cpn-q22008_10q.htm

12. Commitments and Contingencies

Potential Loss on Deconsolidation/Sale of Auburndale Power Plant — Auburndale, our consolidated subsidiary, is a variable interest entity. Pomifer, an unrelated party, holds a preferred interest in Auburndale, which entitles Pomifer to approximately 70% of Auburndale’s cash distributions through 2013. Pomifer also has an option which, upon exercise, would entitle Pomifer to an additional cash distribution of 20% for a cash strike price, giving Pomifer a right to a total of approximately 90% of Auburndale’s cash distributions through 2013. In August 2008, Pomifer notified us that it intends to exercise its option to increase its share of cash distributions to 90%. Pomifer’s exercise of this option may result in a determination that we no longer absorb the majority of expected losses and residual returns of Auburndale, such that we no longer are the primary beneficiary of Auburndale. If we determine that we are no longer the primary beneficiary of Auburndale, we will be required to deconsolidate Auburndale at the time Pomifer exercises its option.

In addition, on June 3, 2008, Pomifer notified us of its intent to sell its preferred interest in Auburndale and that it had also initiated a third-party sales process requesting bids for 100% of Auburndale. Pomifer has certain “drag-along” rights over our equity interest in Auburndale, which would require us to sell our equity interest in Auburndale for a cash payment as specified in our agreement with Pomifer. If Pomifer exercises its drag-along rights and we are required to sell our entire remaining equity interest in Auburndale to a third party, we expect that we would be required to record a loss in the amount of our equity interests in Auburndale of approximately $200 million, less any proceeds we would receive related to the sale. This impairment could be material.

Litigation

We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business, the more significant of which are summarized below. We review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible,” or “probable” as defined by GAAP. Where we have determined an unfavorable outcome is probable and is reasonably estimable, we have accrued for potential litigation losses. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated presently for every case. The liability we may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result of these matters, may potentially be material to our financial position or results of operations. During the pendency of our Chapter 11 cases through the Effective Date, pursuant to automatic stay provisions under the Bankruptcy Code and orders granted by the Canadian Court, all actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date as well as all pending litigation against the Calpine Debtors generally were stayed. See Note 2 for information regarding our Chapter 11 cases and CCAA proceedings. Following the Effective Date, pending actions to enforce or otherwise effect repayment of liabilities preceding the Petition Date, as well as pending litigation against the U.S. Debtors related to such liabilities generally have been permanently enjoined. Any unresolved claims will continue to be subject to the claims reconciliation process under the supervision of the U.S. Bankruptcy Court. However, certain pending litigation related to pre-petition liabilities may proceed in courts other than the U.S. Bankruptcy Court to the extent the parties to such litigation have obtained relief from the permanent injunction. In particular, certain pending actions against us are anticipated to proceed as described below. In addition to the Chapter 11 cases and CCAA proceedings (in connection with which certain of the matters described below arose), and the other matters

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described below, we are involved in various other claims and legal actions, including regulatory and administrative proceedings arising out of the normal course of our business. We do not expect that the outcome of such other claims and legal actions will have a material adverse effect on our financial position or results of operations.

Pre-Petition Litigation

Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. This case was filed in San Diego County Superior Court on March 11, 2003, and later transferred, on a defense motion, to Santa Clara County Superior Court. Defendants in this case are Calpine Corporation, Peter Cartwright, Ann B. Curtis, John Wilson, Kenneth Derr, George Stathakis, Credit Suisse First Boston LLC, Banc of America Securities LLC, Deutsche Bank Securities, Inc., and Goldman Sachs & Co. The Hawaii Structural Ironworkers Pension Trust Fund alleges that the prospectus and registration statement for an April 2002 offering of Calpine Corporation securities contained false or misleading statements regarding: Calpine Corporation’s actual financial results for 2000 and 2001; Calpine Corporation’s projected financial results for 2002; Mr. Cartwright’s alleged agreement not to sell or purchase shares within 90 days of the April 2002 offering; and Calpine Corporation’s alleged involvement in “wash trades.” The action in the Santa Clara County Superior Court was stayed against Calpine Corporation as a result of Calpine Corporation’s Chapter 11 filing.

On December 19, 2007, Calpine Corporation entered into an agreement with the Hawaii Structural Ironworkers Pension Trust Fund to allow the action to proceed in the Santa Clara County Superior Court. Calpine Corporation remains a defendant to the action. However, the December 19, 2007, agreement provides that the Hawaii Structural Ironworkers Pension Fund waived its right to collect from Calpine Corporation on the claim it had filed against Calpine Corporation in the Chapter 11 cases, or for any settlement with Calpine Corporation, and agreed to seek recovery to satisfy its claim against Calpine Corporation, or for any settlement with Calpine Corporation, solely from any insurance coverage that may be available to Calpine Corporation. The December 19, 2007, agreement does not address the Hawaii Structural Ironworkers Pension Fund’s claims against any of the other defendants. Some or all of the other defendants have asserted or may assert indemnification claims against Calpine Corporation in connection with this action.

On July 1, 2008, a second amended complaint was filed against the same defendants. The second amended complaint repeated the allegations from the first amended complaint and added allegations that the above-described prospectus and registration statement included false or misleading statements related, among other things, to Calpine Corporation’s cash balances and cash flow, construction projects and asset sales. Fact discovery is scheduled to close on October 6, 2008. No trial date has been set in this action. We consider this lawsuit to be without merit and intend to continue to defend vigorously against the allegations.

In re Calpine Corp. ERISA Litig. Two nearly identical class action complaints alleging claims under ERISA (Phelps v. Calpine Corporation, et al. and Lenette Poor-Herena v. Calpine Corporation et al.) were consolidated under the caption In re Calpine Corp. ERISA Litig., Master File No. C 03-1685 SBA, in the Northern District Court. Plaintiff Poor-Herena subsequently dropped her claim. The consolidated complaint, which names as defendants Calpine Corporation, the members of Calpine Corporation’s Board of Directors, the 401(k) Plan’s Advisory Committee and its members, signatories of the 401(k) Plan’s Annual Return/Report of Employee Benefit Plan Forms 5500 for 2001 and 2002, an employee of a consulting firm hired by the 401(k) Plan, and unidentified fiduciary defendants, alleged claims under ERISA on behalf of the participants in the 401(k) Plan from January 5, 2001, to the present who invested in the Calpine unitized stock fund. The consolidated complaint alleged that defendants breached their fiduciary duties under ERISA by permitting participants to buy and hold interests in the Calpine unitized stock fund. All claims were dismissed with prejudice by the Northern District Court. The plaintiff appealed the dismissal to the Ninth Circuit Court of Appeals. As a result of the Chapter 11 filings, the appeal was automatically stayed with respect to Calpine Corporation. In addition, Calpine Corporation filed a motion with the U.S. Bankruptcy Court to extend the automatic stay to the individual defendants. Plaintiff opposed the motion and a hearing was scheduled for June 5, 2006; however, prior to the hearing, the parties stipulated to allow the appeal to the Ninth Circuit Court of Appeals to proceed. If the Northern District Court ruling is reversed, the plaintiff may then seek leave from the U.S. Bankruptcy Court to proceed with the action. Plaintiff’s opening brief was filed with the Ninth Circuit Court of Appeals on November 6, 2006. Further briefing on the appeal was then stayed pending completion of the parties’ participation in the Ninth Circuit Court of Appeal’s alternative dispute resolution program. On March 21, 2007, the parties

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reached an agreement in principle to settle the claims of plaintiff and the purported class in return for a payment of approximately $4 million by Calpine’s fiduciary insurance carrier, the net proceeds of which will ultimately be deposited into individual plan members’ accounts. The parties finalized the settlement agreement on March 7, 2008. Pursuant to the terms of the settlement, the Ninth Circuit Court of Appeals dismissed plaintiff’s appeal without prejudice and remanded the case to the Northern District Court by order dated April 8, 2008. The settlement remains subject to approval by the Northern District Court. The Northern District Court granted preliminary approval on July 17, 2008, and has scheduled a fairness hearing for October 21, 2008, to consider whether to give final approval to the settlement.

Panda Energy International, Inc., et al. v. Calpine Corporation, et al. On November 5, 2003, Panda filed suit in the U.S. District Court, Northern District of Texas against Calpine Corporation and certain of its affiliates alleging, among other things, that defendants breached duties of care and loyalty allegedly owed to Panda by failing to correctly construct and operate the Oneta Energy Center, the development rights of which we had acquired from Panda, in accordance with Panda’s original plans. Panda alleges that it is entitled to a portion of the profits of the Oneta Energy Center and that the defendant’s actions have reduced the profits from Oneta Energy Center thereby undermining Panda’s ability to repay monies owed to Calpine Corporation on December 1, 2003, under a promissory note on which approximately $54 million (including related interest) was outstanding as of June 30, 2008. Calpine Corporation has filed a counterclaim against Panda and related parties based on a guaranty and loan agreement. Trial was set for May 22, 2006, but did not proceed due to the automatic stay. Calpine Corporation filed a motion on October 3, 2007, to lift the automatic stay to pursue its counterclaim. On November 14, 2007, the U.S. Bankruptcy Court granted the motion, lifting the automatic stay. On January 30, 2008, the U.S. District Court issued an order that re-instated the case on the court’s docket. Panda has recently amended its pleadings in the U.S. District Court to allege certain causes of action against Calpine Corporation relating to the contingent net profit interest which it has alleged are post-petition. In February 2008, the Panda entities filed proofs of claim with the U.S. Bankruptcy Court asserting an unsecured claim in the amount of approximately $200 million as rejection damages under the development rights and other agreements. Calpine Corporation objected to the claims in the U.S. Bankruptcy Court. The U.S. Bankruptcy Court held a hearing on Calpine Corporation’s claim objection on July 31, 2008. On August 4, 2008, the Bankruptcy Court issued an order disallowing all proofs of claim filed by Panda against the estate. Mediation was conducted on August 5, 2008, without success. The case is set for trial in January 2009 in the U.S. District Court for the Northern District of Texas. We consider Panda’s lawsuit and proofs of claim to be without merit and intend to continue to vigorously defend against them in the U. S. District Court and the U. S. Bankruptcy Court.

Harbert Convertible Arbitrage Master Fund, Ltd. et al. v. Calpine Corporation. Plaintiff Harbert Convertible Fund and two affiliated funds filed this action on July 11, 2005, in the New York County Supreme Court, and filed an amended complaint on July 19, 2005. In their amended complaint, plaintiffs alleged that in a July 5, 2005, letter to Calpine Corporation they provided “reasonable evidence” as required under the indenture governing the 2014 Convertible Notes that, on one or more days beginning on July 1, 2005, the trading price of the 2014 Convertible Notes was less than 95% of the product of the common stock price multiplied by the conversion rate, as those terms are defined in the 2014 Convertible Notes indenture, and that Calpine Corporation therefore was required to instruct the bid solicitation agent for the 2014 Convertible Notes to determine the trading price beginning on the next trading day. If the trading price as determined by the bid solicitation agent was below 95% of the product of the common stock price multiplied by the conversion rate for the next five consecutive trading days, then the 2014 Convertible Notes would become convertible into cash and common stock for a limited period of time. Plaintiffs have asserted a claim for breach of contract, seeking unspecified damages, because Calpine Corporation did not instruct the bid solicitation agent to begin to calculate the trading price. In addition, plaintiffs sought a declaration that Calpine had a duty, based on the statements in the letter dated July 5, 2005, to commence the bid solicitation process, and also sought injunctive relief to force Calpine Corporation to instruct the bid solicitation agent to determine the trading price of the 2014 Convertible Notes. On November 18, 2005, Harbert Convertible Fund filed a second amended complaint for breach and anticipatory breach of indenture, which also added the 2014 Convertible Notes trustee as a plaintiff.

The treatment provided to the holders of the 2014 Convertible Notes under the Plan of Reorganization was in full satisfaction, settlement, release, and discharge of any claims related to the 2014 Convertible Notes. Accordingly, on April 16, 2008, the New York County Supreme Court discontinued this action with prejudice.

