prices as generators bid higher prices to cover greenhouse gas emission costs. Some of these higher costs may be mitigated if some or all of the allocation revenues are rebated to customers.

While many market participants are expected to be negatively impacted by greenhouse gas regulations, others are expected to benefit, including efficient generators that will see higher revenues from increased energy prices that more than offset the higher emission costs. Most of Calpine’s gas-fired fleet falls into this category with the exception of some plants that have contracted to sell power at fixed prices and with no provision to increase these fixed prices to cover future greenhouse gas costs.

B. West Region

West Supply and Demand

California

California is less overbuilt than many other U.S. markets and natural gas is the price-setting fuel the majority of the time. Both of these factors benefit Calpine’s uncontracted assets in the West region. Load growth and relatively little investment in generation over the past few years have improved the balance between supply and demand. Holding other factors constant, this reduction of excess supply is expected to benefit Calpine by putting upward pressure on market spark spreads.

California’s current generation supply is weighted toward natural gas-fired technologies, but includes significant levels of hydroelectric and nuclear capacity. The minimal presence of coal capacity reflects a regional distaste for this less environmentally friendly electricity source, a bias that favors Calpine’s gas-fired and renewable capacity.

California’s regional supply base fosters a market in which higher-variable cost gas units are on the margin during most hours, leading to higher prices than typically seen in coal-dominated markets. Despite expected renewable generation capacity additions over the coming years, the tendency for gas-fired units to set market prices is not expected to change, although a downward trend in gas prices (holding other factors constant) is expected to compress spark spreads in the near term, depending on hydroelectric conditions.

Arizona

The Arizona-New Mexico region of WECC, in which Calpine’s South Point facility is located, currently suffers from higher levels of excess capacity than does California.

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Oregon

The Northwest generating supply mix includes high levels of low-cost capacity, with hydro and coal together representing almost 80% of the installed generation base. But unlike other WECC sub-regions, power prices are driven higher by the need for gas-fired facilities during most hours.

Colorado

Calpine’s capacity in Colorado is fully contracted through the projection period. Excess supply conditions are expected to persist in the Colorado/Wyoming region, where approximately 1,600 MW of new coal-fired capacity is slated to come on line.

West Regulatory Issues

California Market Structure

California began restructuring its energy markets in March 1998 under the oversight of the CAISO, the market operator responsible for most regional transmission and power market activities. Multiple factors contributed to the subsequent period of price spikes, rolling blackouts and utility bankruptcies known as the California Energy Crisis.

Since the California Energy Crisis, California utilities have shown some tendency to return to the traditional vertically integrated business model by moving to build generation to satisfy their own electricity demand (relying on rate-based recovery to increase their supply and grow their revenues). This could create additional competition for Calpine that is advantaged by affiliate relationships and regulatory safeguards.

In addition, the process to enable customers to choose among alternate electric suppliers (retail competition) has been put on hold. Since retail choice often increases the number of LSEs and boosts competition, this trend will likely limit the number of counterparties to whom Calpine can market power in California.

A key market structure change for 2007 is the introduction of a formal capacity or “resource adequacy” (“RA”) requirement, which creates payments to generators for providing capacity to ensure system reliability (in addition to variable payments for providing energy). Unlike some Eastern markets such as New York and New England, the CAISO does not currently have an installed capacity requirement. For 2007, the California Public Utilities Commission (“CPUC”) has mandated that LSEs contract with generators to secure adequate capacity to meet planned reserve targets.

RA is unique among capacity market mechanisms in at least two regards:

RA is bifurcated into local RA and system RA. Local RA requirements create payments to generators in load-constrained areas, much like traditional Reliability Must Run (“RMR”)¹ payments, which compensate otherwise uneconomic generators to remain available to ensure system reliability in transmission constrained areas. CAISO is in the process of finalizing tariff language that incorporates its Interim Capacity Procurement Mechanism (“ICPM”) to implement local RA, with the intention of filing this with FERC on January 17, 2008 and proposing an effective date coincident with the start of the MRTU markets (currently scheduled for March 31, 2008). Local RA is expected to benefit Calpine due to the locations of certain of its plants in Northern California (the projections reflect Local RA contracts with PG&E for certain Calpine facilities through 2012). System RA is expected to benefit peaking facilities by providing fixed payments for capacity in addition to variable payments for energy (note that facilities which collect payments for Local RA are not able to collect incremental system RA payments).

¹ Reliability Must Run payments were designed as a temporary solution in many markets across the country. The need for RMRs arose when plants (particularly older, higher-cost units) deemed critical to system reliability threatened to retire due to uneconomic operating conditions in which market margins failed to cover fixed operating expenses. Rather than letting these plants retire (and thus compromising system reliability), regulators offered payments in return for continued operation. Because these out-of-market payments slow the overall growth of system efficiency (where older plants retire and are replaced by newer, more efficient units), system operators would typically like to reduce RMR payments, if not remove them entirely.

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RA is an “all or nothing” arrangement. Unlike other installed capacity markets, in which all available generators are awarded payments based on the system-wide supply/demand balance (the higher the relative supply, the lower the payments), a generator’s ability to collect RA payments depends on its success securing RA contracts with LSEs. While the signals to market participants may be similar to those under other capacity market structures (payments are made to units that are needed), RA presents challenges for planning: Calpine and other generation investors are forced to anticipate whether or not they will secure an RA contract.

Arizona and Oregon Market Structure

The Arizona and Oregon markets are based purely on bilateral transactions, with local regulated utilities responsible for balancing the hourly market. Neither market has announced plans for major market redesigns.

Colorado Market Structure

In Colorado, Calpine’s power is currently sold exclusively through long-term bilateral arrangements with Xcel, the incumbent utility. Colorado lacks an ISO (all transactions are bilateral) and has not announced any major market redesigns.

