Document and Entity Information

6 Months Ended

Jun. 30, 2013

Jul. 23, 2013

Entity Information [Line Items]

Entity Registrant Name

CALPINE CORP

Entity Central Index Key

0000916457

Current Fiscal Year End Date

--12-31

Entity Filer Category

Large Accelerated Filer

Document Type

10-Q

Document Period End Date

Jun. 30, 2013

Document Fiscal Year Focus

2013

Document Fiscal Period Focus

Q2

Amendment Flag

false

Entity Common Stock, Shares Outstanding

439,023,991

Consolidated Statements of Operations (USD $)

In Millions, except Share data in Thousands, unless otherwise specified

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Operating revenues:

Commodity revenue

$ 1,539

$ 1,177

$ 2,847

$ 2,389

Unrealized mark-to-market gain (loss)

31

(302)

(40)

(280)

Other revenue

2

4

6

Operating revenues

1,572

879

2,813

2,115

Operating expenses:

Commodity expense

998

570

1,833

1,261

Unrealized mark-to-market (gain) loss

2

44

(12)

Fuel and purchased energy expense

1,000

614

1,821

1,249

Plant operating expense

257

271

484

492

Depreciation and amortization expense

145

138

291

278

Sales, general and other administrative expense

36

35

69

68

Other operating expenses

20

19

38

40

Total operating expenses

1,458

1,077

2,703

2,127

(Income) from unconsolidated investments in power plants

(8)

(5)

(16)

(14)

Income (loss) from operations

122

(193)

126

2

Interest expense

170

184

346

369

Loss on interest rate derivatives

0

14

Interest (income)

(1)

(2)

(3)

(5)

Debt extinguishment costs

68

0

68

12

Other (income) expense, net

3

6

8

Income (loss) before income taxes

(118)

(381)

(293)

(396)

Income tax benefit

(48)

(52)

(98)

(58)

Net loss

(70)

(329)

(195)

(338)

Net income attributable to the noncontrolling interest

0

Net loss attributable to Calpine

$ (70)

$ (329)

$ (195)

$ (338)

Basic and diluted loss per common share attributable to Calpine:

Weighted average shares of common stock outstanding (in thousands)

447,558

471,444

449,620

474,775

Net loss per common share attributable to Calpine — basic and diluted

$ (0.16)

$ (0.69)

$ (0.43)

$ (0.71)

Consolidated Statements of Comprehensive Income (USD $)

In Millions, unless otherwise specified

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Net loss

$ (70)

$ (329)

$ (195)

$ (338)

Cash flow hedging activities:

Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss

38

(44)

42

(34)

Reclassification adjustment for (gain) loss on cash flow hedges realized in net loss

10

(4)

19

(14)

Foreign currency translation loss

(5)

(4)

(7)

(1)

Income tax benefit

2

3

4

Other comprehensive income (loss)

45

(50)

57

(45)

Comprehensive loss

(25)

(379)

(138)

(383)

Comprehensive (income) attributable to the noncontrolling interest

0

Comprehensive loss attributable to Calpine

$ (25)

$ (379)

$ (138)

$ (383)

Consolidated Balance Sheets (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Current assets:

Cash and cash equivalents ($112 and $109 attributable to VIEs)

$ 715

$ 1,284

Accounts receivable, net of allowance of $2 and $6

726

437

Margin deposits and other prepaid expense

310

244

Restricted cash, current ($69 and $53 attributable to VIEs)

140

193

Derivative assets, current

601

339

Inventory and other current assets

447

335

Total current assets

2,939

2,832

Property, plant and equipment, net ($4,644 and $4,192 attributable to VIEs)

13,057

13,005

Restricted cash, net of current portion ($57 and $59 attributable to VIEs)

58

60

Investments in power plants

85

81

Long-term derivative assets

136

98

Other assets

483

473

Total assets

16,758

16,549

Current liabilities:

Accounts payable

551

382

Accrued interest payable

175

180

Debt, current portion ($105 and $39 attributable to VIEs)

169

115

Derivative liabilities, current

630

357

Other current liabilities

206

284

Total current liabilities

1,731

1,318

Debt, net of current portion ($2,913 and $2,660 attributable to VIEs)

10,851

10,635

Deferred income tax liability, non-current

3

0

Long-term derivative liabilities

291

293

Other long-term liabilities

298

247

Total liabilities

13,174

12,493

Commitments and contingencies (see Note 10)

Stockholders’ equity:

Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding

0

Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 495,214,960 and 492,495,100 shares issued, respectively, and 441,671,019 and 457,048,970 shares outstanding, respectively

1

Treasury stock, at cost, 53,543,941 and 35,446,130 shares, respectively

(962)

(594)

Additional paid-in capital

12,370

12,335

Accumulated deficit

(7,695)

(7,500)

Accumulated other comprehensive loss

(191)

(248)

Total Calpine stockholders’ equity

3,523

3,994

Noncontrolling interest

61

62

Total stockholders’ equity

3,584

4,056

Total liabilities and stockholders’ equity

$ 16,758

$ 16,549

Consolidated Balance Sheets (Parenthetical) (USD $)

In Millions, except Share data, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Cash and Cash Equivalents, at Carrying Value

$ 715

$ 1,284

Allowance for Doubtful Accounts Receivable, Current

2

6

Restricted cash, current ($69 and $53 attributable to VIEs)

140

193

Property, plant and equipment, net ($4,644 and $4,192 attributable to VIEs)

13,057

13,005

Restricted cash, net of current portion ($57 and $59 attributable to VIEs)

58

60

Debt, Current

169

115

Debt, net of current portion ($2,913 and $2,660 attributable to VIEs)

10,851

10,635

Preferred Stock, Par or Stated Value Per Share

$ 0.001

Preferred Stock, Shares Authorized

100,000,000

Preferred Stock, Shares Issued

0

Preferred Stock, Shares Outstanding

0

Common Stock, Par or Stated Value Per Share

$ 0.001

Common Stock, Shares Authorized

1,400,000,000

Common Stock, Shares, Issued

495,214,960

492,495,100

Common Stock, Shares, Outstanding

441,671,019

457,048,970

Treasury Stock, Shares

53,543,941

35,446,130

Variable Interest Entity, Primary Beneficiary [Member]

Cash and Cash Equivalents, at Carrying Value

112

109

Restricted cash, current ($69 and $53 attributable to VIEs)

69

53

Property, plant and equipment, net ($4,644 and $4,192 attributable to VIEs)

4,644

4,192

Restricted cash, net of current portion ($57 and $59 attributable to VIEs)

57

59

Debt, Current

105

39

Debt, net of current portion ($2,913 and $2,660 attributable to VIEs)

$ 2,913

$ 2,660

Consolidated Statements of Cash Flows (USD $)

In Millions, unless otherwise specified

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Cash flows from operating activities:

Net loss

$ (195)

$ (338)

Adjustments to reconcile net loss to net cash used in operating activities:

Depreciation and amortization expense(1)

315 ¹

299 ¹

Debt extinguishment costs

28

0

Deferred income taxes

(15)

(31)

Loss on disposition of assets

4

Unrealized mark-to-market activity, net

24 ²

119 ²

(Income) from unconsolidated investments in power plants

(16)

(14)

Return on unconsolidated investments in power plants

16

Stock-based compensation expense

20

13

Other

(4)

1

Change in operating assets and liabilities:

Accounts receivable

(285)

63

Derivative instruments, net

1

(111)

Other assets

(182)

(122)

Accounts payable and accrued expenses

67

(86)

Settlement of non-hedging interest rate swaps

0

156

Other liabilities

47

(1)

Net cash used in operating activities

(175)

(32)

Cash flows from investing activities:

Purchases of property, plant and equipment

(335)

(369)

Settlement of non-hedging interest rate swaps

0

(156)

Decrease in restricted cash

55

19

Purchases of deferred transmission credits

0

(12)

Other

(1)

5

Net cash used in investing activities

(281)

(513)

Cash flows from financing activities:

Repayment under First Lien Term Loans

(12)

(8)

Borrowings from CCFC Term Loans

1,197

0

Repayment of CCFC Notes

(1,000)

0

Borrowings from project financing, notes payable and other

116

226

Repayments of project financing, notes payable and other

(43)

(46)

Financing costs

(27)

(5)

Stock repurchases

(362)

(290)

Proceeds from exercises of stock options

17

3

Other

1

0

Net cash used in financing activities

(113)

(120)

Net decrease in cash and cash equivalents

(569)

(665)

Cash and cash equivalents, beginning of period

1,284

1,252

Cash and cash equivalents, end of period

715

587

Cash paid during the period for:

Interest, net of amounts capitalized

334

352

Income taxes

21

13

Supplemental disclosure of non-cash investing activities:

Change in capital expenditures included in accounts payable

$ 17

$ 3

[1] Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations

[2] In addition to changes in market value on derivatives not designated as hedges, changes in unrealized gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

Summary of Significant Accounting Policies

Basis of Presentation and Summary of Significant Accounting Policies

We are a 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 major competitive wholesale power markets in California, Texas and the Mid-Atlantic region of the U.S. We sell wholesale power, steam, 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 purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. 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.

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, 2012, included in our 2012 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, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and unrealized gains and losses from commodity and interest rate derivative contracts.

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.

Reclassifications — Certain reclassifications have been made to our Consolidated Condensed Statements of Operations and Cash Flows for the period ended June 30, 2012, to conform to the current period presentation. Our reclassifications are summarized as follows:


•	We have reclassified environmental compliance expense, primarily related to costs to comply with the Regional Greenhouse Gas Initiative in the Northeast, previously recorded in other operating expenses of $2 million and $5 million to Commodity expense on our Consolidated Condensed Statements of Operations for the three and six months ended June 30, 2012, respectively.


•	We have reclassified $3 million on our Consolidated Condensed Statement of Cash Flows for the six months ended June 30, 2012, to separately report proceeds from the exercises of stock options, previously reflected in other cash flows used in financing activities.

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 June 30, 2013 and December 31, 2012, cash and cash equivalents included $127 million and $131 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 Statements of Cash Flows.

The table below represents the components of our restricted cash as of June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013						December 31, 2012
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service⁽¹⁾	$	14	$	42	$	56	$	11	$	41	$	52
Rent reserve	7		—		7		—		—		—
Construction/major maintenance	26		8		34		32		14		46
Security/project/insurance	73		6		79		101		3		104
Other	20		2		22		49		2		51
Total	$	140	$	58	$	198	$	193	$	60	$	253

___________


(1)	At June 30, 2013 and December 31, 2012, amounts restricted for debt service included approximately $24 million and $25 million, respectively, of repurchase agreements with a financial institution containing maturity dates greater than one year.

Inventory — At June 30, 2013 and December 31, 2012, we had inventory of $345 million and $301 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 or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.

Property, Plant and Equipment, Net — At June 30, 2013 and December 31, 2012, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):



	June 30, 2013		December 31, 2012		Depreciable Lives
Buildings, machinery and equipment	$	14,815	$	14,774	3 – 47 Years
Geothermal properties	1,248		1,243		13 – 59 Years
Other	156		142		3 – 47 Years
	16,219		16,159
Less: Accumulated depreciation	4,641		4,390
	11,578		11,769
Land	103		98
Construction in progress	1,376		1,138
Property, plant and equipment, net	$	13,057	$	13,005

Capitalized Interest — The total amount of interest capitalized was $12 million and $9 million for the three months ended June 30, 2013 and 2012, respectively, and $24 million and $17 million for the six months ended June 30, 2013 and 2012, respectively.

Treasury Stock — During the six months ended June 30, 2013, we repurchased common stock with a value of $362 million under our previously announced share repurchase program and withheld shares with a value of $6 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees under the Equity Plan.

New Accounting Standards and Disclosure Requirements

Disclosures about Offsetting Assets and Liabilities — In December 2011, the FASB issued Accounting Standards Update 2011-11, “Balance Sheet - Disclosures about Offsetting Assets and Liabilities” to enhance disclosure requirements relating to the offsetting of assets and liabilities on an entity’s balance sheet. The update requires enhanced disclosures regarding assets and liabilities that are presented net or gross in the statement of financial position when the right of offset exists, or that are subject to an enforceable master netting arrangement. In January 2013, the FASB issued Accounting Standards Update 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities” to provide clarification that the scope previously defined in Accounting Standards Update 2011-11 applies to derivatives, repurchase agreements, reverse repurchase agreements and securities borrowing and lending transactions that are subject to an enforceable master netting arrangement or similar agreement. The new disclosure requirements relating to these updates are retrospective and effective for annual and interim periods beginning on or after January 1, 2013. We adopted Accounting Standards Updates 2011-11 and 2013-01 as of January 1, 2013. As these updates only required additional disclosures, adoption of these standards did not have a material impact on our financial condition, results of operations or cash flows. See Note 5 for disclosures regarding our assets and liabilities that are presented gross on our Consolidated Condensed Balance Sheets when the right of offset exists, or that are subject to an enforceable master netting arrangement.

Comprehensive Income — In February 2013, the FASB issued Accounting Standards Update 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” to amend the reporting of reclassifications out of AOCI to require an entity to report the effect of significant reclassifications out of AOCI on the respective line items in net income if the amount reclassified is required under U.S. GAAP to be reclassified in its entirety to net income in the same reporting period. An entity shall provide this information together in one location, either on the face of the statement where net income is presented, or as a separate disclosure in the notes to the financial statements. The new disclosure requirements relating to this update are prospective and effective for interim and annual periods beginning after December 15, 2012, with early adoption permitted. We adopted Accounting Standards Update 2013-02 as of January 1, 2013. As this update only required additional disclosures, adoption of this standard did not have a material impact on our financial condition, results of operations or cash flows. See Note 5 for disclosures on the affect of significant reclassifications out of AOCI on the respective line items on our Consolidated Condensed Statements of Operations.

