cpn-q32011_10q.htm

Item 1. Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions, except share and per share amounts)
Operating revenues	$	2,209		$	2,130		$	5,341		$	5,074
Operating expenses:
Fuel and purchased energy expense		1,401			1,143			3,470			3,016
Plant operating expense		212			199			711			630
Depreciation and amortization expense		143			152			405			423
Sales, general and other administrative expense		33			41			99			113
Other operating expenses		22			23			64			75
Total operating expenses		1,811			1,558			4,749			4,257
Impairment losses		—			19			—			19
Income from unconsolidated investments in power plants		(5	)		(1	)		(12	)		(14	)
Income from operations		403			554			604			812
Interest expense		192			230			575			635
(Gain) loss on interest rate derivatives, net		3			84			149			87
Interest (income)		(2	)		(2	)		(7	)		(8	)
Debt extinguishment costs		(4	)		20			94			27
Other (income) expense, net		4			3			14			9
Income (loss) before income taxes and discontinued operations		210			219			(221	)		62
Income tax expense (benefit)		20			21			(45	)		38
Income (loss) before discontinued operations		190			198			(176	)		24
Discontinued operations, net of tax expense		—			19			—			31
Net income (loss)		190			217			(176	)		55
Net income attributable to the noncontrolling interest		—			—			(1	)		—
Net income (loss) attributable to Calpine	$	190		$	217		$	(177	)	$	55

Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)		486,420			486,088			486,363			486,023
Income (loss) before discontinued operations attributable to Calpine	$	0.39		$	0.41		$	(0.36	)	$	0.05
Discontinued operations, net of tax expense attributable to Calpine		—			0.04			—			0.06
Net income (loss) per common share attributable to Calpine – basic	$	0.39		$	0.45		$	(0.36	)	$	0.11

Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands)		489,062			487,443			486,363			487,199
Income (loss) before discontinued operations attributable to Calpine	$	0.39		$	0.41		$	(0.36	)	$	0.05
Discontinued operations, net of tax expense attributable to Calpine		—			0.04			—			0.06
Net income (loss) per common share attributable to Calpine – diluted	$	0.39		$	0.45		$	(0.36	)	$	0.11

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

	September 30, 2011			December 31, 2010
	(in millions, except share and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents ($344 and $345 attributable to VIEs)	$	1,285		$	1,327
Accounts receivable, net of allowance of $8 and $2		755			669
Margin deposits and other prepaid expense		224			221
Restricted cash, current ($111 and $177 attributable to VIEs)		195			195
Derivative assets, current		690			725
Inventory and other current assets		281			292
Total current assets		3,430			3,429

Property, plant and equipment, net ($4,186 and $6,602 attributable to VIEs)		13,010			12,978
Restricted cash, net of current portion ($41 and $52 attributable to VIEs)		43			53
Investments		75			80
Long-term derivative assets		134			170
Other assets		539			546
Total assets	$	17,231		$	17,256
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	558		$	514
Accrued interest payable		166			132
Debt, current portion ($38 and $132 attributable to VIEs)		101			152
Derivative liabilities, current		779			718
Other current liabilities		269			273
Total current liabilities		1,873			1,789

Debt, net of current portion ($2,428 and $4,069 attributable to VIEs)		10,303			10,104
Deferred income taxes, net of current		1			77
Long-term derivative liabilities		303			370
Other long-term liabilities		232			247
Total liabilities		12,712			12,587

Commitments and contingencies (see Note 12)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; 100,000,000 shares authorized; none issued and outstanding		—			—
Common stock, $0.001 par value per share; 1,400,000,000 shares authorized; 490,552,649 and 444,883,356 shares issued, respectively, and 489,779,285 and 444,435,198 shares outstanding, respectively		1			1
Treasury stock, at cost, 773,364 and 448,158 shares, respectively		(9	)		(5	)
Additional paid-in capital		12,299			12,281
Accumulated deficit		(7,686	)		(7,509	)
Accumulated other comprehensive loss		(147	)		(125	)
Total Calpine stockholders’ equity		4,458			4,643
Noncontrolling interest		61			26
Total stockholders’ equity		4,519			4,669
Total liabilities and stockholders’ equity	$	17,231		$	17,256

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2011			2010
	(in millions)
Cash flows from operating activities:
Net income (loss)	$	(176	)	$	55
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization expense(1)		431			464
Debt extinguishment costs		82			27
Deferred income taxes		(56	)		40
Impairment losses		—			19
Loss on disposal of assets		18			11
Unrealized mark-to-market activity, net		42			(97	)
Income from unconsolidated investments in power plants		(12	)		(14	)
Return on unconsolidated investments in power plants		6			11
Stock-based compensation expense		18			18
Other		5			1
Change in operating assets and liabilities:
Accounts receivable		(87	)		34
Derivative instruments, net		(6	)		(42	)
Other assets		27			241
Accounts payable and accrued expenses		95			(1	)
Liabilities related to non-hedging interest rate swaps		147			27
Other liabilities		2			16
Net cash provided by operating activities		536			810
Cash flows from investing activities:
Purchases of property, plant and equipment		(511	)		(191	)
Purchase of Conectiv assets		—			(1,634	)
Cash acquired due to consolidation of OMEC		—			8
Purchases of deferred transmission credits		(16	)		—
Decrease in restricted cash		9			228
Settlement of non-hedging interest rate swaps		(147	)		(27	)
Other		5			4
Net cash used in investing activities		(660	)		(1,612	)
Cash flows from financing activities:
Repayments of project financing, notes payable and other		(476	)		(472	)
Borrowings from project financing, notes payable and other		223			1,272
Repayments on NDH Project Debt		(1,283	)		—
Borrowings under Term Loan and New Term Loan		1,657			—
Issuance of First Lien Notes		1,200			1,491
Repayments on First Lien Credit Facility		(1,191	)		(1,507	)
Capital contributions from noncontrolling interest holder		34			—
Financing costs		(78	)		(67	)
Refund of financing costs		—			10
Other		(4	)		—
Net cash provided by financing activities		82			727
Net decrease in cash and cash equivalents		(42	)		(75	)
Cash and cash equivalents, beginning of period		1,327			989
Cash and cash equivalents, end of period	$	1,285		$	914

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS - Continued

(Unaudited)

	Nine Months Ended September 30,
	2011			2010
	(in millions)
Cash paid during the period for:
Interest, net of amounts capitalized	$	509	$		488
Income taxes	$	15	$		11
Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable	$	(13	$		(5)
Purchase of Conectiv assets included in accounts payable	$	—	$		6

_________

(1)	Includes depreciation and amortization that is also recorded in fuel and purchased energy expense, interest expense and discontinued operations on our Consolidated Condensed Statements of Operations.

The accompanying notes are an integral part of these

Consolidated Condensed Financial Statements.

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

September 30, 2011

(Unaudited)

1. Basis of Presentation and Summary of Significant Accounting Policies

We are an independent wholesale power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in the major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. We sell wholesale power, steam, regulatory capacity, renewable energy credits and ancillary services to our customers, which include industrial companies, retail power providers, utilities, municipalities, independent electric system operators, marketers and others. We engage in the purchase of natural gas and fuel oil as fuel for our power plants and in related natural gas transportation and storage transactions, and in the purchase of electric transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts to economically hedge our business risks and optimize our portfolio of power plants.

Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2010, included in our 2010 Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues, timing of major maintenance expense, volatility of commodity prices and unrealized gains and losses from commodity and interest rate derivative contracts.

Reclassifications — Certain reclassifications have been made to our Consolidated Condensed Statements of Operations and Cash Flows for the three and nine months ended September 30, 2010, to conform to the current period presentation. Our reclassifications are summarized as follows:

•

We have reclassified amounts attributable to interest rate swaps formerly hedging our First Lien Credit Facility term loans previously recorded in interest expense to (gain) loss on interest rate derivatives, net of approximately $84 million and $87 million for the three and nine months ended September 30, 2010, respectively. See Note 7 for further information about our interest rate swaps formerly hedging our First Lien Credit Facility.

•

We have reclassified depreciation expense on corporate assets previously recorded in sales, general and other administrative expense to depreciation and amortization expense of approximately $3 million and $9 million for the three and nine months ended September 30, 2010, respectively.

•

We have reclassified cash payments on our interest rate swaps formerly hedging our First Lien Credit Facility term loans previously included in net cash provided by operating activities of approximately $27 million to settlement of non-hedging interest rate swaps included in net cash used in investing activities for the nine months ended September 30, 2010.

Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.

Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At September 30, 2011 and December 31, 2010, we had cash and cash equivalents of $308 million and $269 million, respectively, that were subject to such project finance facilities and lease agreements.

Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Consolidated Condensed Statements of Cash Flows. The table below represents the components of our restricted cash at September 30, 2011 and December 31, 2010 (in millions):

	September 30, 2011						December 31, 2010
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service	$	22	$	27	$	49	$	44	$	25	$	69
Rent reserve		2		—		2		22		5		27
Construction/major maintenance		46		4		50		35		14		49
Security/project/insurance		112		8		120		75		7		82
Other		13		4		17		19		2		21
Total	$	195	$	43	$	238	$	195	$	53	$	248

Inventory — At September 30, 2011 and December 31, 2010, we had inventory of $251 million and $262 million, respectively. Inventory primarily consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost under the weighted average cost method or market value. Spare parts inventory is valued at the weighted average cost and are expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.

Property, Plant and Equipment — At September 30, 2011 and December 31, 2010, the components of property, plant and equipment were stated at cost less accumulated depreciation as follows (in millions):

	September 30, 2011		December 31, 2010
Buildings, machinery and equipment	$	14,972	$	14,578
Geothermal properties		1,146		1,102
Other		259		273
		16,377		15,953
Less: Accumulated depreciation		4,046		3,690
		12,331		12,263
Land		93		93
Construction in progress		586		622
Property, plant and equipment, net	$	13,010	$	12,978

Capitalized Interest — The total amount of interest capitalized was $6 million for both the three months ended September 30, 2011 and 2010, and $17 million and $8 million for the nine months ended September 30, 2011 and 2010, respectively.

New Accounting Standards and Disclosure Requirements

Fair Value Measurement — In May 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-04, “Fair Value Measurement” to clarify and amend the application or requirements relating to fair value measurements and disclosures relating to fair value measurements. The update stems from the Financial Accounting Standards Board and the International Accounting Standards Board project to develop common requirements for measuring fair value and for disclosing information about fair value measurements. The update is not expected to impact any of our fair value measurements but will require disclosure of the following:

•

quantitative information about the unobservable inputs used in a fair value measurement that is categorized within level 3 of the fair value hierarchy;

•

for those fair value measurements categorized within level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and

•

the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.

The new requirements relating to fair value measurements are prospective and effective for interim and annual periods beginning after December 15, 2011, with early adoption prohibited. We do not expect that the adoption of this standard will have a material impact on our results of operations, cash flows or financial condition.

Comprehensive Income — In June 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-05, “Comprehensive Income” to amend requirements relating to the presentation of comprehensive income. The update eliminates the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity and provides an entity with the option to present comprehensive income in a single continuous financial statement or in two separate but consecutive statements. The new requirements relating to the presentation of comprehensive income are retrospective and effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. We have not elected to early adopt the requirements related to the update at September 30, 2011. Since the update only requires a change in presentation, we do not expect that the adoption of this standard will have a material impact on our results of operations, cash flows or financial condition.

2. Acquisitions, Divestitures and Discontinued Operations

Conectiv Acquisition

On July 1, 2010, we, through our indirect, wholly owned subsidiary NDH, completed the Conectiv Acquisition. The assets acquired include 18 operating power plants and the York Energy Center that was under construction and achieved COD on March 2, 2011, totaling 4,491 MW of capacity. We did not acquire Conectiv’s trading book, load serving auction obligations or collateral requirements. Additionally, we did not assume any of Conectiv’s off-site environmental liabilities, environmental remediation liabilities in excess of $10 million related to assets located in New Jersey that are subject to ISRA, or pre-close accumulated pension and retirement welfare liabilities; however, we did assume pension liabilities on future services and compensation increases for past services for approximately 130 grandfathered union employees who joined Calpine as a result of the Conectiv Acquisition. During the second half of 2010, we initiated a voluntary retirement incentive program which reduced our pension obligation by 31 employees. The net proceeds of $1.3 billion received from the NDH Project Debt were used, together with available operating cash, to pay the Conectiv Acquisition purchase price of approximately $1.64 billion and also fund a cash contribution from Calpine Corporation to NDH of $110 million to fund completion of the York Energy Center.

The Conectiv Acquisition provided us with a significant presence in the Mid-Atlantic market, one of the most robust competitive power markets in the U.S., and positioned us with three scale markets instead of two (California and Texas) giving us greater geographic diversity. We accounted for the Conectiv Acquisition under the acquisition method of accounting in accordance with U.S. GAAP.

During the second quarter of 2011, we finalized the valuations of the net assets acquired in the Conectiv Acquisition which is summarized in the following table (in millions). We did not record any material valuation adjustments during the first half of 2011, and we did not recognize any goodwill as a result of this acquisition.


Consideration	$	1,640

Final values of identifiable assets acquired and liabilities assumed:
Assets:
Current assets	$	78
Property, plant and equipment, net		1,574
Other long-term assets		85
Total assets acquired		1,737
Liabilities:
Current liabilities		46
Long-term liabilities		51
Total liabilities assumed		97
Net assets acquired	$	1,640

Sale of Blue Spruce and Rocky Mountain

On December 6, 2010, we, through our indirect, wholly owned subsidiaries Riverside Energy Center, LLC and Calpine Development Holdings, Inc., completed the sale of 100% of our ownership interests in Blue Spruce and Rocky Mountain for approximately $739 million, and we recorded a pre-tax gain of approximately $209 million during the fourth quarter of 2010. The results of operations for Blue Spruce and Rocky Mountain are reported as discontinued operations on our Consolidated Condensed Statement of Operations for the three and nine months ended September 30, 2010.

The table below presents the components of our discontinued operations for the periods presented (in millions):

	Three Months Ended			Nine Months Ended
	September 30, 2010			September 30, 2010
Operating revenues	$	25		$	74
Income from discontinued operations before taxes	$	17		$	37
Less: Income tax expense (benefit)		(2	)		6
Discontinued operations, net of tax expense	$	19		$	31

3. Variable Interest Entities and Unconsolidated Investments

We consolidate all of our VIEs where we have determined that we are the primary beneficiary. We have the following types of VIEs consolidated in our financial statements:

Subsidiaries with Project Debt — All of our subsidiaries with project debt not guaranteed by Calpine have PPAs that provide financial support and are thus considered VIEs. We retain ownership and absorb the full risk of loss and potential for reward once the project debt is paid in full. Actions by the lender to assume control of collateral can occur only under limited circumstances such as upon the occurrence of an event of default, which we have determined to be unlikely. See Note 5 for further information regarding our project debt and Note 1 for information regarding our restricted cash balances.

Subsidiaries with PPAs — Certain of our majority owned subsidiaries have PPAs that limit the risk and reward of our ownership and thus constitute a VIE.

VIEs with a Purchase Option — Riverside Energy Center and OMEC have agreements that provide third parties a fixed price option to purchase power plant assets exercisable in the years 2013 and 2019, respectively, with an aggregate capacity of 1,211 MW. These purchase options limit the risk and reward of our ownership and, thus, constitute a VIE.

Consolidation of VIEs

We consolidate our VIEs where we determine that we have both the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE. We have determined that we hold the obligation to absorb losses and receive benefits in all of our VIEs where we hold the majority equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following primary activities which we believe to have a significant impact on a power plant’s financial performance: operations and maintenance, plant dispatch, and fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our majority owned VIEs.

Under our consolidation policy and under U.S. GAAP we also:

•

perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and

•

evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE’s economic performance.

On August 23, 2011, we closed on the $373 million Los Esteros Project Debt to fund the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle power plant to a 308 MW combined-cycle generation power plant. The addition of this project debt resulted in Los Esteros Critical Energy Facility, LLC meeting the definition of a VIE for which we are the primary beneficiary. There were no other changes to our determination of whether we are the primary beneficiary of our VIEs during the nine months ended September 30, 2011.

Noncontrolling Interest — We own a 75% interest in Russell City Energy Company, LLC, one of our VIEs, which is also 25% owned by Aircraft Services. We fully consolidate this entity in our Consolidated Condensed Financial Statements and account for the third party ownership interest as a noncontrolling interest under U.S. GAAP.

VIE Disclosures

U.S. GAAP requires separate disclosure on the face of our Consolidated Condensed Balance Sheets of the significant assets of a consolidated VIE that can only be used to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In determining which assets of our VIEs met the separate disclosure criteria, we determined this separate disclosure requirement is met where Calpine Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), and where there are agreements that prohibit the debt holders of the VIE from recourse to the general credit of Calpine Corporation or its other subsidiaries. In determining which liabilities of our VIEs met the separate disclosure criteria, we reviewed all of our VIEs and determined this separate disclosure requirement was met where our VIEs had project

financing that prohibits the VIE from providing guarantees on the debt of others and where the amounts were material to our financial statements.

The VIEs meeting the above disclosure criteria are majority owned subsidiaries of Calpine Corporation and include natural gas-fired power plants with an aggregate capacity of approximately 11,372 MW and 13,553 MW at September 30, 2011 and December 31, 2010, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Calpine Corporation provided support to these VIEs in the form of cash and other contributions other than amounts contractually required of $87 million for the nine months ended September 30, 2011. During the nine months ended September 30, 2010, Calpine Corporation provided $540 million to NDH, an indirect, wholly owned subsidiary, to fund the Conectiv Acquisition, including $110 million to complete the construction of the York Energy Center. Additionally, Calpine Corporation provided support to our other VIEs in the form of cash and other contributions other than amounts contractually required of $1 million during the nine months ended September 30, 2010.

Unconsolidated VIEs and Investments

We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are also VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. We account for these entities under the equity method of accounting and include our net equity interest in investments on our Consolidated Condensed Balance Sheets. At September 30, 2011 and December 31, 2010, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):

	Ownership Interest as of September 30, 2011		September 30, 2011(1)		December 31, 2010
Greenfield LP		50%	$	69	$	77
Whitby		50%		6		3
Total investments			$	75	$	80

_________

(1)

Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At September 30, 2011 and December 31, 2010, equity method investee debt was approximately $476 million and $494 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $238 million and $247 million at September 30, 2011 and December 31, 2010, respectively.

Our ownership interest in the net income for Greenfield LP and Whitby for the three and nine months ended September 30, 2011 and 2010, are recorded in income from unconsolidated investments in power plants. The following table sets forth details of our income from unconsolidated investments in power plants for the periods indicated (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Greenfield LP	$	(4	)	$	—		$	(5	)	$	(7	)
Whitby		(1	)		(1	)		(7	)		(7	)
Total	$	(5	)	$	(1	)	$	(12	)	$	(14	)

Greenfield LP — Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Greenfield LP holds an 18-year term loan in the amount of CAD $648 million. Borrowings under the project finance facility bear interest at Canadian LIBOR plus 1.125% or Canadian prime rate plus 0.125%. Distributions from Greenfield LP were nil and $2 million for the three and nine months ended September 30, 2011, respectively, and $6 million for both the three and nine months ended September 30, 2010.

Whitby — Whitby is a limited partnership between certain subsidiaries of ours and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby. Distributions from Whitby were nil and $4 million for the three and nine months ended September 30, 2011, respectively, and $3 million and $5 million for the three and nine months ended September 30, 2010, respectively.

Inland Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California which achieved COD on May 3, 2010) from GE that may be exercised between years 7 and 14 after the start of commercial operation. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met during year 15 after the start of commercial operation. We determined that we were not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to, but not limited to, the fact that GE directs the most significant activities of the power plant including operations and maintenance.

4. Comprehensive Income (Loss)

Comprehensive income (loss) includes our net income (loss), unrealized gains and losses from derivative instruments, net of tax that qualify as cash flow hedges, our share of equity method investees’ OCI and the effects of foreign currency translation adjustments. See Note 7 for further discussion of our accounting for derivative instruments designated as cash flow hedges and the related amounts recorded in OCI. We report AOCI on our Consolidated Condensed Balance Sheets. The table below details the components of our comprehensive income (loss) for the periods indicated (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net income (loss)	$	190		$	217		$	(176	)	$	55
Other comprehensive income (loss):
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)		(74	)		65			(60	)		95
Reclassification adjustment for cash flow hedges realized in net income (loss)		(20	)		(12	)		24			10
Foreign currency translation loss		(4	)		—			(4	)		—
Income tax (expense) benefit		34			4			18			(5	)
Comprehensive income (loss)		126			274			(198	)		155
Add: Comprehensive income attributable to the noncontrolling interest		—			—			(1	)		—
Comprehensive income (loss) attributable to Calpine	$	126		$	274		$	(199	)	$	155

5. Debt

Our debt at September 30, 2011 and December 31, 2010, was as follows (in millions):

	September 30, 2011		December 31, 2010
First Lien Notes(1)	$	5,892	$	4,691
Project financing, notes payable and other(2)(3)		1,658		1,922
Term Loan and New Term Loan(2)(4)		1,650		—
NDH Project Debt(4)		—		1,258
First Lien Credit Facility(1)		—		1,184
CCFC Notes		970		965
Capital lease obligations		234		236
Total debt		10,404		10,256
Less: Current maturities		101		152
Debt, net of current portion	$	10,303	$	10,104

_________

(1)	On January 14, 2011, we repaid and terminated the First Lien Credit Facility with the issuance of the 2023 First Lien Notes as discussed below.

