Calpine (CPNLQ) 10-Q 30 Jul 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 28, 2015
Entity Information [Line Items]
Entity Registrant Name	CALPINE CORP
Entity Central Index Key	916,457
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		360,092,812

Consolidated Condensed Statemen

Consolidated Condensed Statements of Operations - USD ($) shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating revenues:
Commodity revenue	$ 1,407	$ 1,766	$ 3,045	$ 3,814
Mark-to-market gain	31	169	34	83
Other revenue	4	4	9	7
Operating revenues	1,442	1,939	3,088	3,904
Operating expenses:
Commodity expense	734	1,106	1,811	2,476
Mark-to-market (gain) loss	32	28	(35)	15
Fuel and purchased energy expense	766	1,134	1,776	2,491
Plant operating expense	272	274	532	539
Depreciation and amortization expense	160	147	318	300
Sales, general and other administrative expense	30	38	67	71
Other operating expenses	20	21	40	43
Total operating expenses	1,248	1,614	2,733	3,444
(Income) from unconsolidated investments in power plants	(7)	(4)	(12)	(13)
Income from operations	201	329	367	473
Interest expense	158	169	312	335
Interest (income)	(1)	(2)	(2)	(3)
Debt modification and extinguishment costs	13	0	32	1
Other (income) expense, net	5	6	7	16
Income before income taxes	26	156	18	124
Income tax expense (benefit)	5	15	4	(4)
Net income (loss)	21	141	14	128
Net income attributable to the noncontrolling interest	(2)	(2)	(5)	(6)
Net income attributable to Calpine	$ 19	$ 139	$ 9	$ 122
Basic earnings per common share attributable to Calpine:
Weighted Average Number of Shares Outstanding, Basic and Diluted	366,975	416,507	369,938	418,296
Earnings Per Share, Basic and Diluted	$ 0.05	$ 0.33	$ 0.02	$ 0.29
Weighted Average Number of Shares Outstanding, Diluted	369,946	421,348	373,404	422,697
Earnings Per Share, Diluted	$ 0.05	$ 0.33	$ 0.02	$ 0.29

Consolidated Condensed Stateme3

Consolidated Condensed Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Statement of Comprehensive Income [Abstract]
Net income	$ 21	$ 141	$ 14	$ 128
Cash flow hedging activities:
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income	2	(22)	(16)	(35)
Reclassification adjustment for loss on cash flow hedges realized in net income	12	13	24	26
Foreign currency translation gain (loss)	4	6	(8)	0
Income tax expense	0	0	0	0
Other comprehensive income (loss)	18	(3)	0	(9)
Comprehensive income	39	138	14	119
Comprehensive (income) attributable to the noncontrolling interest	(4)	(1)	(6)	(5)
Comprehensive income attributable to Calpine	$ 35	$ 137	$ 8	$ 114

Consolidated Condensed Balance

Consolidated Condensed Balance Sheets - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents ($254 and $229 attributable to VIEs)	$ 422	$ 717
Accounts receivable, net of allowance of $3 and $4	595	648
Inventories	477	447
Margin deposits and other prepaid expense	152	148
Restricted cash, current ($93 and $106 attributable to VIEs)	162	195
Derivative assets, current	1,607	2,058
Other current assets	32	7
Total current assets	3,447	4,220
Property, plant and equipment, net ($4,260 and $4,342 attributable to VIEs)	13,147	13,190
Restricted cash, net of current portion ($47 and $48 attributable to VIEs)	48	49
Investments in power plants	87	95
Long-term derivative assets	637	439
Other assets ($172 and $164 attributable to VIEs)	391	385
Total assets	17,757	18,378
Current liabilities:
Accounts payable	443	580
Accrued interest payable	133	165
Debt, current portion ($148 and $150 attributable to VIEs)	198	199
Derivative liabilities, current	1,407	1,782
Other current liabilities	355	473
Total current liabilities	2,536	3,199
Debt, net of current portion ($3,168 and $3,242 attributable to VIEs)	11,493	11,083
Long-term derivative liabilities	453	444
Other long-term liabilities	274	221
Total liabilities	$ 14,756	$ 14,947
Commitments and contingencies (see Note 11)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding	$ 0	$ 0
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 504,252,268 and 502,287,022 shares issued, respectively, and 361,150,393 and 381,921,264 shares outstanding, respectively	1	1
Treasury stock, at cost, 143,101,875 and 120,365,758 shares, respectively	(2,810)	(2,345)
Additional paid-in capital	12,463	12,440
Accumulated deficit	(6,531)	(6,540)
Accumulated other comprehensive loss	(179)	(178)
Total Calpine stockholders’ equity	2,944	3,378
Noncontrolling interest	57	53
Total stockholders’ equity	3,001	3,431
Total liabilities and stockholders’ equity	$ 17,757	$ 18,378