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Whitebox Convertible Arbitrage Fund, L.P., et al. v. Calpine Corporation. Plaintiff Whitebox Convertible Arbitrage Fund, L.P. and seven affiliated funds filed an action in the New York County Supreme Court for breach of contract on October 17, 2004. The factual allegations and legal basis for the claims set forth in that action are nearly identical to those set forth in the Harbert Convertible Fund filings. On October 19, 2005, the Whitebox plaintiffs filed a motion for preliminary injunctive relief, but withdrew the motion on November 7, 2005. Whitebox had informed Calpine Corporation and the New York County Supreme Court that the trustee was considering intervening in the case and/or filing a similar action for the benefit of all holders of the 2014 Convertible Notes. The treatment provided to the holders of the 2014 Convertible Notes under the Plan of Reorganization was in full satisfaction, settlement, release, and discharge of any claims related to the 2014 Convertible Notes. Accordingly, on April 11, 2008, the New York County Supreme Court discontinued this action with prejudice.

Pit River Tribe, et al. v. Bureau of Land Management, et al. On June 17, 2002, Pit River filed suit in the U.S. District Court for the Eastern District of California seeking to enjoin further exploration, construction and development of the Calpine Fourmile Hill Project at Glass Mountain. It challenges the validity of the decisions of the BLM and the Forest Service to permit the development of the project under leases previously issued by the BLM. The lawsuit also sought to invalidate the leases. Only declaratory and equitable relief were sought. Our answer was submitted on August 20, 2002. Cross-motions for summary judgment on all claims in the lawsuit were submitted in May and June 2003. The court held oral argument on the motions on September 10, 2003, and took the motions under advisement. Defendants’ motions for summary judgment were granted on February 13, 2004, and the lawsuit was dismissed. Plaintiff filed an appeal to the Ninth Circuit Court of Appeals on April 15, 2004. Briefing on the appeal was completed on December 6, 2004. Following our Chapter 11 filing, we and Pit River filed a stipulation with the U.S. Bankruptcy Court to lift the automatic stay to allow the appeal to proceed with oral arguments, which were held on February 14, 2006. On November 5, 2006, the Ninth Circuit Court of Appeals issued a decision granting the plaintiffs relief by holding that the BLM had not complied with the National Environmental Policy Act, and other procedural requirements, when granting the lease extensions and, therefore, held that the lease extensions were invalid. On February 20, 2007, the federal appellees filed a Petition for Panel Rehearing of the November 5, 2006, order. We filed our Petition for Rehearing and Suggestion for Rehearing En Banc on February 21, 2007. On April 18, 2007, the Ninth Circuit Court of Appeals issued an order denying both the federal appellees and our Petitions for Rehearing. The remedy phase of the Ninth Circuit Court of Appeals’ opinion had been stayed until Calpine Corporation’s emergence from Chapter 11. Upon emergence from Chapter 11, we contacted the U.S. Department of Justice regarding possible remedies which could be argued to the District Court and prepared to file motions regarding how to implement the Ninth Circuit mandate. On August 4, 2008, the U.S. Department of Justice filed a Request to Reopen Case and Proposed Order to Implement Appellate Mandate. The proposed order would remand the procedural defects identified by the Ninth Circuit to the BLM to cure those defects and render a new decision whether or not to allow geothermal development at Glass Mountain, and if so, whether to extend Calpine Corporation’s mineral leases. The U.S. District Court for the Eastern District adopted the U.S. Department of Justice’s proposed briefing schedule and assigned a hearing date of November 5, 2008, for arguments on the proposed order.

In May 2004, Pit River and other interested parties filed two separate suits in the U.S. District Court for the Eastern District of California seeking to enjoin exploration, construction, and development of the Telephone Flat leases and proposed Project at Glass Mountain. These two related cases had been stayed until emergence. Similar to above, we are now in communication with the U.S. Department of Justice and preparing to re-commence litigation.

Post-Petition Litigation

Chapter 11 Related Litigation

Appeal of Confirmation Order. The Confirmation Order was entered by the U.S. Bankruptcy Court on December 19, 2007. Two motions to reconsider the Confirmation Order were filed by holders of shares of our common stock that were canceled on the Effective Date: the first was filed on December 28, 2007, by Elias A. Felluss and the second on December 31, 2007, by Compania Internacional Financiera, S.A., Coudree Global Equities Fund, Standard Bank of London and Leonardo Capital Fund SPC. On January 15, 2008, the U.S. Bankruptcy Court entered an order denying both of the motions to reconsider. On January 18, 2008, the shareholders who had filed the December 31, 2007, motion filed a notice of

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appeal to the SDNY Court and moved the U.S. Bankruptcy Court for a stay of the Confirmation Order pending appeal. Various additional shareholders subsequently filed joinders to the stay motion in the U.S. Bankruptcy Court. On January 24, 2008, the U.S. Bankruptcy Court entered an order denying the stay motion. The shareholders who filed the December 31, 2007, motion filed an emergency motion with the SDNY Court on January 25, 2008, seeking to expedite their appeal and stay the Confirmation Order pending appeal; their emergency motion was denied by the SDNY Court on February 1, 2008. In the meantime, on January 28, 2008, additional shareholders filed notices of appeal to the SDNY Court. On January 31, 2008, the Plan of Reorganization became effective and we emerged from Chapter 11. Despite the effectiveness of the Plan of Reorganization, all of the appeals remained pending in the SDNY Court. On February 25, March 10, and March 14, 2008, the shareholder appellants filed their respective opening briefs. We filed a response on March 28, 2008, seeking to dismiss the appeals on grounds that (i) the appeals were equitably moot, (ii) the appellants had not made the threshold showing required to reverse the U.S. Bankruptcy Court; and (iii) the appeals all lack merit. The appellants filed their reply briefs on April 7, 2008. On June 6, 2008, the SDNY Court entered an order denying the appeals, finding that all of the appeals were equitably moot. One of the shareholders (Mr. Felluss) filed a motion for reconsideration, which was denied on June 24, 2008. On July 3, 2008, Mr. Felluss filed a notice of appeal with the United States Court of Appeals for the Second Circuit Court of Appeals.

Rosetta Avoidance Action. On June 29, 2007, Calpine Corporation filed a petition in the U.S. Bankruptcy Court against Rosetta for avoidance and recovery of a fraudulent transfer. In July 2005, Calpine Corporation had sold substantially all its remaining domestic oil and gas assets for $1.1 billion to a group led by Calpine Corporation insiders who constituted the management team of Rosetta, which prior to the sale, was a subsidiary of Calpine Corporation. The petition alleges that Rosetta’s purchase of the domestic oil and natural gas assets prior to Calpine Corporation’s Chapter 11 filing was for less than reasonably equivalent value. We are seeking monetary damages for the value Rosetta did not pay Calpine Corporation for the assets it acquired, plus interest, which is currently estimated to be approximately $490 million. However, discovery and further analysis may result in changes to that amount. In the alternative, we are seeking the return of the domestic oil and natural gas assets from Rosetta. On September 11, 2007, Rosetta filed a motion to dismiss the adversary proceeding or seek a stay of the proceeding, which the Court denied on October 24, 2007. On November 5, 2007, Rosetta filed its answer and six counterclaims, principally based on state contract and tort law. On January 4, 2008, we filed a motion to dismiss three of the six counterclaims as legally unsustainable. The Court has deferred ruling on our motion to dismiss counterclaims. Pre-trial document and deposition discovery is ongoing. No trial date has been set.

Non-Chapter 11 Related Litigation

Leone v. Calpine Corporation, et al. On May 22 and 29, 2008, respectively, two putative class action complaints (Joseph Leone v. Calpine Corporation, et al. and Alan Laties v. Calpine Corporation, et al.) were filed in state district court in Harris County, Texas against Calpine Corporation and its current directors, alleging that they either had breached, or would breach, their fiduciary duties in connection with Calpine Corporation’s review of NRG Energy, Inc.’s proposal for a stock-for-stock merger on May 14, 2008. Both lawsuits named the same persons as defendants with the exception of Kenneth Derr, who was named only in the first-filed Leone action. In general, the lawsuits sought to enjoin the defendants from accepting the NRG proposal, a declaration that the defendants had breached their fiduciary duties in connection with the NRG proposal, rescission of a transaction based on the terms of the NRG proposal, a court order requiring the defendants to comply with their fiduciary duties, damages, attorneys’ fees, expenses, and court costs. On June 4, 2008, the two lawsuits were consolidated into a single action. Defendants have not yet answered either lawsuit and are not obligated to do so until after plaintiffs file their consolidated amended class action petition in August 2008. Plaintiffs have filed a motion seeking their appointment as interim class representatives and their attorneys’ appointment as interim class counsel. The court has not yet ruled on this motion. We consider this lawsuit to be without merit and intend to vigorously defend against it.

Kissa v. Calpine Corporation, et al. On May 27, 2008, Andrew J. Kissa filed a putative class action complaint in California Superior Court, County of Santa Clara, against Calpine Corporation and its directors. The complaint alleges, among other things, that the defendants violated their fiduciary duties to shareholders by negotiating with NRG, which sought to acquire us in a stock-for-stock merger. The complaint also alleges that the price offered by NRG was inadequate and unfair, and sought declaratory and injunctive relief directing the defendants to exercise their fiduciary duties to obtain a transaction in the best interests of Calpine Corporation’s shareholders. On June 27, 2008, the defendants filed a demurrer to

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the complaint. On July 11, 2008, Kissa filed a request for dismissal of his complaint without prejudice, which was granted on July 24, 2008. We considered this lawsuit also to be without merit.

Other Post-Petition Matters

Texas City and Clear Lake Environmental Matters. As part of an internal review of our Texas City and Clear Lake Cogeneration power plants, we determined that our Acid Rain Program exemption under 40 CFR 72.6(b)(5) had ceased to apply and we were in violation of the requirements of the Acid Rain Program found in 40 CFR Parts 72-78. We were originally exempt from these provisions based upon each plant being a qualifying cogeneration facility in operation before November 1990 with qualifying Power Purchase Agreements; however, the exemptions ceased to apply in 2002 for Texas City and 1999 for Clear Lake. To remedy the violation, we are required to report our SO2 emissions to the U.S. Environmental Protection Agency and purchase allowances and remit an excess emission fee for each ton over the allowance emitted since expiration of the exemption. We recorded estimated fees of $200,000 for Texas City and Clear Lake Cogeneration power plants, during the first quarter of 2008. We self-reported these violations and are working with the Texas Commission on Environmental Quality and the U.S. Environmental Protection Agency to resolve these matters in a timely manner. Although these agencies have the authority and discretion to issue substantial fines that could be material, we do not believe that the penalties, if any, resulting from these matters will have a material adverse effect on our business, financial condition or results of operations based upon our analysis of the facts and circumstances and consideration of recent cases addressed by the agencies involved.

Communications with the SEC. We have been contacted by and have had meetings with the staff of the SEC regarding our financial statements and internal control over financial reporting as well as those of CalGen, a wholly owned subsidiary. We are cooperating with the SEC staff and have voluntarily provided information in response to their requests. We will continue to cooperate with the SEC with respect to these matters. A negative outcome of this investigation could require us to pay fines or penalties or satisfy other remedies under various provisions of the U.S. securities laws, and any of these outcomes could under certain circumstances have a material adverse effect on our business.

13. Segment Information

We operate in one line of business, the generation and sale of electricity and electricity-related products. We assess our business primarily on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. Accordingly, our reportable segments are West (including geothermal), Texas, Southeast, North and Other. Our Other segment includes fuel management, our turbine maintenance group, our PSM business for periods prior to its sale and certain hedging and other corporate activities.

Commodity margin includes our electricity and steam revenues, hedging and optimization activities, renewable energy credit revenue, transmission revenue and expenses, and fuel and purchased energy expense, but excludes mark-to-market commodity activity and other service revenues. Commodity margin is the key operational measure reviewed by our chief operating decision maker to assess the performance of our segments.

DIP Facility Financing and CalGen Secured Debt Repayment Costs — During the six months ended June 30, 2008, we recorded a $4 million credit related to a valuation revision for secured shortfall claims related to our Second Priority Debt. During the six months ended June 30, 2007, we recorded costs related to the refinancing of our Original DIP Facility and repayment of the CalGen Secured Debt consisting of (i) $52 million of DIP Facility transaction costs, (ii) the write-off of $32 million in unamortized discount and deferred financing costs related to the CalGen Secured Debt and (iii) $76 million as our estimate of the expected allowed claims resulting from the unsecured claims for damages granted to the holders of the CalGen Secured Debt.