(2)	On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan as further described below.

(3)

On June 24, 2011, we closed on the approximately $845 million Russell City Project Debt to fund the construction of Russell City and on August 23, 2011, we closed on the $373 million Los Esteros Project Debt to fund the upgrade of our Los Esteros Critical Energy Facility, both further described below.

(4)	On March 9, 2011, we borrowed $1.3 billion under the Term Loan and repaid and terminated the NDH Project Debt as discussed below.

Our First Lien Notes and Termination of the First Lien Credit Facility

Our First Lien Notes are summarized in the table below (in millions):

	September 30, 2011		December 31, 2010
2017 First Lien Notes	$	1,200	$	1,200
2019 First Lien Notes		400		400
2020 First Lien Notes		1,092		1,091
2021 First Lien Notes		2,000		2,000
2023 First Lien Notes(1)		1,200		—
Total First Lien Notes	$	5,892	$	4,691

_________

(1)

On January 14, 2011, we issued $1.2 billion in aggregate principal amount of 7.875% senior secured notes due 2023 in a private placement. Interest on the 2023 First Lien Notes is payable semi-annually on January 15 and July 15 of each year, beginning on July 15, 2011. The 2023 First Lien Notes will mature on January 15, 2023.

Following our emergence from Chapter 11, our First Lien Credit Facility served as our primary debt facility. Beginning in late 2009, we began to repay or exchange our First Lien Credit Facility term loans through proceeds received from the issuances of the First Lien Notes, together with operating cash. On January 14, 2011, we repaid the remaining approximately $1.2 billion from the proceeds from the issuance of the 2023 First Lien Notes, together with operating cash, thereby terminating the First Lien Credit Facility in accordance with its terms.

Our First Lien Notes are secured equally and ratably with indebtedness incurred under our Corporate Revolving Facility, Term Loan and New Term Loan (described below), subject to certain exceptions and permitted liens, on substantially all of our and certain of the guarantors’ existing and future assets. Additionally, our First Lien Notes rank equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee our First Lien Notes. Repayment of the NDH Project Debt also eliminated the restrictions against our NDH subsidiaries being guarantors to our First Lien Notes and Corporate Revolving Facility. On March 9, 2011, we executed assumption agreements to the amended and restated guarantee and collateral agreement, to add our NDH subsidiaries as guarantors to our Corporate Revolving Facility and Term Loan. On April 26, 2011, we executed supplemental indentures for the First Lien Notes to add the NDH subsidiaries as guarantors. On June 17, 2011, we executed assumption agreements to the amended and restated guarantee and collateral agreement, to add Deer Park Holdings, LLC, Metcalf Holdings, LLC, Deer Park Energy Center LLC and Metcalf Energy Center, LLC as guarantors of our Corporate Revolving Facility, Term Loan and New Term Loan. On July 22, 2011, we executed supplemental indentures for the First Lien Notes to add Deer Park Holdings, LLC, Metcalf Holdings, LLC, Deer Park Energy Center LLC and Metcalf Energy Center, LLC as guarantors.

Subject to certain qualifications and exceptions, our First Lien Notes will, among other things, limit our ability and the ability of the guarantors to:

•

incur or guarantee additional first lien indebtedness;

•

enter into certain types of commodity hedge agreements that can be secured by first lien collateral;

•

enter into sale and leaseback transactions;

•

create or incur liens; and

•

consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries on a combined basis.

We recorded approximately $19 million in debt extinguishment costs in the first quarter of 2011 from the write-off of unamortized deferred financing costs related to the repayment and termination of the First Lien Credit Facility, and we recorded approximately $22 million of deferred financing costs on our Consolidated Condensed Balance Sheet during the first quarter of 2011 related to the issuance of the 2023 First Lien Notes.

The Term Loan and New Term Loan and Repayment of the NDH Project Debt and Other Project Debt

On March 9, 2011, we entered into and borrowed $1.3 billion under the Term Loan. We used the net proceeds received, together with operating cash on hand to fully retire the approximately $1.3 billion NDH Project Debt in accordance with its repayment terms. The NDH Project Debt was originally established to partially fund the Conectiv Acquisition.

The Term Loan provides for a senior secured term loan facility in an aggregate principal amount of $1.3 billion and bears interest, at our option, at either (i) the base rate, equal to the higher of the Federal Funds effective rate plus 0.5% per annum or the Prime Rate (as such terms are defined in the Term Loan credit agreement), plus an applicable margin of 2.25%, or (ii) LIBOR plus 3.25% per annum subject to a LIBOR floor of 1.25%.

An aggregate amount equal to 0.25% of the aggregate principal amount of the Term Loan will be payable at the end of each quarter commencing on June 30, 2011, with the remaining balance payable on the maturity date (April 1, 2018). We may elect from time to time to convert all or a portion of the Term Loan from initial LIBOR rate loans to base rate loans or vice versa. In addition, we may at any time, and from time to time, prepay the Term Loan, in whole or in part, without premium or penalty, upon irrevocable notice to the administrative agent. We may also reprice the interest rate on the Term Loan, subject to approval from the Lenders and subject to a 1% premium if a repricing transaction occurs prior to the first anniversary of the closing date. We may elect to extend the maturity of any term loans under the Term Loan, in whole or in part subject to approval from those lenders holding such term loans. The Term Loan is subject to certain qualifications and exceptions, similar to our First Lien Notes.

If a change of control triggering event occurs, the Company shall notify the Administrative Agent in writing and shall make an offer to prepay the entire principal amount of the Term Loan outstanding within thirty (30) days after the date of such change of control triggering event.

In connection with the Term Loan, the Company and its subsidiaries (subject to certain exceptions) have made certain representations and warranties and are required to comply with various affirmative and negative covenants. The Term Loan is subject to customary events of default included in financing transactions, including, among others, failure to make payments when due, certain defaults under other material indebtedness, breach of certain covenants, breach of certain representations and warranties, involuntary or voluntary bankruptcy, and material judgments. If an event of default arises from certain events of bankruptcy or insolvency, all amounts outstanding under the Term Loan will become due and payable immediately without further action or notice. If other events of default arise (as defined in the Credit Agreement) and are continuing, the lenders holding more than 50% of the outstanding Term Loan amounts (as defined in the Credit Agreement) may declare all the Term Loan amounts outstanding to be due and payable immediately.

In connection with the Term Loan, we recorded deferred financing costs of approximately $14 million on our Consolidated Condensed Balance Sheet during the first half of 2011, and we recorded approximately $74 million in debt extinguishment costs during the first quarter of 2011, which includes approximately $36 million from the write-off of unamortized deferred financing costs, the write-off of approximately $25 million of debt discount and approximately $13 million in prepayment premiums related to the NDH Project Debt.

On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan. The New Term Loan carries substantially the same terms as the Term Loan and matures on April 1, 2018. The New Term Loan also contains very similar covenants, qualifications, exceptions and limitations as the Term Loan and First Lien Notes.

In connection with the New Term Loan, we recorded deferred financing costs of approximately $5 million on our Consolidated Condensed Balance Sheet during the second quarter of 2011, and we recorded approximately $5 million in debt extinguishment costs during the nine months ended September 30, 2011.

Russell City Project Debt

On June 24, 2011, we, through our indirect, partially owned subsidiary Russell City Energy Company, LLC, closed on our approximately $845 million Russell City Project Debt to finance construction of Russell City, a 619 MW natural gas-fired, combined-cycle power plant under construction located in Hayward, California, which is comprised of a $700 million construction loan facility, an approximately $77 million project letter of credit facility and a $68 million debt service reserve letter of credit facility. The construction loan converts to a ten year term loan when commercial operations commence. Borrowings bear interest initially at LIBOR plus 2.25%. At September 30, 2011, approximately $161 million had been drawn under the construction loan and approximately $61 million of letters of credit were issued under the letter of credit facilities. Calpine’s pro rata share would be 75% and the pro rata share related to the noncontrolling interest would be 25%.

In connection with the closing of the Russell City Project Debt, we recorded deferred financing costs of approximately $27 million on our Consolidated Condensed Balance Sheet during the second and third quarters of 2011.

Los Esteros Project Debt

On August 23, 2011, we, through our indirect, wholly owned subsidiary Los Esteros Critical Energy Facility, LLC, closed on our $373 million Los Esteros Project Debt to finance the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle power plant to a 308 MW combined-cycle generation power plant. The upgrade will also increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. The Los Esteros Project Debt is comprised of a $305 million construction loan facility, an approximately $38 million project letter of credit facility and an approximately $30 million debt service reserve letter of credit facility. The construction loan converts to a ten year term loan when commercial operations commence. Borrowings bear interest initially at LIBOR plus 2.25%. At September 30, 2011, approximately $63 million had been drawn under the construction loan and approximately $30 million of letters of credit were issued under the letter of credit facilities.

In connection with the closing of the Los Esteros Project Debt, we recorded deferred financing costs of approximately $10 million on our Consolidated Condensed Balance Sheet during the third quarter of 2011.

Corporate Revolving Facility and Other Letter of Credit Facilities

The table below represents amounts issued under our letter of credit facilities at September 30, 2011, and December 31, 2010 (in millions):

	September 30, 2011		December 31, 2010
Corporate Revolving Facility(1)	$	402	$	443
Calpine Development Holdings, Inc.		163		165
NDH Project Debt credit facility(2)		—		34
Various project financing facilities		130		69
Total	$	695	$	711

_________

(1)

When we entered into our $1.0 billion Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced with letters of credit issued by our Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit under our Corporate Revolving Facility at December 31, 2010 include those that were back-stopped of approximately $83 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011.

(2)	We repaid and terminated the NDH Project Debt on March 9, 2011.

The Corporate Revolving Facility represents our primary revolving facility. Borrowings under the Corporate Revolving Facility bear interest, at our option, at either a base rate or LIBOR rate (with the exception of any swingline borrowings, which bear interest at the base rate). Base rate borrowings shall be at the base rate, plus an applicable margin ranging from 2.00% to 2.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is defined as the higher of (i) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50% and (ii) the rate the administrative agent announces from time to time as its prime per annum rate. LIBOR rate borrowings shall be at the British Bankers’ Association Interest Settlement Rates for the interest period as selected by us as a one, two, three, six or, if agreed by all relevant lenders, nine or twelve month interest period, plus an applicable margin ranging from 3.00% to 3.25%. Interest payments are due on the last business day of each calendar quarter for base rate loans and the earlier of (i) the last day of the interest period selected or (ii) each day that is three months (or a whole multiple thereof) after the first day for the interest period selected for LIBOR rate loans. Letter of credit fees for issuances of letters of credit include fronting fees equal to that percentage per annum as may be separately agreed upon between us and the issuing lenders and a participation fee for the lenders equal to the applicable interest margin for LIBOR rate borrowings. Drawings under letters of credit shall be repaid within two business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We will incur an unused commitment fee ranging from 0.50% to 0.75% on the unused amount of commitments under the Corporate Revolving Facility.

The Corporate Revolving Facility does not contain any requirements for mandatory prepayments, except in the case of certain designated asset sales in excess of $3.0 billion in the aggregate. However, we may voluntarily repay, in whole or in part, the Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be reborrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility without premium or penalty. The Corporate Revolving Facility matures December 10, 2015.

The Corporate Revolving Facility is guaranteed and secured by each of our current domestic subsidiaries that was a guarantor under the First Lien Credit Facility and will also be additionally guaranteed by our future domestic subsidiaries that are required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving Facility ranks equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a minimum cash interest coverage ratio and a maximum net leverage ratio.

We also have a letter of credit facility related to our subsidiary Calpine Development Holdings, Inc. which matures on December 11, 2012, under which up to $200 million is available for letters of credit.

Fair Value of Debt

We record our debt instruments based on contractual terms, net of any applicable premium or discount. We did not elect to apply the alternative U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. We measured the fair value of our debt instruments at September 30, 2011 and December 31, 2010, using market information including credit default swap rates and historical default information, quoted market prices or dealer quotes for the identical liability when traded as an asset and discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements. The following table details the fair values and carrying values of our debt instruments at September 30, 2011 and December 31, 2010 (in millions):

	September 30, 2011				December 31, 2010
	Fair Value		Carrying Value		Fair Value		Carrying Value
First Lien Notes	$	5,647	$	5,892	$	4,695	$	4,691
Project financing, notes payable and other(1)		1,434		1,470		1,673		1,708
Term Loan and New Term Loan		1,553		1,650		—		—
NDH Project Debt		—		—		1,303		1,258
First Lien Credit Facility		—		—		1,182		1,184
CCFC Notes		1,030		970		1,067		965
Total	$	9,664	$	9,982	$	9,920	$	9,806

_________

(1)	Excludes leases that are accounted for as failed sale-leaseback transactions under U.S. GAAP and included in our project financing, notes payable and other balance.

6. Assets and Liabilities with Recurring Fair Value Measurements

Cash Equivalents — Highly liquid investments that meet the definition of cash equivalents, primarily investments in money market accounts, are included in both our cash and cash equivalents and in restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Our cash equivalents are classified within level 1 of the fair value hierarchy.

Margin Deposits and Margin Deposits Held by Us Posted by Our Counterparties — Margin deposits and margin deposits held by us posted by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits held by us posted by our counterparties are generally cash and cash equivalents and are classified within level 1 of the fair value hierarchy.

Derivatives — The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); market price levels, primarily for power and natural gas; our credit standing and that of our counterparties; and prevailing interest rates for our interest rate swaps. Prices for power and natural gas are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future.

We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about risks and the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value; however, other qualitative assessments can also be used to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs.

The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and the impact of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.

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

Our level 2 fair value derivative instruments primarily consist of interest rate swaps and OTC power and natural gas forwards for which market-based pricing inputs are observable. Generally, we obtain our level 2 pricing inputs from markets such as the Intercontinental Exchange and Bloomberg. To the extent we obtain prices from brokers in the marketplace, we have procedures in place to ensure that prices represent executable prices for market participants. 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, correlation, volatility, 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 OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions. Complex or structured transactions are tailored to our or 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 fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs.

The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis at September 30, 2011 and December 31, 2010, by level within the fair value hierarchy. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels.

	Assets and Liabilities with Recurring Fair Value Measures at September 30, 2011
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents(1)	$	1,491	$	—	$	—	$	1,491
Margin deposits		182		—		—		182
Commodity instruments:
Commodity futures contracts		631		—		—		631
Commodity forward contracts(2)		—		143		41		184
Interest rate swaps		—		9		—		9
Total assets	$	2,304	$	152	$	41	$	2,497
Liabilities:
Margin deposits held by us posted by our counterparties	$	5	$	—	$	—	$	5
Commodity instruments:
Commodity futures contracts		589		—		—		589
Commodity forward contracts(2)		—		118		14		132
Interest rate swaps		—		361		—		361
Total liabilities	$	594	$	479	$	14	$	1,087

	Assets and Liabilities with Recurring Fair Value Measures at December 31, 2010
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents(1)	$	1,297	$	—	$	—	$	1,297
Margin deposits		162		—		—		162
Commodity instruments:
Commodity futures contracts		550		—		—		550
Commodity forward contracts(2)		—		287		54		341
Interest rate swaps		—		4		—		4
Total assets	$	2,009	$	291	$	54	$	2,354
Liabilities:
Margin deposits held by us posted by our counterparties	$	6	$	—	$	—	$	6
Commodity instruments:
Commodity futures contracts		574		—		—		574
Commodity forward contracts(2)		—		119		24		143
Interest rate swaps		—		371		—		371
Total liabilities	$	580	$	490	$	24	$	1,094

_________

(1)	At September 30, 2011 and December 31, 2010, we had cash equivalents of $1,280 million and $1,094 million included in cash and cash equivalents and $211 million and $203 million included in restricted cash, respectively.

(2)	Includes OTC swaps and options.

The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Balance, beginning of period	$	21		$	43		$	30		$	38
Realized and unrealized gains (losses):
Included in net income (loss):
Included in operating revenues(1)		(8	)		12			(1	)		31
Included in fuel and purchased energy expense(2)		1			2			1			(1	)
Included in OCI		(2	)		4			3			6
Purchases, issuances, sales and settlements:
Settlements		16			(2	)		(6	)		(13	)
Transfers into and/or out of level 3:(3)
Transfers into level 3(4)		—			1			—			—
Transfers out of level 3(5)		(1	)		4			—			3
Balance, end of period	$	27		$	64		$	27		$	64
Change in unrealized gains relating to instruments held at end of period	$	(7	)	$	14		$	—		$	30

_________

(1)	For power contracts and Heat Rate swaps and options, included on our Consolidated Condensed Statements of Operations.

(2)	For natural gas contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.

(3)	We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no significant transfers into/out of level 1 during the three and nine months ended September 30, 2011 and 2010.

(4)

We had no significant transfers into level 3 out of level 2 for the three months ended September 30, 2011 and the nine months ended September 30, 2011 and 2010. We had $1 million in gains transferred into level 3 out of level 2 for the three months ended September 30, 2010, due to changes in market liquidity in various power markets.

(5)

We had $1 million in gains and $4 million in losses transferred out of level 3 into level 2 for the three months ended September 30, 2011 and 2010, respectively. We had no significant transfers out of level 3 into level 2 for the nine months ended September 30, 2011. We had $3 million in losses transferred out of level 3 into level 2 for the nine months ended September 30, 2010. Transfers out of level 3 into level 2 were due to changes in market liquidity in various power markets.

7. Derivative Instruments

Types of Derivative Instruments and Volumetric Information

Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments, such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.

Interest Rate Swaps — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate swaps to adjust the mix between fixed and floating rate debt to hedge our interest rate risk for potential adverse changes in interest rates.

At September 30, 2011, the maximum length of time that our PPAs extended was approximately 23 years into the future and the maximum length of time over which we were hedging using commodity and interest rate derivative instruments was 1 and 15 years, respectively.

At September 30, 2011 and December 31, 2010, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify under the normal purchase normal sale exemption were as follows (in millions):

	Notional Amounts
	September 30, 2011			December 31, 2010
Derivative Instruments
Power (MWh)		(38	)		(50	)
Natural gas (MMBtu)		124			31
Interest rate swaps(1)	$	5,448		$	6,171

_________

(1)	Approximately $4.1 billion and $3.3 billion at September 30, 2011 and December 31, 2010, respectively, related to variable rate debt that was converted to fixed rate debt in 2011 and 2010.

Certain of our derivative instruments contain credit-contingent provisions that require us to maintain a minimum credit rating from each of the major credit rating agencies. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty(ies) to request immediate, full settlement on certain derivative instruments in liability positions. Currently, we do not believe that it is probable that any additional collateral posted as a result of a one credit rating level downgrade would be material. The aggregate fair value of our derivative liabilities with credit-contingent provisions at September 30, 2011, was $34 million for which we have posted collateral of $8 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our Corporate Revolving Facility. If our credit rating were downgraded, we estimate that additional collateral of approximately $10 million would be required and that no counterparty could request immediate, full settlement.

Accounting for Derivative Instruments

We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and fuel costs derived from instruments that qualify for hedge accounting or represent an economic hedge are recorded in the same period and in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged within operating activities or investing activities (in the case of settlements for our interest rate swaps formerly hedging our First Lien Credit Facility term loans or interest rate swap breakage costs associated with interest rate swaps formerly hedging project debt) on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.

Cash Flow Hedges — We report the effective portion of the unrealized gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on commodity hedging instruments are included in unrealized mark-to-market gains and losses and are recognized currently in earnings as a component of operating revenues (for power contracts and swaps), fuel and purchased energy expense (for natural gas contracts and swaps) and interest expense (for interest rate swaps except as discussed below). If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction impacts earnings or until it is determined that the forecasted transaction is probable of not occurring. Upon repayment of our NDH Project Debt and other project debt, we terminated and settled the interest rate swaps related to these debt instruments and recorded $17 million to (gain) loss on interest rate derivatives, net during the second quarter of 2011. See Note 5 for further information about the repayment of the NDH Project Debt as well as the repayment of other project debt with proceeds from our New Term Loan.

Derivatives Not Designated as Hedging Instruments — Along with our portfolio of transactions, which are accounted for as hedges under U.S. GAAP, we enter into power, natural gas and interest rate transactions that primarily act as economic hedges to our asset portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of derivatives not designated as hedging instruments are recognized currently in earnings as a component of operating revenues (for power contracts and Heat Rate swaps and options), fuel and purchased energy expense (for natural gas contracts, swaps and options) and interest expense (for interest rate swaps except as discussed below).

Interest Rate Swaps Formerly Hedging our First Lien Credit Facility and Other Project Debt — During 2010, we repaid approximately $3.5 billion of our First Lien Credit Facility term loans, which had approximately $3.3 billion notional amount of interest rate swaps hedging the scheduled variable interest payments, and in January 2011, we repaid the remaining approximately $1.2 billion of First Lien Credit Facility term loans which had approximately $1.0 billion notional amount of interest rate swaps hedging the scheduled variable interest payments. With the repayment of the remaining First Lien Credit Facility term loans, the remaining unrealized losses of approximately $91 million in AOCI related to the interest swaps formerly hedging the First Lien Credit Facility, were reclassified out of AOCI and into income as an additional (gain) loss on interest rate derivatives, net during the first quarter of 2011. In addition, we reclassified approximately $17 million in unrealized losses in AOCI to (gain) loss on interest rate derivatives, net during the second quarter of 2011 resulting from the repayment of project debt in June 2011. We have presented the reclassification of unrealized losses from AOCI into income and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility described above separate from interest expense as (gain) loss on interest rate derivatives, net on our Consolidated Condensed Statements of Operations. We also have determined that, based upon current market conditions and consistent with our risk management policy, liquidation of these interest rate swaps is not economically beneficial and additional future losses are limited. Accordingly, we have elected to retain and hold these interest rate swap positions at this time.