Consolidated Condensed Balance5

Consolidated Condensed Balance Sheets (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Cash and cash equivalents ($254 and $229 attributable to VIEs)	$ 422	$ 717
Accounts receivable, net of allowance of $3 and $4	3	4
Restricted cash, current ($93 and $106 attributable to VIEs)	162	195
Property, plant and equipment, net ($4,260 and $4,342 attributable to VIEs)	13,147	13,190
Restricted cash, net of current portion ($47 and $48 attributable to VIEs)	48	49
Other assets ($172 and $164 attributable to VIEs)	391	385
Debt, current portion ($148 and $150 attributable to VIEs)	198	199
Debt, net of current portion ($3,168 and $3,242 attributable to VIEs)	$ 11,493	$ 11,083
Preferred Stock, Par or Stated Value Per Share	$ 0.001	$ 0.001
Preferred Stock, Shares Authorized	100,000,000	100,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.001	$ 0.001
Common Stock, Shares Authorized	1,400,000,000	1,400,000,000
Common Stock, Shares, Issued	504,252,268	502,287,022
Common Stock, Shares, Outstanding	361,150,393	381,921,264
Treasury Stock, Shares	143,101,875	120,365,758
Variable Interest Entity, Primary Beneficiary [Member]
Cash and cash equivalents ($254 and $229 attributable to VIEs)	$ 254	$ 229
Restricted cash, current ($93 and $106 attributable to VIEs)	93	106
Property, plant and equipment, net ($4,260 and $4,342 attributable to VIEs)	4,260	4,342
Restricted cash, net of current portion ($47 and $48 attributable to VIEs)	47	48
Other assets ($172 and $164 attributable to VIEs)	172	164
Debt, current portion ($148 and $150 attributable to VIEs)	148	150
Debt, net of current portion ($3,168 and $3,242 attributable to VIEs)	$ 3,168	$ 3,242

Consolidated Condensed Stateme6

Consolidated Condensed Statements of Cash Flows - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities:
Net income		$ 14	$ 128
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense(1)	[1]	342	322
Deferred income taxes		3	(12)
Mark-to-market activity, net	[2]	(70)	(70)
(Income) from unconsolidated investments in power plants		(12)	(13)
Return on unconsolidated investments in power plants		13	13
Stock-based compensation expense		12	22
Other		2	2
Change in operating assets and liabilities:
Accounts receivable		29	(212)
Derivative instruments, net		(36)	(109)
Other assets		(118)	(40)
Accounts payable and accrued expenses		(205)	378
Other liabilities		45	(60)
Net cash provided by operating activities		19	349
Cash flows from investing activities:
Purchases of property, plant and equipment		(279)	(258)
Purchase of Guadalupe Energy Center		0	(656)
Decrease in restricted cash		34	14
Other		(1)	0
Net cash used in investing activities		(246)	(900)
Cash flows from financing activities:
Borrowings under CCFC Term Loans and First Lien Term Loans		1,592	420
Repayment of CCFC Term Loans and First Lien Term Loans		(1,613)	(23)
Borrowings under Senior Unsecured Notes		650	0
Repurchase of First Lien Notes		(147)	0
Proceeds from Issuance of Long-term Debt		0	2
Repayments of project financing, notes payable and other		(85)	(55)
Financing costs		(17)	(10)
Stock repurchases		(454)	(297)
Proceeds from exercises of stock options		6	15
Net cash provided by (used in) financing activities		(68)	52
Net decrease in cash and cash equivalents		(295)	(499)
Cash and cash equivalents, beginning of period		717	941
Cash and cash equivalents, end of period		422	442
Cash paid during the period for:
Interest, net of amounts capitalized		322	288
Income taxes		17	16
Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable		(20)	13
Capital Lease Obligations Incurred		$ 9	$ 0
[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 mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
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 (included in our West segment), Texas (included in our Texas segment) and the Northeast region (included in our East segment) 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. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power and other 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, 2014 , included in our 2014 Form 10-K. The results for interim periods are not 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 mark-to-market 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 — We have reclassified certain prior year amounts for comparative purposes. These reclassifications did not have a material impact on our financial condition, results of operations or cash flows. 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. 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 are expected to 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, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 Current Non-Current Total Current Non-Current Total Debt service $ 16 $ 25 $ 41 $ 10 $ 25 $ 35 Rent reserve — — — 4 — 4 Construction/major maintenance 50 19 69 54 17 71 Security/project/insurance 93 4 97 127 5 132 Other 3 — 3 — 2 2 Total $ 162 $ 48 $ 210 $ 195 $ 49 $ 244 Property, Plant and Equipment, Net — At June 30, 2015 and December 31, 2014 , the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions): June 30, 2015 December 31, 2014 Depreciable Lives Buildings, machinery and equipment $ 16,422 $ 16,059 3 – 47 Years Geothermal properties 1,320 1,294 13 – 58 Years Other 208 203 3 – 47 Years 17,950 17,556 Less: Accumulated depreciation 5,236 4,984 12,714 12,572 Land 121 120 Construction in progress 312 498 Property, plant and equipment, net $ 13,147 $ 13,190 Capitalized Interest — The total amount of interest capitalized was $4 million and $6 million for the three months ended June 30, 2015 and 2014 , respectively, and $9 million and $12 million for the six months ended June 30, 2015 and 2014 , respectively. Treasury Stock — During the six months ended June 30, 2015 , we repurchased a total of 22.1 million shares of our outstanding common stock for approximately $454 million at an average price of $20.50 per share. Additionally, we withheld shares with a value of $11 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees and with net share employee stock option exercises under the Equity Plan. New Accounting Standards and Disclosure Requirements Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding revenue recognition. The standard was effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption being prohibited. In July 2015, the FASB approved a proposal to defer the effective date of Accounting Standards Update 2014-09 for public entities by one year, which would result in the standard being effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The proposal would also permit entities to early adopt, but only as of the original effective date. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows. Consolidation — In February 2015, the FASB issued Accounting Standards Update 2015-02, “Amendments to the Consolidation Analysis.” This standard amends the consolidation model used in determining whether a reporting entity should consolidate the financial results of certain of its partially- and wholly-owned subsidiaries. All of our subsidiaries are subject to reevaluation under the revised consolidation model. Specifically, the amendments (i) modify the evaluation of whether limited partnerships and similar legal entities are voting interest entities or VIEs, (ii) eliminate the presumption that a general partner should consolidate the financial results of a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships and (iv) provide an exception for certain types of entities. This standard is effective for fiscal periods beginning after December 15, 2015, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard. Debt Issuance Costs — In April 2015, the FASB issued Accounting Standards Update 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” The standard requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, which is consistent with the presentation of debt discounts. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period and requires retrospective adoption with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard. Cloud Computing Arrangements — In April 2015, the FASB issued Accounting Standards Update 2015-05, “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” This standard provides guidance regarding whether a cloud computing arrangement represents a software license or a service contract. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods and allows for either prospective or retrospective adoption with early adoption permitted. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows. Inventory — In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” This standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective adoption with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.