West Environmental Issues

California’s environmental programs raise the cost of operating in California but also favor “cleaner” generation technologies such as geothermal and gas-fired assets. California’s RPS and recently passed carbon mitigation measures have important implications for Calpine’s performance.

Renewable Portfolio Standards

RPS creates a pricing premium for power generated by renewable generation capacity such as the Geysers.

As of November 2007, more than 20 states have adopted a renewable portfolio standard (RPS), including California and most of the western states. RPS, designed to reduce greenhouse gas emissions, generally require that renewable energy sources (which typically include zero or near-zero emission technologies such as geothermal, wind, solar and biomass, among others) generate a share of the state’s energy production, which may increase over time. This requirement is typically placed on retail sellers of electricity.

The California RPS, which came into effect on January 1, 2003, originally set a mandatory target of 20% renewable resources by December 31, 2010.¹ Pursuant to the Energy Action Plan and the 2005 Integrated Energy Policy Report, legislators have now accelerated the timeline for achieving 20% to December 31, 2010, and Senate Bill 107, enacted in September 2006, has mandated this timeline.² The new plan will force retail sellers to increase their procurement of eligible renewable energy resource such that 20% of all retail sales come from renewable energy by 2010.³

The proliferation of RPS creates increased demand for RECs, which creates a premium for the renewable attributes of electricity produced by the Geysers (as long as geothermal is specified as an eligible renewable energy resource, which is not the case in Massachusetts).

Aggressive renewable energy standards are expected to drive a significant premium for Geysers electricity. The implementation of a federal RPS (not reflected herein) could further boost the premium value of renewable energy: there is currently discussion of a requirement that 10% of all electricity nationwide come from renewable sources by 2030. If adopted, the federal plan would require nationwide additions of more than 40 GW of renewable energy.

¹ Public Utilities Code Section 399.15(b) establishes the 20% goal by 2017 a deadline which was recently accelerated to 2010.

² California Energy Commission (“CEC”), 2005 Integrated Energy Policy Report, CEC-100-2005-007CMF, November 2005; and CEC, California Public Utilities Commission (“CPUC”), and Consumer Power and Conservation Financing Authority, Energy Action Plan, May 2003. The Energy Action Plan was adopted by the CPUC on May 8, 2003 and by the CEC on April 30, 2003.

³ According to the 2006 CEC RPS Verification Report, renewable energy currently accounts for 11.6% of energy sales in California.

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Further investment in renewable capacity will be driven in part by the status of the Production Tax Credit (“PTC”). The PTC is a federal incentive program offering $20/MWh, over a 10-year duration, for electricity produced by new renewable energy plants brought online before 2008. The PTC, which includes geothermal in its list of eligible technologies, is set to expire on December 31, 2008¹; it has, however, been extended several times in the past and appears likely to be extended into 2008. Extension of the PTC would make prospective investment at Glass Mountain and expansions at the Geysers more cost-effective but would also contribute to the entry of additional REC supply into the market (competition for Calpine).

Greenhouse Gas Regulations

On August 31, 2006, California lawmakers approved the most aggressive piece of greenhouse gas legislation in U.S. history. The plan, which will likely have to overcome several legal challenges before its implementation in 2012, calls for a reduction in greenhouse gas emissions to 1990 levels by 2020, a reduction of approximately 25% versus current levels. Many of the details have yet to be finalized, but it appears the new law will include both mandatory controls and market-based solutions, including a program that permits participants to buy and sell carbon emission allowances.

While the impacts of California greenhouse gas regulations are uncertain, Calpine’s fleet of geothermal assets and low-carbon combined-cycle power plants are likely to be well-positioned. Carbon emissions costs will drive market power prices higher, which will directly benefit the zero carbon emissions of the Geysers. The impact on Calpine’s uncontracted combined-cycle facilities is likely to be neutral to positive, depending on whether or not a portion of the necessary emissions allowances are granted to existing units free of charge.² Coal-fired and older technology gas-fired generators, which emit carbon at higher rates than combined-cycle plants, will be most negatively impacted. The projections assume that carbon regulations are implemented in California in 2012 and that no emissions allowances are granted to market participants (consistent with recent plans for carbon regulation in New York). The projections include a benefit to the Geysers from the higher market prices caused by carbon regulation.

C. Texas Region

Texas Supply and Demand

ERCOT is one of the least overbuilt markets in the U.S. and natural gas is almost always the price-setting fuel. Both of these factors benefit Calpine’s merchant assets in Texas (holding other factors constant).

Supply Conditions

Load growth, retirement and mothballing of uneconomic plants and lower levels of investment in new generation have improved the balance between supply and demand over the past few years³. ERCOT’s 2008 reserve margin is 16% and is projected to decline to 13% by 2010 as load grows and fewer new plants are constructed.⁴

Like California, ERCOT’s current generation supply is weighted towards natural gas-fired technologies. Unlike California, coal-fired generation provides the bulk of ERCOT’s baseload capacity.

The regional supply mix fosters a market in which gas-fired units set prices during most hours – when less efficient gas units set prices, Calpine’s units benefit from positive spark spreads. The supply mix

¹ Source: American Wind Energy Association – AWEA.

² When emissions are capped, a critical program detail is the method by which regulators determine who gets the right to emit each unit of emissions. The number of alternative structures are countless: the allocation process might be an auction, in which plants have to pay for each emissions allowance, it might be an outright allocation of permits according to electricity production in a certain (base) year, in which plants are allocated a certain number of allowances for each MWh of energy produced, or it might be a hybrid.

³ Over 13 GW of capacity, mostly inefficient, steam-gas-fired plants, has been retired or mothballed in ERCOT. “Mothballed” plants have been shut down but are minimally maintained to preserve the option to return to operations if economic conditions improve.