Interest (Income) on Accumulated Cash — The decrease in interest income on accumulated cash for the six months ended June 30, 2008, over the comparable period in 2007 related to our emergence from Chapter 11 at which time we ceased allocating a portion of interest income to reorganization items.

Other — Other reorganization items decreased primarily due to a $96 million decrease in foreign exchange losses on LSTC denominated in a foreign currency, primarily the Canadian dollar, during the six months ended June 30, 2008, compared to 2007 as well as a non-recurring charge of $14 million in the first quarter of 2007, resulting from debt pre-payment and make whole premium fees to the project lenders related to the sale of the Aries Power Plant. Also contributing to the decrease was a $23 million decrease in emergence incentive cost accruals related to our emergence from Chapter 11 recorded during the six months ended June 30, 2008, compared to the six months ended June 30, 2007.

Provision for Income Taxes — For the six months ended June 30, 2008, we recorded a tax provision of approximately $20 million compared to a tax provision of $82 million for the six months ended June 30, 2007. See Note 1 of the Notes to Consolidated Condensed Financial Statements for further information.

Non-GAAP Financial Measures

Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with GAAP, as well as the non-GAAP financial measures, commodity margin and Adjusted EBITDA, discussed below, which we utilize as a measure of our liquidity and performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP.

Consolidated Commodity Margin

We use the non-GAAP financial measure “commodity margin” to assess our financial performance on a consolidated basis and by our reportable segments. Commodity margin includes our electricity and steam revenues, hedging and optimization activities, renewable energy credit revenue, transmission revenue and expenses, and fuel and purchased energy expense, but excludes net commodity mark-to-market activity and other service revenues. We believe that commodity margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity margin is not a measure calculated in accordance with GAAP, and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. Commodity margin does not purport to represent gross profit (loss), the most comparable GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly-titled measures reported by other companies.

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The following table reconciles our commodity margin to our GAAP results for the three months ended June 30, 2008 and 2007 (in millions):

	2008			2007
Operating revenues	$	2,828		$	2,060
(Less): Other service revenues		(11	)		(16	)
(Less): Fuel and purchased energy expense		(2,008	)		(1,456	)
Adjustment to remove: Mark-to-market commodity activity, net(1)		(24	)		(53	)
Consolidated commodity margin	$	785		$	535

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(1)	Included in operating revenues and fuel and purchased energy expense.

Our consolidated commodity margin increased by $250 million, or 47%, for the three months ended June 30, 2008, compared to the three months ended June 30, 2007. The increase is primarily due to higher market spark spreads, particularly in Texas. Generation was relatively unchanged, even though our average total MW in operation decreased by 8% for the three months ended June 30, 2008, compared to 2007. Our average capacity factor, excluding peakers, increased to 46.4% for the three months ended June 30, 2008, compared to 43.3% for the three months ended June 30, 2007. See “— Operating Performance Metrics” below for a definition of average capacity factor.

Commodity Margin by Segment

The following table shows our commodity margin by segment for the three months ended June 30, 2008 and 2007 (in millions, except for percentages):

	2008		2007			$ Change			% Change
West	$	340	$	265		$	75			28	%
Texas		258		138			120			87
Southeast		91		65			26			40
North		72		75			(3	)		(4	)
Other		24		(8	)		32			#
Consolidated commodity margin	$	785	$	535		$	250			47

__________

#	Variance of 100% or greater

West — Commodity margin in our West segment increased by 28% for the three months ended June 30, 2008, compared to the same period in the prior year due in part to higher off-peak spark spreads in April 2008, the impact of new power contracts, and, to a lesser extent, a 2% increase in generation during the three months ended June 30, 2008, compared to 2007. Our average capacity factor, excluding peakers, and our average availability increased marginally, both by 4%, for the three months ended June 30, 2008, compared to the three months ended June 30, 2007.

Texas — Commodity margin in our Texas segment increased by 87% due primarily to higher market spark spreads resulting from transmission congestion and warmer temperatures in the second quarter of 2008, as compared to the same period in 2007. Generation in our Texas segment increased by 19%, and we experienced a 19% increase in our average capacity factor to 59.8% for the three months ended June 30, 2008, from 50.1% for the three months ended June 30, 2007.

Southeast — Commodity margin in our Southeast segment increased by 40% resulting from the impact of new power contracts in the second quarter of 2008, as compared to the same period in 2007. Also contributing to the increase was $21 million of commodity margin recognized during the second quarter of 2008 related to a transmission capacity contract for which we received FERC approval during the three months ended June 30, 2008. The increase in commodity margin in our Southeast segment was partially offset by a 35% decrease in generation for the three months ended

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June 30, 2008, compared to the three months ended June 30, 2007, due in part to a 17% decrease in our average total MW in operation from the sale of our interest in Acadia PP in 2007.

North — Commodity margin in our North segment decreased by 4% resulting from a 29% decrease in generation for the three months ended June 30, 2008, compared to the same period in 2007 due to the deconsolidation of RockGen in the first quarter of 2008 and outages at our Westbrook Power Plant during the second quarter of 2008. The effects of these decreases were largely offset by higher realized spark spreads in the second quarter of 2008 compared to 2007.

Other — Commodity margin in our Other segment increased by $32 million primarily resulting from the favorable impact of our commodity trading activity that is not region specific.

The following table reconciles our commodity margin to our GAAP results for the six months ended June 30, 2008 and 2007 (in millions):

	2008			2007
Operating revenues	$	4,779		$	3,722
(Less): Other service revenues		(22	)		(44	)
(Less): Fuel and purchased energy expense		(3,613	)		(2,727	)
Adjustment to remove: Mark-to-market commodity activity, net(1)		127			6
Consolidated commodity margin	$	1,271		$	957

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(1)	Included in operating revenues and fuel and purchased energy expense.

Our consolidated commodity margin increased by $314 million, or 33%, for the six months ended June 30, 2008, compared to the six months ended June 30, 2007. The increase is primarily due to higher market spark spreads, particularly in Texas. Generation was relatively unchanged, even though our average total MW in operation decreased by 8% for the six months ended June 30, 2008, compared to 2007. Our average capacity factor, excluding peakers, increased to 46.3% for the six months ended June 30, 2008, compared to 42.5% for the six months ended June 30, 2007. See “— Operating Performance Metrics” below for a definition of average capacity factor.

Commodity Margin by Segment

The following table shows our commodity margin by segment for the six months ended June 30, 2008 and 2007 (in millions, except for percentages):

	2008		2007			$ Change			% Change
West	$	609	$	495		$	114			23	%
Texas		388		224			164			73
Southeast		128		102			26			25
North		134		138			(4	)		(3	)
Other		12		(2	)		14			#
Consolidated commodity margin	$	1,271	$	957		$	314			33

__________

#	Variance of 100% or greater

West — Commodity margin in our West segment increased by 23% for the six months ended June 30, 2008, compared to the same period a year ago due to higher off-peak spark spreads in April 2008, the impact of new power contracts, and a 6% increase in generation during the six months ended June 30, 2008, compared to 2007. Our average capacity factor, excluding peakers, increased by 8% for the six months ended June 30, 2008, compared to the six months ended June 30, 2007.

growth opportunities, is dependent on the continued availability of capital on attractive terms. As described below, upon implementation of our Plan of Reorganization and emergence from Chapter 11, we converted our existing DIP Facility into exit financing under our Exit Credit Facility, which, including the term loans funded, currently provides approximately $7.0 billion of term and revolving credit.

We currently obtain cash from our operations, borrowings under credit facilities including the Exit Credit Facility, project financings and refinancings. In the past, we have also obtained cash from issuances of equity or debt securities, proceeds from sale/leaseback transactions, contract monetizations, and sale or partial sale of certain assets. We or our subsidiaries may in the future complete similar transactions consistent with achieving the objectives of our business plan. We utilize this cash to fund our operations, service or prepay debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures, support our hedging, balancing and optimization activities, and meet our other cash and liquidity needs. We reinvest any cash from operations into our business or use it to reduce or pay interest on our debt, rather than to pay cash dividends. We have remaining unused credit under our Exit Credit Facility of approximately $221 million to issue additional letters of credit or to borrow additional cash. We recently entered into two credit facilities that increase our liquidity available to collateralize obligations to counterparties under eligible commodity hedge agreements during periods of increasing gas prices. We entered into the twelve month Knock-in Facility on June 25, 2008, which provides an initial $50 million of available capacity for the issuance of letters of credit up to a total maximum availability of $200 million contingent on natural gas futures contract prices exceeding certain thresholds and the Commodity Collateral Revolver on July 8, 2008, with an initial advance of $100 million and up to a total maximum availability of $300 million contingent on mark-to-market exposure amounts under certain reference transactions.

We have significant NOLs that will provide future tax deductions if we generate sufficient taxable income during the carryover periods. We have recorded a valuation allowance against most of these losses as we determined it is more likely than not they will not be realized as measured under GAAP. Approximately $5.1 billion of our NOLs have annual limitations under IRC Section 382. Amounts subject to limitations, but not used, can be carried forward to succeeding years. We also expect to generate approximately $1.5 billion to $2.0 billion in NOLs in 2008. Approximately 90% of this NOL will not be subject to annual limitation under IRC Section 382 unless we experience another ownership change before it is utilized. In addition, we have approximately $900 million in NOLs related to Canada with a full valuation allowance.

We do not intend to pay any cash dividends on our common stock in the foreseeable future because of our ongoing liquidity constraints and the needs of our business operations. In addition, our ability to pay cash dividends is restricted under the Exit Credit Facility and certain of our other debt agreements. Future cash dividends, if any, will be at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual restrictions and such other factors as our Board of Directors may deem relevant.

In order to improve our liquidity position, maximize our core strategic assets in the markets in which we operate and control our business growth, we began taking steps during and after our emergence from Chapter 11 to stabilize, improve and strengthen our power generation business and our financial health by reducing activities and curtailing expenditures in certain non-core areas. We expect to continue our efforts to reduce overhead and discontinue activities that do not have compelling profit potential or otherwise do not constitute a strategic fit with our core business of generating and selling electricity and electricity-related products. Our development activities were reduced, and we have only one project, Russell City Energy Center, currently in active development. As of the filing of this Report, we have been successful in obtaining an agreement in principle to amend the PPA between PG&E and Russell City Energy Center which provides for continued development of the project and extends the expected commercial operation date by two years from 2010 to June 2012. On July 29, 2008, the EAB remanded the PSD permit to the Bay Area Air Quality Management District for the Russell City Energy Center. The PSD permit was remanded solely based on the finding that the District failed to issue timely notice of the public comment period on the PSD permit. The Bay Area Air Quality Management District is directed to reopen the public comment period on the draft PSD permit, providing public notice fully consistent with the federal noticing requirements. The EAB found no substantive defects in the Permit, and also addressed and denied review of each substantive claim in the Appeal on the basis that they fell beyond the EAB’s jurisdiction and added that it would not subsequently consider these claims. If the PSD permit is not appealed again, it is expected to be final by the end of November 2008. We have interests in two projects, OMEC and Greenfield LP, currently under construction. We continue to review other development opportunities, which were

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put on hold during the pendency of our Chapter 11 cases, to determine whether future actions are appropriate. We may also pursue new opportunities that arise, including expansions of existing facilities, particularly if power contracts and financing are available and attractive returns are expected. We have completed the sale of certain of our power plants or other assets, and expect that, as a result of our ongoing review process, additional power plants or other assets may be sold, the agreements relating to certain of our facilities may be restructured, or commercial operations may be suspended at certain of our power plants. See Note 5 of the Notes to Consolidated Condensed Financial Statements and “— Asset Sales and Purchase of Investment” below for further information regarding activities during the six months ended June 30, 2008.