Income Taxes — In July 2013, the FASB issued Accounting Standards Update 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists”. The provisions of the rule require an unrecognized tax benefit to be presented as a reduction to a deferred tax asset in the financial statements for an NOL carryforward, a similar tax loss, or a tax credit carryforward except in circumstances when the carryforward or tax loss is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes. When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The new financial statement presentation provisions relating to this update are prospective and effective for interim and annual periods beginning after December 15, 2013, with early adoption permitted. We are currently assessing the future impact of this update, but we do not anticipate a material impact on our financial condition, results of operations or cash flows.

Variable Interest Entities and Unconsolidated Investments

Variable Interest Entities and Unconsolidated Investments [Text Block]

Variable Interest Entities and Unconsolidated Investments in Power Plants

We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the six months ended June 30, 2013. See Note 5 in our 2012 Form 10-K for further information regarding our VIEs.

VIE Disclosures

Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 9,027 MW and 8,255 MW at June 30, 2013 and December 31, 2012, 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. In addition to amounts contractually required, Calpine Corporation did not provide any support to these VIEs in the form of cash and other contributions during each of the three and six months ended June 30, 2013 and 2012.

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 be used only 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 meet the separate disclosure criteria, we consider that 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 our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation and where the amounts were material to our financial statements.

Unconsolidated VIEs and Investments in Power Plants

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 in power plants on our Consolidated Condensed Balance Sheets. At June 30, 2013 and December 31, 2012, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):



	Ownership Interest as of June 30, 2013	June 30, 2013		December 31, 2012
Greenfield LP	50%	$	75	$	69
Whitby	50%	10		12
Total investments in power plants		$	85	$	81

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 June 30, 2013 and December 31, 2012, equity method investee debt was approximately $412 million and $448 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $206 million and $224 million at June 30, 2013 and December 31, 2012, respectively.

Our equity interest in the net income from Greenfield LP and Whitby for the three and six months ended June 30, 2013 and 2012, is 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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Greenfield LP	$	(5	)	$	(2	)	$	(9	)	$	(8	)
Whitby	(3		)	(3		)	(7		)	(6		)
Total	$	(8	)	$	(5	)	$	(16	)	$	(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 with an original principal amount of CAD $648 million. Distributions from Greenfield LP were $7 million during each of the three and six months ended June 30, 2013, and $9 million during each of the three and six months ended June 30, 2012.

Whitby — Whitby is a limited partnership between certain of our subsidiaries 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 $9 million during each of the three and six months ended June 30, 2013, and $7 million during each of the three months and six months ended June 30, 2012.

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) from GE that may be exercised between years 2017 and 2024. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met by 2025. We determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to the fact that GE directs the most significant activities of the power plant including operations and maintenance.

Debt


	Debt

At June 30, 2013 and December 31, 2012, our debt was as follows (in millions):



	June 30, 2013		December 31, 2012
First Lien Notes	$	5,304	$	5,303
First Lien Term Loans	2,450		2,463
Project financing, notes payable and other	1,858		1,789
CCFC Term Loans	1,197		—
CCFC Notes	—		978
Capital lease obligations	211		217
Total debt	11,020		10,750
Less: Current maturities	169		115
Debt, net of current portion	$	10,851	$	10,635

Our effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and unrealized gains (losses) on interest rate swaps, decreased to 6.9% for the six months ended June 30, 2013, from 7.4% for the six months ended June 30, 2012. The issuance of our 2019 First Lien Term Loan in October 2012 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Notes and variable rate project debt with a corporate level term loan carrying a lower variable interest rate. Also, in February 2013, we repriced our First Lien Term Loans by lowering the LIBOR floor by 0.25% to 1.0% and lowering the margin over LIBOR by 0.25% to 3.0%. The issuance of the CCFC Term Loans in June 2013 also allowed us to reduce our interest expense by replacing the CCFC Notes carrying a higher fixed interest rate with the CCFC Term Loans carrying a lower variable interest rate.

First Lien Notes

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



	June 30, 2013		December 31, 2012
2017 First Lien Notes	$	1,080	$	1,080
2019 First Lien Notes	360		360
2020 First Lien Notes	984		983
2021 First Lien Notes	1,800		1,800
2023 First Lien Notes	1,080		1,080
Total First Lien Notes	$	5,304	$	5,303

First Lien Term Loans

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



	June 30, 2013		December 31, 2012
2018 First Lien Term Loans	$	1,621	$	1,630
2019 First Lien Term Loan	829		833
Total First Lien Term Loans	$	2,450	$	2,463

CCFC Term Loans

On May 3, 2013, CCFC entered into a credit agreement providing for a first lien senior secured term loan facility comprised of (i) a $900 million 7-year term loan and (ii) a $300 million 8.5-year term loan.

CCFC utilized the proceeds received from CCFC Term Loans to redeem the entire $1.0 billion in principal amount of CCFC Notes at a redemption price equal to 104% (plus accrued and unpaid interest), to pay related transaction expenses and for corporate purposes, as described in the credit agreement. The CCFC Notes were redeemed on June 3, 2013, at which date the CCFC Term Loans were fully drawn.

The CCFC Term Loans bear interest, at CCFC’s option, at either (i) the Base Rate, equal to the higher of the Federal Funds Effective Rate plus 0.50% per annum or the Prime Rate (as such terms are defined in the Credit Agreement), plus an applicable margin of (a) 1.25% per annum with respect to the 7-year term loan and (b) 1.50% per annum with respect to the 8.5-year term loan, or (ii) LIBOR plus (a) 2.25% per annum with respect to the 7-year term loan and (b) 2.50% per annum with respect to the 8.5-year term loan (in each case subject to a LIBOR floor of 0.75%). The term loans were offered to investors at an issue price equal to 99.75% of face value.

An amount equal to 0.25% of the aggregate principal amount of the CCFC Term Loans are payable at the end of each quarter commencing in September 2013, with the remaining balance payable on the relevant maturity date (May 3, 2020 with respect to the 7-year term loan and January 31, 2022 with respect to the 8.5-year term loan). CCFC may elect from time to time to convert all or a portion of the CCFC Term Loans from LIBOR loans to Base Rate loans or vice versa. In addition, CCFC may at any time, and from time to time, prepay the Term Loans, in whole or in part, without premium or penalty, upon irrevocable notice to the administrative agent.

The CCFC Term Loans are secured by certain real and personal property of CCFC consisting primarily of six natural gas-fired power plants. The CCFC Term Loans are not guaranteed by Calpine Corporation and are without recourse to Calpine Corporation or any of our non-CCFC subsidiaries or assets; however, CCFC generates the majority of its cash flows from an intercompany tolling agreement with Calpine Energy Services, L.P. and has various service agreements in place with other subsidiaries of Calpine Corporation.

In connection with the redemption of the CCFC Notes, we recorded $68 million in debt extinguishment costs for the three and six months ended June 30, 2013 which is comprised of $40 million of prepayment penalties and $28 million associated with the write-off of unamortized debt discount and deferred financing costs. We also recorded $15 million in new deferred financing costs on our Consolidated Condensed Balance Sheet during the second quarter of 2013 associated with the issuance of the CCFC Term Loans.

Corporate Revolving Facility and Other Letters of Credit Facilities

On June 27, 2013, we executed Amendment No.1 to the Corporate Revolving Facility. Certain key terms of the amendment are listed below:


•	the applicable margin has been reduced from 3.25% to 2.25% for LIBOR rate borrowings and from 2.25% to 1.25% for base rate borrowings;


•	the fee on the undrawn commitment has been reduced from 0.75% to 0.50%; and


•	the maturity date of the Corporate Revolving Facility has been extended to June 27, 2018.

The table below represents amounts issued under our letter of credit facilities at June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013		December 31, 2012
Corporate Revolving Facility⁽¹⁾	$	240	$	243
CDHI	243		253
Various project financing facilities	131		130
Total	$	614	$	626

____________


(1)	The Corporate Revolving Facility represents our primary revolving facility.

CDHI

We have a $300 million letter of credit facility related to CDHI. As a result of the completion of the sale of Riverside Energy Center, LLC, a wholly-owned subsidiary of CDHI, on December 31, 2012, we are required to cash collateralize letters of credit issued in excess of $225 million until replacement collateral is contributed to the CDHI collateral package, which we are in the process of arranging. At June 30, 2013, we had $18 million in outstanding letters of credit issued in excess of $225 million under our CDHI letter of credit facility that were collateralized by cash.

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. The following table details the fair values and carrying values of our debt instruments at June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013				December 31, 2012
	Fair Value		Carrying Value		Fair Value		Carrying Value
First Lien Notes	$	5,621	$	5,304	$	5,863	$	5,303
First Lien Term Loans	2,452		2,450		2,489		2,463
Project financing, notes payable and other⁽¹⁾	1,670		1,723		1,599		1,629
CCFC Term Loans	1,180		1,197		—		—
CCFC Notes	—		—		1,075		978
Total	$	10,923	$	10,674	$	11,026	$	10,373

____________


(1)	Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

We measure the fair value of our First Lien Notes, First Lien Term Loans, CCFC Term Loans and CCFC Notes using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.

Assets and Liabilities with Recurring Fair Value Measurements

Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts, are included in both our cash and cash equivalents and our 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 Posted with Us by Our Counterparties — Margin deposits and margin deposits posted with us by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits posted with us 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); changing commodity market prices, primarily 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. Prices for power and natural gas and interest rates 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 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. We use other qualitative assessments 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 power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange.

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 market sources 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 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 may consist of 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. OTC options are valued using industry-standard models, including the Black-Scholes option-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.

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. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2013 and December 31, 2012, by level within the fair value hierarchy:



	Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2013
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	871	$	—	$	—	$	871
Margin deposits	276		—		—		276
Commodity instruments:
Commodity exchange traded futures and swaps contracts	595		—		—		595
Commodity forward contracts⁽²⁾	—		112		22		134
Interest rate swaps	—		8		—		8
Total assets	$	1,742	$	120	$	22	$	1,884
Liabilities:
Margin deposits posted with us by our counterparties	$	3	$	—	$	—	$	3
Commodity instruments:
Commodity exchange traded futures and swaps contracts	646		—		—		646
Commodity forward contracts⁽²⁾	—		121		9		130
Interest rate swaps	—		145		—		145
Total liabilities	$	649	$	266	$	9	$	924



	Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2012
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	1,502	$	—	$	—	$	1,502
Margin deposits	196		—		—		196
Commodity instruments:
Commodity exchange traded futures and swaps contracts	385		—		—		385
Commodity forward contracts⁽²⁾	—		24		24		48
Interest rate swaps	—		4		—		4
Total assets	$	2,083	$	28	$	24	$	2,135
Liabilities:
Margin deposits posted with us by our counterparties	$	11	$	—	$	—	$	11
Commodity instruments:
Commodity exchange traded futures and swaps contracts	424		—		—		424
Commodity forward contracts⁽²⁾	—		18		8		26
Interest rate swaps	—		200		—		200
Total liabilities	$	435	$	218	$	8	$	661

___________


(1)	As of June 30, 2013 and December 31, 2012, we had cash equivalents of $699 million and $1,274 million included in cash and cash equivalents and $172 million and $228 million included in restricted cash, respectively.


(2)	Includes OTC swaps and options.

At June 30, 2013 and December 31, 2012, the derivative instruments classified as level 3 primarily included a longer-term OTC traded commodity contract which is classified as level 3 because the contract terms relate to a delivery location for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices; however, given the nature of our net derivative position, we do not believe that a significant change in market commodity prices would have a material impact on our level 3 net fair value. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at June 30, 2013 and December 31, 2012:



	Quantitative Information about Level 3 Fair Value Measurements
	June 30, 2013
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Physical Power	$	6	Discounted cash flow	Market price (per MWh)	$31.00 — $50.00/MWh

	December 31, 2012
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Physical Power	$	11	Discounted cash flow	Market price (per MWh)	$23.75 — $53.82/MWh

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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Balance, beginning of period	$	13		$	17		$	16		$	17
Realized and unrealized gains (losses):
Included in net loss:
Included in operating revenues⁽¹⁾	3			(24		)	4			(17		)
Included in fuel and purchased energy expense⁽²⁾	—			2			—			—
Included in OCI	—			—			—			4
Purchases, issuances and settlements:
Purchases	1			1			1			1
Issuances	—			(1		)	(1		)	(1		)
Settlements	(3		)	(5		)	(5		)	(11		)
Transfers in and/or out of level 3⁽³⁾:
Transfers into level 3⁽⁴⁾	—			—			—			—
Transfers out of level 3⁽⁵⁾	(1		)	—			(2		)	(3		)
Balance, end of period	$	13		$	(10	)	$	13		$	(10	)
Change in unrealized gains (losses) relating to instruments still held at end of period	$	3		$	(22	)	$	4		$	(17	)

___________


(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 transfers into or out of level 1 for each of the three and six months ended June 30, 2013 and 2012.


(4)	There were no transfers out of level 2 into level 3 for each of the three and six months ended June 30, 2013 and 2012.

(5)

We had $1 million in gains transferred out of level 3 into level 2 for the three months ended June 30, 2013 and $2 million and $3 million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2013 and 2012, respectively, due to changes in market liquidity in various power markets. There were no transfers out of level 3 into level 2 for the three months ended June 30, 2012.

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. As of June 30, 2013, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 10 years.