⁴ Estimates provided by PA Consulting Group.

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also highlights a challenge for combined-cycle plants in ERCOT. When electricity demand is sufficient to require generation only from a portion of the market’s intermediate gas-fired capacity (with similar variable costs), competition among combined-cycle plants to secure customers can be fierce. The market depth issue creates the need for Calpine to focus on enhancing its plant operational efficiency, providing ancillary and other energy products from its integrated system of plants and building customer relationships as critical elements of successful asset management in Texas.¹

New Coal Construction in Texas

The combination of decreasing reserve margins and historically high natural gas prices has stimulated increased interest in the construction of new coal-fired generation. TXU, NRG, LS Power, CPS (San Antonio) and the PNH Resources have announced a significant amount of new coal-fired power plants targeted to reach commercial operations starting in 2009. Not all of these projects are deemed likely to succeed, but those that do will affect market conditions by reducing the portion of hours during which higher-priced gas-fired units are required to satisfy load.

Notwithstanding the expected coal-fired additions, the tendency for gas-fired units to set market prices is not expected to change, although a downward trend in gas prices (holding other factors constant) is expected to compress spark spreads (the cost differential between gas-fired “Combined-Cycle” and “Peakers” would be lower under lower gas price conditions).

Texas Regulatory Issues

Texas was an early adopter of competitive electric markets (both wholesale and retail) and is viewed by some as a model for the successful transition to a deregulated market. This is partly driven by the influx of new merchant generation construction (which contributed to lower spark spreads) and partly due to relatively high responses by retail customers to alternative suppliers (60% of industrial and 20% of residential have switched away from the default local service providers to competitive retail electric providers). Although the overbuilt market conditions had an adverse effect, Calpine also benefits from this competitive market structure due to the presence of multiple parties with whom Calpine can transact.

Market Changes

ERCOT’s current market design includes a bilateral market (where the vast majority of energy is transacted directly among market participants), a balancing energy (real-time) market, ancillary services markets and zonal price differentiation. Certain changes to the ERCOT market structure are expected within the next few years:

By January 1, 2009, ERCOT expects to move to a nodal market structure. While much is currently uncertain about the nodal design and its implications for Calpine’s assets, moving to a nodal market is generally expected to improve price discovery, relieve congestion and more clearly signal the locations of needed transmission and generation investments. In anticipation of nodal pricing, ERCOT has committed to reduce major transmission congestion through a number of transmission upgrades. By enabling the flow of electricity from high supply areas to high demand areas, these upgrades are expected to reduce the price separation that might otherwise be exhibited under the nodal market structure.²

The introduction of an Independent System Operator (“ISO”) operated day-ahead energy market will accompany the introduction of nodal pricing. This market will provide market participants with an alternative to bilateral arrangements, which currently dominate the ERCOT market. Day-ahead dispatch planning by the ISO is also expected to better inform Calpine’s dispatch decisions and improve dispatch predictability, which will improve Calpine’s ability to optimally dispatch and could reduce unit cycling and maintenance costs.¹

¹ Small differences in costs can have a significant bearing on competitive success, particularly during intermediate-load hours. Actual plant dispatch costs (created by relative fuel efficiency or variable operating costs) have an obvious impact, but so do other costs such as the availability of credit or the presence of customer relationships.

² Under a day-ahead market, participants submit bids to the ISO. It bids are accepted, operators know their units will be called to produce electricity. The ability to economically determine bids based largely on operating costs and know in advance if the unit will be called improves dispatch decision-making and reduces operational uncertainty relative to participating in the real-time market.

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The Public Utility Commission of Texas (“PUCT”) recently approved a new measure to address the possibility of market power abuse (i.e., withholding production, predatory pricing or collusion) in the ERCOT market. While the details are yet to be determined, members of ERCOT that own more than 5% of the installed generation base (such as Calpine) will likely offer voluntary mitigation plans to the PUCT for consideration. This measure is not expected to adversely affect Calpine.

In contrast to California as well as the Northeast markets, Texas legislators have voiced commitment to an “energy only” approach to ensuring system reliability (resource adequacy). Rather than creating a separate payment mechanism for capacity, “energy only” resource adequacy programs count on adequate compensation from variable energy prices to motivate sufficient levels of generation construction. “Energy only” programs typically feature high or nonexistent price caps. ERCOT’s plan is to increase the energy offer cap from the current $1,000 per MWh to $3,000 per MWh, shortly after the nodal market is implemented.

Texas Environmental Issues

Although Texas is generally recognized as an industry-friendly state, tighter NO_x emissions regulations are on the horizon. While changes will affect all plants located in Texas (especially coal plants), they are particularly pertinent to Calpine’s Houston-area assets:

• As of April 2007, power generation facilities are now subject to daily and 30-day emission restrictions under Houston-area rules specified by the Texas Commission on Environmental Quality

• The proposed 8-hour Ozone State Implementation Plan requires installment of increased NOx controls in Eastern Texas. The mandated controls are likely to start in 2010

• Allocations under the Houston-Galveston Mass Emission NO_x cap-and-trade program will decline starting in 2008

• CAIR will cap NO_x and SO₂ emissions in 28 of the easternmost U.S. states, including Texas, starting in 2009

The oldest units in the fleet, Texas City and Clear Lake, will be subject to all four changes. Calpine has retrofitted one of its Texas City units to meet environmental standards and will retrofit one of the remaining two units to avoid decreased run times starting in late 2007. There is no plan to retrofit the third unit since there is no projected need to run that unit more than the level it will be restricted to in the future. Calpine has yet to retrofit any of the three units at Clear Lake.