Derivatives Included on Our Consolidated Condensed Balance Sheets

The following tables present the fair values of our net derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at September 30, 2011 and December 31, 2010 (in millions):

	September 30, 2011
	Interest Rate Swaps			Commodity Instruments		Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	—		$	690	$	690
Long-term derivative assets		9			125		134
Total derivative assets	$	9		$	815	$	824

Current derivative liabilities	$	190		$	589	$	779
Long-term derivative liabilities		171			132		303
Total derivative liabilities	$	361		$	721	$	1,082
Net derivative assets (liabilities)	$	(352	)	$	94	$	(258	)

	December 31, 2010
	Interest Rate Swaps			Commodity Instruments		Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	—		$	725	$	725
Long-term derivative assets		4			166		170
Total derivative assets	$	4		$	891	$	895

Current derivative liabilities	$	197		$	521	$	718
Long-term derivative liabilities		174			196		370
Total derivative liabilities	$	371		$	717	$	1,088
Net derivative assets (liabilities)	$	(367	)	$	174	$	(193	)

	September 30, 2011				December 31, 2010
	Fair Value of Derivative Assets		Fair Value of Derivative Liabilities		Fair Value of Derivative Assets		Fair Value of Derivative Liabilities
Derivatives designated as cash flow hedging instruments:
Interest rate swaps	$	9	$	140	$	2	$	143
Commodity instruments		98		18		161		52
Total derivatives designated as cash flow hedging instruments	$	107	$	158	$	163	$	195

Derivatives not designated as hedging instruments:
Interest rate swaps	$	—	$	221	$	2	$	228
Commodity instruments		717		703		730		665
Total derivatives not designated as hedging instruments	$	717	$	924	$	732	$	893
Total derivatives	$	824	$	1,082	$	895	$	1,088

Derivatives Included on Our Consolidated Condensed Statements of Operations

Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our net income.

The following tables detail the components of our total mark-to-market activity for both the net realized gain (loss) and the net unrealized gain (loss) recognized from our derivative instruments not designated as hedging instruments and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Realized gain (loss)
Interest rate swaps	$	(44	)	$	(14	)	$	(150	)	$	(26	)
Commodity derivative instruments		65			41			117			93
Total realized gain (loss)	$	21		$	27		$	(33	)	$	67

Unrealized gain (loss)(1)
Interest rate swaps	$	43		$	(96	)	$	5		$	(115	)
Commodity derivative instruments		(8	)		131			(47	)		212
Total unrealized gain (loss)	$	35		$	35		$	(42	)	$	97
Total mark-to-market activity	$	56		$	62		$	(75	)	$	164

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(1)	Changes in unrealized gain (loss) include de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into income, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Realized and unrealized gain (loss)
Power contracts included in operating revenues	$	18		$	22		$	9		$	34
Natural gas contracts included in fuel and purchased energy expense		39			150			61			271
Interest rate swaps included in interest expense		2			(26	)		4			(54	)
Gain (loss) on interest rate derivatives, net		(3	)		(84	)		(149	)		(87	)
Total mark-to-market activity	$	56		$	62		$	(75	)	$	164

Derivatives Included in Our OCI and AOCI

The following tables detail the effect of our net derivative instruments that qualify for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions):

	Three Months Ended September 30,
	Gain (Loss) Recognized in OCI (Effective Portion)					Gain (Loss) Reclassified from AOCI Into Income (Effective Portion)(2)						Gain (Loss) Reclassified from AOCI Into Income (Ineffective Portion)
	2011			2010		2011			2010			2011			2010
Interest rate swaps	$	(103	)	$	45	$	(7	)(3)	$	(50	)	$	(1	)	$	—
Commodity derivative instruments		9			8		27	(1)		62			(1	)		(1	)
Total	$	(94	)	$	53	$	20		$	12		$	(2	)	$	(1	)

	Nine Months Ended September 30,
	Gain (Loss) Recognized in OCI (Effective Portion)					Gain (Loss) Reclassified from AOCI Into Income (Effective Portion)(2)						Gain (Loss) Reclassified from AOCI Into Income (Ineffective Portion)
	2011			2010		2011			2010			2011			2010
Interest rate swaps	$	(9	)	$	18	$	(130	)(4)	$	(172	)	$	(2	)	$	—
Commodity derivative instruments		(27	)		87		106	(1)		162			—			—
Total	$	(36	)	$	105	$	(24	)	$	(10	)	$	(2	)	$	—

_________

(1)	Included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations.

(2)	Cumulative cash flow hedge losses remaining in AOCI were $140 million and $122 million at September 30, 2011 and December 31, 2010, respectively.

(3)	Reclassification of losses from OCI to earnings for the three months ended September 30, 2011, consisted of $7 million in losses from the reclassification of interest rate contracts due to settlement.

(4)

Reclassification of losses from OCI to earnings for the nine months ended September 30, 2011 consisted of $24 million in losses from the reclassification of interest rate contracts due to settlement, $15 million in losses from terminated interest rate contracts due to the repayment of project debt in June 2011, and $91 million in losses from existing interest rate contracts reclassified from OCI into earnings due to the refinance of variable rate First Lien Credit Facility term loans.

Assuming constant September 30, 2011, power and natural gas prices and interest rates, we estimate that pre-tax net gains of $52 million would be reclassified from AOCI into our net income during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in natural gas and power prices as well as interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI to our net income (positive or negative) will be for the next 12 months.

8. Use of Collateral

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 our Corporate Revolving Facility as collateral under certain of our power and natural gas agreements that qualify as “eligible commodity hedge agreements” under our Corporate Revolving Facility and 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 share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our Corporate Revolving Facility, First Lien Notes, Term Loan and New Term Loan.

The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities at September 30, 2011, and December 31, 2010 (in millions):

	September 30, 2011		December 31, 2010
Margin deposits(1)	$	182	$	162
Natural gas and power prepayments		38		43
Total margin deposits and natural gas and power prepayments with our counterparties(2)	$	220	$	205

Letters of credit issued(3)	$	524	$	588
First priority liens under power and natural gas agreements(4)		—		—
First priority liens under interest rate swap agreements		364		356
Total letters of credit and first priority liens with our counterparties	$	888	$	944

Margin deposits held by us posted by our counterparties(1)(5)	$	5	$	6
Letters of credit posted with us by our counterparties		15		66
Total margin deposits and letters of credit posted with us by our counterparties	$	20	$	72

_________

(1)

Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation.

(2)

At September 30, 2011 and December 31, 2010, $199 million and $183 million were included in margin deposits and other prepaid expense, respectively, and $21 million and $22 million were included in other assets at September 30, 2011 and December 31, 2010, respectively, on our Consolidated Condensed Balance Sheets.

(3)

When we entered into our Corporate Revolving Facility on December 10, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced by letters of credit issued by the Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit issued under our Corporate Revolving Facility used for our commodity procurement and risk management activities at December 31, 2010 include those that were back-stopped of approximately $63 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011.

(4)	At September 30, 2011 and December 31, 2010, the fair value of our commodity derivative instruments collateralized by first priority liens included assets of $75 million and $193 million, respectively; therefore, there was no collateral exposure at September 30, 2011, or December 31, 2010.

(5)	Included in other current liabilities on our Consolidated Condensed Balance Sheets.

Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.

9. Income Taxes

The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest), and our imputed tax rates, as well as intraperiod tax allocations for the periods indicated (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Income tax expense (benefit)	$	20		$	21		$	(45	)(1)	$	38	(2)
Imputed tax rate		10	%		10	%		20	%		61	%
Intraperiod tax allocation expense (benefit)	$	36		$	44		$	20		$	27

_________

(1)	Includes a tax benefit of approximately $76 million related to the consolidation of the CCFC and Calpine groups for federal income tax reporting purposes for the nine months ended September 30, 2011 (as described below).

(2)	Includes approximately $13 million in intraperiod tax expense related to a prior period with an offsetting benefit in OCI.

Intraperiod Tax Allocation — In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of a tax expense (benefit) to continuing operations due to current OCI gains (losses) and income from discontinued operations with a partial offsetting amount recognized in OCI and discontinued operations. The following table details the effects of our intraperiod tax allocations for the three and nine months ended September 30, 2011 and 2010 (in millions).

	Three Months Ended September 30,
	Included in continuing operations				Included in discontinued operations					Included in OCI
	2011		2010		2011		2010			2011			2010
Intraperiod tax allocation expense (benefit)	$	36	$	44	$	—	$	(2	)	$	(34	)	$	(4	)

	Nine Months Ended September 30,
	Included in continuing operations				Included in discontinued operations				Included in OCI
	2011		2010		2011		2010		2011			2010
Intraperiod tax allocations expense (benefit)	$	20	$	27	$	—	$	6	$	(18	)	$	5

Accounting for Income Taxes

Consolidation of CCFC and Calpine Tax Reporting Groups — For federal income tax reporting purposes, our historical tax reporting group was comprised primarily of two separate groups, CCFC and its subsidiaries, which we referred to as the CCFC group, and Calpine Corporation and its subsidiaries other than CCFC, which we referred to as the Calpine group. During the first quarter of 2011, we elected to consolidate our CCFC and Calpine groups for federal income tax reporting purposes and Calpine will file a consolidated federal income tax return for the year ended December 31, 2011 that will include the CCFC group. As a result of the consolidation, the CCFC group deferred tax liabilities will be eligible to offset existing Calpine group NOLs that were reserved by a valuation allowance. Accordingly, we recorded a one-time federal deferred income tax benefit of approximately $76 million during the first quarter of 2011 to reduce our valuation allowance. For the three and nine months ended September 30, 2010, the CCFC group was deconsolidated from the Calpine group for federal income tax reporting purposes.

For the three and nine months ended September 30, 2011 and 2010, we used the effective rate method to determine both the CCFC and Calpine groups’ tax provision, as applicable; however, our income tax rates did not bear a customary relationship to statutory income tax rates primarily as a result of the consolidation of the CCFC and Calpine groups for 2011, the impact of state income taxes, changes in unrecognized tax benefits, the Calpine group valuation allowance and intraperiod tax allocations.

Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses in prior periods, we are unable to assume future profits; however, since our emergence from Chapter 11, we are able to consider available tax planning strategies.

Unrecognized Tax Benefits and Liabilities — At September 30, 2011, we had unrecognized tax benefits of $87 million. If recognized, $40 million of our unrecognized tax benefits could impact the annual effective tax rate and $47 million related to deferred tax assets could be offset against the recorded valuation allowance resulting in no impact to our effective tax rate. We also had accrued interest and penalties of $21 million for income tax matters at September 30, 2011. The amount of unrecognized tax benefits at September 30, 2011 remained comparable to the amount of unrecognized tax benefits at December 31, 2010. We believe it is reasonably possible that a decrease within the range of approximately nil and $14 million in unrecognized tax benefits could occur within the next 12 months primarily related to federal tax liabilities, interest and penalties.

NOL Carryforwards — Under federal income tax law, our NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Section 382 of the Internal Revenue Code. We experienced an ownership change on the Effective Date as a result of the cancellation of our old common stock and the distribution of our new common stock pursuant to our Plan of Reorganization. However, this ownership change and the resulting annual limitations are not expected to result in the expiration of our NOL carryforwards if we are able to generate sufficient future taxable income within the carryforward periods. At December 31, 2010, approximately $2.5 billion of our $7.4 billion total NOLs remain subject to annual section 382 limitations with the remaining $4.9 billion no longer subject to the Section 382 limitation. If a subsequent ownership change were to occur as a result of future transactions in our common stock, accompanied by a significant

reduction in our market value immediately prior to the ownership change, our ability to utilize the NOL carryforwards may be significantly limited.

Under state income tax laws, our NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Section 382 of the Internal Revenue Code. We are analyzing the effect of our change in ownership on the Effective Date for each of our significant states to determine the amount of our NOL limitation. The analysis will also determine our state NOLs expected to expire unutilized as a result of the cessation of business operations and changes in apportionment as of the Effective Date. Although our analysis is not complete, we believe that the statutory limitations on the use of some of our pre-emergence state NOLs will cause them to expire unutilized. We believe our analysis could result in a reduction of available state NOLs, which had a full valuation allowance at September 30, 2011 and December 31, 2010. Upon completion of the analysis, we will reduce our deferred tax asset for state NOLs that we are unable to utilize and make an equal reduction in our valuation allowance. The result is not expected to have an effect on our income tax expense in 2011.

We have certain intercompany accounts payable/receivable balances that we will be eliminating as part of the final steps of our emergence from bankruptcy. We are analyzing the federal and state income tax effects of eliminating these balances. However, the elimination is not expected to have an effect on our income tax expense in 2011.

The State of California enacted legislation in 2010 suspending the ability of taxpayers to use NOLs for tax years 2010 and 2011; however, they have extended the 20 year carryforward period to account for the suspension period.

As a result of the settlement with holders of the CalGen Third Lien Debt and the final distribution to the holders of allowed unsecured claims in accordance with our Plan of Reorganization, Calpine will recognize approximately $51 million in cancellation of debt income related to this distribution.

To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our amended and restated certificate of incorporation permits our Board of Directors to meet to determine whether to impose certain transfer restrictions on our common stock in the following circumstances: if, prior to February 1, 2013, our Market Capitalization declines by at least 35% from our Emergence Date Market Capitalization of approximately $8.6 billion (in each case, as defined in and calculated pursuant to our amended and restated certificate of incorporation) and at least 25 percentage points of shift in ownership has occurred with respect to our equity for purposes of Section 382 of the Internal Revenue Code. We believe as of the filing of this Report, an ownership change of 25 percentage points has occurred; however, we have not experienced declines in our stock price of more than 35% from our Emergence Date Market Capitalization. Accordingly, the transfer restrictions have not been put in place by our Board of Directors; however, if both of the foregoing events were to occur together and our Board of Directors was to elect to impose them, they could become operative in the future. There can be no assurance that the circumstances will not be met in the future, or in the event that they are met, that our Board of Directors would choose to impose these restrictions or that, if imposed, such restrictions would prevent an ownership change from occurring.

Should our Board of Directors elect to impose these restrictions, it will have the authority and discretion to determine and establish the definitive terms of the transfer restrictions, provided that the transfer restrictions apply to purchases by owners of 5% or more of our common stock, including any owners who would become owners of 5% or more of our common stock via such purchase. The transfer restrictions will not apply to the disposition of shares provided they are not purchased by a 5% or more owner.

Income Tax Audits —We remain subject to various audits and reviews by taxing authorities; however, we do not expect these will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to U.S. Internal Revenue Service examination regardless of when the NOLs occurred. Due to significant NOLs, any adjustment of state returns or federal returns from 2007 and forward would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes.

10. Earnings (Loss) per Share

Pursuant to our Plan of Reorganization, all shares of our common stock outstanding prior to the Effective Date were canceled, and the issuance of 485 million new shares of reorganized Calpine Corporation common stock was authorized to resolve allowed unsecured claims. A portion of the 485 million authorized shares was immediately distributed, and the remainder was reserved for distribution to holders of certain disputed claims that, although allowed as of the Effective Date, were unresolved. In June 2011, we settled the largest remaining claim outstanding and began the process of distributing the balance of the reserved shares, which are now fully distributed, pursuant to our Plan of Reorganization. Accordingly, although the reserved shares were not issued and outstanding for the balance of the periods presented, all conditions of distribution had been met for these reserved shares as of the Effective Date, and such shares are considered issued and are included in our calculation of weighted average shares outstanding. We also include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding.

As we incurred a net loss for the nine months ended September 30, 2011, diluted loss per share for this period is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive.

Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the three and nine months ended September 30, 2011 and 2010, are:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(shares in thousands)
Diluted weighted average shares calculation:
Weighted average shares outstanding (basic)		486,420		486,088		486,363		486,023
Share-based awards		2,642		1,355		—		1,176
Weighted average shares outstanding (diluted)		489,062		487,443		486,363		487,199

We excluded the following potentially dilutive securities from our calculation of weighted average shares outstanding from diluted earnings per common share for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(shares in thousands)
Share-based awards		12,696		14,625		15,202		14,193

11. Stock-Based Compensation

The Calpine Equity Incentive Plans provide for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. The equity awards may include incentive or non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance compensation awards and other share-based awards. The equity awards granted under the Calpine Equity Incentive Plans include both graded and cliff vesting options which vest over periods between one and five years, contain contractual terms between approximately five and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. At September 30, 2011, there were 567,000 and 27,533,000 shares of our common stock authorized for issuance to participants under the Director Plan and the Equity Plan, respectively.

We use the Black-Scholes option-pricing model or the Monte Carlo simulation model, as appropriate, to estimate the fair value of our employee stock options on the grant date, which takes into account the exercise price and expected life of the stock option, the current price of the underlying stock and its expected volatility, expected dividends on the stock, and the risk-free interest rate for the expected term of the stock option as of the grant date. For our restricted stock and restricted stock units, we use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Stock-based compensation expense is recognized over the period in which the related employee services are rendered. The service period is generally presumed to begin on the grant date and end when the equity award is fully vested. We use the graded vesting attribution method to recognize fair value of the equity award over the service period. For example, the graded vesting attribution method views one three-year option grant with annual graded vesting as three separate sub-grants, each representing 33 1/3% of the total number of stock options granted. The first sub-grant vests over one year, the second sub-grant vests over two years and the third sub-grant vests over three years. A three-year option grant with cliff vesting is viewed as one grant vesting over three years.

Stock-based compensation expense recognized was $6 million for both the three months ended September 30, 2011 and 2010, and $18 million for both the nine months ended September 30, 2011 and 2010. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the three and nine months ended September 30, 2011 and 2010. At September 30, 2011, there was unrecognized compensation cost of $14 million related to options, $19 million related to restricted stock and $1 million related to restricted stock units, which is expected to be recognized over a weighted average period of 1.6 years for options, 1.5 years for restricted stock and 0.6 years for restricted stock units. We issue new shares from our reserves set aside for the Calpine Equity Incentive Plans and employment inducement options when stock options are exercised and for other share-based awards.

A summary of all of our non-qualified stock option activity for the nine months ended September 30, 2011, is as follows:

	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Term (in years)		Aggregate Intrinsic Value (in millions)
Outstanding - December 31, 2010		17,164,890	$	17.44		5.6	$	8
Granted		953,467	$	14.27
Exercised		7,554	$	11.66
Forfeited		179,809	$	13.21
Expired		211,385	$	17.58
Outstanding - September 30, 2011		17,719,609	$	17.31		5.1	$	12
Exercisable - September 30, 2011		8,287,446	$	19.54		4.8	$	1
Vested and expected to vest - September 30, 2011		17,375,455	$	17.40		5.0	$	12

The total intrinsic value and the cash proceeds received from our employee stock options exercised were not significant for the nine months ended September 30, 2011 and 2010.

The fair value of options granted during the nine months ended September 30, 2011 and 2010, was determined on the grant date using the Black-Scholes pricing model or the Monte Carlo simulation model, as appropriate. Certain assumptions were used in order to estimate fair value for options as noted in the following table.

	2011			2010
Expected term (in years)(1)		6.5			4.0 — 6.5
Risk-free interest rate(2)		1.7 — 3.2	%		1.3 — 3.3	%
Expected volatility(3)		31.2 — 44.9	%		34.1 — 37.6	%
Dividend yield(4)		—			—
Weighted average grant-date fair value (per option)	$	5.49		$	1.80

_________

(1)	Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data to provide a reasonable basis to estimate the expected term.

(2)	Zero Coupon U.S. Treasury rate or equivalent based on expected term.

(3)	Volatility calculated using the implied volatility of our exchange traded stock options.

(4)	We have never paid cash dividends on our common stock, and it is not anticipated that any cash dividends will be paid on our common stock in the near future.

No restricted stock or restricted stock units have been granted other than under the Calpine Equity Incentive Plans. A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the nine months ended September 30, 2011, is as follows:

	Number of Restricted Stock Awards		Weighted Average Grant-Date Fair Value
Nonvested - December 31, 2010		2,683,117	$	11.16
Granted		1,636,026	$	14.37
Forfeited		238,200	$	12.24
Vested		473,600	$	14.51
Nonvested - September 30, 2011		3,607,343	$	12.09

The total fair value of our restricted stock and restricted stock units that vested during the nine months ended September 30, 2011 and 2010, was $7 million and $4 million, respectively.

12. Commitments and Contingencies

Litigation

We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect to our financial position, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect to our financial position, results of operations or cash flows. Further, following the Effective Date, pending actions to enforce or otherwise effect repayment of liabilities preceding December 20, 2005, 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.