Acquisition (Notes)

Acquisition (Notes)	6 Months Ended
	Jun. 30, 2015
Business Combinations [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	Acquisitions Acquisition of Champion Energy On July 20, 2015, we announced that we have entered into an agreement, through our indirect, wholly-owned subsidiary Calpine Energy Services Holdco LLC, to purchase Champion Energy Marketing, LLC from Champion Energy Holdings, LLC, which owns a 75% interest, and EDF Trading North America, LLC, which owns a 25% interest, for approximately $240 million , excluding working capital adjustments. Champion Energy, a leading retail electric provider, is expected to serve approximately 22 million MWh of commercial, industrial and residential customer load in 2015, concentrated in Texas, PJM and the Northeast U.S. where Calpine has a substantial power generation presence. The addition of this well-established retail sales organization is expected to provide us an important outlet for directly reaching a much greater portion of the load we serve. We expect the transaction to close by the fourth quarter of 2015, subject to regulatory approvals, and will fund the acquisition with cash on hand. Acquisition of Fore River Energy Center On November 7, 2014, we, through our indirect, wholly-owned subsidiary Calpine Fore River Energy Center, LLC, completed the purchase of Fore River Energy Center, a power plant with a nameplate capacity of 809 MW, and related plant inventory from a subsidiary of Exelon Corporation, for approximately $ 530 million , excluding working capital adjustments. During the six months ended June 30, 2015 , there were no material adjustments made to the initial purchase price allocation recorded in the fourth quarter of 2014 related to our acquisition of Fore River Energy Center. Although the purchase price allocation has not been finalized, we do not expect to record any material adjustments to the preliminary purchase price allocation nor do we expect to recognize any goodwill as a result of this acquisition.

Variable Interest Entities and

Variable Interest Entities and Unconsolidated Investments in Power Plants	6 Months Ended
	Jun. 30, 2015
Variable Interest Entities and Unconsolidated Investments [Abstract]
Variable Interest Entities and Unconsolidated Investments in Power Plants	Variable Interest Entities and Unconsolidated Investments 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, 2015 . See Note 5 in our 2014 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 10,266 MW and 10,365 MW at June 30, 2015 and December 31, 2014 , 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. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil during each of the three and six months ended June 30, 2015 and nil and $ 40 million during the three and six months ended June 30, 2014 , respectively. 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. 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. 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. 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, 2015 and December 31, 2014 , our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions): Ownership Interest as of June 30, 2015 June 30, 2015 December 31, 2014 Greenfield LP 50% $ 78 $ 78 Whitby 50% 9 17 Total investments in power plants $ 87 $ 95 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; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At June 30, 2015 and December 31, 2014 , equity method investee debt was approximately $ 312 million and $ 342 million , respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $ 156 million and $ 171 million at June 30, 2015 and December 31, 2014 , respectively. Our equity interest in the net income from Greenfield LP and Whitby for the three and six months ended June 30, 2015 and 2014 , is recorded in (income) from unconsolidated investments in power plants on our Consolidated Condensed Statements of Operations. 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, 2015 2014 2015 2014 Greenfield LP $ (4 ) $ — $ (6 ) $ (5 ) Whitby (3 ) (4 ) (6 ) (8 ) Total $ (7 ) $ (4 ) $ (12 ) $ (13 ) Distributions from Greenfield LP were nil during each of the three and six months ended June 30, 2015 and 2014 . Distributions from Whitby were $13 million during each of the three and six months ended June 30, 2015 and nil and $13 million during the three and six months ended June 30, 2014, respectively. Inland Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) 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. Significant Unconsolidated Subsidiaries — Greenfield LP and Whitby met the criteria of significant unconsolidated subsidiaries for the six months ended June 30, 2015 , based upon the relationship of our equity income from our investment to our consolidated net income before taxes. Aggregated summarized financial data for the six months ended June 30, 2015 and 2014 are set forth below (in millions): Condensed Combined Statements of Operations of Our Unconsolidated Subsidiaries (Unaudited) Six Months Ended June 30, 2015 2014 Revenues $ 98 $ 149 Operating expenses 66 111 Income from operations 32 38 Interest expense, net of interest income 10 12 Other (income) expense, net (1 ) — Net income $ 23 $ 26