D. Southeast Region

Southeast Supply and Demand

Most regions of the Southeast are considerably more overbuilt than California and ERCOT and coal is often the price-setting fuel.¹ These factors, combined with the dominance of incumbent utilities, contribute to a challenging market climate for merchant gas-fired plants.

SERC-ENTERGY

Reserve margins in certain SERC sub-regions are currently among the highest in the nation. These excess supply levels were partially caused by merchant generation investments in the early part of the decade, but the legislative climate also contributes by discouraging plant retirements. Entergy’s grandfathered transmission rights (which essentially guarantee preferred transmission access for life) provide a significant incentive to prolong the life of certain existing facilities.

¹ The VACAR sub-region of SERC is an exception: lower reserve margins in VACAR suggest market recovery (when supply and demand come into balance) in 2009.

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Many older plants in SERC (almost two-thirds of Entergy’s non-hydroelectric facilities are more than 20 years old) would be less likely to operate economically in an unencumbered competitive market, especially given pending environmental legislation.¹ If these units are retired, reserve margins will improve, although many years are expected to pass before demand catches up to supply.

In spite of the fact that 69% of Entergy’s supply is gas-fired, excessive reserve margins mean that gas-fired units are often not required to meet electricity demand. Instead, prices are often set by coal-fired plants, leading to lower power prices and negative spark spreads during many hours. In spite of demand growth, reserve margins in Entergy are expected to remain high.

SERC-Southern

The Southern region is also overbuilt with 25% reserve margin. However, reserve margins are expected to decrease to 15% by 2012 due to demand growth and uneconomic plant retirements. New capacity is projected to be needed in 2012 and the spark spread growth is expected to benefit the Hog Bayou facility.

The Southern region supply is generally split between gas (39%) and coal (41%) capacity, with some hydro (9%), nuclear (9%) and oil (2%) as well. This, along with current excess supply, causes current prices to be set by both coal (54% of the time) and gas (46% of the time).

SERC-TVA

Excessive supply also adversely affects Calpine’s Morgan and Decatur plants in the TVA sub-region of SERC. The reserve margin is expected to remain high due to new capacity construction already in progress (including 1,300 MW of nuclear capacity through the restart of the Brown’s Ferry facility in 2007).

TVA’s fleet is heavily weighted toward baseload generation, including coal (43%), hydro (16%) and nuclear (13%). High levels of baseload capacity in TVA contribute to lower prices.

SERC-VACAR

The VACAR sub-region is the exception within SERC. Load growth is expected to create the need for new plant construction by 2011 (if certain uneconomic units retire, as anticipated) and higher market pricing is expected to benefit Calpine’s Columbia facility. Current VACAR capacity is heavily weighted toward baseload generation. Coal and nuclear generation account for more than 90% of the electricity produced in the region. Announced construction projects suggest that coal is the fuel of choice for new generation, but the superior operational flexibility of gas-fired units will be needed to serve demand swings. Coal prices often drive power prices in VACAR.

FRCC

Significant long-term contracts mitigate Calpine’s exposure to Florida’s excess supply conditions. Plans for several new plants have recently been announced, including 3 GW of coal-fired generation, although these projects face local opposition.

SPP

SPP is a fragmented regional market: transmission constraints create multiple pockets of isolated load and generation. By limiting the delivery of power from production areas to load areas, these constraints have slowed the growth of a competitive wholesale market. However, ongoing transmission upgrades in the region as well as tightening reserve margins may create significant upside for Calpine’s Oneta facility. Most notably, a transmission upgrade is in progress in the Tulsa

¹ Significant capacity in SERC consists of older, inefficient steam gas units, which are generally believed to be uneconomic under competitive market conditions. Public utility commissions have started to pressure incumbent utilities to retire these units, but whether or not these units actually retire remains a risk factor for Calpine (retirements of inefficient units are a risk factor across all Southeast markets).

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area, near the Oneta facility. The Tulsa Loop project, due to be completed in 2008, is expected to alleviate most of the congestion into Tulsa which has materially adversely affected Oneta’s historical performance. Declining gas prices are expected to put downward pressure on prices in the near term, and tightening reserve margins are expected to put upward pressure on prices over time.

Southeast Regulatory Issues

Relatively little progress has been made towards restructuring the electricity markets of the Southeast. In contrast to more developed competitive markets, the Southeast markets are characterized by:

Incumbent utilities: Local utilities have not been compelled to divest their generating assets or to procure electricity from third parties.¹ Consequently, these entities dominate the large load pockets and exert control over the transmission system.

Limited players: Market participants are dependent on bilateral market transactions (frequently longer-term contracts) with relatively few counterparties. SERC and FRCC have not adopted an ISO or Regional Transmission Organization (“RTO”) to help facilitate a transition towards competitive electricity markets. SPP, the exception, was granted RTO status in 2004 and introduced a balancing market in February 2007.²

Inefficient generators: Older generating units that are less efficient and would otherwise face retirement are effectively protected by regulations.

Two notable examples of the limitations on competition created by the political strength of incumbent utilities are grandfathered transmission rights in Entergy and barriers to new merchant plant construction in Florida:

• Grandfathered transmission rights in Entergy effectively limit transmission access and create an aging fleet of generators.³ Despite FERC Order 888, which guarantees “open access” to transmission for all generators, local utilities continue to exert significant control over the transmission system.⁴

• FRCC’s Florida Electric Power Plant Act of 1996 has essentially prevented out-of-state power producers from building plants in Peninsular Florida without first obtaining a contract for the plant’s output.⁵ This notoriously high barrier to plant-siting helps protect the value of Calpine’s three plants in FRCC by limiting entry by other merchant generators.