As of June 30, 2013 and December 31, 2012, 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:



Derivative Instruments	Notional Amounts
Derivative Instruments	June 30, 2013			December 31, 2012
Power (MWh)	(11		)	(16		)
Natural gas (MMBtu)	163			66
Interest rate swaps (in millions)	$	1,597		$	1,602

Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty 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 notch downgrade from its current level would be material. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of June 30, 2013, was $16 million for which we have posted collateral of $7 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that no additional collateral 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. In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this election are reflected in unrealized mark-to-market gain/loss on our Consolidated Condensed Statements of Operations and could create more volatility in our earnings. Revenues and fuel costs derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Although we have discontinued the application of hedge accounting treatment for our commodity derivative instruments, prior to this change and for our interest rate swaps, 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 (or economically 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) 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 recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in unrealized mark-to-market gain/loss as a component of operating revenues (for power contracts and swaps) and fuel and purchased energy expense (for natural gas contracts and swaps). Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of 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.

Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas and interest rate transactions that primarily act as economic hedges to our asset and interest rate 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 commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in unrealized mark-to-market gain/loss as a component of operating revenues (for power contracts and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, swaps and options). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense (for interest rate swaps except as discussed below).

Interest Rate Swaps Formerly Hedging our First Lien Credit Facility — On March 26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and recorded the fair value of the swaps totaling approximately $156 million. Approximately $14 million of the settlement amount was recorded as a component of loss on interest rate derivatives on our Consolidated Condensed Statement of Operations for the six months ended June 30, 2012, and approximately $142 million reflected the realization of losses recorded in prior periods.

Derivatives Included on Our Consolidated Condensed Balance Sheets

During the first quarter of 2012, we de-designated our remaining commodity derivative cash flow hedges; therefore, as of June 30, 2013 and December 31, 2012, we do not have any designated commodity derivative cash flow hedges. 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 June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013
	Commodity Instruments			Interest Rate Swaps			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	601		$	—		$	601
Long-term derivative assets	128			8			136
Total derivative assets	$	729		$	8		$	737

Current derivative liabilities	$	583		$	47		$	630
Long-term derivative liabilities	193			98			291
Total derivative liabilities	$	776		$	145		$	921
Net derivative liabilities	$	(47	)	$	(137	)	$	(184	)



	December 31, 2012
	Commodity Instruments			Interest Rate Swaps			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	339		$	—		$	339
Long-term derivative assets	94			4			98
Total derivative assets	$	433		$	4		$	437

Current derivative liabilities	$	317		$	40		$	357
Long-term derivative liabilities	133			160			293
Total derivative liabilities	$	450		$	200		$	650
Net derivative liabilities	$	(17	)	$	(196	)	$	(213	)



	June 30, 2013				December 31, 2012
	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	$	8	$	134	$	4	$	184
Total derivatives designated as cash flow hedging instruments	$	8	$	134	$	4	$	184

Derivatives not designated as hedging instruments:
Commodity instruments	$	729	$	776	$	433	$	450
Interest rate swaps	—		11		—		16
Total derivatives not designated as hedging instruments	$	729	$	787	$	433	$	466
Total derivatives	$	737	$	921	$	437	$	650

We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013
	Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
	Gross Amounts Presented on our Consolidated Condensed Balance Sheets			Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets			Margin/Cash (Received) Posted⁽¹⁾			Net Amount
Derivative assets:
Commodity exchange traded futures and swaps contracts	$	595		$	(580	)	$	(15	)	$	—
Commodity forward contracts	134			(107		)	(3		)	24
Interest rate swaps	8			—			—			8
Total derivative assets	$	737		$	(687	)	$	(18	)	$	32
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(646	)	$	580		$	66		$	—
Commodity forward contracts	(130		)	107			11			(12		)
Interest rate swaps	(145		)	—			—			(145		)
Total derivative (liabilities)	$	(921	)	$	687		$	77		$	(157	)
Net derivative assets (liabilities)	$	(184	)	$	—		$	59		$	(125	)



	December 31, 2012
	Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
	Gross Amounts Presented on our Consolidated Condensed Balance Sheets			Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets			Margin/Cash (Received) Posted⁽¹⁾			Net Amount
Derivative assets:
Commodity exchange traded futures and swaps contracts	$	385		$	(379	)	$	(6	)	$	—
Commodity forward contracts	48			(17		)	(1		)	30
Interest rate swaps	4			—			—			4
Total derivative assets	$	437		$	(396	)	$	(7	)	$	34
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(424	)	$	379		$	45		$	—
Commodity forward contracts	(26		)	17			1			(8		)
Interest rate swaps	(200		)	—			—			(200		)
Total derivative (liabilities)	$	(650	)	$	396		$	46		$	(208	)
Net derivative assets (liabilities)	$	(213	)	$	—		$	39		$	(174	)

____________

(1)

Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 6 for a further discussion of our collateral.

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 unrealized mark-to-market activity within our earnings.

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 in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):



	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013			2012
Realized gain (loss)⁽¹⁾
Commodity derivative instruments	$	5	$	94		$	33		$	212
Interest rate swaps	—		—			—			(157		)
Total realized gain (loss)	$	5	$	94		$	33		$	55

Unrealized gain (loss)⁽²⁾
Commodity derivative instruments	$	29	$	(346	)	$	(28	)	$	(268	)
Interest rate swaps	2		3			4			149
Total unrealized gain (loss)	$	31	$	(343	)	$	(24	)	$	(119	)
Total mark-to-market activity, net	$	36	$	(249	)	$	9		$	(64	)

___________


(1)	Does not include the realized value associated with derivative instruments that settle through physical delivery.


(2)	In addition to changes in market value on derivatives not designated as hedges, changes in unrealized gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.



	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013			2012
Realized and unrealized gain (loss)
Derivatives contracts included in operating revenues	$	15	$	(272	)	$	(59	)	$	(180	)
Derivatives contracts included in fuel and purchased energy expense	19		20			64			124
Interest rate swaps included in interest expense	2		3			4			6
Loss on interest rate derivatives	—		—			—			(14		)
Total mark-to-market activity, net	$	36	$	(249	)	$	9		$	(64	)

Derivatives Included in OCI and AOCI

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



	Three Months Ended June 30,					Three Months Ended June 30,
	Gain (Loss) Recognized in OCI (Effective Portion)					Gain (Loss) Reclassified from AOCI into Income (Effective Portion)⁽³⁾
	2013		2012			2013			2012			Affected Line Item on the Consolidated Condensed Statements of Operations
Commodity derivative instruments⁽¹⁾:
Power derivative instruments	$	—	$	(29	)	$	—		$	29		Commodity revenue
Natural gas derivative instruments	—		16			—			(17		)	Commodity expense
Interest rate swaps⁽²⁾	48		(35		)	(10		)	(8		)	Interest expense
Total	$	48	$	(48	)	$	(10	)	$	4



	Six Months Ended June 30,					Six Months Ended June 30,
	Gain (Loss) Recognized in OCI (Effective Portion)					Gain (Loss) Reclassified from AOCI into Income (Effective Portion)⁽³⁾
	2013		2012			2013			2012			Affected Line Item on the Consolidated Condensed Statements of Operations
Commodity derivative instruments⁽¹⁾:
Power derivative instruments	$	—	$	(44	)	$	—		$	67		Commodity revenue
Natural gas derivative instruments	—		30			—			(38		)	Commodity expense
Interest rate swaps⁽²⁾	61		(34		)	(19		)	(15		)	Interest expense
Total	$	61	$	(48	)	$	(19	)	$	14

____________


(1)	There were no commodity derivative instruments designated as cash flow hedges during the three and six months ended June 30, 2013. We recorded a gain on hedge ineffectiveness of nil and $2 million related to our commodity derivative instruments designated as cash flow hedges during the three and six months ended June 30, 2012.


(2)	We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the three and six months ended June 30, 2013 and 2012.


(3)	Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $178 million and $242 million at June 30, 2013 and December 31, 2012, respectively.

We estimate that pre-tax net losses of $49 million would be reclassified from AOCI into interest expense 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 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.

Use of Collateral

Use of Collateral [Text Block]

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 various debt agreements as collateral under certain of our power and natural gas agreements 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 various debt agreements.

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 as of June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013		December 31, 2012
Margin deposits⁽¹⁾	$	276	$	196
Natural gas and power prepayments	33		35
Total margin deposits and natural gas and power prepayments with our counterparties⁽²⁾	$	309	$	231

Letters of credit issued	$	486	$	484
First priority liens under power and natural gas agreements	21		14
First priority liens under interest rate swap agreements	150		206
Total letters of credit and first priority liens with our counterparties	$	657	$	704

Margin deposits posted with us by our counterparties⁽¹⁾⁽³⁾	$	3	$	11
Letters of credit posted with us by our counterparties	1		1
Total margin deposits and letters of credit posted with us by our counterparties	$	4	$	12

___________

(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, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 5 for further discussion of our derivative instruments subject to master netting arrangements.


(2)	At June 30, 2013 and December 31, 2012, $291 million and $211 million, respectively, were included in margin deposits and other prepaid expense and $18 million and $20 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.


(3)	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.

Income Taxes

Income Tax Benefit

The table below shows our consolidated income tax benefit from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions):



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Income tax benefit	$	(48	)	$	(52	)	$	(98	)	$	(58	)
Effective tax rate	41		%	14		%	33		%	15		%

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

Canadian Tax Audits — In January 2013, we received an adjusted reassessment on one of two transfer pricing issues that we are disputing with the Canadian Revenue Authority (“CRA”). We have proposed a tentative settlement of the adjusted reassessment with the CRA. If accepted, any adjustments to our transfer pricing would increase taxable income and would be offset by existing NOL’s to which a valuation allowance has been applied. Any interest assessments resulting from acceptance of the CRA offer would be immaterial.

We continue to evaluate the remaining proposed adjustments received on our other Canadian subsidiary; however, based on our current analysis which is supported by our tax advisors, we believe that our transfer pricing positions and policies are appropriate, and we intend to challenge the CRA’s proposed adjustments. If we are unsuccessful in our challenge, any adjustment to Canadian taxable income would first be offset against the existing NOLs that are available; however, we do not believe any reassessment resulting in an adjustment to taxable income which is greater than our existing NOLs, or including interest or penalties which cannot be offset by existing NOLs, would have a material adverse effect on our financial condition, results of operations or cash flows.

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, 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 — At June 30, 2013, we had unrecognized tax benefits of $79 million. If recognized, $24 million of our unrecognized tax benefits could impact the annual effective tax rate and $55 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 $14 million for income tax matters at June 30, 2013. We recognize interest and penalties related to unrecognized tax benefits in income tax benefit on our Consolidated Condensed Statements of Operations. We believe it is reasonably possible that a decrease within the range of approximately nil and $5 million in unrecognized tax benefits could occur within the next 12 months primarily related to state and foreign tax issues.

Earnings (Loss) per Share

Loss per Share

We 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 each of the three and six months ended June 30, 2013 and 2012, diluted loss per share for these periods is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. We excluded the following items from diluted loss per common share for the three and six months ended June 30, 2013 and 2012, because they were anti-dilutive (shares in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
Share-based awards	10,002	13,920	9,741	15,236

Stock-Based Compensation

Calpine Equity Incentive Plans

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 awards 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 June 30, 2013, there were 567,000 and 40,533,000 shares of our common stock authorized for issuance to participants under the Director Plan and the Equity Plan, respectively.

Equity Classified Share-Based Awards

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 term 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 $11 million and $7 million for the three months ended June 30, 2013 and 2012, and $19 million and $13 million for the six months ended June 30, 2013 and 2012, respectively. 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 six months ended June 30, 2013 and 2012. At June 30, 2013, there was unrecognized compensation cost of $3 million related to options, $39 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 0.4 years for options, 1.6 years for restricted stock and 0.9 years for restricted stock units. We issue new shares from our share 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 Calpine Equity Incentive Plans for the six months ended June 30, 2013, is as follows:



	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in millions)
Outstanding — December 31, 2012	17,862,501	$	17.30	4.0	$	42
Granted	11,299	$	18.34
Exercised	1,047,364	$	16.30
Forfeited	—	$	—
Expired	22,300	$	17.72
Outstanding — June 30, 2013	16,804,136	$	17.37	3.4	$	75
Exercisable — June 30, 2013	9,910,449	$	18.88	3.1	$	31
Vested and expected to vest – June 30, 2013	16,675,607	$	17.38	3.4	$	74

The total intrinsic value of our employee stock options exercised was $4 million and nil for the six months ended June 30, 2013 and 2012, respectively. The total cash proceeds received from our employee stock options exercised was $17 million and $3 million for the six months ended June 30, 2013 and 2012, respectively.

The fair value of options granted during the six months ended June 30, 2013 and 2012, was determined on the grant date using the Black-Scholes option-pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table:



	2013			2012
Expected term (in years)⁽¹⁾	6.5			6.5
Risk-free interest rate⁽²⁾	1.4		%	1.6		%
Expected volatility⁽³⁾	25.6		%	30.0 – 30.5		%
Dividend yield⁽⁴⁾	—			—
Weighted average grant-date fair value (per option)	$	5.31		$	5.18

___________


(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 we do not anticipate any cash dividend payments 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 six months ended June 30, 2013, is as follows:



	Number of Restricted Stock Awards	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2012	4,134,037	$	14.33
Granted	1,759,198	$	18.45
Forfeited	93,914	$	15.96
Vested	1,129,424	$	11.79
Nonvested — June 30, 2013	4,669,897	$	16.47

The total fair value of our restricted stock and restricted stock units that vested during the six months ended June 30, 2013 and 2012, was approximately $21 million and $19 million, respectively.