We believe the actions we have taken, including implementing our Plan of Reorganization, closing on our Exit Credit Facility, Commodity Collateral Revolver and Knock-in Facility, reducing our activities in certain non-core areas and disposing of certain underperforming assets, will allow us to generate sufficient cash to support our operations over the next twelve months and beyond. Our ability to generate sufficient cash is dependent upon, among other things: (i) improving the profitability of our operations; (ii) complying with the covenants under our Exit Credit Facility and other existing financing obligations; (iii) developing a long-term strategy focused on projects that fit our core business; and (iv) stabilizing and increasing future contractual cash flows.

Exit Facilities — Upon our emergence from Chapter 11, we converted the approximately $4.9 billion of loans and commitments outstanding under our DIP Facility (including the $1.0 billion revolver) into loans and commitments under our approximately $7.3 billion of Exit Facilities. The Exit Facilities provide for approximately $2.1 billion in senior secured term loans and $300 million in senior secured bridge loans in addition to the loans and commitments that had been available under the DIP Facility. The Exit Facilities include:

The Exit Credit Facility, comprising (i) approximately $6.0 billion of senior secured term loans; (ii) a $1.0 billion senior secured revolving facility; and (iii) the ability to raise up to $2.0 billion of incremental term loans available on a senior secured basis in order to refinance secured debt of subsidiaries under an “accordion” provision; and

The Bridge Facility, which, prior to its repayment as described below, provided for a $300 million senior secured bridge term loan.

The approximately $6.0 billion of senior secured term loans and the $300 million Bridge Facility were fully drawn and we drew approximately $150 million under the $1.0 billion senior secured revolving facility on the Effective Date. The proceeds of the drawdowns, above the amounts that had been applied under the DIP Facility as described below, were used to repay a portion of the Second Priority Debt, fund distributions under the Plan of Reorganization to holders of other secured claims and to pay fees, costs, commissions and expenses in connection with the Exit Facilities and the implementation of our Plan of Reorganization. Term loan borrowings under the Exit Credit Facility bear interest at a floating rate of, at our option, LIBOR plus 2.875% per annum or base rate plus 1.875% per annum. Borrowings under the Exit Credit Facility term loan facility require quarterly payments of principal equal to 0.25% of the original principal amount of the term loan, with the remaining unpaid amount due and payable at maturity on March 29, 2014.

As of March 6, 2008, the Bridge Facility had been repaid in full in accordance with its terms with proceeds from the sales of the Hillabee and Fremont development project assets.

The obligations under the Exit Credit Facility are unconditionally guaranteed by certain of our direct and indirect domestic subsidiaries and are secured by a security interest in substantially all of the tangible and intangible assets of Calpine Corporation and the guarantors. The obligations under the Exit Credit Facility are also secured by a pledge of the equity interests of the direct subsidiaries of each guarantor, subject to certain exceptions, including exceptions for equity interests in foreign subsidiaries, existing contractual prohibitions and prohibitions under other legal requirements.

The Exit Credit Facility contains covenant restrictions, including limiting our ability to, among other things: (i) incur additional indebtedness and issue stock; (ii) make prepayments on or purchase indebtedness in whole or in part; (iii) pay dividends and other distributions with respect to our stock or repurchase our stock or make other restricted payments; (iv) use money borrowed under the Exit Credit Facility for non-guarantors (including foreign subsidiaries); (v) make certain

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investments; (vi) create or incur liens to secure debt; (vii) consolidate or merge with another entity, or allow one of our subsidiaries to do so; (viii) lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales; (ix) limit dividends or other distributions from certain subsidiaries up to Calpine; (x) make capital expenditures beyond specified limits; (xi) engage in certain business activities; and (xii) acquire facilities or other businesses.

The Exit Credit Facility also requires compliance with financial covenants that include (i) a maximum ratio of total net debt to Consolidated EBITDA (as defined in the Exit Credit Facility), (ii) a minimum ratio of Consolidated EBITDA to cash interest expense and (iii) a maximum ratio of total senior net debt to Consolidated EBITDA. We were in compliance with all our covenants related to our Exit Credit Facility at June 30, 2008.

As of June 30, 2008, under the Exit Credit Facility we had approximately $6.0 billion outstanding under the term loan facilities, and $525 million outstanding under the revolving credit facility and $254 million of letters of credit issued against the revolving credit facility.

Other Financing Activities — On February 1, 2008, Blue Spruce entered into a $90 million senior term loan. Net proceeds from the senior term loan were used to refinance all outstanding indebtedness under the existing Blue Spruce term loan facility, to pay fees and expenses related to the transaction and for general corporate purposes. The senior term loan carries interest at LIBOR plus an initial base rate of 1.63%, which escalates to 2.50% over the life of the senior term loan and matures December 31, 2017. The senior term loan is secured by the assets of Blue Spruce. In connection with this refinancing, we recorded $7 million in loss on debt extinguishment, related to the write-off of deferred financing costs of $4 million and breakage costs of $3 million, which are recorded in other (income) expense, net on our Consolidated Condensed Statements of Operations.

During the first quarter of 2008, we entered into a letter of credit facility related to our subsidiary Calpine Development Holdings, Inc. under which up to $150 million is available for letters of credit. As of June 30, 2008, $115 million in letters of credit had been issued under this facility.

On June 10, 2008, Metcalf closed on a $265 million new term loan facility. The proceeds were used to repay Metcalf’s existing $100 million term loan facility and $155 million preferred interests. The new term loan facility, which matures on June 10, 2015, bears interest at Metcalf’s option at LIBOR plus 3.25% or base rate plus 2.25% and is secured by the assets of Metcalf and the sole member interest held by Metcalf’s parent, Metcalf Holdings, LLC. In connection with this refinancing, we recorded $6 million in loss on debt extinguishment, related to the write-off of deferred financing costs of $3 million and breakage costs of $3 million, which are recorded in other (income) expense, net on our Consolidated Condensed Statements of Operations.

On June 25, 2008, we entered into the Knock-in Facility, a 12-month, $200 million letter of credit facility. Our obligations under the Knock-in Facility are unsecured. Availability of letters of credit for issuance under the Knock-in Facility is up to a total maximum availability of $200 million contingent on natural gas futures contract prices exceeding certain thresholds, with initial availability for up to $50 million. As of June 30, 2008, no letters of credit had been issued under this facility.

On July 8, 2008, we entered into the Commodity Collateral Revolver, a two-year, $300 million secured revolving credit facility, which shares the benefits of the collateral subject to the liens under the Exit Credit Facility ratably with the lenders under the Exit Credit Facility. At closing, we borrowed an initial advance of $100 million. Future advances under the Commodity Collateral Revolver are limited to the lesser of $300 million and the MTM Exposure (as defined in the Commodity Collateral Revolver) under certain reference transactions, less the advanced amount then outstanding. Amounts borrowed under the Commodity Collateral Revolver are to be used to collateralize obligations to counterparties under eligible commodity hedge agreements. The Commodity Collateral Revolver bears interest at LIBOR plus 2.875% per annum. Advances may be repaid prior to the maturity date, in whole or in part, provided that partial payment shall not reduce the aggregate outstanding advances to less than $100 million. Repayments made prior to the maturity date that do not reduce the total available commitment amount are subject to a 5% premium (plus breakage costs, if any).

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Both the Knock-in Facility and Commodity Collateral Revolver contain covenant restrictions and require compliance with financial covenants substantially equivalent to those under the Exit Credit Facility.

Cash Management — We manage our cash in accordance with our intercompany cash management system subject to the requirements of the Exit Credit Facility and requirements under certain of our project debt and lease agreements or by regulatory agencies.

During the pendency of our Chapter 11 cases, in lieu of distributions, our U.S. Debtor subsidiaries were permitted under the terms of the Cash Collateral Order to make transfers from their excess cash flow in the form of loans to other U.S. Debtors, notwithstanding the existence of any default or event of default related to our Chapter 11 cases.

Cash Flow Activities — The following table summarizes our cash flow activities for the six months ended June 30, 2008 and 2007 (in millions):

	2008			2007
Beginning cash and cash equivalents	$	1,915		$	1,077
Net cash provided by (used in):
Operating activities		(586	)		(184	)
Investing activities		469			343
Financing activities		(1,428	)		168
Net increase (decrease) in cash and cash equivalents		(1,545	)		327
Ending cash and cash equivalents	$	370		$	1,404

Cash flows used in operating activities for the six months ended June 30, 2008, resulted in net outflows of $586 million as compared to net outflows of $184 million for the same period in 2007. The increase in net outflows compared to the same period in 2007 is primarily attributable to non-cash operating items and changes in operating assets and liabilities. For the six months ended June 30, 2008, non-cash operating items included net adjustments of $(137) million, primarily related to changes in derivatives and derivative contracts classified as fiinancing activities of $(192) million and reorganization items of $(322) from gains on sales of assets and the reconsolidation of our Canadian Debtors, partially offset by depreciation and amortization and deferred income taxes of $280 million and $85 million, respectively, as compared to net adjustments of $853 million for the same period a year ago, related to reorganization items of $497 million and depreciation and amortization and deferred income taxes of $284 million and $82 million, respectively. Other non-cash operating items remained relatively comparable from period to period. Our changes in operating assets and liabilities accounted for a net use of funds of $432 million in the six months ended June 30, 2008, compared to a net use of funds of $78 million in the same period in 2007, primarily due to $356 million in additional margin deposits and prepayments made after December 31, 2007, due to higher gas prices and corresponding increased collateral requirements.

Cash flows provided from investing activities were primarily obtained from sales of investments, turbines and power plant assets for the six months ended June 30, 2008 and the same period in 2007. Our proceeds from the sales of these assets remained the same for both periods at $398 million; however, cash flows provided by investing activities for the six months ended June 30, 2008, increased $126 million compared to the same period in 2007. The increase is primarily due to a decrease of $49 million in purchases of property, plant and equipment, a decrease of $59 million in contributions to unconsolidated investments and a favorable effect on cash of $64 million from the reconsolidation of our Canadian subsidiaries for the six months ended June 30, 2008, as compared to an unfavorable effect on cash of $29 million for the deconsolidation of OMEC for the same period in 2007. Offsetting these increases in cash flows from investing activities was a lower return of investment in Greenfield LP of $24 million for the six months ended June 30, 2008, as compared to $92 million for the same period in 2007.

Our cash flows used in financing activities for the six months ended June 30, 2008, resulted in net outflows of $1.4 billion, as compared to cash provided by financing activities of $168 million for the same period in 2007. The increase in net cash outflow was primarily the result of our emergence from Chapter 11 and our recapitalization on the Effective Date. On and subsequent to the Effective Date, we borrowed $3.5 billion under our Exit Facilities and used cash on hand to repay our

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Second Priority Debt of $3.7 billion in addition to cash payment of obligations under the Plan of Reorganization, working capital and other general corporate purposes. We also repaid $855 million of borrowings under our Exit Facilities during the six months ended June 30, 2008. Other increases in net cash outflows used for financing activities compared to the same period in 2007 are an increase of $95 million for repayments under the DIP Facility, an increase in redemption of preferred interests of $157 million and an increase of $127 million in financing costs, primarily related to closing on our Exit Facilities. Offsetting our cash flows used in financing activities for the six months ended June 30, 2008, were $103 million received from project refinancings, net of project financing repayments, compared to net outflows of $54 million for the same period in 2007 and $34 million received from the settlement of derivatives. During the six months ended June 30, 2007, our primarily source of cash provided by financing activities were proceeds of $614 million from borrowings under the DIP Facility, which was partially offset by payments of $224 million to repay a portion of the CalGen Secured Debt, $89 million for notes payable and other lines of credit, net repayments of $54 million under project financings and $60 million in financing costs related to the refinancing in March 2007 of the Original DIP Facility with the DIP Facility.

Letter of Credit Facilities — At June 30, 2008, we had a total of $476 million in amounts outstanding under letters of credit including $254 million under our Exit Credit Facility and $115 million under the letter of credit facility related to our subsidiary Calpine Development Holdings, Inc., as well as amounts outstanding under other credit facilities.

Margin Deposits and Other Credit Support — We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under the Exit Credit Facility as collateral under certain of our power and gas agreements that qualify as “eligible commodity hedge agreements” under the Exit Credit Facility, and under certain of our interest rate swap agreements, in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements will share the benefits of the collateral subject to such first priority liens ratably with the lenders under the Exit Credit Facility. Such first priority liens had also been permitted under the DIP Facility prior to the conversion of the loans and commitments under the DIP Facility to our exit financing under the Exit Credit Facility. See Note 9 of the Notes to Consolidated Condensed Financial Statements for further information on our margin deposits and collateral used for commodity procurement and risk management activities.