While there are no plans to change the market structures of SERC and FRCC, SPP began a node-based imbalance market in February 2007. The employment of a nodal pricing mechanism will improve price discovery in SPP, which will in turn help motivate more efficient economic behavior. Over time, it is hoped that price signals will drive generation and transmission investment to congested areas, thereby alleviating some of the fragmentation that has historically restricted the growth of competition in the SPP market.

¹ Deregulation starts with the “unbundling,” or mandated separation, of the three pieces of the electricity system: generation, transmission and distribution, and the retail electric provision. SERC and FRCC have not made efforts to unbundle generation from transmission or to require competitive procurement of supply in their markets.

² RTOs regulate the flow of electricity throughout geographic regions. Like ISOs, RTOs are considered one of the first steps towards deregulating a region’s power markets because they promise open access to transmission for all market participants.

³ Many of Entergy’s generators have been granted grandfathered transmission rights, which are only forfeited by the plant upon retirement. This grandfathering has resulted in an aging fleet of generators, which Entergy keeps online to retain the associated transmission rights.

⁴ FERC Order 888 requires transmission owners to offer firm transmission capacity to the extent that they have any available and to treat independent users of their transmission system on the same basis as they do their own assets.

⁵ In the late 1990s, Duke Energy sought to build a 514 MW combined-cycle facility in New Smyrna Beach, FL. The Florida Public Service Commission (FPSC) approved the plans, but the Florida Supreme Court reversed the decision in an April 2000 ruling. In its decision, the Court sited the 1996 Power Plant Siting Act clause that requires projects to seek a “determination of need” from the FPSC before they can be granted siting approval. In other words, prospective merchant power projects must obtain a PPA in order to gain siting approval. This ruling effectively insulates Florida IOUs from merchant competition, as IOUs can build to meet their customers’ “need,” but are not compelled to offer PPAs to potential competitors.

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E. Northeast and Midwest Region

Northeast and Midwest Supply and Demand

New England

Calpine’s Westbrook facility in New England is not subject to long-term contracts, making merchant market conditions critical to its performance.

Aggressive combined-cycle construction in New England in the early part of the decade helped create overbuilt conditions in much of New England by 2004. Decreased generation investment and load growth in recent years have reduced reserve margins and contributed to some recovery of power prices and spark spreads. Due, in part, to the wave of gas-fired construction, natural gas- and oil-fired assets dominate the New England Power Pool (“NEPOOL”), together accounting for approximately 63% of the capacity and 46% of the energy produced. This gas and oil capacity sets prices 88% of the time, with gas alone on the margin in 80% of all hours. This near-constant presence of gas or oil on the margin contributes to high electricity prices. New England’s capacity market provides fixed payments in addition to variable payments for power.

New York

In New York, Calpine benefits from relatively tight supply conditions in transmission-constrained New York City and Long Island. Since wholesale electricity and capacity prices are determined on a zonal level, prices in New York City and Long Island tend to be higher. Two key drivers will affect future available supply:

• Transmission projects such as the Cross Sound Cable, which establishes an interconnection with the NEPOOL grid in Connecticut, are expected to open the markets to lower-priced generation imports from surrounding regions, thereby exerting downward pressure on prices and spark spreads.

• The expiration of an expedited permitting process for new construction (the Article X process) may make greenfield development more difficult, potentially protecting or even increasing the value of Calpine’s units.

Gas-fired generators tend to set power prices during most hours in New York City and Long Island. Installed capacity (ICAP) prices are expected to provide significant fixed payments in addition to variable payments from electricity sales.

PJM

Calpine’s capacity in PJM is contracted through 2012, minimizing the impact of merchant market conditions through the forecast period.

The expanded PJM market has a diverse generation mix with a significant portion of low-cost nuclear and coal generation.¹ Coal dominates the baseload generation and accounts for 59% of the total energy produced. The significant amount of coal-fired and nuclear generation makes it difficult for gas-fired generation to compete during off-peak hours. Consequently, capacity factors for intermediate and peaking units tend to be relatively low. Reserve margins in PJM are expected to decline over time.

¹ The most significant recent development in the PJM region came on January 1, 2006, when the PJM region was expanded westward to include the territories of ComEd, AEP, Dayton Power & Light, Duquesne Light and Dominion Virginia Power. The addition of these regions has added significant quantities of low-cost base load nuclear and coal-fired generation to PJM.

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Midwest (MISO)

The bulk of Calpine’s capacity in the Midwest is subject to long-term contracts through the forecast period. The Midwest ISO’s region (“MISO”) includes a large market footprint with transmission-isolated areas primarily in Minnesota and Wisconsin. MISO has significant levels of installed coal capacity, particularly in its Eastern areas, and new coal development projects have been announced. The resulting high percentage of hours with coal on the margin contributes to lower capacity factors for gas-fired units in the eastern regions of MISO. Reserve margins in MISO are expected to decline over time.

Northeast and Midwest Regulatory Issues

The Northeast and PJM are considered to be among the more developed markets. These markets have transitioned to ISO-governed structures with competitive, transparent pricing. New England, PJM and MISO have implemented nodal pricing (New York’s model is zonal) to provide clear investment signals for transmission and generation development and the Northeast markets have implemented distinct capacity markets in addition to energy markets.