Debt

Debt	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Debt	Debt Our debt at June 30, 2015 and December 31, 2014 , was as follows (in millions): June 30, 2015 December 31, 2014 Senior Unsecured Notes $ 3,450 $ 2,800 First Lien Term Loans 2,787 2,799 First Lien Notes 1,928 2,075 Project financing, notes payable and other 1,737 1,810 CCFC Term Loans 1,588 1,596 Capital lease obligations 201 202 Subtotal 11,691 11,282 Less: Current maturities 198 199 Total long-term debt $ 11,493 $ 11,083 Our effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and mark-to-market gains (losses) on interest rate swaps, decreased to 5.5% for the six months ended June 30, 2015 , from 6.1% for the same period in 2014. The issuance of our Senior Unsecured Notes in July 2014 and February 2015 and our 2022 First Lien Term Loan in May 2015 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Notes and all of our 2018 First Lien Term Loans with debt carrying lower interest rates. Senior Unsecured Notes The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions): June 30, 2015 December 31, 2014 2023 Senior Unsecured Notes $ 1,250 $ 1,250 2024 Senior Unsecured Notes 650 — 2025 Senior Unsecured Notes 1,550 1,550 Total Senior Unsecured Notes $ 3,450 $ 2,800 In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024 in a public offering. The 2024 Senior Unsecured Notes bear interest at 5.5% per annum with interest payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2015. The 2024 Senior Unsecured Notes were issued at par, mature on February 1, 2024 and contain substantially similar covenants, qualifications, exceptions and limitations as our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes. We used the net proceeds received from the issuance of our 2024 Senior Unsecured Notes to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 2023 First Lien Notes and for general corporate purposes. During the first quarter of 2015, we recorded approximately $9 million in deferred financing costs related to the issuance of our 2024 Senior Unsecured Notes and approximately $19 million in debt extinguishment costs related to the partial repurchase of our 2023 First Lien Notes. First Lien Term Loans The amounts outstanding under our First Lien Term Loans are summarized in the table below (in millions): June 30, 2015 December 31, 2014 2018 First Lien Term Loans $ — $ 1,597 2019 First Lien Term Loan 812 816 2020 First Lien Term Loan 384 386 2022 First Lien Term Loan 1,591 — Total First Lien Term Loans $ 2,787 $ 2,799 On May 28, 2015, we entered into our $1.6 billion 2022 First Lien Term Loan. We used the net proceeds received, together with operating cash on hand, to repay the 2018 First Lien Term Loans. The 2022 First Lien Term Loan matures on May 27, 2022 and bears interest, at our option, at either (i) the base rate, equal to the highest of (a) the Federal Funds effective rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the 2022 First Lien Term Loan credit agreement), plus an applicable margin of 1.75% , or (ii) LIBOR plus 2.75% per annum subject to a LIBOR floor of 0.75% . An aggregate amount equal to 0.25% of the aggregate principal amount of the 2022 First Lien Term Loan will be payable at the end of each quarter commencing in September 2015. The 2022 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as the First Lien Term Loans and First Lien Notes. We accounted for this transaction as a debt modification rather than an extinguishment of debt and, accordingly, did not record any debt extinguishment costs associated with the repayment of our 2018 First Lien Term Loans. However, in accordance with the accounting guidance for debt modification and extinguishment, we recorded approximately $13 million in debt modification costs associated with issuance costs and approximately $6 million in deferred financing costs related to the 2022 First Lien Term Loan during the second quarter of 2015. First Lien Notes The amounts outstanding under our First Lien Notes are summarized in the table below (in millions): June 30, 2015 December 31, 2014 2022 First Lien Notes $ 745 $ 745 2023 First Lien Notes (1) 693 840 2024 First Lien Notes 490 490 Total First Lien Notes $ 1,928 $ 2,075 ____________ (1) On February 3, 2015, we repurchased approximately $147 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, as described in further detail above. Corporate Revolving Facility and Other Letters of Credit Facilities The table below represents amounts issued under our letter of credit facilities at June 30, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 Corporate Revolving Facility (1) $ 179 $ 223 CDHI 244 214 Various project financing facilities 219 207 Total $ 642 $ 644 ____________ (1) The Corporate Revolving Facility represents our primary revolving facility. Fair Value of Debt We record our debt instruments based on contractual terms, net of any applicable premium or discount. The following table details the fair values and carrying values of our debt instruments at June 30, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 Fair Value Carrying Value Fair Value Carrying Value Senior Unsecured Notes $ 3,347 $ 3,450 $ 2,832 $ 2,800 First Lien Term Loans 2,768 2,787 2,769 2,799 First Lien Notes 2,059 1,928 2,247 2,075 Project financing, notes payable and other (1) 1,660 1,629 1,734 1,688 CCFC Term Loans 1,564 1,588 1,540 1,596 Total $ 11,398 $ 11,382 $ 11,122 $ 10,958 ____________ (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 Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loans 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 Rec