Future collateral requirements for cash, first priority liens and letters of credit may increase based on the extent of our involvement in standard contracts and movements in commodity prices and also based on our credit ratings and general perception of creditworthiness in our market. While we believe that we have adequate liquidity to support our operations at this time, it is difficult to predict future developments and the amount of credit support that we may need to provide as part of our business operations.

Asset Sales and Purchase of Investment — A significant component of our restructuring activities has been to return our focus to our core strategic assets and selectively dispose of or restructure certain less strategically important assets. As a result of the review of our asset portfolio, we sold or otherwise disposed of the following assets, and acquired the RockGen assets, which had previously been leased.

Asset	Transaction Description	Closing Date	Consideration
RockGen Energy Center	Purchase of investment	January 15, 2008	$145 million allowed unsecured claim
Hillabee development project	Sale of assets	February 14, 2008	$156 million
Fremont development project	Sale of assets	March 5, 2008	$254 million

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longer are the primary beneficiary of Auburndale. In addition, on June 3, 2008, Pomifer notified us of its intent to sell its preferred interest in Auburndale and that it had also initiated a third-party sales process requesting bids for 100% of Auburndale. Pomifer has certain “drag-along” rights over our equity interest in Auburndale, which would require us to sell our equity interest in Auburndale to a third party. See Note 12 of the Notes to Consolidated Condensed Financial Statements for a further discussion related to the potential deconsolidation or sale of Auburndale.

Special Purpose Subsidiaries — Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine and our other subsidiaries. In accordance with applicable accounting standards, we consolidate these entities. As of the date of filing this Report, these entities included: Rocky Mountain Energy Center, LLC, Riverside Energy Center, LLC, Calpine Riverside Holdings, LLC, PCF, PCF III, GEC Holdings, LLC, Gilroy Energy Center, LLC, Creed Energy Center, LLC, Goose Haven Energy Center, LLC, Calpine Gilroy Cogen, L.P., Calpine Gilroy 1, Inc., Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine King City Cogen, LLC), Calpine King City, LLC (an indirect parent company of Calpine Securities Company, L.P.), Calpine Deer Park Partner, LLC, Calpine DP, LLC, Deer Park Energy Center Limited Partnership, CCFC Preferred Holdings, LLC, Metcalf Energy Center, LLC and Russell City Energy Company, LLC.

Recent Regulatory Developments

As discussed in our 2007 Form 10-K, to facilitate attainment of its ozone and fine particulates standards issued in 1997, the EPA promulgated regulations in March 2005 called the Clean Air Interstate Rule, or CAIR, applicable to 28 eastern states and the District of Columbia. When fully implemented, CAIR would have reduced SO2 emissions in these states by over 70%, and NOx emissions by over 60%, from 2003 levels. On July 11, 2008, the United States Court of Appeals for the D.C. Circuit invalidated CAIR, stating that the CAIR regional cap-and-trade program cannot be used to facilitate attainment of the ozone and fine particulates standards. The court did not overturn the existing cap-and-trade program for SO2 reductions under the acid rain program or the existing ozone season cap-and-trade program. At this time, we cannot predict the outcome of the legal proceedings related to the court’s decision, what action the EPA will take in response to this decision and the timing of such action, or the ultimate impact on us of these proceedings and resulting regulatory and other actions.

Financial Market Risks

As we are primarily focused on the generation of electricity using gas-fired turbines, our natural physical commodity risk is an option to be “short” fuel (i.e., natural gas buyer) and “long” power (i.e., electricity seller) at our generation’s cost of conversion. As a result, we are exposed to commodity price volatility in the markets in which our plants operate. We utilize derivatives, which are defined in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” to include physical commodity contracts and commodity financial instruments such as swaps, options, and forward contracts, to maximize the risk-adjusted returns from our power and gas assets. We conduct these hedging and optimization activities within a structured risk management framework based on clearly communicated controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, clearly defined roles and responsibilities, and daily risk measurement and reporting. Additionally, we manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by entering into offsetting positions.

Derivative contracts are measured at their fair value and recorded as either assets or liabilities unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of contracts accounted for as derivatives are recognized currently in earnings (as a component of our operating revenues, fuel and purchased energy expense, or interest expense) unless specific hedge criteria are met. The hedge criteria requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

Along with our portfolio of hedging transactions, we enter into electricity and natural gas trading positions that often act as hedges to our asset portfolio, but do not qualify as hedges under hedge accounting criteria guidelines, such as commodity options transactions. While our trading in electricity and natural gas is mostly physical in nature, we also engage in trading activities, particularly in natural gas, that are financial in nature. While we enter into these transactions primarily to provide us with improved price and price volatility discovery as well as greater market access, which benefits our hedging activities, we also are susceptible to commodity price movements (both profits and losses) in connection with these

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transactions. Trading positions are included in and subject to our consolidated risk management portfolio position limits and controls structure. Changes in fair value of commodity trading positions are recognized currently in earnings in mark-to-market activity within operating revenues, in the case of power transactions, and within fuel and purchased energy expense, in the case of natural gas transactions. Our future hedged status and trading activities are subject to change as determined by our commercial operations group, senior management, Chief Risk Officer and Board of Directors.

Effective January 1, 2008, we adopted SFAS No. 157, which provides a framework for measuring fair value under GAAP and, among other things, requires enhanced disclosures about assets and liabilities carried at fair value. See Note 8 of the Notes to Consolidated Condensed Financial Statements for further discussion related to the adoption of this standard.

Derivatives — We enter into a variety of derivative instruments to include both exchange traded and OTC power and gas forwards, options and interest rate swaps.

Our level 1 fair value derivative instruments primarily consist of power and natural gas futures traded on the NYMEX.

Our level 2 fair value derivative instruments primarily consist of our interest rate swaps and our power and gas OTC forwards where market data for pricing inputs is observable. Generally, we obtain our level 2 pricing inputs from markets such as the Intercontinental Exchange. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are primarily industry-standard models that incorporate various assumptions, including quoted interest rates and time value, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Our level 3 fair value derivative instruments primarily consist of our power and gas OTC forwards and options where pricing inputs are unobservable as well as our complex and structured transactions. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. In cases where there is no corroborating market information available to support significant model inputs, we initially use the transaction price as the best estimate of fair value. OTC options are valued using industry-standard models, including the Black-Scholes pricing model. At each balance sheet date, we perform an analysis of all instruments subject to SFAS No. 157 and include in level 3 all of those whose fair value is based on significant unobservable inputs.

Under our risk management policy, most of our level 3 derivatives primarily act as hedges to our asset portfolio. Accordingly, the majority of the unrealized gains and losses are recorded in accumulated other comprehensive income (loss). As of June 30, 2008, our level 3 derivative assets and liabilities represent approximately 14% and 20% of our total assets and total liabilities, respectively. The actual amounts that will ultimately be settled will likely vary based on changes in gas prices and power prices as well as changes in interest rates. Such variances could be material. We validate our price inputs used in our fair value models quarterly through comparisons and validations of our commodity and interest rate pricing curves to prices from external sources such as the Intercontinental Exchange, British Bankers Association and other public sources. The majority of our derivative instruments have terms of five years or less. See further discussion of pre-tax gains (losses) currently held in AOCI in Note 9 of the Notes to Consolidated Condensed Financial Statements. The fair value of our derivatives include the credit standing of the counterparties involved and the impact of credit enhancements, if any. Such valuation adjustments are generally based on market evidence, if available, or management's best estimate.

Mark-to-market activity, a component within operating revenues (for electricity contracts), fuel and purchased energy expense (for gas contracts), and interest expense for interest rate swaps as shown on our Consolidated Condensed Statements of Operations include realized settlements of and unrealized mark-to-market gains and losses on power and gas derivative instruments not designated as cash flow hedges, including those held for trading purposes and for undesignated interest rate swaps together with ineffectiveness on such derivatives designated as cash flow hedges. See Note 9 of the Notes to

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Consolidated Condensed Financial Statements for a discussion of our total mark-to-market activity for the three and six months ended June 30, 2008 and 2007.

The change in fair value of our outstanding commodity and interest rate swap derivative instruments from January 1, 2008, through June 30, 2008, is summarized in the table below (in millions):

	Interest Rate			Commodity
	Swaps			Instruments			Total
Fair value of contracts outstanding at January 1, 2008(1)	$	(169	)	$	(216	)	$	(385	)
Losses recognized or otherwise settled during the period(2)		31			67			98
Fair value attributable to new contracts		(14	)		7			(7	)
Changes in fair value attributable to price movements		40			(534	)		(494	)
Change in fair value attributable to adoption of SFAS No. 157		2			18			20
Fair value of contracts outstanding at June 30, 2008(3)	$	(110	)	$	(658	)	$	(768	)

__________

(1)	Reflects our portfolio of derivative assets and liabilities as of December 31, 2007, adjusted for the day one loss of $(22) million recognized upon adoption of SFAS No. 157 on January 1, 2008.

(2)

Commodity gains (losses) recognized consist of (i) recognized gains from commodity cash flow hedges of $20 million (which represents a portion of the realized value of cash flow hedge activity of $8 million as disclosed in Note 9 of the Notes to Consolidated Condensed Financial Statements), (ii) losses related to deferred items of $(19) million, and (iii) losses related to undesignated derivatives of $(68) million (represents a portion of operating revenues and fuel and purchased energy expense as reported on our Consolidated Condensed Statements of Operations).

(3)	Net commodity and interest rate swap derivative liabilities reported in Notes 8 and 9 of the Notes to Consolidated Condensed Financial Statements.

Our increased accumulated loss in AOCI was primarily driven by an increase in power prices on commodity hedges and a decrease in interest rates on interest rate swap derivatives.

Of the total mark-to-market gain (loss) of $24 million and $(127) million from commodity derivative instruments for the three and six months ended June 30, 2008, which is included in both operating revenues and fuel and purchased energy expense, there was a realized loss of $(99) million and $(63) million, and an unrealized gain (loss) of $123 million and $(64) million, respectively. The total mark-to-market gain (loss) included a non-cash gain of approximately $11 million and $20 million from amortization of various items for the three and six months ended June 30, 2008, respectively.

The fair value of outstanding derivative commodity instruments at June 30, 2008, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):

Fair Value Source	2008			2009-2010			2011-2012			After 2012		Total
Prices actively quoted	$	526		$	5		$	—		$	—	$	531
Prices provided by other external sources		(760	)		(425	)		(4	)		—		(1,189	)
Total fair value	$	(234	)	$	(420	)	$	(4	)	$	—	$	(658	)

The counterparty credit quality associated with the fair value of outstanding derivative commodity instruments at June 30, 2008, and the period during which the instruments will mature are summarized in the table below (in millions):

Credit Quality (Based on Standard & Poor’s Ratings as of June 30, 2008)	2008			2009-2010			2011-2012			After 2012		Total
Investment grade	$	68		$	38		$	(6	)	$	—	$	100
No external ratings		(302	)		(458	)		2			—		(758	)
Total fair value	$	(234	)	$	(420	)	$	(4	)	$	—	$	(658	)

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The fair value of our interest rate swaps are validated based upon external quotes. See further discussion on our interest rate swaps in the “— Interest Rate Risk” section below.

The primary factors affecting the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu and MWh), changing commodity market prices, principally for electricity and natural gas and changes in interest rates. In that prices for electricity and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. The change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in OCI, net of tax, or on our Consolidated Condensed Statements of Operations as a component (gain or loss) of current earnings. As of June 30, 2008, and December 31, 2007, a component of the balance in AOCI represented the unrealized net loss associated with commodity cash flow hedging transactions. As noted above, there is a substantial amount of volatility inherent in accounting for the fair value of these derivatives, and our results during the three and six months ended June 30, 2008 and 2007 have reflected this. See Notes 8 and 9 of the Notes to Consolidated Condensed Financial Statements for additional information on derivative activity.