Liability Classified Share-Based Awards

In February 2013, our Board of Directors approved the aggregate award of 449,798 performance share units to certain senior management employees. These performance share units will be settled in cash with payouts based on the relative performance of Calpine’s TSR over the three-year performance period of January 1, 2013 through December 31, 2015 compared with the TSR performance of the S&P 500 companies over the same period. The performance share units vest on the last day of the performance period and will be settled in cash; thus, these awards are liability classified and are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. The performance share units had a grant date fair value of $21.25 and stock-based compensation expense recognized related to these awards during each of the three and six months ended June 30, 2013 was $1 million.

Commitments and Contingencies

Litigation

We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings will have a material adverse effect on our financial condition, results of operations or cash flows.

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 on our financial condition, 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 on our financial condition, results of operations or cash flows.

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 operation of our power plants. At the present time, we do not 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.

Segment and Significant Customer Information

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 June 30, 2013, our reportable segments were West (including geothermal), Texas, North (including Canada) 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 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 periods indicated (in millions).



	Three Months Ended June 30, 2013
	West		Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	479	$	571		$	348		$	174		$	—		$	1,572
Intersegment revenues	—		(25		)	8			71			(54		)	—
Total operating revenues	$	479	$	546		$	356		$	245		$	(54	)	$	1,572
Commodity Margin	$	198	$	133		$	159		$	43		$	—		$	533
Add: Unrealized mark-to-market commodity activity, net and other⁽¹⁾	19		34			(12		)	7			(9		)	39
Less:
Plant operating expense	88		96			46			35			(8		)	257
Depreciation and amortization expense	52		44			32			18			(1		)	145
Sales, general and other administrative expense	3		21			6			7			(1		)	36
Other operating expenses	11		1			7			(1		)	2			20
(Income) from unconsolidated investments in power plants	—		—			(8		)	—			—			(8		)
Income (loss) from operations	63		5			64			(9		)	(1		)	122
Interest expense, net of interest income															169
Debt extinguishment costs and other (income) expense, net															71
Loss before income taxes															$	(118	)



	Three Months Ended June 30, 2012
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	258		$	188		$	269		$	164		$	—		$	879
Intersegment revenues	1			41			2			(6		)	(38		)	—
Total operating revenues	$	259		$	229		$	271		$	158		$	(38	)	$	879
Commodity Margin⁽²⁾⁽³⁾	$	210		$	145		$	181		$	73		$	—		$	609
Add: Unrealized mark-to-market commodity activity, net and other⁽¹⁾	(76		)	(217		)	(3		)	(42		)	(6		)	(344		)
Less:
Plant operating expense	112			72			58			36			(7		)	271
Depreciation and amortization expense	49			34			34			22			(1		)	138
Sales, general and other administrative expense	6			13			8			7			1			35
Other operating expenses	9			1			6			2			1			19
(Income) from unconsolidated investments in power plants	—			—			(5		)	—			—			(5		)
Income (loss) from operations	(42		)	(192		)	77			(36		)	—			(193		)
Interest expense, net of interest income																182
Other (income) expense, net																6
Loss before income taxes																$	(381	)



	Six Months Ended June 30, 2013
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	862		$	978		$	654		$	319		$	—		$	2,813
Intersegment revenues	1			(18		)	15			104			(102		)	—
Total operating revenues	$	863		$	960		$	669		$	423		$	(102	)	$	2,813
Commodity Margin	$	400		$	209		$	301		$	84		$	—		$	994
Add: Unrealized mark-to-market commodity activity, net and other⁽⁴⁾	(18		)	23			(5		)	14			(16		)	(2		)
Less:
Plant operating expense	181			164			90			65			(16		)	484
Depreciation and amortization expense	103			87			65			37			(1		)	291
Sales, general and other administrative expense	7			38			12			12			—			69
Other operating expenses	20			2			14			1			1			38
(Income) from unconsolidated investments in power plants	—			—			(16		)	—			—			(16		)
Income (loss) from operations	71			(59		)	131			(17		)	—			126
Interest expense, net of interest income																343
Debt extinguishment costs and other (income) expense, net																76
Loss before income taxes																$	(293	)



	Six Months Ended June 30, 2012
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	674		$	544		$	567		$	330		$	—		$	2,115
Intersegment revenues	5			61			5			16			(87		)	—
Total operating revenues	$	679		$	605		$	572		$	346		$	(87	)	$	2,115
Commodity Margin⁽²⁾⁽³⁾	$	418		$	254		$	325		$	129		$	—		$	1,126
Add: Unrealized mark-to-market commodity activity, net and other⁽⁴⁾	(40		)	(183		)	9			(32		)	(14		)	(260		)
Less:
Plant operating expense	193			140			103			69			(13		)	492
Depreciation and amortization expense	99			69			67			45			(2		)	278
Sales, general and other administrative expense	14			24			14			15			1			68
Other operating expenses	20			3			15			3			(1		)	40
(Income) from unconsolidated investments in power plants	—			—			(14		)	—			—			(14		)
Income (loss) from operations	52			(165		)	149			(35		)	1			2
Interest expense, net of interest income																364
Loss on interest rate derivatives																14
Debt extinguishment costs and other (income) expense, net																20
Loss before income taxes																$	(396	)

_________


(1)	Includes $(11) million and $(1) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended June 30, 2013 and 2012, respectively.


(2)	Our North segment includes Commodity Margin of $24 million and $32 million for the three and six months ended June 30, 2012 related to Riverside Energy Center, LLC, which was sold in December 2012.


(3)	Our Southeast segment includes Commodity Margin of $13 million and $24 million for the three and six months ended June 30, 2012 related to Broad River, which was sold in December 2012.


(4)	Includes $(27) million and $(9) million of lease levelization and $7 million and $7 million of amortization expense for the six months ended June 30, 2013 and 2012, respectively.

Summary of Significant Accounting Policies (Policies)

Basis of Interim Presentation

is 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, 2012, included in our 2012 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, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and unrealized gains and losses from commodity and interest rate derivative contracts.

Us

Use of Estimates in Preparation of Financial Statements

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.

R

Reclassifications

lassifications — Certain reclassifications have been made to our Consolidated Condensed Statements of Operations and Cash Flows for the period ended June 30, 2012, to conform to the current period presentation. Our reclassifications are summarized as follows:


•	We have reclassified environmental compliance expense, primarily related to costs to comply with the Regional Greenhouse Gas Initiative in the Northeast, previously recorded in other operating expenses of $2 million and $5 million to Commodity expense on our Consolidated Condensed Statements of Operations for the three and six months ended June 30, 2012, respectively.


•	We have reclassified $3 million on our Consolidated Condensed Statement of Cash Flows for the six months ended June 30, 2012, to separately report proceeds from the exercises of stock options, previously reflected in other cash flows used in financing activities.

Ca

Cash and Cash Equivalents

h 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 June 30, 2013 and December 31, 2012, cash and cash equivalents included $127 million and $131 million, respectively, that were subject to such project finance facilities and lease agreements.

Re

Restricted Cash

tricted 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 Statements of Cash Flows.

Th

Inventory

entory — At June 30, 2013 and December 31, 2012, we had inventory of $345 million and $301 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 or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.

Pr

Derivatives

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. In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this election are reflected in unrealized mark-to-market gain/loss on our Consolidated Condensed Statements of Operations and could create more volatility in our earnings. Revenues and fuel costs derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Although we have discontinued the application of hedge accounting treatment for our commodity derivative instruments, prior to this change and for our interest rate swaps, 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 (or economically 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) 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 recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in unrealized mark-to-market gain/loss as a component of operating revenues (for power contracts and swaps) and fuel and purchased energy expense (for natural gas contracts and swaps). Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of 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.

Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas and interest rate transactions that primarily act as economic hedges to our asset and interest rate 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 commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in unrealized mark-to-market gain/loss as a component of operating revenues (for power contracts and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, swaps and options). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense (for interest rate swaps except as discussed below).

Commitments and Contingencies

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 on our financial condition, 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 on our financial condition, results of operations or cash flows.

Summary of Significant Accounting Policies (Tables)

Schedule of Components of Restricted Cash

table below represents the components of our restricted cash as of June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013						December 31, 2012
	Current		Non-Current		Total		Current		Non-Current		Total
Debt service⁽¹⁾	$	14	$	42	$	56	$	11	$	41	$	52
Rent reserve	7		—		7		—		—		—
Construction/major maintenance	26		8		34		32		14		46
Security/project/insurance	73		6		79		101		3		104
Other	20		2		22		49		2		51
Total	$	140	$	58	$	198	$	193	$	60	$	253

___________


(1)	At June 30, 2013 and December 31, 2012, amounts restricted for debt service included approximately $24 million and $25 million, respectively, of repurchase agreements with a financial institution containing maturity dates greater than one year.

In

Schedule of Property, Plant and Equipment

perty, Plant and Equipment, Net — At June 30, 2013 and December 31, 2012, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):



	June 30, 2013		December 31, 2012		Depreciable Lives
Buildings, machinery and equipment	$	14,815	$	14,774	3 – 47 Years
Geothermal properties	1,248		1,243		13 – 59 Years
Other	156		142		3 – 47 Years
	16,219		16,159
Less: Accumulated depreciation	4,641		4,390
	11,578		11,769
Land	103		98
Construction in progress	1,376		1,138
Property, plant and equipment, net	$	13,057	$	13,005

Ca

Variable Interest Entities and Unconsolidated Investments (Tables)

Income (Loss) From Unconsolidated Investments in Power Plants and Distributions [Table Text Block]

Our equity interest in the net income from Greenfield LP and Whitby for the three and six months ended June 30, 2013 and 2012, is 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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Greenfield LP	$	(5	)	$	(2	)	$	(9	)	$	(8	)
Whitby	(3		)	(3		)	(7		)	(6		)
Total	$	(8	)	$	(5	)	$	(16	)	$	(14	)

Schedule of Equity Method Investments

At June 30, 2013 and December 31, 2012, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):



	Ownership Interest as of June 30, 2013	June 30, 2013		December 31, 2012
Greenfield LP	50%	$	75	$	69
Whitby	50%	10		12
Total investments in power plants		$	85	$	81

Debt (Tables)

Schedule of Long-term Debt Instruments

At June 30, 2013 and December 31, 2012, our debt was as follows (in millions):



	June 30, 2013		December 31, 2012
First Lien Notes	$	5,304	$	5,303
First Lien Term Loans	2,450		2,463
Project financing, notes payable and other	1,858		1,789
CCFC Term Loans	1,197		—
CCFC Notes	—		978
Capital lease obligations	211		217
Total debt	11,020		10,750
Less: Current maturities	169		115
Debt, net of current portion	$	10,851	$	10,635

First Lien Notes

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



	June 30, 2013		December 31, 2012
2017 First Lien Notes	$	1,080	$	1,080
2019 First Lien Notes	360		360
2020 First Lien Notes	984		983
2021 First Lien Notes	1,800		1,800
2023 First Lien Notes	1,080		1,080
Total First Lien Notes	$	5,304	$	5,303

First Lien Term Loans

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



	June 30, 2013		December 31, 2012
2018 First Lien Term Loans	$	1,621	$	1,630
2019 First Lien Term Loan	829		833
Total First Lien Term Loans	$	2,450	$	2,463

Schedule of Line of Credit Facilities

The table below represents amounts issued under our letter of credit facilities at June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013		December 31, 2012
Corporate Revolving Facility⁽¹⁾	$	240	$	243
CDHI	243		253
Various project financing facilities	131		130
Total	$	614	$	626

____________


(1)	The Corporate Revolving Facility represents our primary revolving facility.

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

The following table details the fair values and carrying values of our debt instruments at June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013				December 31, 2012
	Fair Value		Carrying Value		Fair Value		Carrying Value
First Lien Notes	$	5,621	$	5,304	$	5,863	$	5,303
First Lien Term Loans	2,452		2,450		2,489		2,463
Project financing, notes payable and other⁽¹⁾	1,670		1,723		1,599		1,629
CCFC Term Loans	1,180		1,197		—		—
CCFC Notes	—		—		1,075		978
Total	$	10,923	$	10,674	$	11,026	$	10,373

____________


(1)	Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

Assets and Liabilities with Recurring Fair Value Measurements (Tables)

Fair Value, Measurement Inputs, Disclosure

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. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2013 and December 31, 2012, by level within the fair value hierarchy:



	Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2013
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	871	$	—	$	—	$	871
Margin deposits	276		—		—		276
Commodity instruments:
Commodity exchange traded futures and swaps contracts	595		—		—		595
Commodity forward contracts⁽²⁾	—		112		22		134
Interest rate swaps	—		8		—		8
Total assets	$	1,742	$	120	$	22	$	1,884
Liabilities:
Margin deposits posted with us by our counterparties	$	3	$	—	$	—	$	3
Commodity instruments:
Commodity exchange traded futures and swaps contracts	646		—		—		646
Commodity forward contracts⁽²⁾	—		121		9		130
Interest rate swaps	—		145		—		145
Total liabilities	$	649	$	266	$	9	$	924



	Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2012
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Cash equivalents⁽¹⁾	$	1,502	$	—	$	—	$	1,502
Margin deposits	196		—		—		196
Commodity instruments:
Commodity exchange traded futures and swaps contracts	385		—		—		385
Commodity forward contracts⁽²⁾	—		24		24		48
Interest rate swaps	—		4		—		4
Total assets	$	2,083	$	28	$	24	$	2,135
Liabilities:
Margin deposits posted with us by our counterparties	$	11	$	—	$	—	$	11
Commodity instruments:
Commodity exchange traded futures and swaps contracts	424		—		—		424
Commodity forward contracts⁽²⁾	—		18		8		26
Interest rate swaps	—		200		—		200
Total liabilities	$	435	$	218	$	8	$	661

___________


(1)	As of June 30, 2013 and December 31, 2012, we had cash equivalents of $699 million and $1,274 million included in cash and cash equivalents and $172 million and $228 million included in restricted cash, respectively.