New England and New York have implemented capacity markets to motivate investment in levels of generation that are adequate to ensure system reliability:

• New England’s Forward Capacity Market (“FCM”) is designed to encourage entry of new supply, as well as to promote conservation and efficiency. After the ISO determines the level of installed capacity required for a given commitment period, resources are committed 40 months in advance. An annual forward capacity auction is held for these resources and the market capacity price is pegged to the lowest priced new capacity available to meet demand requirements

• New York’s installed capacity (“ICAP”) market links capacity prices to the supply and demand balance and the cost of new capacity construction.¹ LSEs in both markets are required to purchase adequate capacity to cover expected load obligations. New York City and Long Island remain the most capacity-constrained areas in New York, resulting in above average capacity payments for Calpine’s plants

• PJM’s capacity market, called the Reliability Pricing Model (“RPM”), is a forward looking, auction-based market designed to foster the development of capacity resources in regions of PJM deemed constrained because of limited transmission links to other regions of the RTO. Auctions for each constrained region and the RTO are conducted three years in advance of the delivery year and generation, load response and new transmission projects are eligible to bid their capacity into the auction. RPM is currently in its phase-in period, with full implementation scheduled beginning June 1, 2010

Northeast and Midwest Environmental Issues

In addition to complying with federal restrictions on SO₂, NO_x, and mercury emissions, generators in select Northeast states are preparing for additional state-specific mercury emissions regulations as well as carbon abatement measures mandated by the Regional Greenhouse Gas Initiative (“RGGI”).

A growing list of states has adopted state-specific, mercury-specific emissions plans. Consequently, in addition to the federal CAMR obligations, coal plants in the Northeast/Midwest regions will have, further mercury emission reductions to achieve. Massachusetts, Connecticut, New Jersey and Wisconsin have already implemented their own plans and several other states have proposals outstanding. These more stringent standards, which specify aggressive 85% to 90% reductions by 2008 in Connecticut, Massachusetts and New Jersey and 45% reductions in Wisconsin, present a significant competitive challenge for coal producers in these states, discouraging investment, and likely leading to retirements of older, harder-to-upgrade units.

In December 2005, seven northeastern states signed a memorandum of understanding to implement regional carbon emissions reduction measures. Although carbon allowance allocation programs are yet to be determined by most states, the program institutes a regional emissions cap in 2009, which becomes more restrictive over time.

¹ In 2003, to provide investment incentive for capacity in deficient regions, NYISO altered its capacity market to include a demand curve mechanism. Three different demand curves were established: one each for New York City, Long Island and the New York Control Area, which covers all of New York State. Capacity prices are determined according to the level of installed capacity in a region.

Power Markets Overview 56

Holding other factors constant, RGGI is likely to increase the price of power in participating states. It will also likely challenge the entry of additional coal and oil-fired plants, which already face significant siting difficulties in most New England states. The projections assume RGGI is implemented according to plan in 2009.

Power Markets Overview 57

VI. Existing and Pro Forma Indebtedness

The following chart displays the summary of pro forma total indebtedness for Calpine at emergence of bankruptcy, both at the corporate and subsidiary levels.

Figure 22: Debt at September 30, 2007 Pro Forma for the New Exit Facility

($ in millions)

¹ $300 million of posted letters of credit expected at close of the transaction against the $1,000 million revolving credit portion of the New Credit Facilities.

³ Does not include possible issuance of credit facility of up to $200 million of letters of credit at Calpine Development Holdings. Pro forma for Metcalf and Blue Spruce refinancings.

² Other Projects project debt includes DWR Monetization, Power Contract Financing, Gilroy Note, Blue Spruce Project Financing, Agnews Capital Leases and Other Miscellaneous.

Existing and Pro Forma Indebtedness 58

Corporate Level Indebtedness

The following table exhibits Calpine’s existing corporate level debt at September 30, 2007 and the pro forma debt as a result of the contemplated financing and potential equitization of unsecured Calpine debt at emergence of bankruptcy. In the table below the unsecured debt balances exclude all ULC Notes, which are guaranteed by Calpine, due to Canada deconsolidation in December 2005. All debt balances exclude pre-petition accrued interest.

Table 24: Current and Pro Forma Calpine Corporation Debt at September 30, 2007

($ in millions)

Calpine Corporation	Maturity	Actual Debt Sept 30, 2007		Pro Forma Adjustments			Pro Forma Debt Sept 30, 2007
First Lien DIP Revolving Facility	2014		—
First Lien DIP Term Loan	2014	$	3,980	$	(3,980	)		—
Total DIP loan facility		$	3,980	$	(3,980	)		—
First Lien Exit Revolving Facility	2014				—			—
First Lien Exit Term Loans	2014			$	6,300		$	6,300
First Lien Bridge Facility	2008			$	300		$	300
First Lien Exit Facilities				$	6,600		$	6,600
Second Priority senior secured term loan B	2007	$	733	$	(733	)		—
Second Priority senior secured FRNs	2007		489		(489	)		—
Second Priority senior secured notes	2010		1,150		(1,150	)		—
Second Priority senior secured notes	2011		400		(400	)		—
Second Priority senior secured notes	2013		900		(900	)		—
Total Second priority senior secured debt		$	3,672	$	(3,672	)		—
Total secured debt		$	7,652	$	(1,052	)	$	6,600
Unsecured senior notes	2006	$	102	$	(102	)		—
Unsecured senior notes	2006		139		(139	)		—
Unsecured senior notes	2007		190		(190	)		—
Unsecured senior notes	2008		174		(174	)		—
Unsecured senior notes	2009		181		(181	)		—
Unsecured senior notes	2010		411		(411	)		—
Unsecured senior notes	2011		683		(683	)		—
Total unsecured debt		$	1,880	$	(1,880	)		—
Total senior notes		$	9,532	$	(2,932	)	$	6,600
Convertible senior notes	2006	$	1	$	(1	)		—
Convertible senior notes	2014		539		(539	)		—
Convertible senior notes	2015		650		(650	)		—
Convertible senior notes	2023		634		(634	)		—
Total convertible senior notes		$	1,824	$	(1,824	)		—
Total Calpine Corporation debt		$	11,356	$	(4,756	)	$	6,600

Note: $300 million of posted letters of credit expected at close of the transaction against the $1,000 million revolving credit portion of the New Credit Facilities.