Assets and Liabilities with Recurring Fair Value Measurements	6 Months Ended
	Jun. 30, 2015
Fair Value Measurements [Abstract]
Assets and Liabilities with Recurring Fair Value Measurements	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 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, 2015 and December 31, 2014 , by level within the fair value hierarchy: Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2015 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 577 $ — $ — $ 577 Margin deposits 103 — — 103 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,684 — — 1,684 Commodity forward contracts (2) — 284 273 557 Interest rate swaps — 3 — 3 Total assets $ 2,364 $ 287 $ 273 $ 2,924 Liabilities: Margin deposits posted with us by our counterparties $ 53 $ — $ — $ 53 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,506 — — 1,506 Commodity forward contracts (2) — 219 30 249 Interest rate swaps — 105 — 105 Total liabilities $ 1,559 $ 324 $ 30 $ 1,913 Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2014 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 896 $ — $ — $ 896 Margin deposits 96 — — 96 Commodity instruments: Commodity exchange traded futures and swaps contracts 2,134 — — 2,134 Commodity forward contracts (2) — 195 164 359 Interest rate swaps — 4 — 4 Total assets $ 3,126 $ 199 $ 164 $ 3,489 Liabilities: Margin deposits posted with us by our counterparties $ 47 $ — $ — $ 47 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,870 — — 1,870 Commodity forward contracts (2) — 163 79 242 Interest rate swaps — 114 — 114 Total liabilities $ 1,917 $ 277 $ 79 $ 2,273 ___________ (1) As of June 30, 2015 and December 31, 2014 , we had cash equivalents of $367 million and $679 million included in cash and cash equivalents and $210 million and $217 million included in restricted cash, respectively. (2) Includes OTC swaps and options. At June 30, 2015 and December 31, 2014 , the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor 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. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at June 30, 2015 and December 31, 2014 : Quantitative Information about Level 3 Fair Value Measurements June 30, 2015 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ 237 Discounted cash flow Market price (per MWh) $12.68 — $121.40/MWh Power Congestion Products $ 7 Discounted cash flow Market price (per MWh) $(19.56) — $19.56/MWh December 31, 2014 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ 74 Discounted cash flow Market price (per MWh) $14.00 — $122.79/MWh Natural Gas Contracts $ 5 Discounted cash flow Market price (per MMBtu) $1.00 — $10.86/MMBtu Power Congestion Products $ 9 Discounted cash flow Market price (per MWh) $(19.56) — $19.56/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, 2015 2014 2015 2014 Balance, beginning of period $ 203 $ 8 $ 85 $ 14 Realized and mark-to-market gains (losses): Included in net income: Included in operating revenues (1) 45 (7 ) 176 (15 ) Included in fuel and purchased energy expense (2) — — 2 6 Purchases and settlements: Purchases 2 — 4 — Settlements (10 ) (3 ) (21 ) (6 ) Transfers in and/or out of level 3 (3) : Transfers into level 3 (4) — 2 — — Transfers out of level 3 (5) 3 (9 ) (3 ) (8 ) Balance, end of period $ 243 $ (9 ) $ 243 $ (9 ) Change in unrealized gains (losses) relating to instruments still held at end of period $ 45 $ (7 ) $ 178 $ (9 ) ___________ (1) For power contracts and other power-related products, 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, 2015 and 2014 . (4) There were no transfers out of level 2 into level 3 for each of the three and six months ended June 30, 2015 and for the six months ended June 30, 2014. We had $2 million in gains transferred out of level 2 into level 3 for the three months ended June 30, 2014, due to changes in market liquidity in various power markets. (5) We had $3 million in losses and $(9) million in gains transferred out of level 3 into level 2 for the three months ended June 30, 2015 and 2014, respectively, and $(3) million and $(8) million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2015 and 2014 , respectively, due to changes in market liquidity in various power markets.