(2)	Includes OTC swaps and options.

Fair Value Inputs, Liabilities, Quantitative Information

At June 30, 2013 and December 31, 2012, the derivative instruments classified as level 3 primarily included a longer-term OTC traded commodity contract which is classified as level 3 because the contract terms relate to a delivery location for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices; however, given the nature of our net derivative position, we do not believe that a significant change in market commodity prices would have a material impact on our level 3 net fair value. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at June 30, 2013 and December 31, 2012:



	Quantitative Information about Level 3 Fair Value Measurements
	June 30, 2013
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Physical Power	$	6	Discounted cash flow	Market price (per MWh)	$31.00 — $50.00/MWh

	December 31, 2012
	Fair Value, Net Asset			Significant Unobservable
	(Liability)		Valuation Technique	Input	Range
	(in millions)
Physical Power	$	11	Discounted cash flow	Market price (per MWh)	$23.75 — $53.82/MWh

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

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 June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Balance, beginning of period	$	13		$	17		$	16		$	17
Realized and unrealized gains (losses):
Included in net loss:
Included in operating revenues⁽¹⁾	3			(24		)	4			(17		)
Included in fuel and purchased energy expense⁽²⁾	—			2			—			—
Included in OCI	—			—			—			4
Purchases, issuances and settlements:
Purchases	1			1			1			1
Issuances	—			(1		)	(1		)	(1		)
Settlements	(3		)	(5		)	(5		)	(11		)
Transfers in and/or out of level 3⁽³⁾:
Transfers into level 3⁽⁴⁾	—			—			—			—
Transfers out of level 3⁽⁵⁾	(1		)	—			(2		)	(3		)
Balance, end of period	$	13		$	(10	)	$	13		$	(10	)
Change in unrealized gains (losses) relating to instruments still held at end of period	$	3		$	(22	)	$	4		$	(17	)

___________


(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 transfers into or out of level 1 for each of the three and six months ended June 30, 2013 and 2012.


(4)	There were no transfers out of level 2 into level 3 for each of the three and six months ended June 30, 2013 and 2012.

(5)

We had $1 million in gains transferred out of level 3 into level 2 for the three months ended June 30, 2013 and $2 million and $3 million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2013 and 2012, respectively, due to changes in market liquidity in various power markets. There were no transfers out of level 3 into level 2 for the three months ended June 30, 2012.

Derivative Instruments (Tables)

Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location [Table Text Block]

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 June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013
	Commodity Instruments			Interest Rate Swaps			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	601		$	—		$	601
Long-term derivative assets	128			8			136
Total derivative assets	$	729		$	8		$	737

Current derivative liabilities	$	583		$	47		$	630
Long-term derivative liabilities	193			98			291
Total derivative liabilities	$	776		$	145		$	921
Net derivative liabilities	$	(47	)	$	(137	)	$	(184	)



	December 31, 2012
	Commodity Instruments			Interest Rate Swaps			Total Derivative Instruments
Balance Sheet Presentation
Current derivative assets	$	339		$	—		$	339
Long-term derivative assets	94			4			98
Total derivative assets	$	433		$	4		$	437

Current derivative liabilities	$	317		$	40		$	357
Long-term derivative liabilities	133			160			293
Total derivative liabilities	$	450		$	200		$	650
Net derivative liabilities	$	(17	)	$	(196	)	$	(213	)

Schedule of Notional Amounts of Outstanding Derivative Positions

As of June 30, 2013 and December 31, 2012, 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:



Derivative Instruments	Notional Amounts
Derivative Instruments	June 30, 2013			December 31, 2012
Power (MWh)	(11		)	(16		)
Natural gas (MMBtu)	163			66
Interest rate swaps (in millions)	$	1,597		$	1,602

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value



	June 30, 2013				December 31, 2012
	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	$	8	$	134	$	4	$	184
Total derivatives designated as cash flow hedging instruments	$	8	$	134	$	4	$	184

Derivatives not designated as hedging instruments:
Commodity instruments	$	729	$	776	$	433	$	450
Interest rate swaps	—		11		—		16
Total derivatives not designated as hedging instruments	$	729	$	787	$	433	$	466
Total derivatives	$	737	$	921	$	437	$	650

Derivative Instruments Subject to Master Netting Arrangements [Table Text Block]

The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013
	Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
	Gross Amounts Presented on our Consolidated Condensed Balance Sheets			Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets			Margin/Cash (Received) Posted⁽¹⁾			Net Amount
Derivative assets:
Commodity exchange traded futures and swaps contracts	$	595		$	(580	)	$	(15	)	$	—
Commodity forward contracts	134			(107		)	(3		)	24
Interest rate swaps	8			—			—			8
Total derivative assets	$	737		$	(687	)	$	(18	)	$	32
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(646	)	$	580		$	66		$	—
Commodity forward contracts	(130		)	107			11			(12		)
Interest rate swaps	(145		)	—			—			(145		)
Total derivative (liabilities)	$	(921	)	$	687		$	77		$	(157	)
Net derivative assets (liabilities)	$	(184	)	$	—		$	59		$	(125	)



	December 31, 2012
	Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
	Gross Amounts Presented on our Consolidated Condensed Balance Sheets			Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets			Margin/Cash (Received) Posted⁽¹⁾			Net Amount
Derivative assets:
Commodity exchange traded futures and swaps contracts	$	385		$	(379	)	$	(6	)	$	—
Commodity forward contracts	48			(17		)	(1		)	30
Interest rate swaps	4			—			—			4
Total derivative assets	$	437		$	(396	)	$	(7	)	$	34
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts	$	(424	)	$	379		$	45		$	—
Commodity forward contracts	(26		)	17			1			(8		)
Interest rate swaps	(200		)	—			—			(200		)
Total derivative (liabilities)	$	(650	)	$	396		$	46		$	(208	)
Net derivative assets (liabilities)	$	(213	)	$	—		$	39		$	(174	)

____________

(1)

Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 6 for a further discussion of our collateral.

Realized Unrealized Gain Loss by Instrument

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 in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):



	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013			2012
Realized gain (loss)⁽¹⁾
Commodity derivative instruments	$	5	$	94		$	33		$	212
Interest rate swaps	—		—			—			(157		)
Total realized gain (loss)	$	5	$	94		$	33		$	55

Unrealized gain (loss)⁽²⁾
Commodity derivative instruments	$	29	$	(346	)	$	(28	)	$	(268	)
Interest rate swaps	2		3			4			149
Total unrealized gain (loss)	$	31	$	(343	)	$	(24	)	$	(119	)
Total mark-to-market activity, net	$	36	$	(249	)	$	9		$	(64	)

___________


(1)	Does not include the realized value associated with derivative instruments that settle through physical delivery.


(2)	In addition to changes in market value on derivatives not designated as hedges, changes in unrealized gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location



	Three Months Ended June 30,					Six Months Ended June 30,
	2013		2012			2013			2012
Realized and unrealized gain (loss)
Derivatives contracts included in operating revenues	$	15	$	(272	)	$	(59	)	$	(180	)
Derivatives contracts included in fuel and purchased energy expense	19		20			64			124
Interest rate swaps included in interest expense	2		3			4			6
Loss on interest rate derivatives	—		—			—			(14		)
Total mark-to-market activity, net	$	36	$	(249	)	$	9		$	(64	)

Derivatives Designated as Hedges

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



	Three Months Ended June 30,					Three Months Ended June 30,
	Gain (Loss) Recognized in OCI (Effective Portion)					Gain (Loss) Reclassified from AOCI into Income (Effective Portion)⁽³⁾
	2013		2012			2013			2012			Affected Line Item on the Consolidated Condensed Statements of Operations
Commodity derivative instruments⁽¹⁾:
Power derivative instruments	$	—	$	(29	)	$	—		$	29		Commodity revenue
Natural gas derivative instruments	—		16			—			(17		)	Commodity expense
Interest rate swaps⁽²⁾	48		(35		)	(10		)	(8		)	Interest expense
Total	$	48	$	(48	)	$	(10	)	$	4



	Six Months Ended June 30,					Six Months Ended June 30,
	Gain (Loss) Recognized in OCI (Effective Portion)					Gain (Loss) Reclassified from AOCI into Income (Effective Portion)⁽³⁾
	2013		2012			2013			2012			Affected Line Item on the Consolidated Condensed Statements of Operations
Commodity derivative instruments⁽¹⁾:
Power derivative instruments	$	—	$	(44	)	$	—		$	67		Commodity revenue
Natural gas derivative instruments	—		30			—			(38		)	Commodity expense
Interest rate swaps⁽²⁾	61		(34		)	(19		)	(15		)	Interest expense
Total	$	61	$	(48	)	$	(19	)	$	14

____________


(1)	There were no commodity derivative instruments designated as cash flow hedges during the three and six months ended June 30, 2013. We recorded a gain on hedge ineffectiveness of nil and $2 million related to our commodity derivative instruments designated as cash flow hedges during the three and six months ended June 30, 2012.


(2)	We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the three and six months ended June 30, 2013 and 2012.


(3)	Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $178 million and $242 million at June 30, 2013 and December 31, 2012, respectively.

Use of Collateral (Tables)

Schedule of Collateral

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 as of June 30, 2013 and December 31, 2012 (in millions):



	June 30, 2013		December 31, 2012
Margin deposits⁽¹⁾	$	276	$	196
Natural gas and power prepayments	33		35
Total margin deposits and natural gas and power prepayments with our counterparties⁽²⁾	$	309	$	231

Letters of credit issued	$	486	$	484
First priority liens under power and natural gas agreements	21		14
First priority liens under interest rate swap agreements	150		206
Total letters of credit and first priority liens with our counterparties	$	657	$	704

Margin deposits posted with us by our counterparties⁽¹⁾⁽³⁾	$	3	$	11
Letters of credit posted with us by our counterparties	1		1
Total margin deposits and letters of credit posted with us by our counterparties	$	4	$	12

___________

(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, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 5 for further discussion of our derivative instruments subject to master netting arrangements.


(2)	At June 30, 2013 and December 31, 2012, $291 million and $211 million, respectively, were included in margin deposits and other prepaid expense and $18 million and $20 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.


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

Income Taxes Income Taxes (Tables)

Schedule of Components of Income Tax Expense (Benefit)

The table below shows our consolidated income tax benefit from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions):



	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Income tax benefit	$	(48	)	$	(52	)	$	(98	)	$	(58	)
Effective tax rate	41		%	14		%	33		%	15		%

Earnings (Loss) per Share (Tables)

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

We excluded the following items from diluted loss per common share for the three and six months ended June 30, 2013 and 2012, because they were anti-dilutive (shares in thousands):



	Three Months Ended June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
Share-based awards	10,002	13,920	9,741	15,236

Stock-Based Compensation (Tables)

Schedule of Non-Qualified Stock Option Activity

A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the six months ended June 30, 2013, is as follows:



	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Term (in years)	Aggregate Intrinsic Value (in millions)
Outstanding — December 31, 2012	17,862,501	$	17.30	4.0	$	42
Granted	11,299	$	18.34
Exercised	1,047,364	$	16.30
Forfeited	—	$	—
Expired	22,300	$	17.72
Outstanding — June 30, 2013	16,804,136	$	17.37	3.4	$	75
Exercisable — June 30, 2013	9,910,449	$	18.88	3.1	$	31
Vested and expected to vest – June 30, 2013	16,675,607	$	17.38	3.4	$	74

Schedule of Assumptions Used to Estimate Fair Value for Options

Certain assumptions were used in order to estimate fair value for options as noted in the following table:



	2013			2012
Expected term (in years)⁽¹⁾	6.5			6.5
Risk-free interest rate⁽²⁾	1.4		%	1.6		%
Expected volatility⁽³⁾	25.6		%	30.0 – 30.5		%
Dividend yield⁽⁴⁾	—			—
Weighted average grant-date fair value (per option)	$	5.31		$	5.18

___________


(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 we do not anticipate any cash dividend payments on our common stock in the near future.

Schedule of Restricted Stock and Restricted Stock Unit Activity

A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the six months ended June 30, 2013, is as follows:



	Number of Restricted Stock Awards	Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2012	4,134,037	$	14.33
Granted	1,759,198	$	18.45
Forfeited	93,914	$	15.96
Vested	1,129,424	$	11.79
Nonvested — June 30, 2013	4,669,897	$	16.47

Segment and Significant Customer Information (Tables)

Schedule of Financial Data for Segments

The tables below show our financial data for our segments for the periods indicated (in millions).