Pit River Tribe, et al. v. Bureau of Land Management, et al. — On June 17, 2002, the Pit River Tribe filed suit against the BLM and other federal agencies in the U.S. District Court for the Eastern District of California seeking to enjoin further exploration, construction and development of the Calpine Four-Mile Hill Project in the Glass Mountain and Medicine Lake geothermal areas. The complaint challenged the validity of the decisions of the BLM and the U.S. Forest Service to permit the development of the proposed project under two geothermal mineral leases previously issued by the BLM. The lawsuit also sought to invalidate the leases. Only declaratory and equitable relief was sought.

On November 5, 2006, the U.S. Court of Appeals for the Ninth Circuit 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 and, therefore, held that the lease extensions were invalid. As reported last quarter, on November 4, 2010, the United States District Court for the Eastern District of California entered an order remanding the matter to federal agencies to implement the Court’s order. We consider this matter closed and anticipate it will take the federal agencies at least one year to implement the Court’s order to conduct additional analysis.

In addition, in May 2004, the Pit River Tribe and other interested parties filed two separate suits in the District Court seeking to enjoin exploration, construction, and development of the Telephone Flat leases and proposed project at Glass Mountain. These two cases have remained mostly inactive pending the outcome of the above described Pit River Tribe case. Now that the above Pit River Tribe case has been resolved, we anticipate the Pit River Tribe and other interested parties may seek to reactivate the two additional suits, and we are in communication with the U.S. Department of Justice regarding how to proceed.

Environmental Matters

We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the normal operation of our power plants. We do not, however, have environmental violations or other matters that would have a material impact on our financial condition, results of operations or cash flows or that would significantly change our operations. A summary of our larger environmental matters are as follows:

Environmental Remediation of Certain Assets Acquired from Conectiv — As part of the Conectiv Acquisition on July 1, 2010, we assumed environmental remediation liabilities related to certain of the assets located in New Jersey that are subject to the ISRA. We have accrued or paid $10 million related to these liabilities at September 30, 2011. Pursuant to the Conectiv Purchase Agreement, PHI is responsible for any amounts that exceed $10 million associated with New Jersey environmental remediation liabilities. Our accrual is included in our allocation of the Conectiv Acquisition purchase price. See Note 2 for disclosures related to our Conectiv Acquisition.

Other Contingencies

Distribution of Calpine Common Stock under our Plan of Reorganization — On June 2, 2011, we reached a settlement with holders of the CalGen Third Lien Debt which was funded from the sale of a portion of the shares held in reserve. The bankruptcy court approved the settlement with the CalGen Third Lien Debt claimants on June 16, 2011 and the settlement agreements were fully implemented in August 2011. As of the filing of this Report, all 485 million shares authorized in the confirmed Plan of Reorganization have been distributed to creditors in accordance with the terms of the Plan of Reorganization. The final distributions included approximately 21 million shares which had been held in the reserve for unsecured creditors pending final resolution of claims. The distribution of the remaining shares did not represent the issuance of new or additional shares and had no impact on our results of operations, financial position or cash flows.

13. Segment Information

We assess our business 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. At September 30, 2011, our reportable segments were West (including geothermal), Texas, North (including Canada and the assets purchased in the Conectiv Acquisition) and Southeast. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result.

Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, RGGI compliance and other environmental costs, and cash settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales that are included in mark-to-market activity, but excludes the unrealized portion of our mark-to-market activity and other revenues. Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the period indicated (in millions).

	Three Months Ended September 30, 2011
	West		Texas			North			Southeast		Consolidation and Elimination			Total
Revenues from external customers	$	688	$	843		$	430		$	248	$	—		$	2,209
Intersegment revenues		3		3			(8	)		31		(29	)		—
Total operating revenues	$	691	$	846		$	422		$	279	$	(29	)	$	2,209
Commodity Margin	$	329	$	162		$	259		$	75	$	—		$	825
Add: Mark-to-market commodity activity, net and other(1) (2)		20		(21	)		(11	)		—		(8	)		(20	)
Less:
Plant operating expense		94		50			44			33		(9	)		212
Depreciation and amortization expense		52		34			36			22		(1	)		143
Sales, general and other administrative expense		10		10			7			7		(1	)		33
Other operating expenses(3)		11		(1	)		7			—		2			19
Income from unconsolidated investments in power plants		—		—			(5	)		—		—			(5	)
Income from operations		182		48			159			13		1			403
Interest expense, net of interest income															190
(Gain) loss on interest rate derivatives, net															3
Debt extinguishment costs and other (income) expense, net															—
Income before income taxes and discontinued operations														$	210

	Three Months Ended September 30, 2010
	West		Texas		North			Southeast		Consolidation and Elimination			Total
Revenues from external customers	$	716	$	670	$	468		$	276	$	—		$	2,130
Intersegment revenues		2		6		2			53		(63	)		—
Total operating revenues	$	718	$	676	$	470		$	329	$	(63	)	$	2,130
Commodity Margin	$	338	$	165	$	259		$	90	$	—		$	852
Add: Mark-to-market commodity activity, net and other(1)		42		62		18			18		(6	)		134
Less:
Plant operating expense		86		55		38			28		(8	)		199
Depreciation and amortization expense		52		37		37			28		(2	)		152
Sales, general and other administrative expense		10		13		12			5		1			41
Other operating expenses(3)		14		—		6			—		2			22
Impairment losses		—		—		—			19		—			19
Income from unconsolidated investments in power plants		—		—		(1	)		—		—			(1	)
Income from operations		218		122		185			28		1			554
Interest expense, net of interest income														228
(Gain) loss on interest rate derivatives, net														84
Debt extinguishment costs and other (income) expense, net														23
Income before income taxes and discontinued operations													$	219

	Nine Months Ended September 30, 2011
	West		Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	1,753	$	1,939		$	1,025		$	624		$	—		$	5,341
Intersegment revenues		7		13			5			116			(141	)		—
Total operating revenues	$	1,760	$	1,952		$	1,030		$	740		$	(141	)	$	5,341
Commodity Margin	$	798	$	357		$	578		$	188		$	—		$	1,921
Add: Mark-to-market commodity activity, net and other(1) (2)		36		(54	)		(12	)		(4	)		(23	)		(57	)
Less:
Plant operating expense		297		193			136			107			(22	)		711
Depreciation and amortization expense		140		99			102			67			(3	)		405
Sales, general and other administrative expense		29		33			19			18			—			99
Other operating expenses(3)		30		2			23			3			(1	)		57
Income from unconsolidated investments in power plants		—		—			(12	)		—			—			(12	)
Income (loss) from operations		338		(24	)		298			(11	)		3			604
Interest expense, net of interest income																568
(Gain) loss on interest rate derivatives, net																149
Debt extinguishment costs and other (income) expense, net																108
Loss before income taxes and discontinued operations															$	(221	)

	Nine Months Ended September 30, 2010
	West		Texas		North			Southeast		Consolidation and Elimination			Total
Revenues from external customers	$	1,906	$	1,749	$	725		$	694	$	—		$	5,074
Intersegment revenues		7		16		4			97		(124	)		—
Total operating revenues	$	1,913	$	1,765	$	729		$	791	$	(124	)	$	5,074
Commodity Margin	$	809	$	400	$	390		$	216	$	—		$	1,815
Add: Mark-to-market commodity activity, net and other(1)		60		148		18			31		(20	)		237
Less:
Plant operating expense		264		217		83			87		(21	)		630
Depreciation and amortization expense		155		113		76			84		(5	)		423
Sales, general and other administrative expense		36		29		37			11		—			113
Other operating expenses(3)		43		2		21			2		1			69
Impairment losses		—		—		—			19		—			19
Income from unconsolidated investments in power plants		—		—		(14	)		—		—			(14	)
Income from operations		371		187		205			44		5			812
Interest expense, net of interest income														627
(Gain) loss on interest rate derivatives, net														87
Debt extinguishment costs and other (income) expense, net														36
Income before income taxes and discontinued operations													$	62

_________

(1)	Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, included in operating revenues and fuel and purchased energy expense on our Consolidated Condensed Statements of Operations.

(2)	Includes $11 million and $15 million of lease levelization and $4 million and $5 million of contract amortization for the three and nine months ended September 30, 2011, respectively, related to contracts that became effective in 2011.

(3)	Excludes $3 million and $1 million of RGGI compliance and other environmental costs for the three months ended September 30, 2011 and 2010, respectively, and $7 million and $6 million for the nine months ended September 30, 2011 and 2010, respectively, which are components of Commodity Margin.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Information

This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our accompanying Consolidated Condensed Financial Statements and related notes. See the cautionary statement regarding forward-looking statements on page ix of this Report for a description of important factors that could cause actual results to differ from expected results.

Introduction and Overview

We are the largest independent wholesale power generation company in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. We sell wholesale power, steam, regulatory capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. We purchase natural gas and fuel oil as fuel for our power plants, engage in related natural gas transportation and storage transactions, and we purchase electric transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants. Our goal is to be recognized as the premier independent power company in the U.S. as measured by our customers, regulators, shareholders and communities in which our power plants are located. We seek to achieve sustainable growth through financially disciplined power plant development, construction, acquisition, operation and ownership. We will continue to pursue opportunities to improve our fleet performance and reduce operating costs. In order to manage our various physical assets and contractual obligations, we will continue to execute commodity hedging agreements within the guidelines of our commodity risk policy.

We continue to make significant progress to maintain financially disciplined growth, to enhance shareholder value and to set the foundation for continued growth and success with the following achievements during the nine month ended September 30, 2011:

•

Our York Energy Center, a 565 MW dual fuel, combined-cycle power plant achieved COD on March 2, 2011, and began selling power under a six-year PPA with a third party which commenced on June 1, 2011.

•

Construction of our Russell City Energy Center, which closed on construction financing in June 2011, and upgrades at our Los Esteros Critical Energy Facility, which closed on construction financing in August 2011, continue to move forward with expected completion dates in 2013.

•

We issued our 2023 First Lien Notes, terminated our First Lien Credit Facility and extended our corporate debt maturities. Together, these changes eliminated the more restrictive of our debt covenants, resulting in increased operational, strategic and financial flexibility in managing our capital resources including the flexibility to reinvest more earnings for organic growth, issue and/or buyback shares of our common stock and incur additional debt, if needed, for acquisitions or development projects. Additionally, we achieved attractive yields and a maturity schedule stretching from 2017 to 2023 with no more than $2.0 billion of corporate debt maturing in any given year.

•

We have further continued to reduce our overall cost of debt and simplify our capital structure by refinancing subsidiary level debt with corporate level term loans eliminating the need for subsidiary level reporting and the potential for cash to be temporarily trapped at the subsidiary level. On March 9, 2011, we closed on the $1.3 billion Term Loan and used the net proceeds received, together with operating cash on hand, to fully retire the approximately $1.3 billion NDH Project Debt in accordance with its repayment terms. On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan.

In addition, on August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares of our common stock. Through the filing of this Report, 2,122,922 shares of our outstanding common stock have been repurchased under this program for approximately $29 million at an average price paid of $13.65 per share.

Our portfolio, including partnership interests, includes 92 operating power plants, located throughout 20 states in the U.S. and Canada, with an aggregate generation capacity of 28,134 MW and 584 MW under construction. Our generation capacity includes approximately 725 MW of baseload capacity from our Geysers Assets and 4,542 MW of baseload capacity from our cogeneration power plants, 16,393 MW of intermediate load capacity from our combined-cycle combustion turbines and 6,474 MW of peaking capacity from our simple-cycle combustion turbines and duct-fired capability, which includes approximately 4 MW of capacity from solar, photovoltaic power generation technology located in New Jersey. Our segments have an aggregate generation capacity of 6,898 MW with an additional 584 MW under construction in the West, 7,239 MW in Texas, 7,914 MW in the North and 6,083 MW in the Southeast. Our Geysers Assets, included in our West segment, have generation capacity of approximately 725 MW from 15 operating geothermal power plants, and we have begun expansion efforts to increase our generation capacity at our Geysers Assets.

Legislative and Regulatory Update

We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our power plants. Ongoing state, regional and federal initiatives to implement new environmental and other governmental regulations are expected to have a significant impact on the power generation industry. Such changes could have positive or negative impacts on our existing business. We are actively participating in these debates at the federal, regional and state levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, please see “— Governmental and Regulatory Matters” in Part I, Item 1. of our 2010 Form 10-K.

Cross-State Air Pollution Rule

On July 6, 2011, the EPA finalized rules to control interstate transportation of fine particulate matter (PM-2.5) and ozone. The Cross-State Air Pollution Rule (“CSAPR”) requires substantial emissions reductions of NOx and SO2 from electric generating units in 27 states primarily in the eastern U.S. The rule sets up three distinct cap and trade programs: annual NOx and SO2 trading programs to control fine particles, and a NOx trading program from May through September (the ozone season) to control ozone. Emission reductions are scheduled to take effect starting January 1, 2012 for SO2 and annual NOx reductions and May 1, 2012 for ozone season NOx reductions. Significant additional SO2 emission reductions in Group 1 states will be required in 2014. Compared to 2005, the EPA estimates that by 2014 this rule and other federal rules will lower power plant annual emissions in the CSAPR region by 6.4 million tons per year of SO2 (a 73% reduction) and 1.4 million tons per year of NOx (a 54% reduction). The rule establishes an unlimited intrastate and limited interstate trading program with allowances allocated to sources based on historic heat input but capped at maximum annual emissions from 2003 to 2010. At current capacity factors, Calpine generally will be allocated sufficient allowances; thus, this legislation is not expected to have a material impact on our operations. We expect the overall impact of this rule will be a net positive to Calpine as the significant emission reductions will require coal-fired electric generating units to either purchase allowances, switch to more expensive fuels, install air pollution controls, or reduce or discontinue operations.

A number of power generation companies, states and other groups have filed petitions for review in the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) challenging CSAPR. Several of these petitioners have also filed motions for either full or partial stays of the Rule. Calpine and other power generation companies have been granted intervenor status on behalf of respondent EPA. Calpine and other respondent intervenors have either opposed these stay motions or plan to oppose the motions. All stay motions are still pending and EPA may file further motions in the case. Once the D.C. Circuit determines a briefing schedule, Calpine will have an opportunity to submit a brief, though most likely as part of a group of respondent intervenors.

On October 14, 2011, EPA proposed revisions to CSAPR to address discrepancies in unit-specific modeling assumptions that affect state budgets in Texas, Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York and Wisconsin. In addition, EPA proposed delaying the assurance provisions, which were established to ensure that state’s emissions do not exceed their emissions budgets plus a variability allowance. The proposed two-year delay in the assurance provisions would allow unlimited interstate trading of CSAPR allowances, thereby providing more compliance options for affected sources.

The EPA Toxics Rule

The Clean Air Act regulates a large number of air pollutants that are known to cause or may reasonably be anticipated to cause adverse effects to human health or adverse environmental effects, known as hazardous air pollutants (“HAPs”). On October 22, 2009, the EPA signed a consent decree that was lodged in the U.S. District Court for the District of Columbia by the EPA in settlement of a suit brought by several environmental groups alleging that the EPA failed to promulgate final emissions standards based on maximum achievable control technology for hazardous air pollutants from coal- and oil-fired power plants, pursuant to Section 112(d) of the Clean Air Act, by the statutorily-mandated deadline. On March 16, 2011, the EPA published proposed National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-fired Electric Utility Steam Generating Units (“The Toxics Rule”). We are not directly affected by the rule because it does not apply to natural gas-fired units, peaker units or units that use fuel oil as a backup fuel. The consent decree requires the EPA to promulgate final HAP emission standards by November 2011. We

believe that the proposed emission standards are sufficiently stringent to force coal units without emission controls to retire or to install acid gas, mercury, and particulate matter controls by 2014 or 2015, which could benefit our competitive position. We filed comments in support of The Toxics Rule on August 3, 2011.

On October 7, 2011, the Utility Air Regulatory Group filed a motion asking the U.S. District Court for the District of Columbia to re-open the consent decree and push back the publication of the final rule by one year. On October 21, 2011, Calpine, along with a group of generators and utilities jointly filed a Motion for Leave to File a Brief as Amici Curiae in support of EPA’s opposition to extending The Toxics Rule. Also on October 21, 2011, the parties to the consent decree agreed to delay the publication of the final rule by one month such that the rule shall be final on December 16, 2011.

California AB 32

California’s AB 32 creates a statewide cap on GHG emissions and requires the state to return to 1990 emission levels by 2020. On October 20, 2011, the CARB adopted the final regulation. The regulation will be sent to the Office of Administrative Law (“OAL”) for final approval and is likely to be approved by OAL in time to take effect as scheduled on January 1, 2012. The first compliance year when covered sources, including Calpine, will have to turn in allowances has been moved from 2012 to 2013. Litigation challenging CARB’s implementation of CARB’s AB 32 Scoping Plan for a cap and trade program is currently before the Court of Appeals. As part of finalizing the regulation, CARB rewrote and approved a new environmental analysis for the AB 32 Scoping Plan which was found to be deficient by the lower court. Thus, should the Court of Appeal deny CARB’s appeal, CARB will be able to present the updated alternatives analysis to the Superior Court as satisfying its order. Thus, the current litigation does not appear likely to slow or delay the implementation of CARB’s cap and trade program. However, we cannot predict whether new legal challenges will be filed against the regulation and what the associated impacts of any such litigation would be. A number of parties continue to seek further refinements to improve the regulation. As a result, on October 20, 2011 CARB also adopted Resolution 11-32 outlining the issues it will continue to address including, but not limited to, issues raised by Calpine on the market’s auction purchase and holding limit rules and issues involving long-term contracts executed prior to AB 32. Overall, we support AB 32 and believe we are favorably positioned to comply with these regulations.

Dodd-Frank Act

The anticipated regulations that will arise under the Dodd-Frank Act are being written by various regulatory agencies. While we are closely monitoring this rule writing process, the exact impact of new rules on our business remains uncertain. We will continue to monitor all relevant developments and rule-making initiatives in the implementation of the Dodd-Frank Act, and we expect to successfully implement any new applicable legislative and regulatory requirements. At this time, we cannot predict the impact or possible additional costs to us, if any, related to the implementation of, or compliance with, the potential future requirements under the Dodd-Frank Act.

Clean Water Act and the Water Intake Rule

The federal Clean Water Act establishes rules regulating the discharge of pollutants into waters of the U.S. Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact. On March 28, 2011, the EPA proposed rules (the “Water Intake Rule”) that would allow states to require power plants employing older once-through cooling systems, particularly along biologically productive estuaries and rivers, to undertake major modifications to their cooling water intake structures or even install cooling towers to reduce impingement (where fish and other aquatic life get trapped against the intake screens) and entrainment (where small aquatic life passes through the intake screens and goes through the condenser at high temperatures). While these rules will likely affect our competitors, we do not expect these rules to have a material impact on our operations because we have only two peaking power plants that employ once-through cooling.

California RPS

On April 12, 2011, California’s governor signed into law legislation establishing a new and higher RPS. The new law requires implementation of a 33% RPS by 2020, with intermediate targets between now and 2020. The previous RPS legislation required certain retail power providers to generate or procure 20% of the power they sell to retail customers from renewable resources beginning in 2010. The new standard applies to all load-serving entities, including entities such as large municipal utilities that are not CPUC-jurisdictional. Under the new law, there are limits on different classes of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy at least a fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour. Similarly, the legislation places limits on the use of “firmed and shaped” transactions and tradable renewable energy credits (“TRECs”) — claims to the renewable aspect of the power produced by a renewable resource that can be traded separately from the underlying power. In general, the ability to use “firmed and shaped”

transactions and TRECs becomes more limited over the course of the implementation period. The details of how specific types of transactions will count and load-serving entities’ obligations will be satisfied under the 33% RPS are the subject of ongoing regulatory proceedings at both the CPUC and the California Energy Commission.

QFs and California State Regulation of Power

Cogeneration and certain small power production facilities are eligible to be QFs under PURPA, which provides certain exemptions and other benefits to the QF, including, in some cases, the right to sell power to utilities at the utilities’ avoided cost (“PURPA put”). In California, five of our natural gas-fired power plants are QFs affected by a recently approved CPUC settlement that has the potential to change significant aspects of policy towards these plants. Our geothermal QF power plants at the Geysers Assets sell power under RPS contracts and are not subject to this policy change.

Energy pricing under many of these QF contracts is intended to become “market based” once functioning wholesale markets exist. The California Investor Owned Utilities (“IOUs”) have argued that the launch of CAISO’s MRTU satisfies the conditions necessary to end their mandatory purchase obligation under the PURPA put and that prices from the MRTU markets should provide the basis for energy pricing under existing QF contracts. Moreover, independent of issues related to existing QFs, CARB’s scoping plan to implement AB 32 includes mandates for load serving entities to procure existing and new efficient combined heat and power sales. Stakeholders, including Calpine and other QF generators, the CPUC, and the California IOUs, engaged in lengthy settlement negotiations to resolve issues related to the PURPA put, power pricing for generators under existing QF contracts and prospective combined heat and power procurement mandates. A settlement was reached by most major parties and approved by the CPUC on December 16, 2010. The settlement establishes new power pricing options for QFs under long-term contracts, including the option to shed the QF host and efficiency obligations and become dispatchable, and specifies mechanisms for the California IOUs to procure both existing combined heat and power that is not otherwise under contract and new combined heat and power (“CHP”). The settlement will take effect in late 2011 or early 2012.