Derivative Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2015
Derivative Instruments [Abstract]
Derivative Instruments	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, environmental products 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. We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading gains and losses were not material for the three and six months ended June 30, 2015 and 2014 . 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, 2015 , the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 8 years. As of June 30, 2015 and December 31, 2014 , the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions): Derivative Instruments Notional Amounts June 30, 2015 December 31, 2014 Power (MWh) (99 ) (62 ) Natural gas (MMBtu) 874 291 Environmental credits (Tonnes) 3 — Interest rate swaps $ 1,411 $ 1,431 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, 2015 , was $12 million for which we have posted collateral of $9 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 additional collateral of $14 million would be required and that no counterparty could request immediate, full settlement. Accounting for Derivative Instruments We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses 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. 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 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 only apply hedge accounting to our interest rate derivative instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate swaps 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 interest rate hedging instruments are recognized currently in earnings as a component of interest expense. 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, interest rate and environmental product 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 mark-to-market gain/loss as a component of operating revenues (for power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, environmental product 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. Derivatives Included on Our Consolidated Condensed Balance Sheets The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at June 30, 2015 and December 31, 2014 (in millions): June 30, 2015 Commodity Instruments Interest Rate Swaps Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 1,607 $ — $ 1,607 Long-term derivative assets 634 3 637 Total derivative assets $ 2,241 $ 3 $ 2,244 Current derivative liabilities $ 1,365 $ 42 $ 1,407 Long-term derivative liabilities 390 63 453 Total derivative liabilities $ 1,755 $ 105 $ 1,860 Net derivative asset (liabilities) $ 486 $ (102 ) $ 384 December 31, 2014 Commodity Interest Rate Swaps Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 2,058 $ — $ 2,058 Long-term derivative assets 435 4 439 Total derivative assets $ 2,493 $ 4 $ 2,497 Current derivative liabilities $ 1,738 $ 44 $ 1,782 Long-term derivative liabilities 374 70 444 Total derivative liabilities $ 2,112 $ 114 $ 2,226 Net derivative asset (liabilities) $ 381 $ (110 ) $ 271 June 30, 2015 December 31, 2014 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 $ 3 $ 105 $ 4 $ 112 Total derivatives designated as cash flow hedging instruments $ 3 $ 105 $ 4 $ 112 Derivatives not designated as hedging instruments: Commodity instruments $ 2,241 $ 1,755 $ 2,493 $ 2,112 Interest rate swaps — — — 2 Total derivatives not designated as hedging instruments $ 2,241 $ 1,755 $ 2,493 $ 2,114 Total derivatives $ 2,244 $ 1,860 $ 2,497 $ 2,226 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, 2015 and December 31, 2014 (in millions): June 30, 2015 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 $ 1,684 $ (1,506 ) $ (178 ) $ — Commodity forward contracts 557 (231 ) (9 ) 317 Interest rate swaps 3 — — 3 Total derivative assets $ 2,244 $ (1,737 ) $ (187 ) $ 320 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,506 ) $ 1,506 $ — $ — Commodity forward contracts (249 ) 231 9 (9 ) Interest rate swaps (105 ) — — (105 ) Total derivative (liabilities) $ (1,860 ) $ 1,737 $ 9 $ (114 ) Net derivative assets (liabilities) $ 384 $ — $ (178 ) $ 206 December 31, 2014 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 $ 2,134 $ (1,865 ) $ (269 ) $ — Commodity forward contracts 359 (222 ) — 137 Interest rate swaps 4 — — 4 Total derivative assets $ 2,497 $ (2,087 ) $ (269 ) $ 141 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,870 ) $ 1,865 $ 5 $ — Commodity forward contracts (242 ) 222 10 (10 ) Interest rate swaps (114 ) — — (114 ) Total derivative (liabilities) $ (2,226 ) $ 2,087 $ 15 $ (124 ) Net derivative assets (liabilities) $ 271 $ — $ (254 ) $ 17 ____________ (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 7 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 mark-to-market activity within our earnings. The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market 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, 2015 2014 2015 2014 Realized gain (loss) (1) Commodity derivative instruments $ 104 $ 18 $ 163 $ (21 ) Total realized gain (loss) $ 104 $ 18 $ 163 $ (21 ) Mark-to-market gain (loss) (2) Commodity derivative instruments $ (1 ) $ 141 $ 69 $ 68 Interest rate swaps — 1 1 2 Total mark-to-market gain (loss) $ (1 ) $ 142 $ 70 $ 70 Total activity, net $ 103 $ 160 $ 233 $ 49 ___________ (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 mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Realized and mark-to-market gain (loss) Derivatives contracts included in operating revenues $ 115 $ 158 $ 234 $ (79 ) Derivatives contracts included in fuel and purchased energy expense (12 ) 1 (2 ) 126 Interest rate swaps included in interest expense — 1 1 2 Total activity, net $ 103 $ 160 $ 233 $ 49 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)(4) 2015 2014 2015 2014 Affected Line Item on the Consolidated Condensed Statements of Operations Interest rate swaps (1)(2) $ 14 $ (9 ) $ (12 ) $ (13 ) Interest expense 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)(4) 2015 2014 2015 2014 Affected Line Item on the Consolidated Condensed Statements of Operations Interest rate swaps (1)(2) $ 8 $ (9 ) $ (24 ) $ (26 ) Interest expense ____________ (1) 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, 2015 and 2014 . (2) We recorded an income tax expense of nil for each of the three and six months ended June 30, 2015 and 2014, in AOCI related to our cash flow hedging activities. (3) Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $142 million and $149 million at June 30, 2015 and December 31, 2014 , respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $11 million and $12 million at June 30, 2015 and December 31, 2014 , respectively. (4) Includes a loss of $5 million and $10 million for the three and six months ended June 30, 2014, respectively, that was reclassified from AOCI to interest expense, where the hedged transactions are no longer expected to occur. We estimate that pre-tax net losses of $46 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	6 Months Ended
	Jun. 30, 2015
Use of Collateral [Abstract]
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, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 Margin deposits (1) $ 103 $ 96 Natural gas and power prepayments 25 22 Total margin deposits and natural gas and power prepayments with our counterparties (2) $ 128 $ 118 Letters of credit issued $ 452 $ 450 First priority liens under power and natural gas agreements 24 48 First priority liens under interest rate swap agreements 106 116 Total letters of credit and first priority liens with our counterparties $ 582 $ 614 Margin deposits posted with us by our counterparties (1)(3) $ 53 $ 47 Letters of credit posted with us by our counterparties 52 61 Total margin deposits and letters of credit posted with us by our counterparties $ 105 $ 108 ___________ (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 6 for further discussion of our derivative instruments subject to master netting arrangements. (2) At June 30, 2015 and December 31, 2014 , $114 million and $109 million , respectively, were included in margin deposits and other prepaid expense and $14 million and $9 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 Taxes	6 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Income Tax Expense (Benefit) The table below shows our consolidated income tax expense (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, 2015 2014 2015 2014 Income tax expense (benefit) $ 5 $ 15 $ 4 $ (4 ) Effective tax rate 21 % 10 % 31 % (3 )% Our income tax rates do not bear a customary relationship to statutory income tax rates primarily as a result of the impact of our NOLs, changes in unrecognized tax benefits and valuation allowances. For the three and six months ended June 30, 2015 and 2014 , our income tax expense (benefit) is largely comprised of discrete tax items and estimated state and foreign income taxes in jurisdictions where we do not have NOLs. See Note 10 in our 2014 Form 10-K for further information regarding our NOLs. 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. Any adjustment of state or federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs. 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 earnings history, we are unable to assume future profits; however, we are able to consider available tax planning strategies. Unrecognized Tax Benefits — At June 30, 2015 , we had unrecognized tax benefits of $ 54 million . If recognized, $ 13 million of our unrecognized tax benefits could impact the annual effective tax rate and $ 41 million , related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact on our effective tax rate. We had accrued interest and penalties of $ 11 million for income tax matters at June 30, 2015 . We recognize interest and penalties related to unrecognized tax benefits in income tax benefit on our Consolidated Condensed Statements of Operations.