	Three Months Ended June 30, 2013
	West		Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	479	$	571		$	348		$	174		$	—		$	1,572
Intersegment revenues	—		(25		)	8			71			(54		)	—
Total operating revenues	$	479	$	546		$	356		$	245		$	(54	)	$	1,572
Commodity Margin	$	198	$	133		$	159		$	43		$	—		$	533
Add: Unrealized mark-to-market commodity activity, net and other⁽¹⁾	19		34			(12		)	7			(9		)	39
Less:
Plant operating expense	88		96			46			35			(8		)	257
Depreciation and amortization expense	52		44			32			18			(1		)	145
Sales, general and other administrative expense	3		21			6			7			(1		)	36
Other operating expenses	11		1			7			(1		)	2			20
(Income) from unconsolidated investments in power plants	—		—			(8		)	—			—			(8		)
Income (loss) from operations	63		5			64			(9		)	(1		)	122
Interest expense, net of interest income															169
Debt extinguishment costs and other (income) expense, net															71
Loss before income taxes															$	(118	)



	Three Months Ended June 30, 2012
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	258		$	188		$	269		$	164		$	—		$	879
Intersegment revenues	1			41			2			(6		)	(38		)	—
Total operating revenues	$	259		$	229		$	271		$	158		$	(38	)	$	879
Commodity Margin⁽²⁾⁽³⁾	$	210		$	145		$	181		$	73		$	—		$	609
Add: Unrealized mark-to-market commodity activity, net and other⁽¹⁾	(76		)	(217		)	(3		)	(42		)	(6		)	(344		)
Less:
Plant operating expense	112			72			58			36			(7		)	271
Depreciation and amortization expense	49			34			34			22			(1		)	138
Sales, general and other administrative expense	6			13			8			7			1			35
Other operating expenses	9			1			6			2			1			19
(Income) from unconsolidated investments in power plants	—			—			(5		)	—			—			(5		)
Income (loss) from operations	(42		)	(192		)	77			(36		)	—			(193		)
Interest expense, net of interest income																182
Other (income) expense, net																6
Loss before income taxes																$	(381	)



	Six Months Ended June 30, 2013
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	862		$	978		$	654		$	319		$	—		$	2,813
Intersegment revenues	1			(18		)	15			104			(102		)	—
Total operating revenues	$	863		$	960		$	669		$	423		$	(102	)	$	2,813
Commodity Margin	$	400		$	209		$	301		$	84		$	—		$	994
Add: Unrealized mark-to-market commodity activity, net and other⁽⁴⁾	(18		)	23			(5		)	14			(16		)	(2		)
Less:
Plant operating expense	181			164			90			65			(16		)	484
Depreciation and amortization expense	103			87			65			37			(1		)	291
Sales, general and other administrative expense	7			38			12			12			—			69
Other operating expenses	20			2			14			1			1			38
(Income) from unconsolidated investments in power plants	—			—			(16		)	—			—			(16		)
Income (loss) from operations	71			(59		)	131			(17		)	—			126
Interest expense, net of interest income																343
Debt extinguishment costs and other (income) expense, net																76
Loss before income taxes																$	(293	)



	Six Months Ended June 30, 2012
	West			Texas			North			Southeast			Consolidation and Elimination			Total
Revenues from external customers	$	674		$	544		$	567		$	330		$	—		$	2,115
Intersegment revenues	5			61			5			16			(87		)	—
Total operating revenues	$	679		$	605		$	572		$	346		$	(87	)	$	2,115
Commodity Margin⁽²⁾⁽³⁾	$	418		$	254		$	325		$	129		$	—		$	1,126
Add: Unrealized mark-to-market commodity activity, net and other⁽⁴⁾	(40		)	(183		)	9			(32		)	(14		)	(260		)
Less:
Plant operating expense	193			140			103			69			(13		)	492
Depreciation and amortization expense	99			69			67			45			(2		)	278
Sales, general and other administrative expense	14			24			14			15			1			68
Other operating expenses	20			3			15			3			(1		)	40
(Income) from unconsolidated investments in power plants	—			—			(14		)	—			—			(14		)
Income (loss) from operations	52			(165		)	149			(35		)	1			2
Interest expense, net of interest income																364
Loss on interest rate derivatives																14
Debt extinguishment costs and other (income) expense, net																20
Loss before income taxes																$	(396	)

_________


(1)	Includes $(11) million and $(1) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended June 30, 2013 and 2012, respectively.


(2)	Our North segment includes Commodity Margin of $24 million and $32 million for the three and six months ended June 30, 2012 related to Riverside Energy Center, LLC, which was sold in December 2012.


(3)	Our Southeast segment includes Commodity Margin of $13 million and $24 million for the three and six months ended June 30, 2012 related to Broad River, which was sold in December 2012.


(4)	Includes $(27) million and $(9) million of lease levelization and $7 million and $7 million of amortization expense for the six months ended June 30, 2013 and 2012, respectively.

Summary of Significant Accounting Policies (Details) (USD $)

In Millions, unless otherwise specified

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Dec. 31, 2012

Restricted Cash and Cash Equivalents Items [Line Items]

Held-to-maturity Securities, Restricted

$ 24

$ 25

Current

140

193

Non-current

58

60

Total

198

253

Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]

Cash and cash equivalents subject to project finance facilities and lease agreements

127

131

Interest Costs Capitalized

12

9

24

17

Inventory

345

301

Treasury Stock, Value, Acquired, Cost Method

362

Adjustments Related to Tax Withholding for Share-based Compensation

6

Debt Service

Restricted Cash and Cash Equivalents Items [Line Items]

Current

14 ¹

11 ¹

Non-current

42 ¹

41 ¹

Total

56 ¹

52 ¹

Rent Reserve

Restricted Cash and Cash Equivalents Items [Line Items]

Current

7

0

Non-current

0

Total

7

0

Construction Major Maintenance

Restricted Cash and Cash Equivalents Items [Line Items]

Current

26

32

Non-current

8

14

Total

34

46

Security Project Insurance

Restricted Cash and Cash Equivalents Items [Line Items]

Current

73

101

Non-current

6

3

Total

79

104

Other

Restricted Cash and Cash Equivalents Items [Line Items]

Current

20

49

Non-current

2

Total

22

51

Geothermal Properties, Gross [Member] |
Minimum [Member]

Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]

Property, Plant and Equipment, Estimated Useful Lives

13 years

Geothermal Properties, Gross [Member] |
Maximum [Member]

Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]

Property, Plant and Equipment, Estimated Useful Lives

59 years

Property, Plant and Equipment, Other Types [Member] |
Minimum [Member]

Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]

Property, Plant and Equipment, Estimated Useful Lives

3 years

Property, Plant and Equipment, Other Types [Member] |
Maximum [Member]

Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]

Property, Plant and Equipment, Estimated Useful Lives

47 years

Building, Machinery and Equipment, Gross [Member] |
Minimum [Member]

Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]

Property, Plant and Equipment, Estimated Useful Lives

3 years

Building, Machinery and Equipment, Gross [Member] |
Maximum [Member]

Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]

Property, Plant and Equipment, Estimated Useful Lives

47 years

Income Statement [Member]

Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]

Prior Period Reclassification Adjustment

2

5

Cash Flow Statement [Member]

Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]

Prior Period Reclassification Adjustment

$ 3

[1] June 30, 2013 and December 31, 2012, amounts restricted for debt service included approximately $24 million and $25 million, respectively, of repurchase agreements with a financial institution containing maturity dates greater than one year.In

Summary of Significant Accounting Policies Property, Plant and Equipment, Net (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Property, Plant and Equipment [Line Items]

Buildings, machinery and equipment

$ 14,815

$ 14,774

Geothermal properties

1,248

1,243

Other

156

142

Property, Plant and Equipment, Gross

16,219

16,159

Less: Accumulated depreciation

4,641

4,390

Property, Plant and Equipment, Gross, Less Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment

11,578

11,769

Land

103

98

Construction in progress

1,376

1,138

Property, plant and equipment, net

$ 13,057

$ 13,005

Variable Interest Entities and Unconsolidated Investments (Unconsolidated VIEs) (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Schedule of Equity Method Investments [Line Items]

Equity Method Investments

$ 85

$ 81

Greenfield [Member]

Schedule of Equity Method Investments [Line Items]

Equity Method Investments

75

69

Equity Method Investment, Ownership Percentage

50.00%

Whitby [Member]

Schedule of Equity Method Investments [Line Items]

Equity Method Investments

$ 10

$ 12

Equity Method Investment, Ownership Percentage

50.00%

Variable Interest Entities and Unconsolidated Investments (Income from Unconsolidated Investements 10-Q) (Details) (USD $)

In Millions, unless otherwise specified

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

(Income) from unconsolidated investments in power plants

$ (8)

$ (5)

$ (16)

$ (14)

Greenfield [Member]

(Income) from unconsolidated investments in power plants

(5)

(2)

(9)

(8)

Whitby [Member]

(Income) from unconsolidated investments in power plants

$ (3)

$ (7)

$ (6)

Variable Interest Entities and Unconsolidated Investments (VIE Texuals) (Details)

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

Jun. 30, 2013

USD ($)

MW

Jun. 30, 2012

USD ($)

Jun. 30, 2013

USD ($)

MW

Jun. 30, 2012

USD ($)

Dec. 31, 2012

USD ($)

MW

Jun. 30, 2013

Greenfield [Member]

USD ($)

Jun. 30, 2012

Greenfield [Member]

USD ($)

Jun. 30, 2013

Greenfield [Member]

USD ($)

Jun. 30, 2012

Greenfield [Member]

USD ($)

Jun. 30, 2013

Greenfield [Member]

CAD ($)

MW

Jun. 30, 2013

Whitby [Member]

USD ($)

MW

Jun. 30, 2012

Whitby [Member]

USD ($)

Jun. 30, 2013

Whitby [Member]

USD ($)

MW

Jun. 30, 2012

Whitby [Member]

USD ($)

Jun. 30, 2013

Inland Empire Energy Center [Member]

Y

MW

Jun. 30, 2013

Inland Empire Energy Center [Member]

Minimum [Member]

Y

Jun. 30, 2013

Inland Empire Energy Center [Member]

Maximum [Member]

Y

Variable Interest Entity [Line Items]

Power generation capacity

9,027

8,255

1,038

50

775

Variable Interest Entity, Financial or Other Support, Amount

$ 0

Equity Method Investment, Ownership Percentage

50.00%

Equity Method Investment, Summarized Financial Information, Debt

412,000,000

448,000,000

Prorata Share of Equity Method Investment, Summarized Financial Information, Debt

206,000,000

224,000,000

Equity Method Investment, Summarized Financial Information, Term Loan Period

18 years

Equity Method Investment, Summarized Financial Information, Term Loan

648,000,000

Distribution from equity method investee

$ 7,000,000

$ 9,000,000

$ 7,000,000

$ 9,000,000

$ 7,000,000

$ 9,000,000

$ 7,000,000

Call Option Exercise Period

2,017

2,024

Put Option Exercise Period

2,025

Debt (Debt) (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Debt Instrument [Line Items]

Long-term Debt

$ 11,020

$ 10,750

Debt, Current

169

115

Long-term Debt, Excluding Current Maturities

(10,851)

(10,635)

Corporate Debt Securities [Member]

Debt Instrument [Line Items]

Long-term Debt

5,304

5,303

Notes Payable, Other Payables [Member]

Debt Instrument [Line Items]

Long-term Debt

2,450

2,463

Loans Payable [Member]

Debt Instrument [Line Items]

Long-term Debt

1,858

1,789

CCFC Term Loans [Member]

Debt Instrument [Line Items]

Long-term Debt

1,197

0

Secured Debt [Member]

Debt Instrument [Line Items]

Long-term Debt

0

978

Capital Lease Obligations [Member]

Debt Instrument [Line Items]

Long-term Debt

$ 211

$ 217

Debt (First Lien Notes) (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Debt Instrument [Line Items]

Long-term Debt

$ 11,020

$ 10,750

First Lien Notes 2017 [Member]

Debt Instrument [Line Items]

Long-term Debt

1,080

First Lien Notes 2019 [Member]

Debt Instrument [Line Items]

Long-term Debt

360

First Lien Notes 2020 [Member]

Debt Instrument [Line Items]

Long-term Debt

984

983

First Lien Notes 2021 [Member]

Debt Instrument [Line Items]

Long-term Debt

1,800

First Lien Notes 2023 [Member]

Debt Instrument [Line Items]

Long-term Debt

1,080

Corporate Debt Securities [Member]

Debt Instrument [Line Items]

Long-term Debt

$ 5,304

$ 5,303

Debt (First Lien Term Loans) (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Debt Instrument [Line Items]

Long-term Debt

$ 11,020

$ 10,750

First Lien Term Loans 2018 [Member]

Debt Instrument [Line Items]

Long-term Debt

1,621

1,630

First Lien Term Loan 2019 [Member]

Debt Instrument [Line Items]

Long-term Debt

829

833

First Lien Term Loans [Member]

Debt Instrument [Line Items]

Long-term Debt

$ 2,450

$ 2,463

Debt (Letter of Credit) (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Line of Credit Facility [Line Items]

Letters of Credit Outstanding, Amount

$ 614

$ 626

Corporate Revolving Facility [Member]

Line of Credit Facility [Line Items]

Letters of Credit Outstanding, Amount

240 ¹

243 ¹

CDH [Member]

Line of Credit Facility [Line Items]

Letters of Credit Outstanding, Amount

243

253

Various Project Financing Facilities [Member]

Line of Credit Facility [Line Items]

Letters of Credit Outstanding, Amount

$ 131

$ 130

[1] The Corporate Revolving Facility represents our primary revolving facility.