Commodity Price Risk — Commodity price risks result from exposure to changes in spot prices, forward prices, price volatilities and correlations between the price of electricity and natural gas. We manage the commodity price risks and the variability in future cash flows from forecasted sales of electricity and purchases of natural gas of our entire portfolio of generating assets and contractual positions by entering into various derivative or non-derivative instruments.

We measure the commodity price risks in our portfolio on a daily basis using a VAR model to determine the maximum potential one-day risk of loss resulting from market movements in comparison to internally established thresholds. Our VAR is calculated for our entire portfolio which is comprised of commodity derivatives, generating facilities, PPAs, and other physical and financial transactions. The portfolio VAR calculation incorporates positions for the remaining portion of the current calendar year plus the following two calendar years. We measure VAR using a variance/covariance approach based on a confidence level of 95%, a one-day holding period, and actual observed historical correlation. While we believe that our VAR assumptions and approximations are reasonable, different assumptions and/or approximations could produce materially different estimates.

The table below presents the high, low and average of our daily VAR for the three and six months ended June 30, 2008, as well as our VAR at June 30, 2008 (in millions):

	2008
Three months ended June 30:
High	$	70
Low	$	47
Average	$	56
Six months ended June 30:
High	$	70
Low	$	39
Average	$	50
As of June 30	$	66

Interest Rate Risk — We are exposed to interest rate risk related to our variable rate debt. Interest rate risk represents the potential loss in earnings arising from adverse changes in market interest rates. Our variable rate financings are indexed to base rates, generally LIBOR. Significant LIBOR increases could have an adverse impact on our future interest expense.

Our fixed-rate debt instruments do not expose us to the risk of loss in earnings due to changes in market interest rates. In general, such a change in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of the fixed rate debt in the open market prior to their maturity.

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Currently, we use interest rate swaps to adjust the mix between fixed and floating rate debt as a hedge of our interest rate risk. We do not use interest rate derivative instruments for trading purposes. In order to manage our risk to significant increases in LIBOR, we have effectively hedged $7.6 billion of our variable rate debt through December 31, 2009, through the use of variable to fixed interest rate swaps. The majority of our interest rate swaps mature in years 2010 through 2013. See the table below for additional illustration of our interest rate swaps. To the extent eligible, our interest rate swaps have been designed as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective.

The following table summarizes the contract terms as well as the fair values of our significant financial instruments exposed to interest rate risk as of June 30, 2008. All outstanding balances and fair market values are shown gross of applicable premium or discount, if any (in millions):

																								Fair Value
																								June 30,
	2008				2009				2010				2011			2012			Thereafter			Total		2008
Debt by Maturity Date:

Fixed Rate		$	107			$	219			$	254		$	128		$	86		$	759		$	1,553	$	1,532
Average Interest Rate			6.5	%			7.1	%			7.8	%		9.0	%		11.3	%		9.2	%

Variable Rate		$	44			$	448			$	83		$	1,724		$	74		$	6,512		$	8,885	$	8,628
Average Interest Rate			5.5	%			8.5	%			6.1	%		9.4	%		6.7	%		7.7	%

Interest Rate Derivative Instruments (Notional Value):

Variable to Fixed Swaps(1)		$	7,572			$	7,572			$	7,175		$	4,905		$	3,870		$	66			n/a	$	(110	)
Average Pay Rate			4.1	%			4.3	%			4.4	%		4.5	%		4.6	%		3.5	%
Average Receive Rate			2.8	%			3.4	%			3.7	%		4.0	%		4.2	%		4.5	%

__________

(1)	Includes interest rate swaps where forecasted issuance of variable rate debt is deemed probable.

Recent Accounting Pronouncements

See Note 1 of the Notes to Consolidated Condensed Financial Statements for a discussion of recent accounting pronouncements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

See “Financial Market Risks” in Item 2.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure.

As of the end of the period covered by this Report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon, and

INDEX

as of the date of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

During the second quarter of 2008, there were no changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations on the Effectiveness of Controls

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls or our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Calpine have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people or by management override of the controls. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with associated policies or procedures. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

	Large accelerated filer	[X]	Accelerated filer	[ ]
	Non-accelerated filer	[ ] (Do not check if a smaller reporting company)	Smaller reporting company	[ ]

ABBREVIATION		DEFINITION

2007 Form 10-K		Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 29, 2008

2014 Convertible Notes		Calpine Corporation’s Contingent Convertible Notes Due 2014

401(k) Plan		Calpine Corporation Retirement Savings Plan

Acadia PP		Acadia Power Partners, LLC

AOCI		Accumulated Other Comprehensive Income

ARB		Accounting Research Board

Auburndale		Auburndale Holdings, LLC

Bankruptcy Code		U.S. Bankruptcy Code

Bankruptcy Courts		The U.S. Bankruptcy Court and the Canadian Court

BLM		Bureau of Land Management of the U.S. Department of the Interior

Blue Spruce		Blue Spruce Energy Center LLC

Bridge Facility		Bridge Loan Agreement, dated as of January 31, 2008, among Calpine Corporation as borrower, the lenders party thereto, Goldman Sachs Credit Partners L.P., Credit Suisse, Deutsche Bank Securities Inc. and Morgan Stanley Senior Funding Inc., as co-documentation agents, and Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent

Btu(s)		British thermal unit(s)

CAIR		Clean Air Interstate Rule

CalGen		Calpine Generating Company, LLC

CalGen First Lien Debt		Collectively, $235,000,000 First Priority Secured Floating Rate Notes Due 2009, issued by CalGen and CalGen Finance; $600,000,000 First Priority Secured Institutional Terms Loans Due 2009, issued by CalGen; and the CalGen First Priority Revolving Loans, in each case repaid on March 29, 2007

CalGen First Priority Revolving Loans		$200,000,000 First Priority Revolving Loans issued on or about March 23, 2004, pursuant to that Amended and Restated Agreement, among CalGen, the guarantors party thereto, the lenders party thereto, The Bank of Nova Scotia, as administrative agent, L/C Bank, lead arranger and sole bookrunner, Bayerische Landesbank, Cayman Islands Branch, as arranger and co-syndication agent, Credit Lyonnais, New York Branch, as arranger and co-syndication agent, ING Capital LLC, as arranger and co-syndication agent, Toronto Dominion (Texas) Inc., as arranger and co-syndication agent, and Union Bank of California, N.A., as arranger and co-syndication agent, repaid on March 29, 2007

CalGen Second Lien Debt		Collectively, $640,000,000 Second Priority Secured Floating Rate Notes Due 2010, issued by CalGen and CalGen Finance; and $100,000,000 Second Priority Secured Institutional Term Loans Due 2010 issued by CalGen, in each case repaid on March 29, 2007

ABBREVIATION		DEFINITION

CalGen Secured Debt		Collectively, the CalGen First Lien Debt, the CalGen Second Lien Debt and the CalGen Third Lien Debt

CalGen Third Lien Debt		Collectively, $680,000,000 Third Priority Secured Floating Rate Notes Due 2011, issued by CalGen and CalGen Finance; and $150,000,000 11 1/2% Third Priority Secured Notes Due 2011, issued by CalGen and CalGen Finance, in each case repaid on March 29, 2007

Calpine Debtors		The U.S. Debtors and the Canadian Debtors

Calpine Equity Incentive Plans		Collectively, the MEIP and the DEIP, which provide for grants of equity awards to Calpine employees and non-employee members of Calpine’s Board of Directors

Canadian Court		The Court of Queen’s Bench of Alberta, Judicial District of Calgary

Canadian Debtors		The subsidiaries and affiliates of Calpine Corporation that have been granted creditor protection under the CCAA in the Canadian Court

Canadian Effective Date		February 8, 2008, the date on which the Canadian Court ordered and declared that the Canadian Debtors’ proceedings under the CCAA were terminated

Cash Collateral Order		Second Amended Final Order of the U.S. Bankruptcy Court Authorizing Use of Cash Collateral and Granting Adequate Protection, dated February 24, 2006 as modified by orders of the U.S. Bankruptcy Court dated June 21, 2006, July 12, 2006, October 25, 2006, November 15, 2006, December 20, 2006, December 28, 2006, January 17, 2007, and March 1, 2007

CCAA		Companies’ Creditors Arrangement Act (Canada)

CCFC		Calpine Construction Finance Company, L.P.

CES		Calpine Energy Services, L.P.

Chapter 11		Chapter 11 of the Bankruptcy Code

Cleco		Cleco Corp.

Commodity Collateral Revolver		Commodity Collateral Revolving Credit Agreement, dated as of July 8, 2008, among Calpine Corporation as borrower, Goldman Sachs Credit Partners L.P., as payment agent, sole lead arranger and sole bookrunner, and the lenders from time to time party thereto

Commodity Margin		Non-GAAP financial measure that includes electricity and steam revenues, hedging and optimization activities, renewable energy credit revenue, transmission revenue and expenses, and fuel and purchased energy expense, but excludes mark-to-market activity and other service revenues

Company		Calpine Corporation, a Delaware corporation, and subsidiaries

Confirmation Order		The order of the U.S. Bankruptcy Court entitled “Findings of Fact, Conclusions of Law, and Order Confirming Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code,” entered December 19, 2007, confirming the Plan of Reorganization pursuant to section 1129 of the Bankruptcy Code

Convertible Senior Notes		Collectively, Calpine Corporation’s 4% Contingent Convertible Notes Due 2006, 6% Contingent Convertible Notes Due 2014, 7 3/4% Contingent Convertible Notes Due 2015 and 4 3/4% Contingent Convertible Senior Notes Due 2023

Deer Park		Deer Park Energy Center Limited Partnership

DEIP		Calpine Corporation 2008 Director Incentive Plan, which provides for grants of equity awards to non-employee members of Calpine’s Board of Directors

DIP		Debtor-in-possession

ABBREVIATION		DEFINITION

DIP Facility		The Revolving Credit, Term Loan and Guarantee Agreement, dated as of March 29, 2007, among the Company, as borrower, certain of the Company’s subsidiaries, as guarantors, the lenders party thereto, Credit Suisse, Goldman Sachs Credit Partners L.P. and JPMorgan Chase Bank, N.A., as co-syndication agents and co-documentation agents, General Electric Capital Corporation, as sub-agent, and Credit Suisse, as administrative agent and collateral agent, with Credit Suisse Securities (USA) LLC, Goldman Sachs Credit Partners L.P., JPMorgan Securities Inc., and Deutsche Bank Securities Inc. acting as Joint Lead Arrangers and Bookrunners

EAB		Environmental Appeals Board of the U.S. Environmental Protection Agency

EBITDA		Earnings before interest, taxes, depreciation and amortization

Effective Date		January 31, 2008, the date on which the conditions precedent enumerated in the Plan of Reorganization were satisfied or waived and the Plan of Reorganization became effective

EITF		Emerging Issues Task Force

Emergence Date Market Capitalization		Determined as Calpine’s Market Capitalization using the 30-day weighted average stock price following the Effective Date

EPA		U.S. Environmental Protection Agency

ERISA		Employee Retirement Income Security Act

Exchange Act		U.S. Securities Exchange Act of 1934, as amended

Exit Credit Facility		Credit Agreement, dated as of January 31, 2008, among Calpine Corporation, as borrower, the lenders party thereto, General Electric Capital Corporation, as sub-agent, Goldman Sachs Credit Partners L.P., Credit Suisse, Deutsche Bank Securities Inc., and Morgan Stanley Senior Funding, Inc., as co-syndication agents and co-documentation agents, and Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent

Exit Facilities		Together, the Exit Credit Facility and the Bridge Facility

FASB		Financial Accounting Standards Board

FIN		FASB Interpretation Number

Fremont		Fremont Energy Center, LLC

FSP		FASB Staff Position

GAAP		Generally accepted accounting principles

Greenfield LP		Greenfield Energy Centre LP

Harbert Convertible Fund		Harbert Convertible Arbitrage Master Fund, L.P.