Earnings (Loss) per Share

Earnings (Loss) per Share	6 Months Ended
	Jun. 30, 2015
Earnings (Loss) per Share [Abstract]
Earnings (Loss) per Share	Earnings 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. Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the three and six months ended June 30, 2015 and 2014 , are as follows (shares in thousands): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Diluted weighted average shares calculation: Weighted average shares outstanding (basic) 366,975 416,507 369,938 418,296 Share-based awards 2,971 4,841 3,466 4,401 Weighted average shares outstanding (diluted) 369,946 421,348 373,404 422,697 We excluded the following items from diluted earnings per common share for the three and six months ended June 30, 2015 and 2014 , because they were anti-dilutive (shares in thousands): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Share-based awards 5,042 2,854 5,042 5,066

Stock-Based Compensation

Stock-Based Compensation	6 Months Ended
	Jun. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	Stock-Based Compensation Equity Classified Share-Based Awards Stock-based compensation expense recognized for our equity classified share-based awards was $ 7 million and $ 8 million for the three months ended June 30, 2015 and 2014 , respectively, and $ 16 million and $ 17 million for the six months ended June 30, 2015 and 2014 , 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, 2015 and 2014 . At June 30, 2015 , there was unrecognized compensation cost of $ 38 million related to restricted stock which is expected to be recognized over a weighted average period of 1.5 years. A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the six months ended June 30, 2015 , is as follows: Number of Restricted Stock Awards Weighted Average Grant-Date Fair Value Nonvested — December 31, 2014 4,201,868 $ 18.01 Granted 1,572,761 $ 21.42 Forfeited 157,807 $ 19.40 Vested 1,577,169 $ 16.52 Nonvested — June 30, 2015 4,039,653 $ 19.86 The total fair value of our restricted stock and restricted stock units that vested during the six months ended June 30, 2015 and 2014 was approximately $ 33 million and $ 30 million , respectively. Liability Classified Share-Based Awards Performance share units granted under the Equity Plan are settled in cash with payouts based on the relative performance of Calpine’s TSR over a three-year performance period 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 classified as a liability and measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was $ (6) million and $ 4 million for the three months ended June 30, 2015 and 2014 , respectively, and $ (4) million and $ 5 million for the six months ended June 30, 2015 and 2014 , respectively. A summary of our performance share unit activity for the six months ended June 30, 2015 , is as follows: Number of Performance Share Units Weighted Average Grant-Date Fair Value Nonvested — December 31, 2014 867,479 $ 21.93 Granted 365,667 $ 23.91 Forfeited 45,654 $ 22.09 Vested (1) 8,254 $ 22.56 Nonvested — June 30, 2015 1,179,238 $ 22.53 ___________ (1) In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date. For a further discussion of the Calpine Equity Incentive Plans, see Note 12 in our 2014 Form 10-K.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	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, individually or in the aggregate, 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. Bay Area Air Quality Management District (“BAAQMD”) . On March 13, 2014, the Hearing Board of the BAAQMD entered into a stipulated conditional order for abatement agreed to by Russell City Energy Company, LLC (“RCEC”), our indirect, majority-owned subsidiary, and the BAAQMD concerning a violation of the vendor-guaranteed water droplet drift rate for RCEC’s cooling tower discovered during initial performance testing. RCEC installed additional drift eliminators and came into compliance with its water droplet drift rate on April 17, 2014. The BAAQMD issued a notice of violation for this event on April 24, 2015. The BAAQMD continues to reserve its rights to assert any penalty claims associated with this violation and RCEC continues to reserve its rights to assert any defenses to such claims in future proceedings.