Debt (Fair Value of Debt) (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Portion at Fair Value, Fair Value Disclosure [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Notes Payable, Fair Value Disclosure

$ 5,621

$ 5,863

Subsidiaries Notes Disclosure

0

1,075

Notes Payable, Other Payables, Disclosure

1,670 ¹

1,599 ¹

Subsidiaries Term Loan

1,180

0

Loans Payable, Fair Value Disclosure

2,452

2,489

Debt Excluding Capital Leases

10,923

11,026

Carrying (Reported) Amount, Fair Value Disclosure [Member]

Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]

Notes Payable, Fair Value Disclosure

5,304

5,303

Subsidiaries Notes Disclosure

0

978

Notes Payable, Other Payables, Disclosure

1,723 ¹

1,629 ¹

Subsidiaries Term Loan

1,197

0

Loans Payable, Fair Value Disclosure

2,450

2,463

Debt Excluding Capital Leases

$ 10,674

$ 10,373

[1] Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

Debt (Debt Textuals) (Details) (USD $)

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Effective Percentage

6.90%

7.40%

6.90%

7.40%

Gains (Losses) on Extinguishment of Debt

$ (68,000,000)

$ 0

$ (68,000,000)

$ (12,000,000)

First Lien Term Loans [Member]

Debt Instrument [Line Items]

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum

3.00%

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum

1.00%

Lowering the LIBOR margin due to repricing

0.25%

Lowering the LIBOR floor due to repricing

0.25%

CCFC Term Loan B-1 [Member]

Debt Instrument [Line Items]

Debt Instrument, Face Amount

900,000,000

Term Loan Period

7 years

Term loan interest rate spread option Prime Rate

1.25%

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum

2.25%

CCFC Term Loan B-2 [Member]

Debt Instrument [Line Items]

Debt Instrument, Face Amount

300,000,000

Term Loan Period

8 years 6 months

Term loan interest rate spread option Prime Rate

1.50%

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum

2.50%

CCFC Notes [Member]

Debt Instrument [Line Items]

Debt Instrument, Face Amount

1,000,000,000

CCFC Term Loans [Member]

Debt Instrument [Line Items]

Fair Value Inputs, Discount Rate

99.75%

Percentage of the principal amount of the Term Loan to be paid quarterly

0.25%

Debt Instrument, Redemption Price, Percentage

104.00%

Term loan interest rate spread option Federal Funds effective rate

0.50%

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum

0.75%

Prepayment Penalties

40,000,000

Write off of Deferred Debt Issuance Cost

28,000,000

Deferred Finance Costs, Net

15,000,000

Corporate Revolving Facility [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Unused Capacity, Commitment Fee Percentage

0.75%

Term loan interest rate spread option Prime Rate

2.25%

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum

3.25%

Corporate Revolving Facility Amendment No. 1 [Member]

Debt Instrument [Line Items]

Line of Credit Facility, Unused Capacity, Commitment Fee Percentage

0.50%

Term loan interest rate spread option Prime Rate

1.25%

Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum

2.25%

CDHI [Member]

Debt Instrument [Line Items]

Letter of Credit Total

300,000,000

Letter of Credit Uncollateral Total

225,000,000

Pledged Financial Instruments, Not Separately Reported, Securities for Letter of Credit Facilities

$ 18,000,000

Assets and Liabilities with Recurring Fair Value Measurements Fair Value Hierarchy (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Cash equivalents

$ 871 ¹

$ 1,502 ¹

Margin deposits

276 ²

196 ²

Commodity futures contracts

595

385

Commodity forward contracts

134 ³

48 ³

Interest Rate Swap Assets, Fair Value Disclosure

8

4

Total assets

1,884

2,135

Margin deposits held by us posted by our counterparties

3 ² ⁴

11 ² ⁴

Commodity futures contracts

646

424

Commodity forward contracts

130 ³

26 ³

Interest rate swaps

145

200

Liabilities, Fair Value Disclosure

924

661

Fair Value, Inputs, Level 1 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Cash equivalents

871 ¹

1,502 ¹

Margin deposits

276

196

Commodity futures contracts

595

385

Commodity forward contracts

0 ³

Interest Rate Swap Assets, Fair Value Disclosure

0

Total assets

1,742

2,083

Margin deposits held by us posted by our counterparties

3

11

Commodity futures contracts

646

424

Commodity forward contracts

0 ³

Interest rate swaps

0

Liabilities, Fair Value Disclosure

649

435

Fair Value, Inputs, Level 2 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Cash equivalents

0 ¹

Margin deposits

0

Commodity futures contracts

0

Commodity forward contracts

112 ³

24 ³

Interest Rate Swap Assets, Fair Value Disclosure

8

4

Total assets

120

28

Margin deposits held by us posted by our counterparties

0

Commodity futures contracts

0

Commodity forward contracts

121 ³

18 ³

Interest rate swaps

145

200

Liabilities, Fair Value Disclosure

266

218

Fair Value, Inputs, Level 3 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Cash equivalents

0 ¹

Margin deposits

0

Commodity futures contracts

0

Commodity forward contracts

22 ³

24 ³

Interest Rate Swap Assets, Fair Value Disclosure

0

Total assets

22

24

Margin deposits held by us posted by our counterparties

0

Commodity futures contracts

0

Commodity forward contracts

9 ³

8 ³

Interest rate swaps

0

Liabilities, Fair Value Disclosure

$ 9

$ 8

[1] As of June 30, 2013 and December 31, 2012, we had cash equivalents of $699 million and $1,274 million included in cash and cash equivalents and $172 million and $228 million included in restricted cash, respectively.

[2] 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, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 5 for further discussion of our derivative instruments subject to master netting arrangements.

[3] Includes OTC swaps and options.

[4] Included in other current liabilities on our Consolidated Condensed Balance Sheets.

Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) (USD $)

In Millions, unless otherwise specified

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Dec. 31, 2012

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

Balance, beginning of period

$ 13

$ 17

$ 16

$ 17

Included in net income:

Included in operating revenues

3 ¹

(24)¹

4 ¹

(17)¹

Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Gain (Loss) Included In Fuel And Purchased Energy Expense

0 ²

2 ²

0 ²

Included in OCI

0

4

Purchases, issuances and settlements:

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

1

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issues

0

(1)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

(3)

(5)

(11)

Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount

0

Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount

0

Transfers into level 3

0 ³

Transfers out of Level 3

1 ⁴

0 ⁴

2 ⁴

3 ⁴

Balance, end of period

13

(10)

13

(10)

Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Change in Unrealized Gain (Loss) Held At Period End

3

(22)

4

(17)

Assets and Liabilities with Recurring Fair Value Measurements (Textuals) [Abstract]

Cash Equivalents Included In Cash And Cash Equivalents, Fair Value Disclosure

699

1,274

Cash Equivalents Included In Restricted Cash, Fair Value Disclosure

$ 172

$ 228

[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] There were no transfers out of level 2 into level 3 for each of the three and six months ended June 30, 2013 and 2012.

[4] We had $1 million in gains transferred out of level 3 into level 2 for the three months ended June 30, 2013 and $2 million and $3 million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2013 and 2012, respectively, due to changes in market liquidity in various power markets. There were no transfers out of level 3 into level 2 for the three months ended June 30, 2012.

Assets and Liabilities with Recurring Fair Value Measurements Quantitative Info on Level 3 (Details) (USD $)

Jun. 30, 2013

Dec. 31, 2012

Minimum [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Fair Value Inputs Quantitative Information Power

$ 31.00

$ 23.75

Maximum [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Fair Value Inputs Quantitative Information Power

50.00

53.82

Physical Power [Member]

Fair Value Inputs, Assets, Quantitative Information [Line Items]

Fair Value Inputs Quantitative Information Power

$ 6,000,000

$ 11,000,000

Derivative Instruments (Details) (USD $)

In Millions, unless otherwise specified

6 Months Ended

12 Months Ended

Jun. 30, 2013

MWh

MMBTU

Dec. 31, 2012

MWh

MMBTU

Derivative Instruments [Abstract]

Derivative, Nonmonetary Notional Amount, Energy Measure

(11)

(16)

Nonmonetary Notional Amount of Price Risk Derivatives Natural Gas

163

66

Price Risk Derivatives [Abstract]

Derivative, Notional Amount

$ 1,597

$ 1,602

Derivative Instruments (Details 2) (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Derivatives, Fair Value [Line Items]

Derivative assets, current

$ 601

$ 339

Derivative Assets, Noncurrent

136

98

Total derivative assets

737

437

Current derivative liabilities

630

357

Derivative Liabilities, Noncurrent

291

293

Total derivative liabilities

921

650

Net derivative assets (liabilities)

(184)

(213)

Designated as Hedging Instrument [Member]

Derivatives, Fair Value [Line Items]

Total derivative assets

8

4

Total derivative liabilities

134

184

Not Designated as Hedging Instrument [Member]

Derivatives, Fair Value [Line Items]

Total derivative assets

729

433

Total derivative liabilities

787

466

Interest Rate Swap [Member]

Derivatives, Fair Value [Line Items]

Derivative assets, current

0

Derivative Assets, Noncurrent

8

4

Total derivative assets

8

4

Current derivative liabilities

47

40

Derivative Liabilities, Noncurrent

98

160

Total derivative liabilities

145

200

Net derivative assets (liabilities)

(137)

(196)

Interest Rate Swap [Member] |
Designated as Hedging Instrument [Member]

Derivatives, Fair Value [Line Items]

Total derivative assets

8

4

Total derivative liabilities

134

184

Interest Rate Swap [Member] |
Not Designated as Hedging Instrument [Member]

Derivatives, Fair Value [Line Items]

Total derivative assets

0

Total derivative liabilities

11

16

Commodity Option [Member]

Derivatives, Fair Value [Line Items]

Derivative assets, current

601

339

Derivative Assets, Noncurrent

128

94

Total derivative assets

729

433

Current derivative liabilities

583

317

Derivative Liabilities, Noncurrent

193

133

Total derivative liabilities

776

450

Net derivative assets (liabilities)

(47)

(17)

Commodity Option [Member] |
Not Designated as Hedging Instrument [Member]

Derivatives, Fair Value [Line Items]

Total derivative assets

729

433

Total derivative liabilities

$ 776

$ 450

Derivative Instruments (Details 3) (Details) (USD $)

In Millions, unless otherwise specified

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Summary of Derivative Instruments by Risk Exposure [Abstract]

Power contracts included in operating revenues

$ 15

$ (272)

$ (59)

$ (180)

Natural gas contracts included in fuel and purchased energy expense

19

20

64

124

Interest rate swaps included in interest expense

2

3

4

6

Gain (Loss) on interest rate derivatives, net

0

(14)

Gain (Loss) on Derivative Instruments, Net, Pretax

36 ¹

(249)¹

9

(64)

Gain (Loss) on Sale of Derivatives

5

94

33 ¹

55 ¹

Unrealized gain (loss)

31 ¹

(343)¹

(24)²

(119)²

Interest Rate Swap [Member]

Summary of Derivative Instruments by Risk Exposure [Abstract]

Gain (Loss) on Sale of Derivatives

0 ¹

(157)¹

Unrealized gain (loss)

2 ²

3 ²

4 ²

149 ²

Commodity Option [Member]

Summary of Derivative Instruments by Risk Exposure [Abstract]

Gain (Loss) on Sale of Derivatives

5

94

33 ¹

212 ¹

Unrealized gain (loss)

$ 29 ¹

$ (346)¹

$ (28)²

$ (268)²

[1] Does not include the realized value associated with derivative instruments that settle through physical delivery.

[2] In addition to changes in market value on derivatives not designated as hedges, changes in unrealized gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

Derivative Instruments (Details 4) (Details) (USD $)

In Millions, unless otherwise specified

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Derivative Instruments, Gain (Loss) [Line Items]

Gains (Loss) Recognized in OCI (Effective Portion)

$ 48

$ (48)

$ 61

$ (48)

Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)

(10)¹

4 ¹

(19)¹

14 ¹

Interest Rate Swap [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gains (Loss) Recognized in OCI (Effective Portion)

48 ²

(35)²

61 ²

(34)²

Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)

(10)¹ ²

(8)¹ ²

(19)¹ ²

(15)¹ ²

Power Derivative Instruments [Member] |
Commodity Option [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gains (Loss) Recognized in OCI (Effective Portion)

0 ³

(29)³

0 ³

(44)³

Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)

0 ¹ ³

29 ¹ ³

0 ¹ ³

67 ¹ ³

Natural Gas Derivative Instruments [Member] |
Commodity Option [Member]

Derivative Instruments, Gain (Loss) [Line Items]

Gains (Loss) Recognized in OCI (Effective Portion)

0 ³

16 ³

0 ³

30 ³

Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)

$ 0 ¹ ³

$ (17)¹ ³

$ 0 ¹ ³

$ (38)¹ ³

[1] Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $178 million and $242 million at June 30, 2013 and December 31, 2012, respectively.

[2] We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the three and six months ended June 30, 2013 and 2012.

[3] There were no commodity derivative instruments designated as cash flow hedges during the three and six months ended June 30, 2013. We recorded a gain on hedge ineffectiveness of nil and $2 million related to our commodity derivative instruments designated as cash flow hedges during the three and six months ended June 30, 2012.