PJM Capacity Market

Certain states in the PJM market region have taken actions that could impact the PJM capacity market. In New Jersey, legislation enacted earlier this year required the New Jersey Board of Public Utilities (“BPU”) to solicit interest in 2,000 MW of new generation. Market participants and others were concerned that either or both of these efforts could result in the award of long term contracts that could impact the clearing prices of future PJM capacity auctions. The BPU subsequently held a Request for Proposal (“RFP”) and awarded contracts for approximately 2,000 MW to three prospective project developers. The BPU has also initiated a proceeding and held hearings to investigate whether there is a need for New Jersey to pursue additional generation capacity beyond the 2,000 MW already contracted for pursuant to the legislation. That proceeding continues. Meanwhile, in response to a filing by PJM that was intended in part to address the negative implications from these state actions by revising the Minimum Offer Price Rule (“MOPR”) in its tariff, FERC issued an order on April 12, 2011 approving PJM’s MOPR tariff changes. Also, on February 9, 2011, we joined a group of generators and utilities in filing a complaint in federal district court challenging the constitutionality of the New Jersey legislation. The court proceeding is continuing.

On September 29, 2011, the Maryland Public Service Commission (“MPSC”) issued a “Notice of Approval of Request for Proposals for New Generation to be Issued by Maryland Electric Distribution Companies.” The Notice required the state’s IOUs to issue RFPs by October 7, 2011, with responses due by November 11, 2011. The MPSC will hold a hearing on January 31, 2012 to determine whether new capacity is required. The Notice specifies that proposals must be for new natural gas-fired capacity capable of delivery into the PJM Southwest Mid-Atlantic Area Council delivery area.

Texas Disgorgement Bill

On June 17, 2011, Texas Governor Rick Perry signed House Bill 2133 into law effective September 1, 2011. Under this law, for a violation of market power abuse under the Utilities Code, the PUCT is now required to order disgorgement of all revenue in excess of revenue that would have occurred absent a violation. Disgorgement is in addition to any penalty the PUCT may assess. For any other violation of statutes, rules or protocols relating to wholesale electric markets, the PUCT has the discretion to order disgorgement of excess revenue resulting from a violation. The PUCT and an alleged violator can develop and enter into a voluntary mitigation plan relating to a violation. Adherence to the plan would constitute an absolute defense against an alleged violation with respect to activities covered by the plan. This law applies only to violations occurring on or after September 1, 2011.

Greenfield LP and Ontario Power Authority

Effective December 2009, the Independent Electricity System Operator (“IESO”) of Ontario implemented several rule changes that impacted Greenfield LP’s financial performance in 2010 and will impact Greenfield LP in future years. Greenfield LP’s power supply contract with the Ontario Power Authority provides it with a right to recover for financial consequences of market rule changes that negatively impact Greenfield LP; however, after extended negotiations to modify the agreement to address the financial impacts, Greenfield LP has initiated arbitration as provided for under the power supply contract to preserve its recovery rights. We continue to pursue arbitration of this matter and cannot predict at this time the outcome of arbitration, or the potential impact, if any, to our 50% partnership interest in Greenfield LP.

FERC Credit Reforms in Organized Wholesale Electric Markets

In October 2010, FERC issued a final rule regarding credit reforms in the organized wholesale electric markets. The reforms include shortening the settlement timeframes, restricting or eliminating the use of unsecured credit, clarifying the ability to offset market obligations, establishing minimum criteria for market participation, and establishing and clarifying when an Independent System Operator (“ISO”) or Regional Transmission Organization (“RTO”) may require additional collateral from market participants for a material adverse change. ISO and RTO compliance filings were submitted in June 2011. Many of the credit rules took effect on October 1, 2011, with additional requirements being developed by the ISOs and RTOs. The credit rules and procedures for each ISO and RTO differ in requirements and compliance obligations. We continue to work to enhance uniformity and compliance obligations among the ISOs and RTOs, but, we do not believe these changes to FERC’s credit rules will have a material impact on our business.

Court Rulings

GHG Emissions

In the absence of federal climate change legislation, litigation raising claims relating to GHG emissions is working its way through the federal courts. Recent federal court decisions are divided as to whether large emitters of GHGs may be sued under common law theories of nuisance and negligence.

On September 21, 2009, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a ruling in State of Connecticut, et al. v. American Electric Power Company Inc., et al., reversing a lower court's dismissal of two public nuisance claims filed by various states, municipalities and private entities against operators of coal-fired power plants. Plaintiffs argued that the power plant defendants contribute to global warming by emitting 650 million tons of CO2 per year and these emissions are causing and will continue to cause serious harm affecting human health and natural resources. The lower court held that plaintiffs' claims presented a non-legal political question and dismissed the complaints. The Second Circuit vacated the lower court's decision, ruling in favor of the plaintiffs. The Second Circuit’s decision was appealed to the U.S. Supreme Court. On June 20, 2011, the Supreme Court issued a decision rejecting the plaintiffs’ federal common law claim. The Court found that even if a federal common law claim could be made by plaintiffs, the CAA essentially “displaced” that claim. The case was remanded to the Second Circuit for further consideration of other issues in the case, including whether the plaintiffs may raise their claims under state common law or whether those claims are also preempted by federal law. The Second Circuit remanded to the district court for additional fact-finding. We cannot predict the outcome of this case on remand or what impact the precedent of this case could have on our business.

Station Power Ruling

On August 30, 2010, FERC issued an order on remand (“remand order”) regarding its station power policies in response to a ruling by the D.C. Circuit. The D.C. Circuit’s ruling vacated and remanded FERC’s prior orders on CAISO’s station power procedures, finding that FERC had not adequately justified its decision that no retail sale occurs when a generator self-supplies station power over a monthly netting period. In its remand order, FERC reversed its prior orders relating to a generator’s self-supply of station power in the markets administered by CAISO, concluding that FERC’s jurisdiction covers only the transmission of station power and the states have exclusive jurisdiction to determine when the use of station power results in a retail sale. The remand order could impact FERC’s station power policies in all of the organized markets throughout the nation. Calpine, along with several other parties sought rehearing of FERC’s decision. On February 28, 2011, FERC denied all requests for rehearing. Calpine and several other generators filed an appeal of FERC’s decision. If left unchanged, FERC’s remand order could result in our power plants paying more for station power service. However, we do not believe such increases will be material to us.

Results of Operations for the Three Months Ended September 30, 2011 and 2010

Below are the results of operations for the three months ended September 30, 2011, as compared to the same period in 2010 (in millions, except for percentages and operating performance metrics). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.

	2011			2010			$ Change			% Change
Operating revenues:
Commodity revenue	$	2,200		$	2,113		$	87			4
Mark-to-market activity(1)		21			14			7			50
Other(2)		(12	)		3			(15	)		#
Operating revenues		2,209			2,130			79			4
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		1,372			1,260			(112	)		(9	)
Mark-to-market activity(1)		29			(117	)		(146	)		#
Fuel and purchased energy expense		1,401			1,143			(258	)		(23	)

Plant operating expense		212			199			(13	)		(7	)
Depreciation and amortization expense		143			152			9			6
Sales, general and other administrative expense		33			41			8			20
Other operating expenses(3)		22			23			1			4
Total operating expenses		1,811			1,558			(253	)		(16	)
Impairment losses		—			19			19			#
Income from unconsolidated investments in power plants		(5	)		(1	)		4			#
Income from operations		403			554			(151	)		(27	)
Interest expense		192			230			38			17
(Gain) loss on interest rate derivatives, net		3			84			81			96
Interest (income)		(2	)		(2	)		—			—
Debt extinguishment costs		(4	)		20			24			#
Other (income) expense, net		4			3			(1	)		(33	)
Income before income taxes and discontinued operations		210			219			(9	)		(4	)
Income tax expense		20			21			1			5
Income before discontinued operations		190			198			(8	)		(4	)
Discontinued operations, net of tax expense		—			19			(19	)		#
Net income		190			217			(27	)		(12	)
Net income attributable to the noncontrolling interest		—			—			—			—
Net income attributable to Calpine	$	190		$	217		$	(27	)		(12	)

	2011			2010			Change			% Change
Operating Performance Metrics:
MWh generated (in thousands)(4)		28,400			28,208			192			1
Average availability		95.9	%		95.9	%		—			—
Average total MW in operation(4)		27,354			26,958			396			1
Average capacity factor, excluding peakers		53.8	%		54.3	%		(0.5	)%		(1	)
Steam Adjusted Heat Rate		7,464			7,415			(49	)		(1	)

_________

#	Variance of 100% or greater.

(1)	Amount represents the unrealized portion of our mark-to-market activity.

(2)	Includes $11 million of lease levelization and $4 million of contract amortization for the three months ended September 30, 2011, related to contracts that became effective in 2011.

(3)	Includes $3 million and $1 million of RGGI compliance and other environmental costs for the three months ended September 30, 2011 and 2010, respectively, which are components of Commodity Margin.

(4)

Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby, Freeport Energy Center and 21.5% of Hidalgo Energy Center for both the three months ended September 30, 2011 and 2010. Excludes 25% of Freestone Energy Center for the three months ended September 30, 2011.

We evaluate our commodity revenue and commodity expense on a collective basis because the price of power and natural gas move together as the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our commodity revenue and commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion under “Commodity Margin and Adjusted EBITDA.”

Commodity revenue, net of commodity expense, decreased $25 million for the three months ended September 30, 2011, compared to the same period in 2010, primarily due to:

•

weaker price conditions in the West resulting from an increase in hydroelectric generation in California;

•

lower Commodity Margin in Texas due to the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010 which was largely offset by significantly higher power prices driven by extreme heat and drought conditions which increased Spark Spreads during the third quarter of 2011 on our relatively small open position; and

•

lower Commodity Margin in the Southeast largely due to the expiration of certain hedge contracts which benefited the third quarter of 2010 and the negative impact of an unscheduled outage at one of our power plants in the third quarter of 2011.

Our average total MW in operation increased by 396 MW, or 1%, primarily due to our York Energy Center which achieved COD in March 2011, partially offset by the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010. Generation increased 1% as a result of strong market pricing in Texas and our York Energy Center partially offset by a decrease in generation due to weaker price conditions in the West and lower generation attributable to the sale of a 25% undivided interest in the assets of our Freestone power plant.

Unrealized mark-to-market earnings from hedging our future generation and fuel needs had an unfavorable variance of $139 million primarily driven by the impact of a larger decrease in forward natural gas prices during 2010, compared to the decrease in forward natural gas prices during 2011, resulting in $117 million of unrealized gains on our short natural gas hedge position during the three months ended September 30, 2010, that did not qualify for hedge accounting or where we elected not to apply hedge accounting treatment.

Other revenue decreased for the three months ended September 30, 2011, compared to the same period in 2010, due primarily to $11 million in lease levelization and $4 million in contract amortization recorded during the three months ended September 30, 2011, related to contracts that became effective in 2011.

Plant operating expense increased by $13 million for the three months ended September 30, 2011, compared to the same period in 2010. Our normal, recurring plant operating expense decreased $18 million for the three months ended September 30, 2011, compared to the same period in 2010. The increase in plant operating expense was primarily due to an increase of $20 million in major maintenance expense resulting from our plant outage schedule, a $6 million increase in costs from scrap parts related to outages, a $2 million increase in costs related to our voluntary departure incentive program which was initiated in the second quarter of 2011 and a $3 million increase related to our York Energy Center which achieved COD in March 2011.

Depreciation and amortization expense decreased for the three months ended September 30, 2011, compared to the same period in 2010, primarily resulting from a decrease of $14 million due to assets being fully depreciated for several of our plants. The decrease was partially offset by an increase of $2 million related to our York Energy Center, which achieved COD in March 2011.

Sales, general and other administrative expense decreased for the three months ended September 30, 2011, compared to the same period in 2010, primarily resulting from $5 million in Conectiv acquisition-related costs incurred during the third quarter of 2010.

Impairment losses decreased for the three months ended September 30, 2011, compared to the same period in 2010, primarily due to a $19 million impairment charge incurred during the third quarter of 2010 related to a development project originated prior to our Chapter 11 bankruptcy proceedings. During the third quarter of 2010, we learned the project would not receive a PPA that would support its continued development and made the determination that continued development was unlikely.

Income from unconsolidated investments in power plants had a favorable variance for the three months ended September 30, 2011, compared to the same period in 2010, primarily due to a $4 million period over period increase in operating income for Greenfield LP related to mechanical issues which impacted plant performance during the third quarter of 2010.

Interest expense decreased for the three months ended September 30, 2011, compared to the same period in 2010, primarily due to a $27 million favorable change in unrealized mark-to-market activity related to the interest rate swaps hedging our variable rate debt that do not qualify for hedge accounting and an $11 million decrease in interest expense related to NDH Project Debt which was repaid in March 2011 with proceeds from the Term Loan. Also, contributing to the favorable period over period change in interest expense was a decrease in our annualized effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and unrealized gains (losses) on interest rate swaps, which decreased to 7.6% for the three months ended September 30, 2011, from 7.7% for the same period in 2010.

(Gain) loss on interest rate derivatives, net had a favorable change of $81 million for the three months ended September 30, 2011, compared to the same period in 2010, primarily resulting from a favorable period over period change due to the reclassification of $70 million in historical unrealized losses during the third quarter of 2010 previously deferred in AOCI related to interest rate swaps formerly hedging our First Lien Credit Facility term loans. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further discussion of our interest rate swaps formerly hedging our First Lien Credit Facility term loans.

Debt extinguishment costs decreased for the three months ended September 30, 2011, compared to the same period in 2010, primarily due to $20 million in debt extinguishment costs recorded during the third quarter of 2010 associated with the retirement of term loans under the First Lien Credit Facility in July 2010 in connection with the issuance of the 2020 First Lien Notes.

During the three months ended September 30, 2011, we recorded an income tax expense of $20 million compared to income tax expense of $21 million for the three months ended September 30, 2010. The period over period change primarily resulted from a decrease in income tax expense of $8 million related to the application of intraperiod tax allocation and a $2 million decrease in income taxes related to various state and foreign jurisdiction income taxes. The decrease was partially offset by an increase of $8 million in federal income taxes for the three months ended September 30, 2011, compared to the same period in 2010.

Income from discontinued operations for the three months ended September 30, 2010, consists of the results of operations for Blue Spruce and Rocky Mountain which were sold in December 2010. See Note 2 of the Notes to Consolidated Condensed Financial Statements for further discussion of our discontinued operations.

Results of Operations for the Nine Months Ended September 30, 2011 and 2010

Below are the results of operations for the nine months ended September 30, 2011, as compared to the same period in 2010 (in millions, except for percentages and operating performance metrics). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.

	2011			2010			$ Change			% Change
Operating revenues
Commodity revenue	$	5,295		$	5,042		$	253			5
Mark-to-market activity(1)		56			7			49			#
Other(2)		(10	)		25			(35	)		#
Operating revenues		5,341			5,074			267			5
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		3,367			3,221			(146	)		(5	)
Mark-to-market activity(1)		103			(205	)		(308	)		#
Fuel and purchased energy expense		3,470			3,016			(454	)		(15	)

Plant operating expense		711			630			(81	)		(13	)
Depreciation and amortization expense		405			423			18			4
Sales, general and other administrative expense		99			113			14			12
Other operating expenses(3)		64			75			11			15
Total operating expenses		4,749			4,257			(492	)		(12	)
Impairment losses		—			19			19			#
Income from unconsolidated investments in power plants		(12	)		(14	)		(2	)		(14	)
Income from operations		604			812			(208	)		(26	)
Interest expense		575			635			60			9
(Gain) loss on interest rate derivatives, net		149			87			(62	)		(71	)
Interest (income)		(7	)		(8	)		(1	)		(13	)
Debt extinguishment costs		94			27			(67	)		#
Other (income) expense, net		14			9			(5	)		(56	)
Income (loss) before income taxes and discontinued operations		(221	)		62			(283	)		#
Income tax expense (benefit)		(45	)		38			83			#
Income (loss) before discontinued operations		(176	)		24			(200	)		#
Discontinued operations, net of tax expense		—			31			(31	)		#
Net income (loss)		(176	)		55			(231	)		#
Net income attributable to the noncontrolling interest		(1	)		—			(1	)		#
Net income (loss) attributable to Calpine	$	(177	)	$	55		$	(232	)		#

	2011			2010			Change			% Change
Operating Performance Metrics:
MWh generated (in thousands)(4)		65,921			67,813			(1,892	)		(3	)
Average availability		89.8	%		91.5	%		(1.7	)%		(2	)
Average total MW in operation(4)		27,191			24,364			2,827			12
Average capacity factor, excluding peakers		42.9	%		47.9	%		(5.0	)%		(10	)
Steam Adjusted Heat Rate		7,434			7,328			(106	)		(1	)

_________

#	Variance of 100% or greater.

(1)	Amount represents the unrealized portion of our mark-to-market activity.

(2)	Includes $15 million of lease levelization and $5 million of contract amortization for the nine months ended September 30, 2011, related to contracts that became effective in 2011.

(3)	Includes $7 million and $6 million of RGGI compliance and other environmental costs for the nine months ended September 30, 2011 and 2010, respectively, which are components of Commodity Margin.

(4)

Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby, Freeport Energy Center and 21.5% of Hidalgo Energy Center for both the nine months ended September 30, 2011 and 2010. Excludes 25% of Freestone Energy Center for the nine months ended September 30, 2011.

Commodity revenue, net of commodity expense, increased $107 million for the nine months ended September 30, 2011, compared to the same period in 2010, primarily due to:

•

an increase in the North primarily due to the Conectiv Acquisition which closed on July 1, 2010 and our York Energy Center which achieved COD in March 2011; partially offset by

•

the negative impact in Texas of unplanned outages at some of our power plants caused by an extreme cold weather event in early February 2011, that required us to purchase physical replacement power at prices substantially above our hedged price; and

•

a decrease in the Southeast primarily due to the expiration of certain hedge contracts which benefited the nine months ended September 30, 2010.

Our average total MW in operation increased by 2,827 MW, or 12%, primarily due to the Conectiv Acquisition which closed on July 1, 2010 and our York Energy Center which achieved COD on March 2011 partially offset by the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010. Generation decreased 3% due primarily to weaker price conditions in the West and lower generation in Texas primarily caused by the sale of a 25% undivided interest in the assets of our Freestone power plant. The decrease in generation was partially offset by higher generation in the North due to the Conectiv Acquisition and our York Energy Center. Our average capacity factor, excluding peakers decreased 10% largely due to the decrease in generation in the West and Texas resulting from the factors previously discussed.

Unrealized mark-to-market earnings from hedging our future generation and fuel needs had an unfavorable variance of $259 million primarily driven by the impact of a larger decrease in forward natural gas prices during the nine months ended September 30, 2010, compared to the decrease in forward natural gas prices during the nine months ended September 30, 2011, resulting in a $308 million unfavorable period over period change on our short natural gas hedge position that did not qualify for hedge accounting or where we elected not to apply hedge accounting treatment.

Other revenue decreased for the nine months ended September 30, 2011, compared to the same period in 2010, due primarily to $15 million in lease levelization and $5 million in contract amortization recorded during the nine months ended September 30, 2011, related to contracts that became effective during 2011. In addition, there was a decrease in other revenue for the nine months ended September 30, 2011, compared to the same period in 2010, due to higher revenue recognized in the second quarter of 2010 which included a $15 million adjustment related to prior periods on a major maintenance contract.

Plant operating expense increased by $81 million for the nine months ended September 30, 2011, compared to the same period in 2010. Our normal, recurring plant operating expense decreased $28 million for the nine months ended September 30, 2011, compared to the same period in 2010. The increase in plant operating expense was primarily due to an increase of $38 million related to our Mid-Atlantic assets acquired in the Conectiv Acquisition, an increase of $50 million in major maintenance expense resulting from our plant outage schedule, a $10 million increase in costs from scrap parts related to outages, a $5 million increase related to our York Energy Center which achieved COD in March 2011, a $3 million increase in costs related to our voluntary departure incentive program which was initiated in the second quarter of 2011 and a $3 million increase in stock-based compensation expense.

Depreciation and amortization expense decreased for the nine months ended September 30, 2011, compared to the same period in 2010, primarily resulting from a decrease of $29 million due to assets being fully depreciated for several of our plants, a decrease of $17 million related to a revision in the expected settlement dates of the asset retirement obligations of our power plants and a decrease of $4 million due to the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010. The decrease was partially offset by an increase of $25 million related to our Mid-Atlantic assets acquired in the Conectiv Acquisition and an increase of $4 million related to York Energy Center which achieved COD in March 2011.

Sales, general and other administrative expense decreased for the nine months ended September 30, 2011, compared to the same period in 2010, primarily resulting from $24 million in Conectiv acquisition-related costs incurred during the nine months ended September 30, 2010. The decrease was partially offset by a credit of $10 million due to the reversal of a bad debt allowance in the first quarter of 2010 as a result of Lyondell Chemical Co.’s emergence from Chapter 11 bankruptcy and the bankruptcy court’s acceptance of our claim in the first quarter of 2010.

Other operating expenses decreased for the nine months ended September 30, 2011, compared to the same period in 2010, primarily resulting from a decrease of $8 million in operating lease expense due to our purchase from a third party of the entity that held the lease for our South Point power plant in December 2010 and a decrease of $2 million in royalty expense due to lower revenues from our Geysers Assets resulting from lower power prices during the nine months ended September 30, 2011 compared to the same period in 2010.