Existing and Pro Forma Indebtedness 59

The table below provides the project level debt for Calpine by entity. Since all subsidiary debt is secured through senior liens on the assets (i.e. encumbered assets), the New Exit Facility Lenders will have a first priority lien on the equity in the subsidiaries of the Borrower to the extent permitted by existing contractual arrangements and requirements of law. The pro forma debt at September 30, 2007 assumes potential equitization of unsecured Calpine debt at emergence of bankruptcy.

Table 25: Current and Pro Forma CCFC and Project Finance Debt at September 30, 2007

($ in millions)

	Maturity	Actual Debt September 30, 2007		Pro Forma Adjustments			Pro Forma Debt September 30, 2007
First Priority Term Loan	2009	$	368		—		$	368
Second Priority Senior Floating Rate Note	2011		411		—			411
Preferred Interest	2011		300		—			300
Total CCFC		$	1,080	$	0		$	1,080
Riverside Energy Center	2011	$	344		—		$	344
Rocky Mountain Energy Center	2011		212		—			212
Total Riverside and Rocky Mountain		$	556	$	0		$	556
Project financing
Bethpage Energy Center 1	2020	$	102		—		$	102
Bethpage Energy Center 2	2020		14		—			14
Blue Spruce Energy Center¹	2018		57		35			92
Broad River Energy	2041		246		—			246
Freeport Energy Center	2011		249		—			249
Gilroy Energy Center, LLC	2011		149		—			149
Mankato Power Plant	2011		213		—			213
Metcalf Energy Center¹	2010		104		165			269
Otay Mesa Energy Center	2018		0		—			0
Pasadena Power Plant	2048		263		—			263
Total project financing		$	1,396	$	200		$	1,596
Hidalgo Energy Center	2008	$	100		—		$	100
King City Power Plant	2028		105		—			105
Stony Brook Power Plant	N/A		61		—			61
Agnews Power Plant	2020		18		—			18
Corporate	N/A		0		—			0
Total capital leases		$	284	$	0		$	284
DWR Monetization due 2010	2010	$	256		—		$	256
Power Contract Financing	2010		67		—			67
Gilroy Note	2014		102		—			102
Metcalf	2035		6		—			6
Contra Costa Water District	2015		2		—			2
Hermiston	2013		1		—			1
Total notes payable / Lines of credit		$	433	$	0		$	433
Auburndale Power Plant	2013	$	76		—		$	76
Gilroy Energy Center	2011		44		—			44
Metcalf Energy Center	2010		155		(155	)		0
Total preferred interest		$	275	$	(155	)	$	120
Total project level debt		$	4,024	$	45		$	4,069
Total Calpine Corp. debt		$	11,356	$	(4,756	)	$	6,600
Total Consolidated Debt		$	15,380	$	(4,711	)	$	10,669

Note: All debt balances exclude pre-petition accrued interest and exclude project-level operating leases. Does not include possible issuance of credit facility of up to $200 million of letters of credit facility at Calpine Development Holdings. Numbers may not foot due to rounding.

1. Refinancing of Blue Spruce and Metcalf will lead to approximately $35mm and $10mm of incremental debt at these projects.

Existing and Pro Forma Indebtedness 60

VII.  Financial Summary

A. Financial Assumptions

Methodology

Financial projections were prepared by Calpine management, in conjunction with the Company’s restructuring advisors and consultants. Projections for 2008 and 2009 rely on forward market prices as of June 29, 2007, while longer term projects were estimated based on a fundamental analysis of Calpine’s earning power:

• Conditions in each of Calpine’s regional markets were forecasted and the revenues and costs resulting from the specific operations of each generating unit in Calpine’s fleet were projected

• Research was conducted to track key drivers of market conditions, including supply and demand. Data regarding generator operating characteristics, new construction project and unit retirements are key inputs to the regional market modeling. Load forecasts such as those published by the Energy Information Agency and other third parties who are widely regarded as objective provide an indication of which units will be needed in each region

• Characteristics of Calpine’s unique asset fleet were reviewed. Such review was critical for identifying operating characteristics and other key inputs, which drive unit specific revenues and costs

• Certain items that impact the forecast since April 2007 are listed below.

• Higher spark spreads in 2009 and higher long-term gas prices (at June 29, 2007)

• Benefits from new carbon regulations now expected in 2012

• Upward pressure on cost of new builds, which influence longer-term market pricing

• Renegotiated and received CPUC approval for the Southern California Edison contract

• Entered into contracts for power for Santa Rosa, Hog Bayou, The Geysers and Pastoria

• RockGen is no longer assumed to be divested

Plant Operating and Maintenance Costs

Plant operating and maintenance expense estimates were based on Calpine’s 2008 budget, which was constructed on a plant-by-plant, account-by-account basis by Calpine plant management and finance staff and authorized by senior management according to Calpine’s standard annual budgeting process. Key budget items include labor, insurance, variable expenses for materials such as water and chemical prudent maintenance activities and property taxes.

Corporate Overhead

• Major components of Calpine’s corporate overhead consist of salaries and wages, benefits, bonuses, outside services, office rent and equipment maintenance, office expenses and selected miscellaneous expenses such as travel and recruiting.

Financial Summary 61

Minority Interest and Equity Investments

Calpine owns 50% of Greenfield and 65% of Russell City, both power plants under development / construction. In the Company’s November 2007 Business Plan, Calpine has presented forecast of Consolidated EBITDAR. Calpine has also forecasted adjusted Cash EBITDAR excluding the financial results attributable to the minority investors in Russell City and including income from equity investments in Greenfield and Otay Mesa. Reporting for Otay Mesa changed in Q2 2007 from full consolidation to equity accounting due to the terms of contractual arrangements with San Diego Gas & Electric Co. Further details are included in Calpine’s recent SEC quarterly report.