Derivative Instruments (Textuals) (Details) (USD $)

In Millions, unless otherwise specified

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Dec. 31, 2012

Derivatives, Fair Value [Line Items]

(Gain) Loss On Interest Rate Derivative Instruments Not Designated As Hedging Instruments, Unrealized

$ 14

Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net

0

2

Derivative Instruments (Textuals) [Abstract]

Maximum length of time hedging using interest rate derivative instruments

10 years

Derivative, Net Liability Position, Aggregate Fair Value

16

Collateral Already Posted, Aggregate Fair Value

7

Additional Collateral, Aggregate Fair Value

0

Cumulative cash flow hedge losses remaining in AOCI

178

242

Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months

49

Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments

0

(14)

Interest Rate Derivative Liabilities, Fair Value on Settlement Date [Line Items]

(Gain) Loss on Interest Rate Derivative Instruments Not Designated as Hedging Instruments, realized

142

Interest Rate Swap [Member]

Derivative Instruments (Textuals) [Abstract]

Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments

$ 156

Derivative Instruments (Detail 5) (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Derivative Instruments Subject to Master Netting Arrangement [Line Items]

Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net

$ (184)

$ (213)

Derivative Fair Value, Amount Not Offset Against Collateral, Net

0

Derivative Asset, Fair Value, Amount Offset Against Collateral

32

34

Derivative Asset, Fair Value, Gross Asset

737

437

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

(687)

(396)

Derivative Liability, Fair Value, Gross Liability

(921)

(650)

Derivative Liability, Fair Value, Amount Not Offset Against Collateral

687

396

Margin/Cash (Received) Posted Subject to Master Netting Arrangement

59 ¹

39 ¹

Derivative Liability, Fair Value, Amount Offset Against Collateral

(157)

(208)

Derivative, Fair Value, Amount Offset Against Collateral, Net

(125)

(174)

Derivative, Collateral, Right to Reclaim Cash

77 ¹

46 ¹

Derivative, Collateral, Obligation to Return Cash

(18)¹

(7)¹

Commodity Exchange Traded Futures and Swaps Contracts [Member]

Derivative Instruments Subject to Master Netting Arrangement [Line Items]

Derivative Asset, Fair Value, Amount Offset Against Collateral

0

Derivative Asset, Fair Value, Gross Asset

595

385

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

(580)

(379)

Derivative Liability, Fair Value, Gross Liability

(646)

(424)

Derivative Liability, Fair Value, Amount Not Offset Against Collateral

580

379

Derivative Liability, Fair Value, Amount Offset Against Collateral

0

Derivative, Collateral, Right to Reclaim Cash

66 ¹

45 ¹

Derivative, Collateral, Obligation to Return Cash

(15)¹

(6)¹

Commodity Forward Contract [Member]

Derivative Instruments Subject to Master Netting Arrangement [Line Items]

Derivative Asset, Fair Value, Amount Offset Against Collateral

24

30

Derivative Asset, Fair Value, Gross Asset

134

48

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

(107)

(17)

Derivative Liability, Fair Value, Gross Liability

(130)

(26)

Derivative Liability, Fair Value, Amount Not Offset Against Collateral

107

17

Derivative Liability, Fair Value, Amount Offset Against Collateral

(12)

(8)

Derivative, Collateral, Right to Reclaim Cash

11 ¹

1 ¹

Derivative, Collateral, Obligation to Return Cash

(3)¹

(1)¹

Interest Rate Swap [Member]

Derivative Instruments Subject to Master Netting Arrangement [Line Items]

Derivative, Fair Value, Gross Amount Not Offset Against Collateral, Net

(137)

(196)

Derivative Asset, Fair Value, Amount Offset Against Collateral

8

4

Derivative Asset, Fair Value, Gross Asset

8

4

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

0

Derivative Liability, Fair Value, Gross Liability

(145)

(200)

Derivative Liability, Fair Value, Amount Not Offset Against Collateral

0

Derivative Liability, Fair Value, Amount Offset Against Collateral

(145)

(200)

Derivative, Collateral, Right to Reclaim Cash

0 ¹

Derivative, Collateral, Obligation to Return Cash

$ 0 ¹

[1] Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 6 for a further discussion of our collateral.

Use of Collateral (Details) (USD $)

In Millions, unless otherwise specified

Jun. 30, 2013

Dec. 31, 2012

Use of Collateral [Abstract]

Margin deposits

$ 276 ¹

$ 196 ¹

Natural gas and power prepayments

33

35

Total margin deposits and natural gas and power prepayments with our counterparties

309 ²

231 ²

Letters of credit issued

486

484

First priority liens under power and natural gas agreements

21

14

First priority liens under interest rate swap agreements

150

206

Total letters of credit and first priority liens with our counterparties

657

704

Margin deposits held by us posted by our counterparties

3 ¹ ³

11 ¹ ³

Letters of credit posted with us by our counterparties

1

Total margin deposits and letters of credit posted with us by our counterparties

4

12

Use of Collateral (Textuals) [Abstract]

Margin And Prepayment Amounts Included In Other Assets

18

20

Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses

$ 291

$ 211

[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, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 5 for further discussion of our derivative instruments subject to master netting arrangements.

[2] At June 30, 2013 and December 31, 2012, $291 million and $211 million, respectively, were included in margin deposits and other prepaid expense and $18 million and $20 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.

[3] Included in other current liabilities on our Consolidated Condensed Balance Sheets.

Income Taxes (Income Tax Expense (Benefit)) (Details) (USD $)

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Income Tax Disclosure [Abstract]

Income tax expense (benefit)

$ 48,000,000

$ 52,000,000

$ 98,000,000

$ 58,000,000

Effective Income Tax Rate, Continuing Operations

41.00%

14.00%

33.00%

15.00%

Unrecognized Tax Benefits

79,000,000

Unrecognized Tax Benefits that Would Impact Effective Tax Rate

24,000,000

Unrecognized Tax Benefits Resulting in Net Operating Loss Carryforward

55,000,000

Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued

14,000,000

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Lower Bound

0

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Estimated Range of Change, Upper Bound

$ 5,000,000

Earnings (Loss) per Share (Details)

In Thousands, unless otherwise specified

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Earnings (Loss) per Share [Abstract]

Share-based awards

10,002

13,920

9,741

15,236

Stock-Based Compensation (Schedule of Non-qualified Stock Option Activity) (Details) (USD $)

In Millions, except Share data, unless otherwise specified

6 Months Ended

12 Months Ended

Jun. 30, 2013

Dec. 31, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Options, Outstanding

16,804,136

17,862,501

Options, Outstanding, Weighted Average Exercise Price

$ 17.37

$ 17.30

Options, Outstanding, Weighted Average Remaining Contractual Term

3 years 4 months 26 days

4 years

Options, Outstanding, Intrinsic Value

$ 75

$ 42

Options, Grants in Period, Gross

11,299

Options, Grants in Period, Weighted Average Exercise Price

$ 18.34

Options, Exercises in Period

1,047,364

Options, Exercises in Period, Weighted Average Exercise Price

$ 16.30

Options, Forfeitures in Period

0

Options, Forfeitures in Period, Weighted Average Exercise Price

$ 0.00

Options, Expirations in Period

22,300

Options, Expirations in Period, Weighted Average Exercise Price

$ 17.72

Options, Exercisable

9,910,449

Options, Exercisable, Weighted Average Exercise Price

$ 18.88

Options, Exercisable, Weighted Average Remaining Contractual Term

3 years 1 month 6 days

Options, Exercisable, Intrinsic Value

31

Options, Vested and Expected to Vest, Outstanding

16,675,607

Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price

$ 17.38

Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term

3 years 4 months 26 days

Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value

$ 74

Stock-Based Compensation (Asummptions used to estimate fair value for options) (Details)

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term

6 years 6 months ¹

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate

1.40% ²

1.60% ²

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate

25.60% ³

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate

0.00% ⁴

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value

$ 5.31

$ 5.18

Minimum [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate

30.00% ³

Maximum [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate

30.50% ³

[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 we do not anticipate any cash dividend payments on our common stock in the near future.

Stock-Based Compensation (Summary restricted stock and restricted stock unit activity) (Details) (Restricted Stock [Member], USD $)

6 Months Ended

Jun. 30, 2013

Dec. 31, 2012

Restricted Stock [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number

4,669,897

4,134,037

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value

$ 16.47

$ 14.33

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period

1,759,198

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value

$ 18.45

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period

93,914

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value

$ 15.96

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period

1,129,424

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value

$ 11.79

Stock-Based Compensation (Stock Based Compensation Textuals) (Details) (USD $)

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Vesting period for graded and cliff vesting options - minimum

1 year

Vesting period for graded and cliff vesting options - maximum

5 years

Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Minimum Range

5 years

Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Maximum Range

10 years

Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized for Directors

567,000

Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized for Employees

40,533,000

Percentage of sub-grants representing the total

33.33%

Vest Term of First Sub Grant

1 year

Vest Term of the Second Sub-Grant

2 years

Vest Term of the Third Sub-Grant

3 years

Grants in Option Grants with Three Year Cliff Vesting

1

Vesting term of option grants with three year cliff vesting

3 years

Allocated Share-based Compensation Expense

$ 11,000,000

$ 7,000,000

$ 19,000,000

$ 13,000,000

Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value

4,000,000

0

Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options

17,000,000

3,000,000

Liability Classified Share-Based Awards

1,000,000

Stock Options [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized

3,000,000

Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition

5 months

Restricted Stock [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized

39,000,000

Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition

1 year 7 months

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value

21,000,000

19,000,000

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period

1,759,198

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value

$ 18.45

Restricted Stock Units (RSUs) [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized

$ 1,000,000

Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition

11 months

Performance Shares [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period

449,798

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value

$ 21.25

Segment and Significant Customer Information (Details) (USD $)

In Millions, unless otherwise specified

3 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2013

Jun. 30, 2012

Revenues from External Customers and Long-Lived Assets [Line Items]

Revenue from External Customer

$ 1,572

$ 879

$ 2,813

$ 2,115

Intersegment revenue

0

Operating revenues

1,572

879

2,813

2,115

Commodity Margin

533

609 ¹ ²

994

1,126 ¹ ²

Add: Mark-to-market commodity activity, net and other

39 ³

(344)³

(2)⁴

(260)⁴

Plant operating expense

257

271

484

492

Depreciation and amortization expense

145

138

291

278

Sales, general and other administrative expense

36

35

69

68

Other operating expenses

20

19

38

40

(Income) loss from unconsolidated investments in power plants

(8)

(5)

(16)

(14)

Income (loss) from operations

122

(193)

126

2

Interest expense, net of interest income

169

182

343

364

Loss on interest rate derivatives

0

14

Debt Extinguishment Costs and Other (Income) Expense, Net

71

6

76

20

Income (loss) before income taxes

(118)

(381)

(293)

(396)

Lease levelization

(11)

(1)

(27)

(9)

Commodity Margin Riverside Energy Center

24

32

Commodity Margin Broad River Energy Center

13

24

Contract amortization

3

7

West [Member]

Revenues from External Customers and Long-Lived Assets [Line Items]

Revenue from External Customer

479

258

862

674

Intersegment revenue

0

1

5

Operating revenues

479

259

863

679

Commodity Margin

198

210 ¹ ²

400

418 ¹ ²

Add: Mark-to-market commodity activity, net and other

19 ³

(76)³

(18)⁴

(40)⁴

Plant operating expense

88

112

181

193

Depreciation and amortization expense

52

49

103

99

Sales, general and other administrative expense

3

6

7

14

Other operating expenses

11

9

20

(Income) loss from unconsolidated investments in power plants

0

Income (loss) from operations

63

(42)

71

52

Texas [Member]

Revenues from External Customers and Long-Lived Assets [Line Items]

Revenue from External Customer

571

188

978

544

Intersegment revenue

(25)

41

(18)

61

Operating revenues

546

229

960

605

Commodity Margin

133

145 ¹ ²

209

254 ¹ ²

Add: Mark-to-market commodity activity, net and other

34 ³

(217)³

23 ⁴

(183)⁴

Plant operating expense

96

72

164

140

Depreciation and amortization expense

44

34

87

69

Sales, general and other administrative expense

21

13

38

24

Other operating expenses

1

2

3

(Income) loss from unconsolidated investments in power plants

0

Income (loss) from operations

5

(192)

(59)

(165)

North [Member]

Revenues from External Customers and Long-Lived Assets [Line Items]

Revenue from External Customer

348

269

654

567

Intersegment revenue

8

2

15

5

Operating revenues

356

271

669

572

Commodity Margin

159

181 ¹ ²

301

325 ¹ ²

Add: Mark-to-market commodity activity, net and other

(12)³

(3)³

(5)⁴

9 ⁴

Plant operating expense

46

58

90

103

Depreciation and amortization expense

32

34

65

67

Sales, general and other administrative expense

6

8

12

14

Other operating expenses

7

6

14

15

(Income) loss from unconsolidated investments in power plants

(8)

(5)

(16)

(14)

Income (loss) from operations

64

77

131

149

Southeast [Member]

Revenues from External Customers and Long-Lived Assets [Line Items]

Revenue from External Customer

174

164

319

330

Intersegment revenue

71

(6)

104

16

Operating revenues

245

158

423

346

Commodity Margin

43

73 ¹ ²

84

129 ¹ ²

Add: Mark-to-market commodity activity, net and other

7 ³

(42)³

14 ⁴

(32)⁴

Plant operating expense

35

36

65

69

Depreciation and amortization expense

18

22

37

45

Sales, general and other administrative expense

7

12

15

Other operating expenses

(1)

2

1

3

(Income) loss from unconsolidated investments in power plants

0

Income (loss) from operations

(9)

(36)

(17)

(35)

Consolidation and Elimination [Member]

Revenues from External Customers and Long-Lived Assets [Line Items]

Revenue from External Customer

0

Intersegment revenue

(54)

(38)

(102)

(87)

Operating revenues

(54)

(38)

(102)

(87)

Commodity Margin

0

0 ¹ ²

0

0 ¹ ²

Add: Mark-to-market commodity activity, net and other

(9)³

(6)³

(16)⁴

(14)⁴

Plant operating expense

(8)

(7)

(16)

(13)

Depreciation and amortization expense

(1)

(2)

Sales, general and other administrative expense

(1)

1

0

1

Other operating expenses

2

1

(1)

(Income) loss from unconsolidated investments in power plants

0

Income (loss) from operations

$ (1)

$ 0

$ 1

[1] Our Southeast segment includes Commodity Margin of $13 million and $24 million for the three and six months ended June 30, 2012 related to Broad River, which was sold in December 2012.

[2] Our North segment includes Commodity Margin of $24 million and $32 million for the three and six months ended June 30, 2012 related to Riverside Energy Center, LLC, which was sold in December 2012.

[3] Includes $(11) million and $(1) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended June 30, 2013 and 2012, respectively

[4] Includes $(27) million and $(9) million of lease levelization and $7 million and $7 million of amortization expense for the six months ended June 30, 2013 and 2012, respectively.