Impairment losses decreased for the nine months ended September 30, 2011, compared to the same period in 2010, primarily due to a $19 million impairment charge incurred during the third quarter of 2010 related to a development project originated prior to our Chapter 11 bankruptcy proceedings. During the third quarter of 2010, we learned the project would not receive a PPA that would support its continued development and made the determination that continued development was unlikely.

Interest expense decreased for the nine months ended September 30, 2011, compared to the same period in 2010, primarily due to a $63 million favorable change in unrealized mark-to-market activity related to the interest rate swaps hedging our variable rate debt that do not qualify for hedge accounting. Also, contributing to the favorable period over period change in interest expense was a decrease in our annualized effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and unrealized gains (losses) on interest rate swaps, which decreased to 7.7% for the nine months ended September 30, 2011, from 7.9% for the same period in 2010.

(Gain) loss on interest rate derivatives, net had an unfavorable change of $62 million for the nine months ended September 30, 2011, compared to the same period in 2010, primarily resulting from an unfavorable period over period change of approximately $24 million due to changes in fair value subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility term loans. Also, contributing to the unfavorable period over period change was an increase of $17 million resulting from interest rate swap breakage costs related to the repayment of project debt in June 2011 and a period over period decrease of $21 million in historical unrealized losses previously deferred in AOCI related to interest rate swaps formerly hedging our First Lien Credit Facility term loans. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further discussion of our interest rate swaps formerly hedging our First Lien Credit Facility term loans.

Debt extinguishment costs for the nine months ended September 30, 2011, primarily consisted of $74 million associated with the repayment of the NDH Project Debt in March 2011, $19 million associated with the retirement of the First Lien Credit Facility term loans in January 2011 in connection with the issuance of the 2023 First Lien Notes and $5 million related to the write-off of unamortized deferred financing costs related to the repayment of project debt in June 2011. See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information regarding the issuance of the 2023 First Lien Notes, the repayment of the NDH Project Debt and the repayment of other project debt. Debt extinguishment costs for the nine months ended September 30, 2010, consisted of $27 million in debt extinguishment costs associated with the retirement of the term loans under the First Lien Credit Facility in May and July 2010 in connection with the issuance of the 2019 First Lien Notes and 2020 First Lien Notes, respectively.

During the nine months ended September 30, 2011, we recorded an income tax benefit of $45 million compared to income tax expense of $38 million for the nine months ended September 30, 2010. The period over period change primarily resulted from a decrease in federal income tax of $86 million due primarily from a one-time $76 million benefit to reduce our valuation allowance due to the election to consolidate the CCFC group with the Calpine group for 2011 for federal income tax reporting purposes. See Note 9 of the Notes to Consolidated Condensed Financial Statements for further discussion of the election to consolidate the CCFC group and the Calpine group for federal tax reporting purposes. Also contributing to the favorable period over period change was a decrease in income tax expense of $7 million related to the application of intraperiod tax allocation. The overall decrease in income tax expense was partially offset by an increase in various state and foreign jurisdiction income taxes of $10 million for the nine months ended September 30, 2011, compared to the same period in 2010.

Income from discontinued operations for the nine months ended September 30, 2010 consists of the results of operations for Blue Spruce and Rocky Mountain which were sold in December 2010. See Note 2 of the Notes to Consolidated Condensed Financial Statements for further discussion of our discontinued operations.

Commodity Margin and Adjusted EBITDA

Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with U.S. GAAP, as well as the non-GAAP financial measures, Commodity Margin and Adjusted EBITDA, discussed below, which we use as measures of our performance.

We use Commodity Margin, a non-GAAP financial measure, to assess our performance by our reportable segments. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, RGGI compliance and other environmental costs, and cash settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales that are included in mark-to-market activity, but excludes the unrealized portion of our mark-to-market activity and other 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 U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. See Note 13 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.

Commodity Margin by Segment for the Three Months September 30, 2011 and 2010

The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended September 30, 2011 and 2010. In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets.

West:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	329		$	338		$	(9	)		(3	)
Commodity Margin per MWh generated	$	50.31		$	41.76		$	8.55			20

MWh generated (in thousands)		6,540			8,093			(1,553	)		(19	)
Average availability		91.2	%		92.9	%		(1.7	)		(2	)
Average total MW in operation		6,898			6,886			12			—
Average capacity factor, excluding peakers		47.4	%		58.7	%		(11.3	)		(19	)
Steam Adjusted Heat Rate		7,479			7,345			(134	)		(2	)

West — Commodity Margin in our West segment decreased by $9 million, or 3%, for the three months ended September 30, 2011 compared to the same period in 2010, due to lower Spark Spreads resulting from an increase in hydroelectric generation in California which has been significantly higher in 2011 compared to 2010. The decrease in Commodity Margin was partially offset by higher Commodity Margin contributions from hedges as well as the positive impact of origination activities for the third quarter of 2011 compared to the same period in 2010. Consistent with weaker price conditions, generation decreased 19% for the three months ended September 30, 2011 compared to the same period in 2010 which also led to a 19% decrease in our average capacity factor, excluding peakers.

Texas:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	162		$	165		$	(3	)		(2	)
Commodity Margin per MWh generated	$	14.95		$	17.31		$	(2.36	)		(14	)

MWh generated (in thousands)		10,833			9,533			1,300			14
Average availability		98.2	%		96.5	%		1.7			2
Average total MW in operation		7,003			7,197			(194	)		(3	)
Average capacity factor, excluding peakers		70.1	%		60.0	%		10.1			17
Steam Adjusted Heat Rate		7,296			7,305			9			—

Texas — Commodity Margin in our Texas segment for the three months ended September 30, 2011 was comparable to the same period in 2010. During the third quarter of 2011, Commodity Margin was negatively impacted by the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010 which was largely offset by significantly higher power prices driven by extreme heat and drought conditions which increased spark spreads during the third quarter of 2011 on our relatively small open position. Strong market pricing was the primary driver of a 14% increase in generation, while the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010 resulted in a 194 MW, or 3% decrease in our average total MW in operation.

North:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	259		$	259		$	—			—
Commodity Margin per MWh generated	$	50.69		$	57.34		$	(6.65	)		(12	)

MWh generated (in thousands)		5,109			4,517			592			13
Average availability		97.5	%		96.8	%		0.7			1
Average total MW in operation		7,370			6,792			578			9
Average capacity factor, excluding peakers		43.4	%		43.7	%		(0.3	)		(1	)
Steam Adjusted Heat Rate		8,003			7,865			(138	)		(2	)

North — Commodity Margin in our North segment was comparable for the three months ended September 30, 2011 compared to the same period in 2010. Commodity Margin increased by $26 million due to our York Energy Center which achieved commercial operations in March 2011 whose positive impact was largely offset by lower spark spreads in the PJM market resulting from milder weather during the third quarter of 2011 compared to the same period in 2010. Commodity Margin among our legacy power plants was comparable for the three months ended September 30, 2011 compared to the three months ended September 30, 2010. Generation increased 13% primarily due to our York Energy Center which also was the primary driver of a 578 MW, or 9% increase in our average total MW in operation.

Southeast:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	75		$	90		$	(15	)		(17	)
Commodity Margin per MWh generated	$	12.67		$	14.84		$	(2.17	)		(15	)

MWh generated (in thousands)		5,918			6,065			(147	)		(2	)
Average availability		96.6	%		97.4	%		(0.8	)		(1	)
Average total MW in operation		6,083			6,083			—			—
Average capacity factor, excluding peakers		48.9	%		49.3	%		(0.4	)		(1	)
Steam Adjusted Heat Rate		7,344			7,366			22			—

Southeast — Commodity Margin in our Southeast segment decreased by $15 million, or 17%, for the three months ended September 30, 2011 compared to the same period in 2010 largely due to the expiration of certain hedge contracts which benefited the third quarter of 2010 and the negative impact of an unscheduled outage at one of our power plants in the third quarter of 2011. Generation decreased 2% largely driven by lower generation at power plants contracted and dispatched by third parties during the third quarter of 2011 compared to the third quarter of 2010.

Commodity Margin by Segment for the Nine Months Ended September 30, 2011 and 2010

The following tables show our Commodity Margin and related operating performance metrics by segment for the nine months ended September 30, 2011 and 2010. In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets.

West:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	798		$	809		$	(11	)		(1	)
Commodity Margin per MWh generated	$	49.29		$	35.49		$	13.80			39

MWh generated (in thousands)		16,189			22,795			(6,606	)		(29	)
Average availability		86.4	%		91.5	%		(5.1	)		(6	)
Average total MW in operation		6,891			6,919			(28	)		—
Average capacity factor, excluding peakers		39.6	%		55.7	%		(16.1	)		(29	)
Steam Adjusted Heat Rate		7,488			7,315			(173	)		(2	)

West — Commodity Margin in our West segment for the nine months ended September 30, 2011 was comparable to the same period in 2010. During the nine months ended September 30, 2011, we experienced higher Commodity Margin contribution from hedges as well as the positive impact of origination activities. These positive factors were offset by lower Spark Spreads resulting from a significant increase in hydroelectric generation in California in 2011 compared to 2010, and lower Commodity Margin resulting from an unscheduled outage at OMEC during the second quarter of 2011. Consistent with weaker price conditions, generation decreased 29% for the nine months ended September 30, 2011 compared to the same period in 2010. Average availability decreased by 6% due to an increase in the duration of outages during the second quarter of 2011 compared to the second quarter of 2010, as the weaker price environment provided an opportunity to extend the duration of scheduled maintenance outages due to limited opportunity costs. Our average total MW in operation decreased 28 MW primarily due to the retirement of our Pittsburg power plant in March 2010 as well as the expiration of our operating lease and subsequent retirement of our Watsonville (Monterey) cogeneration power plant in May 2010.

Texas:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	357		$	400		$	(43	)		(11	)
Commodity Margin per MWh generated	$	14.86		$	16.38		$	(1.52	)		(9	)

MWh generated (in thousands)		24,019			24,419			(400	)		(2	)
Average availability		88.8	%		89.1	%		(0.3	)		—
Average total MW in operation		6,983			7,183			(200	)		(3	)
Average capacity factor, excluding peakers		52.5	%		51.9	%		0.6			1
Steam Adjusted Heat Rate		7,256			7,222			(34	)		—

Texas — Commodity Margin in our Texas segment decreased by $43 million, or 11%, for the nine months ended September 30, 2011, compared to the same period in 2010. Despite an increase in Commodity Margin contributions from hedges, Commodity Margin was negatively impacted by unplanned outages at some of our power plants caused by an extreme cold weather event which occurred on February 2, 2011. Power prices increased dramatically as a result of the cold weather event and the plant outages, which required us to purchase physical replacement power at prices substantially above our hedged prices. Also contributing to the period over period decrease in Commodity Margin was the sale of a 25% undivided interest in the assets of our Freestone power plant in December 2010 which also drove a 200 MW, or 3% decrease in our average total MW in operation. The decrease in Commodity Margin was partially offset by significantly higher power prices driven by extreme heat and drought conditions which increased Spark Spreads during the third quarter of 2011 on our relatively small open position.

North:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	578		$	390		$	188			48
Commodity Margin per MWh generated	$	51.50		$	56.63		$	(5.13	)		(9	)

MWh generated (in thousands)		11,224			6,887			4,337			63
Average availability		92.3	%		93.1	%		(0.8	)		(1	)
Average total MW in operation		7,234			4,179			3,055			73
Average capacity factor, excluding peakers		34.4	%		36.8	%		(2.4	)		(7	)
Steam Adjusted Heat Rate		7,939			7,773			(166	)		(2	)

North — Commodity Margin in our North segment increased by $188 million primarily due to the Conectiv Acquisition which closed on July 1, 2010 and our York Energy Center which achieved COD in March 2011 which were both also the primary driver of the period over period increase in generation as well as the 3,055 MW increase in average total MW in operation during the nine months ended September 30, 2011 compared to the same period in 2010. Average capacity factor, excluding peakers decreased 7% primarily due to a decrease in generation among our legacy power plants which are largely contracted and dispatched by third parties.

Southeast:	2011			2010			Change			% Change
Commodity Margin (in millions)	$	188		$	216		$	(28	)		(13	)
Commodity Margin per MWh generated	$	12.98		$	15.75		$	(2.77	)		(18	)

MWh generated (in thousands)		14,489			13,712			777			6
Average availability		92.0	%		93.4	%		(1.4	)		(1	)
Average total MW in operation		6,083			6,083			—			—
Average capacity factor, excluding peakers		41.0	%		38.4	%		2.6			7
Steam Adjusted Heat Rate		7,323			7,331			8			—

Southeast — Commodity Margin in our Southeast segment decreased by $28 million, or 13%, for the nine months ended September 30, 2011 compared to the same period in 2010 largely due to the expiration of certain hedge contracts which benefited the nine months ended September 30, 2010 as well as lower Commodity Margin that resulted from unscheduled outages that occurred during the second and third quarters of 2011. Generation increased 6% largely driven by higher generation at power plants contracted and dispatched by third parties during the nine months ended September 30, 2011 compared to the same period in 2010.

Adjusted EBITDA

The tables below provide a reconciliation of Adjusted EBITDA by operating segment to our income (loss) from operations on an operating segment basis and to net income (loss) attributable to Calpine on a consolidated basis for the periods indicated (in millions).

	Three Months Ended September 30, 2011
	West			Texas		North		Southeast		Consolidation and Elimination			Total
Net income attributable to Calpine													$	190
Income tax expense														20
Other (income) expense and debt extinguishment costs, net														—
(Gain) loss on interest rate derivatives, net														3
Interest expense, net														190
Income from operations	$	182		$	48	$	159	$	13	$	1		$	403
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)		52			34		36		22		(1	)		143
Major maintenance expense		13			9		6		5		—			33
Operating lease expense		3			—		6		—		—			9
Unrealized (gain) loss on commodity derivative mark-to-market activity		(21	)		25		2		3		—			9
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)		—			—		9		—		—			9
Stock-based compensation expense		2			1		2		1		—			6
Loss on dispositions of assets		5			2		1		—		—			8
Contract amortization		—			—		4		—		—			4
Other		7			1		6		—		—			14
Total Adjusted EBITDA	$	243		$	120	$	231	$	44	$	—		$	638

	Three Months Ended September 30, 2010
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Net income attributable to Calpine																$	217
Discontinued operations, net of tax expense																	(19	)
Income tax expense																	21
Other (income) expense and debt extinguishment costs, net																	23
(Gain) loss on interest rate derivatives, net																	84
Interest expense, net																	228
Income from operations	$	218		$	122		$	185		$	28		$	1		$	554
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)		51			37			37			27			(1	)		151
Impairment losses		—			—			—			19			—			19
Major maintenance expense		2			8			1			2			—			13
Operating lease expense		5			—			6			—			—			11
Unrealized gains on commodity derivative mark-to-market activity		(39	)		(57	)		(17	)		(18	)		—			(131	)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)		—			—			10			—			—			10
Stock-based compensation expense		3			1			1			1			—			6
Loss on dispositions of assets		—			2			—			—			—			2
Conectiv acquisition-related costs		—			—			6			—			—			6
Other		—			1			1			—			—			2
Adjusted EBITDA from continuing operations		240			114			230			59			—			643
Adjusted EBITDA from discontinued operations		20			—			—			—			—			20
Total Adjusted EBITDA	$	260		$	114		$	230		$	59		$	—		$	663

	Nine Months Ended September 30, 2011
	West			Texas			North		Southeast			Consolidation and Elimination			Total
Net loss attributable to Calpine															$	(177	)
Net income attributable to noncontrolling interest																1
Income tax benefit																(45	)
Other (income) expense and debt extinguishment costs, net																108
(Gain) loss on interest rate derivatives, net																149
Interest expense, net																568
Income (loss) from operations	$	338		$	(24	)	$	298	$	(11	)	$	3		$	604
Add:
Adjustments to reconcile income (loss) from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)		140			99			102		68			(3	)		406
Major maintenance expense		51			68			19		31			—			169
Operating lease expense		7			—			19		—			—			26
Unrealized (gain) loss on commodity derivative mark-to-market activity		(32	)		70			1		9			—			48
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)		—			—			30		—			—			30
Stock-based compensation expense		7			5			3		3			—			18
Loss on dispositions of assets		7			6			2		2			—			17
Contract amortization		—			—			5		—			—			5
Other		8			1			14		1			—			24
Total Adjusted EBITDA	$	526		$	225		$	493	$	103		$	—		$	1,347

	Nine Months Ended September 30, 2010
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Net income attributable to Calpine																$	55
Discontinued operations, net of tax expense																	(31	)
Income tax expense																	38
Other (income) expense and debt extinguishment costs, net																	36
(Gain) loss on interest rate derivatives, net																	87
Interest expense, net																	627
Income from operations	$	371		$	187		$	205		$	44		$	5		$	812
Add:
Adjustments to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(1)		155			113			76			85			(5	)		424
Impairment losses		—			—			—			19			—			19
Major maintenance expense		21			68			7			15			—			111
Operating lease expense		14			—			19			—			—			33
Unrealized gains on commodity derivative mark-to-market activity		(50	)		(118	)		(16	)		(28	)		—			(212	)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments(2)		—			—			25			—			—			25
Stock-based compensation expense		8			6			2			2			—			18
(Gain) loss on dispositions of assets		(1	)		7			—			1			—			7
Conectiv acquisition-related costs		—			—			25			—			—			25
Other		1			1			1			—			—			3
Adjusted EBITDA from continuing operations		519			264			344			138			—			1,265
Adjusted EBITDA from discontinued operations		61			—			—			—			—			61
Total Adjusted EBITDA	$	580		$	264		$	344		$	138		$	—		$	1,326

_________

(1)	Depreciation and amortization expense in the income from operations calculation on our Consolidated Condensed Statements of Operations excludes amortization of other assets.

(2)	Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized losses on mark-to-market activity of $1 million for both the three and nine months ended September 30, 2011, and 2010.

Liquidity and Capital Resources

Our business is capital intensive. Our ability to successfully implement our strategy is dependent on the continued availability of capital on attractive terms. In addition, our ability to successfully operate our business is dependent on maintaining sufficient liquidity. We believe that we have adequate resources from a combination of cash and cash equivalents on hand and cash expected to be generated from future operations to continue to meet our obligations as they become due.

Liquidity

At September 30, 2011, we had $1,285 million in cash and cash equivalents and $238 million of restricted cash. Amounts available for future cash borrowings were $598 million under the Corporate Revolving Facility. The following table provides a summary of our liquidity position at September 30, 2011, and December 31, 2010 (in millions):

	September 30, 2011		December 31, 2010
Cash and cash equivalents, corporate(1)	$	977	$	1,058
Cash and cash equivalents, non-corporate		308		269
Total cash and cash equivalents		1,285		1,327
Restricted cash		238		248
Revolving facility(ies) availability(2)		598		623
Letter of credit availability(3)		37		35
Total current liquidity availability	$	2,158	$	2,233

_________

(1)	Includes $5 million and $6 million of margin deposits held by us posted by our counterparties at September 30, 2011, and December 31, 2010, respectively.

(2)

On December 10, 2010, we executed our $1.0 billion Corporate Revolving Facility, which replaced our $1.0 billion revolver under our First Lien Credit Facility. At December 31, 2010, the letters of credit issued under our First Lien Credit Facility were either replaced by letters of credit issued by the Corporate Revolving Facility or back-stopped by an irrevocable standby letter of credit issued by a third party. Our letters of credit under our Corporate Revolving Facility at December 31, 2010 include those that were back-stopped of approximately $83 million. The back-stopped letters of credit were returned and extinguished during the first quarter of 2011. The balance at December 31, 2010, includes availability under the NDH Project Debt, which was retired on March 9, 2011.

(3)	Includes availability under Calpine Development Holdings, Inc.

Our principal source for future liquidity is cash flows generated from our operations. Our principal uses of liquidity and capital resources, outside of those required for our operations, include, but are not limited to, collateral requirements to support our commercial hedging and optimization activities, debt service obligations including principal and interest payments, and capital expenditures for construction, project development and other growth initiatives. In addition, we may use capital resources to opportunistically repurchase our shares of common stock. The ultimate decision to allocate capital to share repurchases will be based upon the expected returns compared to other alternative uses of capital. We believe that cash on hand and expected future cash flows from operations will be sufficient to meet our liquidity needs for our operations, both in the near and longer term.

Cash Management — We manage our cash in accordance with our intercompany cash management system subject to the requirements of our Corporate Revolving Facility and requirements under certain of our project debt and lease agreements or by regulatory agencies. Our cash and cash equivalents, as well as our restricted cash balances are invested in money market accounts with investment banks that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be credit-worthy financial institutions and certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities.

We have never paid cash dividends on our common stock. 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 and financing restrictions and such other factors as our Board of Directors may deem relevant.

Liquidity Sensitivity

Significant changes in commodity prices and Market Heat Rates can have an impact on our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. Utilizing our portfolio of transactions subject to collateral exposure, we estimate that as of October 14, 2011, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $100 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $83 million. Changes in Market Heat Rates also affect our liquidity. For example, as demand increases, less efficient generation is dispatched, which increases the Market Heat Rate and results in increased collateral requirements. Historical relationships of natural gas and Market Heat Rate movements for our portfolio of assets have been volatile over time and are influenced by the absolute price of natural gas; therefore, we derived a statistical analysis that implies that a change of $1/MMBtu in natural gas approximates an average Market Heat Rate change of 500 Btu/KWh at current natural gas price levels. We estimate that at October 14, 2011, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $54 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by $48 million. These amounts are not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above, and also exclude any correlation between the changes in natural gas prices and Market Heat Rates that may occur concurrently. These sensitivities will change as new contracts or hedging activities are executed.