Heat Rate		A measure of the amount of fuel required to produce a unit of electricity

Hillabee		Hillabee Energy Center, LLC

IRC		Internal Revenue Code

IRS		U.S. Internal Revenue Service

Knock-in Facility		Letter of Credit Facility Agreement, dated as of June 25, 2008, among Calpine Corporation as borrower and Morgan Stanley Capital Services Inc., as issuing bank

KWh		Kilowatt hour(s)

LIBOR		London Inter-Bank Offered Rate

LSTC		Liabilities subject to compromise

ABBREVIATION		DEFINITION

Market Capitalization		Market value of Calpine Corporation common stock outstanding, calculated in accordance with the Calpine Corporation amended and restated certificate of incorporation

MEIP		Calpine Corporation 2008 Equity Incentive Plan, which provides for grants of equity awards to Calpine employees and non-employee members of Calpine’s Board of Directors

Metcalf		Metcalf Energy Center, LLC

MMBtu		Million Btu

MW		Megawatt(s)

MWh		Megawatt hour(s)

Ninth Circuit Court of Appeals		U.S. Court of Appeals for the Ninth Circuit

NOL(s)		Net operating loss(es)

Non-U.S. Debtor(s)		The consolidated subsidiaries and affiliates of Calpine Corporation that are not U.S. Debtors

Northern District Court		U.S. District Court for the Northern District of California

NRG		NRG Energy, Inc.

NYMEX		New York Mercantile Exchange

NYSE		New York Stock Exchange

OCI		Other Comprehensive Income

OMEC		Otay Mesa Energy Center, LLC

Original DIP Facility		The Revolving Credit, Term Loan and Guarantee Agreement, dated as of December 22, 2005, as amended on January 26, 2006, and as amended and restated by that certain Amended and Restated Revolving Credit, Term Loan and Guarantee Agreement, dated as of February 23, 2006, among Calpine Corporation, as borrower, the Guarantors party thereto, the Lenders from time to time party thereto, Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as joint syndication agents, Deutsche Bank Trust Company Americas, as administrative agent for the First Priority Lenders, General Electric Capital Corporation, as Sub-Agent for the Revolving Lenders, Credit Suisse, as administrative agent for the Second Priority Term Lenders, Landesbank Hessen Thuringen Girozentrale, New York Branch, General Electric Capital Corporation and HSH Nordbank AG, New York Branch, as joint documentation agents for the First Priority Lenders and Bayerische Landesbank, General Electric Capital Corporation and Union Bank of California, N.A., as joint documentation agents for the Second Priority Lenders

OTC		Over the Counter

Panda		Panda Energy International, Inc., and related party PLC II, LLC

PCAOB		Public Company Accounting Oversight Board

PCF		Power Contract Financing, L.L.C.

PCF III		Power Contract Financing III, LLC

Petition Date		December 20, 2005

	(Mark One)
	[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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	Page
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements
Consolidated Condensed Balance Sheets at June 30, 2008 and December 31, 2007	1
Consolidated Condensed Statements of Operations for the Three and Six Months Ended June 30, 2008 and 2007	2
Consolidated Condensed Statements of Comprehensive Income (Loss) and Stockholders’ Equity (Deficit) for the Six Months Ended June 30, 2008	3
Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2008 and 2007	4
Notes to Consolidated Condensed Financial Statements	6
1. Basis of Presentation and Summary of Significant Accounting Policies	6
2. Our Emergence from Chapter 11	11
3. Property, Plant and Equipment, Net	15
4. Investments	15
5. Asset Sales	16
6. Comprehensive Income (Loss)	16
7. Debt	17
8. Fair Value Measurements	19
9. Derivative Instruments and Mark-to-Market Activity	22
10. Earnings (Loss) per Share	24
11. Stock-Based Compensation	25
12. Commitments and Contingencies	27
13. Segment Information	32
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Forward-Looking Information	35
Executive Overview	35
Results of Operations	38
Non-GAAP Financial Measures	43
Operating Performance Metrics	48
Liquidity and Capital Resources	50
Financial Market Risks	56
Recent Accounting Pronouncements	60
Item 3. Quantitative and Qualitative Disclosures About Market Risk	60
Item 4. Controls and Procedures	60

PART II — OTHER INFORMATION

Item 1. Legal Proceedings	62
Item 6. Exhibits	62
Signatures	63

ABBREVIATION		DEFINITION

Plan of Reorganization		Debtors’ Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the U.S. Bankruptcy Code filed by the U.S. Debtors with the U.S. Bankruptcy Court on December 19, 2007, as amended, modified or supplemented through the filing of this Report

Pomifer		Pomifer Power Funding, LLC, a subsidiary of Arclight Energy Partners Fund I, L.P.

PPA(s)		Any contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any electric power product, including electric energy, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which part of the consideration provided by the purchaser of an electric power product is the fuel required by the seller to generate such electric power

PSD		Prevention of Significant Deterioration Permit

PSM		Power Systems Manufacturing, LLC

RockGen		RockGen Energy LLC

RockGen Owner Lessors		Collectively, RockGen OL-1, LLC; RockGen OL-2, LLC; RockGen OL-3, LLC and RockGen OL-4, LLC

Rosetta		Rosetta Resources Inc.

SAB		Staff Accounting Bulletin

SDG&E		San Diego Gas & Electric Company

SDNY Court		U.S. District Court for the Southern District of New York

SEC		U.S. Securities and Exchange Commission

Second Circuit Court of Appeals		U.S. Court of Appeals for the Second Circuit

Second Priority Debt		Collectively, the Second Priority Notes and Senior Secured Term Loans Due 2007

Second Priority Notes		Calpine Corporation’s Second Priority Senior Secured Floating Rate Notes Due 2007, 8 1/2% Second Priority Senior Secured Notes Due 2010, 8 3/4% Second Priority Senior Secured Notes Due 2013 and 9 7/8% Second Priority Senior Secured Notes Due 2011

Securities Act		U.S. Securities Act of 1933, as amended

SFAS		Statement of Financial Accounting Standards

SO2		Sulfur dioxide

SOP 90-7		Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code”

Spark spread		The spread between the sales price for electricity generated and the cost of fuel

Unsecured Senior Notes		Collectively, Calpine Corporation’s 7 5/8% Senior Notes due 2006, 10 1/2% Senior Notes due 2006, 8 3/4% Senior Notes due 2007, 7 7/8% Senior Notes due 2008, 7 3/4% Senior Notes due 2009, 8 5/8% Senior Notes due 2010 and 8 1/2% Senior Notes due 2011

U.S.		United States of America

U.S. Bankruptcy Court		U.S. Bankruptcy Court for the Southern District of New York

ABBREVIATION		DEFINITION

U.S. Debtor(s)		Calpine Corporation and each of its subsidiaries and affiliates that have filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court, which matters are being jointly administered in the U.S. Bankruptcy Court under the caption In re Calpine Corporation, et al., Case No. 05-60200 (BRL)

VAR		Value-at-risk

Whitby		Whitby Cogeneration Limited Partnership

	June 30,			December 31,
	2008			2007
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	370		$	1,915
Accounts receivable, net of allowance of $31 and $54		1,443			878
Accounts receivable, related party		1			226
Materials and supplies		152			114
Margin deposits and other prepaid expense		836			452
Restricted cash, current		357			422
Current derivative assets		5,053			731
Current assets held for sale		—			195
Other current assets		113			98
Total current assets		8,325			5,031

Property, plant and equipment, net		12,131			12,292
Restricted cash, net of current portion		168			159
Investments		386			260
Long-term derivative assets		694			290
Other assets		917			1,018
Total assets	$	22,621		$	19,050
LIABILITIES & STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	1,190		$	642
Accrued interest payable		101			324
Debt, current portion		308			1,710
Current derivative liabilities		5,486			806
Income taxes payable		49			51
Other current liabilities		318			571
Total current liabilities		7,452			4,104

Debt, net of current portion		10,104			9,946
Deferred income taxes, net of current portion		127			38
Long-term derivative liabilities		1,029			578
Other long-term liabilities		235			245
Total liabilities not subject to compromise		18,947			14,911
Liabilities subject to compromise		—			8,788
Commitments and contingencies (see Note 12)
Minority interest		3			3
Stockholders’ equity (deficit):
Preferred stock, $.001 par value per share; authorized 100,000,000 shares, none issued and outstanding in 2008; authorized 10,000,000 shares, none issued and outstanding in 2007		—			—
Common stock, $.001 par value per share; authorized 1,400,000,000 shares, 423,127,138 shares issued and 423,126,665 shares outstanding in 2008; authorized 2,000,000,000 shares, 568,314,685 issued and 479,314,685 outstanding in 2007		1			1
Additional paid-in capital		12,185			3,263
Accumulated deficit		(7,724	)		(7,685	)
Accumulated other comprehensive loss		(791	)		(231	)
Total stockholders’ equity (deficit)		3,671			(4,652	)
Total liabilities and stockholders’ equity (deficit)	$	22,621		$	19,050

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(in millions, except share and per share amounts)
Operating revenues	$	2,828		$	2,060		$	4,779		$	3,722

Cost of revenue:
Fuel and purchased energy expense		2,008			1,456			3,613			2,727
Plant operating expense		206			211			438			379
Depreciation and amortization expense		108			118			219			236
Other cost of revenue		30			33			62			70
Total cost of revenue		2,352			1,818			4,332			3,412
Gross profit		476			242			447			310
Sales, general and other administrative expense		48			39			96			79
Other operating (income) expense		(5	)		3			—			12
Income from operations		433			200			351			219
Interest expense		206			264			625			564
Interest (income)		(14	)		(17	)		(27	)		(34	)
Minority interest income		—			(3	)		—			(1	)
Other (income) expense, net		1			(6	)		11			(7	)
Income (loss) before reorganization items and income taxes		240			(38	)		(258	)		(303	)
Reorganization items		18			469			(261	)		574
Income (loss) before income taxes		222			(507	)		3			(877	)
Provision (benefit) for income taxes		25			(7	)		20			82
Net income (loss)	$	197		$	(500	)	$	(17	)	$	(959	)
Basic earnings (loss) per common share:
Weighted average shares of common stock outstanding (in thousands)		485,004			479,175			485,002			479,155
Net income (loss)	$	0.41		$	(1.04	)	$	(0.04	)	$	(2.00	)
Diluted earnings (loss) per common share:
Weighted average shares of common stock outstanding (in thousands)		485,732			479,175			485,002			479,155
Net income (loss)	$	0.41		$	(1.04	)	$	(0.04	)	$	(2.00	)

													Accumulated Other
													Comprehensive Income(Loss)
													Net Unrealized
													Gain (Loss) From								Total
					Additional												Foreign				Stockholders’
	Common				Paid-In				Accumulated				Cash Flow				Currency				Equity
	Stock				Capital				Deficit				Hedges				Translation				(Deficit)
	(in millions)
Balance, December 31, 2007		$	1			$	3,263			$	(7,685	)		$	(241	)		$	10			$	(4,652	)
Cancellation of Calpine Corporation common stock			(1	)			(3,263	)			—				—				—				(3,264	)
Issuance of reorganized Calpine Corporation common stock in accordance with the Plan of Reorganization			1				12,166				—				—				—				12,167
Stock compensation expense			—				19				—				—				—				19
Cumulative effect of adjustment from adoption of SFAS No. 157			—				—				(22	)			—				—				(22	)
Total stockholders’ equity before comprehensive income (loss) items																							4,248
Net loss			—				—				(17	)			—				—				(17	)
Loss on cash flow hedges before reclassification adjustment			—				—				—				(572	)			—				(572	)
Reclassification adjustment			—				—				—				22				—				22
Foreign currency translation loss			—				—				—				—				(6	)			(6	)
Provision for income taxes			—				—				—				(4	)			—				(4	)
Total comprehensive loss																							(577	)
Balance, June 30, 2008		$	1			$	12,185			$	(7,724	)		$	(795	)		$	4			$	3,671

	June 30, 2008						December 31, 2007
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	116	$	114	$	230	$	128	$	111	$	239
Rent reserve		20		—		20		11		—		11
Construction/major maintenance		51		29		80		62		26		88
Security/project reserves		107		1		108		189		—		189
Collateralized letters of credit and other credit support		39		1		40		4		—		4
Other		24		23		47		28		22		50
Total	$	357	$	168	$	525	$	422	$	159	$	581

	December 31, 2007
	As Previously
	Reported			As Adjusted
Current derivative assets	$	231		$	731
Total current assets		4,531			5,031
Long-term derivative assets		222			290
Total assets	$	18,482		$	19,050