B. Forecast Financial Performance

Table 26: Calpine Forecast EBITDAR

	2008			2009			2010			2011			2012			2013
Total Revenue Receipts	$	7,201		$	7,577		$	7,813		$	8,413		$	9,177		$	9,758
Fuel Cost Disbursements		(4,623	)		(4,836	)		(4,969	)		(5,151	)		(5,138	)		(5,483	)
Gross Margin	$	2,578		$	2,741		$	2,844		$	3,261		$	4,039		$	4,275
Total Operating and SG&A Expenses		(896	)		(948	)		(1,067	)		(1,097	)		(1,603	)		(1,742	)
Consolidated EBITDAR	$	1,682		$	1,794		$	1,777		$	2,164		$	2,437		$	2,533
Minority Interest/Equity Investment EBITDAR Adj.		19			98			75			67			73			72
Cash EBITDAR	$	1,702		$	1,892		$	1,852		$	2,231		$	2,510		$	2,605

Note: Cash EBITDAR is after minority interest for Russell City and including income from equity investments in Otay Mesa and Greenfield. Reporting for Otay Mesa changed in Q2 2007 from full consolidation to equity accounting due to the terms of contractual arrangements with San Diego Gas & Electric Co. Further details are included in Calpine’s recent SEC quarterly report.

Financial Summary 62

VIII.  Appendices

Appendix A: Certain Industry Terms

The following glossary defines key terms used throughout this memorandum:

“baseload” means the minimum amount of electric power delivered or required over a given period, at a constant rate

“Btu” means one British thermal unit, the amount of thermal energy required to raise the temperature of one pound of water at its highest density by one degree Fahrenheit. One Btu is equivalent to approximately 1,055 joules

“California Independent System Operator” or “CAISO” is a not-for-profit public-benefit corporation charged with operating the majority of California’s high-voltage wholesale power grid

“Chapter 11” Chapter 11 of the U.S. Bankruptcy Code

“CPUC” means the California Public Utilities Commission

“day-ahead” means the one day forward market price

“DIP” Debtor-in-Possession

“EBITDAR” Earnings Before Interest, Taxes, Depreciation, Amortization, Rent and Reorganization Charges

“ERCOT” means the Electric Reliability Council of Texas, Inc., which is a NERC region

“FERC” means the Federal Energy Regulatory Commission

“FCM” Forward Capacity market

“FPSC” Florida Public Service Commission

“FRCC” Florida Reliability Coordinating Council

“gigawatt” or “GW” means 1,000 megawatts of electrical power

“grid” means the network of high-voltage transmission lines through which power moves. In the United States, there are three distinct electric power grids: the Eastern Interconnect, ERCOT and the Western Interconnect

“heat rate” means the amount of gas required to produce one kWh of energy, expressed as Btu/kWh

“kilowatt” or “kW” means 1,000 watts of electrical power

“kilowatt hour” or “kWh” means one hour during which one kilowatt of electrical power has been continuously produced

“ISO” Independent System Operator

“LSE” Load Serving Entities

Appendices 63

“megawatt” or “MW” means 1,000 kilowatts of electrical power

“megawatt hour” or “MWh” means 1,000 kilowatt hours

“MISO” Midwest Independent System Operator

“MMBtu” means one million Btus

“NEPOOL” New England Power Pool

“nominal” means unadjusted for operational and ambient conditions

“North American Electric Reliability Council” or “NERC” means the North American Reliability Council, which is a power industry alliance composed of 10 regional councils and includes virtually all the power regions of the contiguous United States, Canada, and part of Mexican State of Baja

“NOx” Nitrogen Oxides

“PIK Toggle Debt” Payment in Kind Toggle debt instrument which allows the borrower to add interest to the principal instead of paying cash interest to the lender if the borrower has a better use for the cash or if under restricted liquidity

“peak demand” means the maximum electric load, including losses experienced by a system, in a given period. It is the actual demand by all system customers plus losses

“PG&E” Pacific Gas and Electric Company

“PJM” Pennsylvania Maryland New Jersey Interconnection Association

“POP” Plant Optimization Program

“PPA” Power Purchase Agreement

“PUCT” Public Utilities Commission of Texas

“PUHCA” means the Public Utility Holding Act of 1935, as amended

“PURPA” means the Public Utility Regulatory Act of 1978, as amended, which was enacted by Congress in 1978 to encourage the development of alternative energy sources, PURPA exempts certain QF facilities from regulation under PUHCA, and most rate, financial and organization regulation under state laws. PURPA is administered by FERC, and state and local public utility regulations

“QF” means a “qualifying facility” under PURPA that produces electricity and thermal energy for valid use in an industrial or commercial process in specified minimum proportions, meets certain minimum operating and energy efficiency standards and satisfies an ownership test, which requires that no more than 50% of the QF’s equity can be held by an electric utility or utilities

“Reliability Must-Run” or “RMR”: In return for payment, the ISO may call upon the owner of a generating unit to run the unit when required for grid reliability

“Reserve Margin” Percentage by which available capacity exceeds peak demand in an electric utility system

“RGGI” Regional Greenhouse Gas Institute

“RPM” Reliability Pricing Model

“RPS” Renewable Portfolio Standards

Appendices 64

“RTEP” Regional Transmission Expansion Plan

“RTO” Regional Transmission Operator

“SCE” Southern California Edison

“SERC” Southeastern Electric Reliability Commission

“SMUD” Sacramento Municipal Utility District

“SO₂” Sulfur Dioxide

“spark spread” means the difference between fuel costs and the revenues received for electric generation

“SPP” Southwest Power Pool

“watt” means the scientific unit of electrical power or typically the rate of energy use that gives rise to the production of energy at a rate of one joule per second

Appendices 65