In order to effectively manage our future Commodity Margin, we have economically hedged a substantial portion of our generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions for 2011; however, we remain susceptible to significant price movements for 2012 and beyond. In addition to the price of natural gas, the future impact on our Commodity Margin is highly dependent on other factors such as:

•

the level of Market Heat Rates;

•

our continued ability to successfully hedge our Commodity Margin;

•

the speed, strength and duration of an economic recovery;

•

maintaining acceptable availability levels for our fleet;

•

improving the efficiency and profitability of our operations;

•

continued compliance with the covenants under our existing financing obligations, including our First Lien Notes, Term Loan, New Term Loan, Corporate Revolving Facility, CCFC and other debt obligations;

•

stabilizing and increasing future contractual cash flows; and

•

our significant counterparties performing under their contracts with us.

Additionally, scheduled outages related to the life cycle of our power plant fleet in addition to unscheduled outages may result in maintenance expenditures that are disproportionate in differing periods. In order to manage such liquidity requirements, we maintain additional liquidity availability in the form of our Corporate Revolving Facility (noted in the table above), letters of credit and the ability to issue first priority liens for collateral support. It is difficult to predict future developments and the amount of credit support that we may need to provide should such conditions occur, we experience another economic recession that persists for a significant period of time or energy commodity prices increase significantly.

Our letters of credit, capital management, construction, upgrades and growth initiatives are further discussed below.

Letter of Credit Facilities

The Corporate Revolving Facility represents our primary revolving facility. The table below represents amounts issued under our letter of credit facilities at September 30, 2011 and December 31, 2010 (in millions):

	September 30, 2011		December 31, 2010
Corporate Revolving Facility(1)	$	402	$	443
Calpine Development Holdings, Inc.		163		165
NDH Project Debt credit facility(2)		—		34
Various project financing facilities		130		69
Total	$	695	$	711

_________

(1)

(2)	We repaid and terminated the NDH Project Debt on March 9, 2011.

Capital Management and Significant Financing Transactions

In connection with our goals of enhancing shareholder value and leveraging our three scale regions, we have completed or initiated six key capital and financing transactions during the nine months ended September 30, 2011, as further described below.

Issuance of the 2023 First Lien Notes and Termination of the First Lien Credit Facility

On January 14, 2011, we issued the 2023 First Lien Notes, which, together with operating cash on hand, were used to fully repay the remaining First Lien Credit Facility term loans thereby terminating the First Lien Credit Facility in accordance with its terms. See Note 5 of the Notes to Consolidated Condensed Financial Statements for further discussion of the issuance of the 2023 First Lien Notes and the termination of the First Lien Credit Facility. The issuance of the First Lien Notes, the refinancing of the First Lien Credit Facility revolver with the Corporate Revolving Facility in 2010 and the resulting termination of the First Lien Credit Facility, provide us with significant benefits. The termination of the First Lien Credit Facility eliminated the more restrictive of our debt covenants, resulting in increased operational, strategic and financial flexibility in managing our capital resources including the flexibility to reinvest more earnings for internal growth, issue and/or buyback shares of our common stock and incur additional debt, if needed for acquisition or development. Additionally, we extended the remaining contractual debt maturities under the First Lien Credit Facility of approximately $1.2 billion, due in 2014 to 2023. Under the First Lien Notes and Corporate Revolving Facility, subject in each case to the limitations contained therein and in the Collateral Agency and Intercreditor Agreement, we may:

•

re-invest future earnings internally for additional growth and/or may elect to return cash to shareholders;

•

issue and/or buyback additional shares of our common stock;

•

incur additional first lien indebtedness up to certain consolidated net tangible asset ratios;

•

incur additional subordinated or junior secured debt; and

•

use corporate resources to freely invest in our subsidiaries which are not first lien guarantors.

Additionally, except as required under certain of our project debt, we are no longer subject to an excess cash flow payment calculation or cash sweeps, and we are no longer limited in the amount of capital expenditures for future growth.

Closing the Term Loan and New Term Loan and Termination of the NDH Project Debt and Other Project Debt

On March 9, 2011, we closed on the $1.3 billion Term Loan, and we used the proceeds received, together with operating cash on hand to fully retire the approximately $1.3 billion NDH Project Debt in accordance with its repayment terms. The NDH Project Debt was originally established to partially fund the Conectiv Acquisition. On June 17, 2011, we repaid approximately $340 million of project debt with the proceeds received from $360 million in borrowings under the New Term Loan. The Term Loan and New Term Loan refinancing reduces our overall cost of debt and simplifies our capital structure by bringing debt up to the corporate level from the subsidiary level, eliminating the need for subsidiary level reporting and the potential for cash to be temporarily trapped at the subsidiary level. Additionally, these transactions demonstrate our continued ability to strategically access capital markets. The Term Loan and New Term Loan contain very similar covenants, qualifications, exceptions and limitations as the First Lien Notes.

Russell City Project Debt

Los Esteros Project Debt

See also Note 5 of the Notes to Consolidated Condensed Financial Statements for further discussion of our First Lien Notes, Term Loan, New Term Loan, Russell City Project Debt and Los Esteros Project Debt.

Share Repurchase Program

On August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares of our common stock. The announced share repurchase program did not specify an expiration date. The repurchases may be commenced or suspended from time to time without prior notice. Through the filing of this Report, 2,122,922 shares of our outstanding common stock have been repurchased under this program for approximately $29 million at an average price paid of $13.65 per share. The shares repurchased as of the date of this Report were purchased in open market transactions.

Riverside Energy Center Purchase Option

As disclosed in Note 3 to the Consolidated Condensed Financial Statements, Riverside Energy Center has a PPA that provides a third party a fixed price option to purchase the power plant which is exercisable in 2013. The third party has publicly stated their intent to exercise this purchase option. As a result, we expect to receive approximately $375 million during the fourth quarter of 2012 as a deposit on the purchase option.

Construction, Upgrades and Growth Initiatives

We remain focused on our goal to continue to grow our presence in core markets with an emphasis on expansions or upgrades of existing power plants. We intend to take advantage of favorable opportunities to continue to design, develop, acquire, construct and operate the next generation of highly efficient, operationally flexible and environmentally responsible power plants where such investment meets our rigorous financial hurdles, particularly if power contracts and financing are available and attractive returns are expected. We will consider selective acquisitions or additions of new capacity supported by long-term hedging programs, including PPAs and natural gas tolling agreements, particularly where limited or non-recourse project financing is available. In addition, we believe that upgrades and expansions to our current assets or using existing equipment offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. Our significant projects under construction, growth initiatives and upgrades are discussed below.

York Energy Center

We acquired the York Energy Center, a 565 MW dual fuel, combined-cycle power plant under construction as part of the Conectiv Acquisition. York Energy Center achieved COD on March 2, 2011, three months early, and sells power under a six-year PPA with a third party which commenced on June 1, 2011.

Russell City Energy Center

The Russell City Energy Center is under construction and continues to move forward with expected COD in 2013. Upon completion, this project will bring on line approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity) representing our 75% share. We are in possession of all required approvals and permits, and we closed on construction financing on June 24, 2011. The project’s prevention of significant deterioration permit is currently the subject of an ongoing appeal at the U.S. Court of Appeals for the Ninth Circuit brought by Chabot-Las Positas Community College District against the EPA. Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&E under a ten-year PPA.

Los Esteros

During 2009, we and PG&E negotiated a new PPA to replace the existing California Department of Water Resources contract and facilitate the upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power plant to a 308 MW combined-cycle generation power plant, which will also increase the efficiency and environmental performance of the power plant by lowering the Heat Rate. The PPA and related agreements with PG&E have received all of the necessary approvals and licenses, which are now effective. The California Energy Commission has renewed our license and emission limits, which is final. The Bay Area Air Quality Management District issued its renewal of the Authority to Construct. We began construction in the second quarter of 2011 and obtained construction financing on August 23, 2011. We expect COD in 2013.

Turbine Upgrades

We continue to move forward with our turbine upgrade program. Through September 30, 2011, we have completed the upgrade of eight Siemens and five GE turbines and have agreed to upgrade approximately eight additional Siemens and GE turbines (and may upgrade additional turbines in the future). Our turbine upgrade program is expected to increase our generation capacity in total by approximately 275 MW. This upgrade program began in the fourth quarter of 2009 and is scheduled through 2014. The upgraded turbines have been operating with Heat Rates consistent with expectations.

Geysers Assets Expansion

We continue to look to expand our production from our Geysers Assets. Beginning in the fourth quarter of 2009, we conducted an exploratory drilling program, which effectively proved the commercial viability of the steam field in the northern part of our Geysers Assets; however, permitting challenges have emerged that we are continuing to resolve, and we are pursuing commercial arrangements which will need to be in place prior to commencing expansion activities. We continue to believe our northern Geysers Assets have potential for development. In the near term, we will connect the test wells to our existing power plants to capture incremental production from those wells, while continuing with the permitting process, baseline engineering work and sales efforts for an expansion.

PJM

Given our view of the potential need for new generation in the PJM region, driven both by market growth and the expected impacts of environmental regulations on older, less efficient generation within the region, we view the PJM region as a market with an attractive growth profile. In order to capitalize on this outlook, we are actively pursuing a set of development options, including projects at:

•

Edge Moor (Delaware): Recent completion of the feasibility study by PJM for the addition of 300 MW of combined-cycle capacity at our existing site, leveraging existing infrastructure. The study results are being analyzed and the decision to proceed to system impact study phase is under consideration.

•

Garrison (Delaware): Actively permitting 618 MW of new combined-cycle capacity at a development site secured by a lease option with the City of Dover. PJM’s system impact study for the first phase and the feasibility study for the second phase will be completed shortly. Environmental permitting, site development planning and development engineering are underway.

•

Talbert (Maryland): Existing interconnect agreement for 200 MW of new simple-cycle capacity at a development site secured by a lease option. Discussions regarding construction of natural gas lateral to the project are in progress.

•

Powell (Maryland): Existing interconnect agreement for up to 500 MW of new simple-cycle capacity at a development site that is owned by Calpine. Fuel supply options are being pursued with potential suppliers.

•

Other locations that we feel provide similar opportunity to position us for growth within the region.

Mankato Power Plant Expansion Proposal

In March 2011, Xcel Energy Inc. (“Xcel”) filed a proposal with the Minnesota Public Utilities Commission (“MPUC”) to construct a new 700 MW natural gas-fired, combined-cycle facility to be located at its existing Black Dog site. The MPUC required Xcel to also seek potential third party alternatives so that MPUC could compare any offers to Xcel’s proposal. We proposed to expand our Mankato power plant, a 375 MW natural gas-fired, combined-cycle power plant, by 345 MW under a PPA with Xcel. We believe that our proposal is less expensive, environmentally preferable and a closer match to Xcel’s demand forecast than its self-build proposal. The MPUC is expected to make a decision in 2012.

Channel and Deer Park Expansion

We continue to evaluate the ERCOT market for expansion opportunities based on tightening reserve margins and potential impact of EPA regulations on generation in Texas. At both our Deer Park and Channel Energy Centers, we have the ability to install an additional combustion turbine generator and connect to the existing steam turbine generator to expand the capacity of these facilities and to improve the overall efficiency. In September 2011, we submitted an air permit application with the Texas Commission on Environmental Quality (“TCEQ”) and the EPA to expand the Deer Park Energy Center by approximately 275 MW. We anticipate filing similar permits in the fourth quarter of 2011 with the TCEQ and the EPA to expand the Channel Energy Center by approximately 275 MW.

Customer-Oriented Origination Business

We continue to focus on providing products and services that are beneficial to our customers.

•

We have entered into a new ten-year PPA with a third party to provide 485 MW of power generated by our Carville Energy Center which will commence in June 2012.

•

We have entered into a new tolling agreement with Southern California Edison to provide 750 MW of power generated by our Pastoria Energy Center which will commence in 2013, and we executed a new resource adequacy contract with the same counterparty for 715 MW from our Pastoria Energy Center which will commence in 2014.

NOLs

We have significant NOLs that will provide future tax deductions when we generate sufficient taxable income during the applicable carryover periods. As discussed in Note 9 of the Notes to Consolidated Condensed Financial Statements, we elected to consolidate our CCFC and Calpine groups for federal income tax reporting purposes during the first quarter of 2011. As a result of the consolidation, we will be able to utilize approximately $76 million additional Calpine group NOLs against CCFC group deferred tax liabilities. At December 31, 2010, our consolidated federal NOLs totaled approximately $7.4 billion. See Note 9 of the Notes to Consolidated Condensed Financial Statements for further discussion of our NOLs.

Cash Flow Activities

The following table summarizes our cash flow activities for the nine months ended September 30, 2011 and 2010 (in millions):

	2011			2010
Beginning cash and cash equivalents	$	1,327		$	989
Net cash provided by (used in):
Operating activities		536			810
Investing activities		(660	)		(1,612	)
Financing activities		82			727
Net decrease in cash and cash equivalents		(42	)		(75	)
Ending cash and cash equivalents	$	1,285		$	914

Net Cash Provided By Operating Activities

Cash flows provided by operating activities for the nine months ended September 30, 2011, resulted in net inflows of $536 million compared to $810 million for the same period in 2010. The decrease in cash flows from operating activities was primarily due to:

•

Working capital — Working capital employed increased by approximately $284 million during the period after adjusting for debt related balances and non-hedging interest rate swaps which did not impact cash provided by operating activities. The increase was primarily due to a reduction in margin requirements during the nine months ended September 30, 2010.

•

Interest Paid — Cash paid for interest, inclusive of interest rate swaps in hedging relationships, increased by $21 million to $509 million for the nine months ended September 30, 2011, as compared to $488 million for the nine months ended September 30, 2010. The increase was primarily due to timing of interest payments on the new bonds and term loans as compared to the previously outstanding First Lien Credit Facility and project debt.

•

Prepayment Premiums — For the nine months ended September 30, 2011, we paid $13 million of prepayment premiums related to the extinguishment of the NDH Project Debt.

Our decrease in cash provided by operating activities was partially offset by the following:

•

Income from operations — Income from operations, adjusted for non-cash items increased by $8 million for the nine months ended September 30, 2011, as compared to the nine months ended September 30, 2010. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments and unrealized gains and losses in mark-to-market activity.

Net Cash Used In Investing Activities

Cash flows used in investing activities for the nine months ended September 30, 2011, were $660 million compared to cash flows used in investing activities of $1,612 million for the nine months ended September 30, 2010. The difference was primarily due to:

•

Conectiv Acquisition — On July 1, 2010 we paid approximately $1.6 billion for the purchase of the Conectiv assets. We had no similar cash outflows in the nine months ended September 30, 2011.

•

Capital expenditures — Capital expenditures increased by approximately $320 million primarily resulting from construction activity at the Russell City Energy Center, Los Esteros Critical Energy Facility and York Energy Center combined with our turbine upgrade program.

•

Settlement of non-hedging interest rate swaps — During the nine months ended September 30, 2011, we made payments on interest rate swap derivative instruments associated with swaps that formerly hedged the variable rate debt which was converted to fixed rate debt of $147 million compared to payments of $27 million during the same period in 2010.

•

Restricted cash — The net decrease in restricted cash was $9 million for the nine months ended September 30, 2011, compared to $228 million for the same period in 2010. The decrease in restricted cash in 2011 as compared to 2010 was due primarily to the maturity of project debt and the corresponding reduction in restricted cash requirements during the first quarter of 2010.

Net Cash Provided By Financing Activities

Cash flows provided by financing activities for the nine months ended September 30, 2011, were $82 million compared to cash flows provided by financing activities of $727 million for the same period in 2010. The decrease was primarily due to:

•

Reduced proceeds from project debt — During the nine months ended September 30, 2011, we received proceeds of approximately $223 million from the issuance of project debt to fund our Russell City and Los Esteros projects. During the nine months ended September 30, 2010, we received proceeds of approximately $1.3 billion to fund the Conectiv acquisition.

•

Additional finance costs — During the nine months ended September 30, 2011, primarily due to the refinancing of the First Lien Credit Facility and the NDH Project Debt, we incurred $78 million of financing costs compared to $67 million during the nine months ended September 30, 2010. In addition, we received a reimbursement of finance costs of $10 million associated with the repayment of notes related to Power Contract Financing in the nine months ended September 30, 2010.

The decrease was partially offset by:

•

Issuance of First Lien Notes — We received proceeds of approximately $1.2 billion from the issuance of the 2023 First Lien Notes and used those proceeds to terminate the First Lien Credit Facility in accordance with its repayment terms resulting in a net increase of $9 million during the nine months ended September 30, 2011.

•

Issuance of the Term Loan and New Term Loan — During the nine months ended September 30, 2011, we received proceeds of approximately $1.7 billion from the issuance of the Term Loan and New Term Loan. We used the proceeds to repay NDH Project Debt of approximately $1.3 billion resulting in a net increase of $374 million.

•

Contributions from non-controlling interest holder — During the nine months ended September 30, 2011, we received proceeds of approximately $34 million from a non-controlling interest holder in Russell City. We received contributions of nil in the nine months ended September 30, 2010.

Special Purpose Subsidiaries

Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine Corporation 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: 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.), Russell City Energy Company, LLC and OMEC.

Risk Management and Commodity Accounting

Our hedging strategy focuses first on protecting our balance sheet, given our debt obligations, our committed capital expenditures and other obligations. Secondly, our commercial efforts attempt to maximize our risk adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power.

We actively seek to manage and limit the commodity risks of our portfolio, utilizing multiple strategies of buying and selling power, natural gas and Heat Rate contracts to manage our Spark Spread and products that manage geographic price differences (basis differential). We have approximately 364 MW of capacity from power plants where we may purchase fuel oil to meet our generation requirements if required; however, we have not currently entered into any hedging or optimization transactions for fuel oil as we do not expect our fuel oil requirements to be material to us, but may elect to do so in the future.

Along with our portfolio of hedging transactions, we enter into power and natural gas positions that often act as hedges to our asset portfolio, but do not qualify as hedges under hedge accounting guidelines, such as commodity options transactions and instruments that settle on power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power price relationships between delivery points. While our selling and purchasing of power and natural gas is mostly physical in nature, we also engage in marketing, hedging and optimization activities, particularly in natural gas, that are financial in nature. We use derivative instruments, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) for the purchase and sale of power, natural gas, and emission allowances to manage commodity price risk and to maximize the risk-adjusted returns from our power and natural gas assets. We conduct these hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk measurement and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by entering into offsetting positions that lock in a margin. While we enter into these transactions primarily to provide us with improved price and price volatility transparency, as well as greater market access, which benefits our hedging activities, we also are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are included in and subject to our consolidated risk management portfolio position limits and controls structure. Changes in fair value of commodity positions that do not qualify for either hedge accounting or the normal purchase normal sale exemption 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 marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, Risk Management Committee of senior management and Board of Directors.

We have economically hedged a substantial portion of our expected generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions for 2011; however, we remain susceptible to significant price movements for 2012 and beyond. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels. We use a combination of PPAs and other hedging instruments to manage our variability in future cash flows. At September 30, 2011, the maximum length of time that our PPAs extended was approximately 23 years into the future and the maximum length of time over which we were hedging using commodity and interest rate derivative instruments was 1 and 15 years, respectively.

We have historically used interest rate swaps to adjust the mix between our fixed and variable rate debt. The majority of our interest rate swaps mature in years 2011 through 2012. To the extent eligible, our interest rate swaps have been designated as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The reclassification of unrealized losses from AOCI into income and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility is presented separate from interest expense as (gain) loss on interest rate derivatives, net on our Consolidated Condensed Statement of Operations. On January 14, 2011, we repaid the remaining balance under the First Lien Credit Facility term loans with the proceeds received from the issuance of the 2023 First Lien Notes and the unrealized losses related to these interest swaps of approximately $91 million remaining in AOCI were reclassified out of AOCI and into income as additional (gain) loss on interest rate derivatives, net, during the first quarter of 2011. In addition, we reclassified approximately $17 million in unrealized losses in AOCI to (gain) loss on interest rate derivatives, net during the second quarter of 2011 resulting from the repayment of project debt in June 2011.

Assuming constant September 30, 2011, power and natural gas prices and interest rates, we estimate that pre-tax net gains of $52 million would be reclassified from AOCI into earnings during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will vary based on changes in natural gas and power prices as well as interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative) will be for the next 12 months.

The primary factors affecting our market risk and the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, principally for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate swaps. Since prices for power and natural gas and interest rates are volatile, 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. Our derivative assets have decreased to approximately $0.8 billion at September 30, 2011, compared to $0.9 billion at December 31, 2010, and our derivative liabilities have remained constant at $(1.1) billion at September 30, 2011, when compared to December 31, 2010. At September 30, 2011, the fair value of our level 3 derivative assets and liabilities represent only a small portion of our total assets and liabilities (less than 1%). See Note 6 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.