Current derivative liabilities	$	(306	)	$	(806	)
Total current liabilities		(3,604	)		(4,104	)
Long-term derivative liabilities		(510	)		(578	)
Total liabilities not subject to compromise		(14,343	)		(14,911	)
Total liabilities and stockholders’ equity (deficit)	$	(18,482	)	$	(19,050	)

	Three Months			Six Months
	Ended			Ended
	June 30, 2007			June 30, 2007
Total revenue	$	1,828		$	3,380
Total cost of revenue		1,912			3,466
Operating (income) expense		(40	)		11
Loss from operations		(44	)		(97	)
Interest expense		177			378
Other (income) expense, net		(15	)		2
Reorganization items		382			485
Provision (benefit) for income taxes		(25	)		70
Net loss	$	(563	)	$	(1,032	)

	June 30,			December 31,
	2008			2007
Buildings, machinery and equipment	$	13,459		$	13,439
Geothermal properties		958			944
Other		260			259
		14,677			14,642
Less: Accumulated depreciation		(2,786	)		(2,582	)
		11,891			12,060
Land		74			77
Construction in progress		166			155
Property, plant and equipment, net	$	12,131		$	12,292

	Ownership
	Interest as of
	June 30,		June 30,			December 31,
	2008		2008			2007
Greenfield LP		50%		$	80		$	114
OMEC		100%			159			146
RockGen		100%			138			—
Whitby		50%			9			—
Total investments				$	386		$	260

	Recurring Fair Value Measures at Fair Value as of June 30, 2008
	Level 1			Level 2			Level 3			Total
	(in millions)
Assets:
Commodity derivatives	$	1,712		$	777		$	3,202		$	5,691
Interest rate derivatives		—			56			—			56
Total derivative assets		1,712			833			3,202			5,747
Margin deposits(1)		696			—			—			696
Total	$	2,408		$	833		$	3,202		$	6,443

Liabilities:
Commodity derivatives	$	(1,510	)	$	(988	)	$	(3,851	)	$	(6,349	)
Interest rate derivatives		—			(166	)		—			(166	)
Total derivative liabilities		(1,510	)		(1,154	)		(3,851	)		(6,515	)
Margin held by us posted by our counterparties(1)		(86	)		—			—			(86	)
Total	$	(1,596	)	$	(1,154	)	$	(3,851	)	$	(6,601	)

	June 30, 2008
Margin deposits	$	696
Gas and power prepayments		113
Total margin deposits and gas and power prepayments with our counterparties(1)	$	809

Letters of credit issued	$	376
First priority liens under power and natural gas agreements		421
First priority liens under interest rate swap agreements		92
Total letters of credit and first priority liens with our counterparties	$	889

Margin deposits posted with us by our counterparties(2)	$	86
Letters of credit posted with us by our counterparties		6
Total margin deposits and letters of credit posted with us by our counterparties	$	92

	June 30, 2008
Net derivative liabilities	$	(768	)
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness		13
Equity investment OCI		(19	)
Cash flow hedges terminated prior to maturity		(28	)
Cumulative OCI tax benefit		7
Accumulated other comprehensive loss from derivative instruments, net of tax(1)	$	(795	)

				Weighted
				Average
		Weighted		Remaining	Aggregate
	Number of	Average		Term	Intrinsic Value
	Options	Exercise Price		(in years)	(in millions)
Outstanding – December 31, 2007	—	$	—
Granted	5,281,300	$	17.54
Exercised	—	$	—
Forfeited	577,100	$	17.12
Expired	—	$	—
Outstanding – June 30, 2008	4,704,200	$	17.59	9.5	$	23
Exercisable – June 30, 2008	3,200	$	17.64	0.8	$	—
Vested and expected to vest – June 30, 2008	4,425,194	$	17.58	9.5	$	22

	June 30, 2008
Expected term (in years)(1)		5.4 – 6.1
Risk-free interest rate(2)		2.7 – 3.3	%
Expected volatility(3)		34.8 – 40.9	%
Dividend yield		—
Weighted average grant-date fair value (per option)	$	7.22

	Three Months Ended June 30, 2008
												Consolidation
												and
	West		Texas		Southeast		North		Other			Elimination			Total
Revenues from external customers	$	1,156	$	1,185	$	400	$	170	$	(83	)	$	—		$	2,828
Intersegment revenues		12		75		59		6		3			(155	)		—
Total revenue	$	1,168	$	1,260	$	459	$	176	$	(80	)	$	(155	)	$	2,828
Commodity margin		340		258		91		72		24			—			785
Add: Mark-to-market commodity activity, net and other service revenues(1)		4		74		—		—		(40	)		(3	)		35
Less:
Plant operating expense		95		48		22		24		22			(5	)		206
Depreciation and amortization		44		33		18		13		1			(1	)		108
Other cost of revenue		14		—		8		6		2			—			30
Gross profit (loss)		191		251		43		29		(41	)		3			476
Other operating expense																43
Income from operations																433
Interest expense, net of interest income																192
Other (income) expense, net																1
Income before reorganization items and income taxes																240
Reorganization items																18
Income before income taxes															$	222

	Three Months Ended June 30, 2007
												Consolidation
												and
	West		Texas		Southeast		North		Other			Elimination			Total
Revenues from external customers	$	806	$	797	$	294	$	147	$	16		$	—		$	2,060
Intersegment revenues		8		1		50		1		2			(62	)		—
Total revenue	$	814	$	798	$	344	$	148	$	18		$	(62	)	$	2,060
Commodity margin		265		138		65		75		(8	)		—			535
Add: Mark-to-market commodity activity, net and other service revenues(1)		3		48		8		—		13			(3	)		69
Less:
Plant operating expense		86		39		31		22		36			(3	)		211
Depreciation and amortization		54		29		19		14		1			1			118
Other cost of revenue		13		—		8		9		4			(1	)		33
Gross profit (loss)		115		118		15		30		(36	)		—			242
Other operating expense																42
Income from operations																200
Interest expense, net of interest income																247
Other (income) expense, net																(9	)
Loss before reorganization items and income taxes																(38	)
Reorganization items																469
Loss before income taxes															$	(507	)

	Six Months Ended June 30, 2008
												Consolidation
												and
	West		Texas		Southeast		North		Other			Elimination			Total
Revenues from external customers	$	2,118	$	1,826	$	657	$	320	$	(142	)	$	—		$	4,779
Intersegment revenues		21		116		93		11		5			(246	)		—
Total revenue	$	2,139	$	1,942	$	750	$	331	$	(137	)	$	(246	)	$	4,779
Commodity margin		609		388		128		134		12			—			1,271
Add: Mark-to-market commodity activity, net and other service revenues(1)		14		41		1		—		(155	)		(6	)		(105	)
Less:
Plant operating expense		199		110		50		49		37			(7	)		438
Depreciation and amortization		94		63		37		25		2			(2	)		219
Other cost of revenue		30		—		16		12		4			—			62
Gross profit (loss)		300		256		26		48		(186	)		3			447
Other operating expense																96
Income from operations																351
Interest expense, net of interest income																598
Other (income) expense, net																11
Loss before reorganization items and income taxes																(258	)
Reorganization items																(261	)
Income before income taxes															$	3

	Six Months Ended June 30, 2007
														Consolidation
														and
	West		Texas			Southeast			North		Other			Elimination			Total
Revenues from external customers	$	1,604	$	1,320		$	501		$	299	$	(2	)	$	—		$	3,722
Intersegment revenues		15		(2	)		72			2		15			(102	)		—
Total revenue	$	1,619	$	1,318		$	573		$	301	$	13		$	(102	)	$	3,722
Commodity margin		495		224			102			138		(2	)		—			957
Add: Mark-to-market commodity activity, net and other service revenues(1)		15		52			8			—		(21	)		(16	)		38
Less:
Plant operating expense		165		68			55			38		58			(5	)		379
Depreciation and amortization		105		60			42			27		2			—			236
Other cost of revenue		22		—			16			17		21			(6	)		70
Gross profit (loss)		218		148			(3	)		56		(104	)		(5	)		310
Other operating expense																		91
Income from operations																		219
Interest expense, net of interest income																		530
Other (income) expense, net																		(8	)
Loss before reorganization items and income taxes																		(303	)
Reorganization items																		574
Loss before income taxes																	$	(877	)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008(1)			2007(1)			2008(1)			2007(1)
	(MWh in thousands)
Total MWh generated		21,211			21,439			42,117			41,782
West		7,982			7,824			17,139			16,243
Texas		9,477			7,962			17,218			15,733
Southeast		2,635			4,084			5,305			6,745
North		1,117			1,569			2,455			3,061

Average Availability		89.9	%		89.9	%		87.9	%		90.3	%
West		89.6	%		86.2	%		86.5	%		88.0	%
Texas		91.8	%		88.0	%		86.9	%		89.3	%
Southeast		89.3	%		95.5	%		90.2	%		94.5	%
North		87.4	%		90.8	%		89.7	%		88.5	%

Average total MW in operation		23,113			25,091			23,113			25,223
West		7,246			7,246			7,246			7,317
Texas		7,251			7,274			7,251			7,274
Southeast		6,254			7,556			6,254			7,615
North		2,362			3,015			2,362			3,017

Average MW of peaker facilities		2,540			3,019			2,540			3,010
West		983			983			983			972
Texas		—			—			—			—
Southeast		963			963			963			963
North		594			1,073			594			1,075

Average capacity factor, excluding peakers		46.4	%		43.3	%		46.3	%		42.5	%
West		57.3	%		55.1	%		61.9	%		57.5	%
Texas		59.8	%		50.1	%		54.4	%		49.8	%
Southeast		21.2	%		26.8	%		21.9	%		22.4	%
North		28.0	%		35.4	%		31.1	%		35.0	%

Steam adjusted Heat Rate		7,268			7,182			7,215			7,147
West		7,319			7,366			7,269			7,342
Texas		7,144			6,780			7,057			6,733
Southeast		7,459			7,462			7,460			7,492
North		7,635			7,857			7,516			7,753

Average realized electric price	$	99.58		$	71.42		$	87.42		$	67.71
Average cost of natural gas per MMBtu	$	8.74		$	6.67		$	8.14		$	6.52

Exhibit
Number		Description

3.1		Amended and Restated Certificate of Incorporation of the Company, as amended (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 1, 2008).

3.2		Amended and Restated By-Laws of the Company (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K, filed with the SEC on February 1, 2008).

10.1.1		Commodity Collateral Revolving Credit Agreement, dated as of July 8, 2008, among Calpine Corporation as Borrower, Goldman Sachs Credit Partners L.P. as Payment Agent, sole Lead Arranger and sole Bookrunner, and the Lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 14, 2008).

10.2.1		Letter Agreement and Addendum dated June 30, 2008, between the Company and Zamir Rauf (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on July 3, 2008).†

10.2.2		Employment Agreement, dated June 19, 2006, between the Company and Gregory L. Doody (incorporated by reference to Exhibit 10.5.15 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on March 14, 2007).†

10.2.3		Amendment, dated July 16, 2008, to Employment Agreement, dated June 19, 2006, between the Company and Gregory L. Doody (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on July 22, 2008).†

10.2.4		Letter Agreement re Employment Separation, dated April 7, 2008 (executed April 11, 2008), between the Company and Charles B. Clark, Jr. (incorporated by reference to Exhibit 10.3.1 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 12, 2008).†

10.2.5		Consulting Agreement, effective May 30, 2008, between the Company and Charles B. Clark, Jr. (incorporated by reference to Exhibit 10.3.2 to the Company’s Quarterly Report on Form 10-Q filed with the SEC on May 12, 2008).†

31.1		Certification of the Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

31.2		Certification of the Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*

32.1		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*

	By:	/s/ ZAMIR RAUF
		Zamir Rauf
		Interim Executive Vice President and
		Interim Chief Financial Officer
		(principal financial officer)
Date: August 8, 2008

	By:	/s/ STEVEN F. HODKINSON
		Steven F. Hodkinson
		Interim Corporate Controller
		(principal accounting officer)

Date: August 8, 2008

	/s/ Robert P. May
	Robert P. May
	CHIEF EXECUTIVE OFFICER
	CALPINE CORPORATION