The change in fair value of our outstanding commodity and interest rate derivative instruments from January 1, 2011, through September 30, 2011, is summarized in the table below (in millions):

	Interest Rate Swaps			Commodity Instruments			Total
Fair value of contracts outstanding at January 1, 2011	$	(367	)	$	174		$	(193	)
Items recognized or otherwise settled during the period(1)(2)		161			(136	)		25
Fair value attributable to new contracts		(42	)		(80	)		(122	)
Changes in fair value attributable to price movements		(94	)		137			43
Change in fair value attributable to nonperformance risk		(10	)		(1	)		(11	)
Fair value of contracts outstanding at September 30, 2011(3)	$	(352	)	$	94		$	(258	)

_________

(1)

Interest rate settlements consist of recognized losses from former interest rate cash flow hedges of $18 million that were de-designated as a result of the repayment of project debt in June 2011, $52 million related to recognition of losses from settlements of designated cash flow hedges and $91 million in losses from settlements of undesignated interest rate swaps (represents a portion of interest expense and (gain) loss on interest rate derivatives, net as reported on our Consolidated Condensed Statements of Operations).

(2)

Gains on settlement of commodity contracts not designated as hedging instruments of $111 million (represents a portion of operating revenues and fuel and purchased energy expense as reported on our Consolidated Condensed Statements of Operations) and $25 million related to recognition of gains from cash flow hedges, previously reflected in OCI, partially offset by other changes in derivative assets and liabilities not reflected in OCI or net income.

(3)	Net commodity and interest rate derivative assets and liabilities reported in Notes 6 and 7 of the Notes to Consolidated Condensed Financial Statements.

The change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in cash for option premiums paid or collected, in OCI, net of tax, for cash flow hedges, or on our Consolidated Condensed Statements of Operations as a component (gain or loss) in current earnings.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Realized gain (loss)
Interest rate swaps	$	(44	)	$	(14	)	$	(150	)	$	(26	)
Commodity derivative instruments		65			41			117			93
Total realized gain (loss)	$	21		$	27		$	(33	)	$	67

Unrealized gain (loss) (1)
Interest rate swaps	$	43		$	(96	)	$	5		$	(115	)
Commodity derivative instruments		(8	)		131			(47	)		212
Total unrealized gain (loss)	$	35		$	35		$	(42	)	$	97
Total mark-to-market activity	$	56		$	62		$	(75	)	$	164

_________

(1)	Changes in unrealized gain (loss) include de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into income, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Realized and unrealized gain (loss)
Power contracts included in operating revenues	$	18		$	22		$	9		$	34
Natural gas contracts included in fuel and purchased energy expense		39			150			61			271
Interest rate swaps included in interest expense		2			(26	)		4			(54	)
Gain (loss) on interest rate derivatives, net		(3	)		(84	)		(149	)		(87	)
Total mark-to-market activity	$	56		$	62		$	(75	)	$	164

Our change in AOCI from an accumulated loss of $125 million at December 31, 2010, to an accumulated loss of $147 million at September 30, 2011, was primarily driven by a decrease in longer-term LIBOR rates which negatively impacted our project debt interest rate swaps by $139 million, and $106 million associated with gains on settlement of commodity derivative cash flow hedges reclassified into net income. These negative factors were partially offset by $39 million in losses on settlement of interest rate swap cash flow hedges reclassified into net income, a reclassification adjustment of $91 million for cash flow hedges formerly hedging the First Lien Credit Facility term loans realized in net income, gains of $79 million on existing commodity derivative cash flow hedges, and the effect of income taxes, which includes a net $18 million increase to tax benefit in OCI with a partial offsetting expense to continuing operations related to the intraperiod tax allocation provisions under U.S. GAAP.

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

The net fair value of outstanding derivative commodity instruments at September 30, 2011, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):

Fair Value Source:	2011		2012 - 2013			2014 - 2015		After 2015		Total
Prices actively quoted	$	10	$	(29	)	$	—	$	—	$	(19	)
Prices provided by other external sources		58		36			—		—		94
Prices based on models and other valuation methods		5		11			3		—		19
Total fair value	$	73	$	18		$	3	$	—	$	94

We measure the energy commodity price risks in our portfolio on a daily basis using a VAR model to estimate the maximum potential one-day risk of loss based upon historical experience resulting from market movements in comparison to internally established thresholds. Our VAR is calculated for our entire portfolio, which is comprised of energy commodity derivatives, power plants, PPAs and other physical and financial transactions. The portfolio VAR calculation incorporates positions for the remaining portion of the current calendar year, exclusive of the current month of measurement, 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 nine months ended September 30, 2011 and 2010, as well as our VAR at September 30, 2011 and 2010 (in millions):

	2011		2010
Three months ended September 30:
High	$	34	$	30
Low	$	21	$	20
Average	$	28	$	25
Nine months ended September 30:
High	$	39	$	58
Low	$	20	$	20
Average	$	31	$	30
At September 30	$	31	$	28

Due to the inherent limitations of statistical measures such as VAR, the VAR calculation may not capture the full extent of our commodity price exposure. As a result, actual changes in the value of our energy commodity portfolio could be different from the calculated VAR, and the actual changes could have a material impact on our financial results. In order to evaluate the risks of our portfolio on a comprehensive basis and augment our VAR analysis, we also measure the risk of the energy commodity portfolio using several analytical methods including sensitivity tests, scenario tests, stress tests, and daily position reports.

Liquidity Risk — Liquidity risk arises from the general funding requirements needed to manage our activities and assets and liabilities. Increasing natural gas prices or Market Heat Rates can cause increased collateral requirements. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 8 of the Notes to Consolidated Condensed Financial Statements.

Credit Risk — Credit risk relates to the risk of loss resulting from nonperformance or non-payment by our counterparties related to their contractual obligations with us. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. We also have credit risk if counterparties are unable to provide collateral or post margin. We monitor and manage our credit risk through credit policies that include:

•

credit approvals;

•

routine monitoring of counterparties’ credit limits and their overall credit ratings;

•

limiting our marketing, hedging and optimization activities with high risk counterparties;

•

margin, collateral, or prepayment arrangements; and

•

payment netting arrangements, or master netting arrangements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty.

We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk. We currently have no individual significant concentrations of credit risk to a single counterparty; however, a series of defaults or events of nonperformance by several of our individual counterparties could impact our liquidity and future results of operations. We monitor and manage our total comprehensive credit risk associated with all of our contracts and PPAs irrespective of whether they are accounted for as an executory contract, a normal purchase normal sale or whether they are marked-to-market and included in our derivative assets and liabilities on our Consolidated Condensed Balance Sheets. Our counterparty credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our derivative assets and liabilities at September 30, 2011, 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 at September 30, 2011
	2011			2012 - 2013			2014 - 2015		After 2015		Total
Investment grade	$	73		$	27		$	3	$	—	$	103
Non-investment grade		2			(5	)		—		—		(3	)
No external ratings		(2	)		(4	)		—		—		(6	)
Total fair value	$	73		$	18		$	3	$	—	$	94

Interest Rate Risk — Our variable rate financings are indexed to base rates, generally LIBOR. Interest rate risk represents the potential loss in earnings arising from adverse changes in market interest rates. The fair value of our interest rate swaps are validated based upon external quotes. Our interest rate swaps are with counterparties we believe are primarily high quality institutions, and we do not believe that our interest rate swaps expose us to any significant credit risk. Holding all other factors constant, we estimate that a 10% decrease in interest rates would result in a change in the fair value of our interest rate swaps formerly hedging our First Lien Credit Facility of approximately $(3) million, and would result in a change in the fair value of our interest rate swaps hedging our other variable rate debt of approximately $(16) million at September 30, 2011.

New Accounting Standards and Disclosure Requirements

See Note 1 of the Notes to Consolidated Condensed Financial Statements for a discussion of new accounting standards and disclosure requirements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

See “Risk Management and Commodity Accounting” in Item 2.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

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 our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act. Based upon, and 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 and that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of fiscal 2011 that materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

See Note 12 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Repurchase of Equity Securities

	(a)		(b)		(c)		(d)
	Total Number of Shares Purchased(1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2)		Maximum Dollar Value of Shares That May Yet Be Purchased Under the Plan or Programs (in millions)
July		2,069	$	16.39		—		N/A
August		2,145	$	14.64		—	$	300
September		190,225	$	13.95		189,450	$	297
Total		194,439	$	13.98		189,450	$	297

_________

(1)

Upon vesting of restricted stock awarded by us to employees, we withhold shares to cover employees’ tax withholding obligations, other than for employees who have chosen to make tax withholding payments in cash. As set forth in the table above, during the third quarter of 2011, we withheld a total of 4,989 shares in the indicated months that are included in treasury stock.

(2)

Item 6. Exhibits

EXHIBIT INDEX

Exhibit
Number		Description


31.1		Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

101.INS		XBRL Instance Document.†

101.SCH		XBRL Taxonomy Extension Schema.†

101.CAL		XBRL Taxonomy Extension Calculation Linkbase.†

101.DEF		XBRL Taxonomy Extension Definition Linkbase.†

101.LAB		XBRL Taxonomy Extension Label Linkbase.†

101.PRE		XBRL Taxonomy Extension Presentation Linkbase.†

__________

†

XBRL (eXtensible Business Reporting Language) information is furnished, not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise is not subject to liability under those sections.

*	Furnished herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

CALPINE CORPORATION

	By:	/s/ ZAMIR RAUF
		Zamir Rauf
		Executive Vice President and
		Chief Financial Officer

Date: October 27, 2011

EXHIBIT INDEX

Exhibit
Number		Description


31.1		Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

101.INS		XBRL Instance Document.†

101.SCH		XBRL Taxonomy Extension Schema.†

101.CAL		XBRL Taxonomy Extension Calculation Linkbase.†

101.DEF		XBRL Taxonomy Extension Definition Linkbase.†

101.LAB		XBRL Taxonomy Extension Label Linkbase.†

101.PRE		XBRL Taxonomy Extension Presentation Linkbase.†

__________

†

*	Furnished herewith.

For the quarterly period ended September 30, 2011

Or

	[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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

ABBREVIATION		DEFINITION

2010 Form 10-K		Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on February 17, 2011

2017 First Lien Notes		The $1.2 billion aggregate principal amount of 7.25% senior secured notes due 2017, issued October 21, 2009, in exchange for a like principal amount of term loans under the First Lien Credit Facility

2019 First Lien Notes		The $400 million aggregate principal amount of 8.0% senior secured notes due 2019, issued May 25, 2010

2020 First Lien Notes		The $1.1 billion aggregate principal amount of 7.875% senior secured notes due 2020, issued July 23, 2010

2021 First Lien Notes		The $2.0 billion aggregate principal amount of 7.50% senior secured notes due 2021, issued October 22, 2010

2023 First Lien Notes		The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011

AB 32		California Assembly Bill 32

Adjusted EBITDA		EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance expense, (c) operating lease expense, (d) unrealized gains or losses on commodity derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (f) stock-based compensation expense, (g) gains or losses on sales, dispositions or retirements of assets, (h) non-cash gains and losses from foreign currency translations, (i) gains or losses on the repurchase or extinguishment of debt, (j) Conectiv acquisition-related costs, (k) Adjusted EBITDA from our discontinued operations, (l) reorganization items and (m) other extraordinary, unusual or non-recurring items

Aircraft Services		Aircraft Services Corporation, an affiliate of GE Energy Financial Services, Inc.

AOCI		Accumulated Other Comprehensive Income

Average availability		Represents the total hours during the period that our plants were in-service or available for service as a percentage of the total hours in the period

Average capacity factor, excluding peakers		Represents a measure of total actual generation as a percent of total potential generation. It is calculated by dividing (a) total MWh generated by our power plants, excluding peakers, by (b) the product of multiplying (i) the average total MW in operation, excluding peakers, during the period by (ii) the total hours in the period

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

Blue Spruce		Blue Spruce Energy Center, LLC, formerly an indirect, wholly owned subsidiary that owned Blue Spruce Energy Center, a 310 MW natural gas-fired, peaker power plant located in Aurora, Colorado, which was sold on December 6, 2010

Btu		British thermal unit(s), a measure of heat content

CAA		Federal Clean Air Act, U.S. Code Title 42, Chapter 85

CAISO		California Independent System Operator

CalGen		Calpine Generating Company, LLC, an indirect, wholly owned subsidiary

CalGen Third Lien Debt		Together, the $680 million Third Priority Secured Floating Rate Notes Due 2011, issued by CalGen and CalGen Finance Corp.; and the $150 million 11.50% Third Priority Secured Notes Due 2011, issued by CalGen and CalGen Finance Corp., in each case repaid on March 29, 2007

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

CARB		California Air Resources Board

CCFC		Calpine Construction Finance Company, L.P., an indirect, wholly owned subsidiary

CCFC Notes		The $1.0 billion aggregate principal amount of 8.0% Senior Secured Notes due 2016 issued May 19, 2009, by CCFC and CCFC Finance Corp.

CEHC		Conectiv Energy Holding Company, LLC, a wholly owned subsidiary of Conectiv

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

CO2		Carbon dioxide

COD		Commercial operations date

Cogeneration		Using a portion or all of the steam generated in the power generating process to supply a customer with steam for use in the customer’s operations

Commodity expense		The sum of our expenses from fuel and purchased energy expense, fuel transportation expense, transmission expense and cash settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales that are included in our mark-to-market activity in fuel and purchased energy expense, but excludes the unrealized portion of our mark-to-market activity

Commodity Margin		Non-GAAP financial measure that includes power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, RGGI compliance and other environmental costs, and cash settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales that are included in mark-to-market activity, but excludes the unrealized portion of our mark-to-market activity and other revenues

Commodity revenue		The sum of our revenues from power and steam sales, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue, and cash settlements from our marketing, hedging and optimization activities that are included in our mark-to-market activity in operating revenues, but excludes the unrealized portion of our mark-to-market activity

Company		Calpine Corporation, a Delaware corporation, and its subsidiaries

Conectiv		Conectiv, LLC, a wholly owned subsidiary of PHI

Conectiv Acquisition		The acquisition of all of the membership interests in CEHC pursuant to the Conectiv Purchase Agreement on July 1, 2010, whereby we acquired all of the power generation assets of Conectiv from PHI, which included 18 operating power plants and York Energy Center that was under construction and achieved COD on March 2, 2011, with 4,491 MW of capacity

Conectiv Purchase Agreement		Purchase Agreement by and among PHI, Conectiv, CEHC and NDH dated as of April 20, 2010

Corporate Revolving Facility		The $1.0 billion aggregate revolving credit facility credit agreement, dated as of December 10, 2010, among Calpine Corporation, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, the lenders party thereto and the other parties thereto

CPUC		California Public Utilities Commission

Director Plan		The Amended and Restated Calpine Corporation 2008 Director Incentive Plan

Dodd-Frank Act		The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010

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

Emergence Date Market Capitalization		The weighted average trading price of Calpine Corporation’s common stock over the 30-day period following the date on which it emerged from Chapter 11 bankruptcy protection, as defined in and calculated pursuant to Calpine Corporation’s amended and restated certificate of incorporation and reported in its Current Report on Form 8-K filed with the SEC on March 25, 2008

EPA		U.S. Environmental Protection Agency

Equity Plan		The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan

ERCOT		Electric Reliability Council of Texas

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

FDIC		U.S. Federal Deposit Insurance Corporation

FERC		U.S. Federal Energy Regulatory Commission

First Lien Credit Facility		Credit Agreement, dated as of January 31, 2008, as amended by the First Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement, dated as of August 20, 2009, among Calpine Corporation, as borrower, certain subsidiaries of the Company named therein, as guarantors, the lenders party thereto, Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent, and the other agents named therein

First Lien Notes		Collectively, the 2017 First Lien Notes, the 2019 First Lien Notes, the 2020 First Lien Notes, the 2021 First Lien Notes and the 2023 First Lien Notes

GE		General Electric International, Inc.

Geysers Assets		Our geothermal power plant assets, including our steam extraction and gathering assets, located in northern California consisting of 15 operating power plants and one plant not in operation

GHG(s)		Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)

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

INDEX

	Page
Definitions	iii

Forward-Looking Statements	ix

Where You Can Find Other Information	x

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements
Consolidated Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010	1
Consolidated Condensed Balance Sheets at September 30, 2011, and December 31, 2010	2
Consolidated Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010	3
Notes to Consolidated Condensed Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Introduction and Overview	32
Results of Operations	37
Commodity Margin and Adjusted EBITDA	43
Liquidity and Capital Resources	51
Risk Management and Commodity Accounting	59
New Accounting Standards and Disclosure Requirements	62
Item 3. Quantitative and Qualitative Disclosures About Market Risk	63
Item 4. Controls and Procedures	63

PART II — OTHER INFORMATION

Item 1. Legal Proceedings	64
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	64
Item 6. Exhibits	65
Signatures	66

Greenfield LP		Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada

Heat Rate(s)		A measure of the amount of fuel required to produce a unit of power

ISRA		Industrial Site Recovery Act

kWh		Kilowatt-hour(s), a measure of power produced

LIBOR		London Inter-Bank Offered Rate

Los Esteros Project Debt		Credit Agreement dated August 23, 2011, between Los Esteros Critical Energy Facility, LLC, as borrower, and the lenders named therein

Mankato		Mankato Energy Center, a 375 MW natural gas-fired, combined-cycle power plant located in Mankato, Minnesota

Market Capitalization		As of any date, Calpine Corporation’s then market capitalization calculated using the rolling 30-day weighted average trading price of Calpine Corporation’s common stock, as defined in and calculated in accordance with the Calpine Corporation amended and restated certificate of incorporation

Market Heat Rate(s)		The regional power price divided by the corresponding regional natural gas price

MMBtu		Million Btu

MRTU		CAISO’s Market Redesign and Technology Upgrade

MW		Megawatt(s), a measure of plant capacity

MWh		Megawatt hour(s), a measure of power produced

NDH		New Development Holdings, LLC, an indirect, wholly owned subsidiary

NDH Project Debt		The $1.3 billion senior secured term loan facility and the $100 million revolving credit facility issued on July 1, 2010, under the credit agreement, dated as of June 8, 2010, among NDH, as borrower, Credit Suisse AG, as administrative agent, collateral agent, issuing bank and syndication agent, Credit Suisse Securities (USA) LLC, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as joint book-runners and joint lead arrangers, Credit Suisse AG, Citibank, N.A., and Deutsche Bank Trust Company Americas, as co-documentation agents and the lenders party thereto repaid on March 9, 2011

New Term Loan		The $360 million first lien senior secured term loan, dated June 17, 2011, among Calpine Corporation, as borrower, and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent

NOL(s)		Net operating loss(es)

NOx		Nitrogen oxides

NYMEX		New York Mercantile Exchange

OCI		Other Comprehensive Income

OMEC		Otay Mesa Energy Center, LLC, an indirect, wholly owned subsidiary that owns the Otay Mesa Energy Center, a 608 MW natural gas-fired, combined-cycle power plant located in San Diego county, California

OTC		Over-the-Counter

PG&E		Pacific Gas & Electric Company

PHI		Pepco Holdings, Inc.

PJM		Pennsylvania – New Jersey – Maryland Interconnection

Plan of Reorganization		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

PPA(s)		Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including power, 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 the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam

PUCT		Public Utility Commission of Texas

PURPA		U.S. Public Utility Regulatory Policies Act of 1978

QF(s)		Qualifying facility(ies), which are cogeneration facilities and certain small power production facilities eligible to be “qualifying facilities” under PURPA, provided that they meet certain power and thermal energy production requirements and efficiency standards. QF status provides an exemption from U.S. Public Utility Holding Company Act of 2005 and grants certain other benefits to the QF

REC		Renewable Energy Credit

RGGI		Regional Greenhouse Gas Initiative

Rocky Mountain		Rocky Mountain Energy Center, LLC, formerly an indirect, wholly owned subsidiary that owned Rocky Mountain Energy Center, a 621 MW natural gas-fired, combined-cycle power plant located in Keenesburg, Colorado, which was sold on December 6, 2010

RPS		Renewable Portfolio Standards

Russell City		Russell City Energy Center, a 619 MW natural gas-fired, combined-cycle power plant under construction and located in Hayward, California, of which, Calpine owns 75%

Russell City Project Debt		Credit Agreement dated June 24, 2011, between Russell City Energy Company, LLC, as borrower, and the lenders named therein

SEC		U.S. Securities and Exchange Commission

SO2		Sulfur dioxide

South Point		South Point Energy Center, a 530 MW natural gas-fired, combined-cycle power plant located in Mohave Valley, Arizona

Spark Spread(s)		The difference between the sales price of power per MWh and the cost of fuel to produce it

Steam Adjusted Heat Rate		The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the kWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation

Term Loan		The $1.3 billion first lien senior secured term loan, dated March 9, 2011, among Calpine Corporation, as borrower, and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, Citibank, N.A., Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as co-documentation agents and Goldman Sachs Bank USA as syndication agent

U.S. Debtors		Calpine Corporation and each of its subsidiaries and affiliates that filed voluntary petitions for reorganization under Chapter 11 of the U.S. 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)

U.S. GAAP		Generally accepted accounting principles in the U.S.

VAR		Value-at-risk

VIE(s)		Variable interest entity(ies)

Whitby		Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Whitby 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada

York Energy Center		565 MW dual fuel, combined-cycle generation power plant (formerly known as the Delta Project) located in Peach Bottom Township, Pennsylvania, included in the Conectiv Acquisition, which achieved COD on March 2, 2011