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Segment 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. During the third quarter of 2014, we altered the composition of our geographic segments to combine our former North and Southeast segments into one segment which was renamed the East segment. This change reflects the manner in which our geographic information is presented internally to our chief operating decision maker following the sale of six power plants in July 2014 that composed a substantial portion of our former Southeast segment. Thus, beginning in the third quarter of 2014, our reportable segments were West (including geothermal), Texas and East (including Canada). We continue to evaluate the manner in which we assess our performance, including our segments, which may result in future changes to the composition of our geographic segments. 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, 2015 West Texas East Consolidation Total Revenues from external customers $ 421 $ 570 $ 451 $ — $ 1,442 Intersegment revenues — 5 2 (7 ) — Total operating revenues $ 421 $ 575 $ 453 $ (7 ) $ 1,442 Commodity Margin $ 240 $ 170 $ 247 $ — $ 657 Add: Mark-to-market commodity activity, net and other (1) (14 ) 10 30 (7 ) 19 Less: Plant operating expense 120 82 77 (7 ) 272 Depreciation and amortization expense 65 50 45 — 160 Sales, general and other administrative expense 6 15 9 — 30 Other operating expenses 10 2 8 — 20 (Income) from unconsolidated investments in power plants — — (7 ) — (7 ) Income from operations 25 31 145 — 201 Interest expense, net of interest income 157 Debt modification costs and other (income) expense, net 18 Income before income taxes $ 26 Three Months Ended June 30, 2014 West Texas East Consolidation Total Revenues from external customers $ 487 $ 960 $ 492 $ — $ 1,939 Intersegment revenues 1 3 27 (31 ) — Total operating revenues $ 488 $ 963 $ 519 $ (31 ) $ 1,939 Commodity Margin (2) $ 228 $ 177 $ 227 $ — $ 632 Add: Mark-to-market commodity activity, net and other (1) 21 184 (24 ) (8 ) 173 Less: Plant operating expense 95 83 103 (7 ) 274 Depreciation and amortization expense 58 48 40 1 147 Sales, general and other administrative expense 7 18 12 1 38 Other operating expenses 15 1 9 (4 ) 21 (Income) from unconsolidated investments in power plants — — (4 ) — (4 ) Income from operations 74 211 43 1 329 Interest expense, net of interest income 167 Other (income) expense, net 6 Income before income taxes $ 156 Six Months Ended June 30, 2015 West Texas East Consolidation and Elimination Total Revenues from external customers $ 936 $ 1,151 $ 1,001 $ — $ 3,088 Intersegment revenues 2 8 4 (14 ) — Total operating revenues $ 938 $ 1,159 $ 1,005 $ (14 ) $ 3,088 Commodity Margin $ 458 $ 319 $ 415 $ — $ 1,192 Add: Mark-to-market commodity activity, net and other (3) 105 51 (22 ) (14 ) 120 Less: Plant operating expense 226 171 149 (14 ) 532 Depreciation and amortization expense 132 99 87 — 318 Sales, general and other administrative expense 16 32 19 — 67 Other operating expenses 20 4 16 — 40 (Income) from unconsolidated investments in power plants — — (12 ) — (12 ) Income from operations 169 64 134 — 367 Interest expense, net of interest income 310 Debt modification and extinguishment costs and other (income) expense, net 39 Income before income taxes $ 18 Six Months Ended June 30, 2014 West Texas East Consolidation and Elimination Total Revenues from external customers $ 978 $ 1,607 $ 1,319 $ — $ 3,904 Intersegment revenues 3 15 44 (62 ) — Total operating revenues $ 981 $ 1,622 $ 1,363 $ (62 ) $ 3,904 Commodity Margin (2) $ 430 $ 298 $ 549 $ — $ 1,277 Add: Mark-to-market commodity activity, net and other (3) 50 138 (35 ) (17 ) 136 Less: Plant operating expense 200 173 182 (16 ) 539 Depreciation and amortization expense 118 90 91 1 300 Sales, general and other administrative expense 17 30 24 — 71 Other operating expenses 27 3 16 (3 ) 43 (Income) from unconsolidated investments in power plants — — (13 ) — (13 ) Income from operations 118 140 214 1 473 Interest expense, net of interest income 332 Debt extinguishment costs and other (income) expense, net 17 Income before income taxes $ 124 _________ (1) Includes $ (18) million and $ (27) million of lease levelization and $ 3 million and $ 3 million of amortization expense for the three months ended June 30, 2015 and 2014 , respectively. (2) Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was $ 42 million and $ 81 million for the three and six months ended June 30, 2014 , respectively. (3) Includes $ (42) million and $ (56) million of lease levelization and $ 7 million and $ 7 million of amortization expense for the six months ended June 30, 2015 and 2014 , respectively.

Basis of Presentation and Sum19

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
New Accounting Pronouncements, Policy [Policy Text Block]	Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding revenue recognition. The standard was effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption being prohibited. In July 2015, the FASB approved a proposal to defer the effective date of Accounting Standards Update 2014-09 for public entities by one year, which would result in the standard being effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The proposal would also permit entities to early adopt, but only as of the original effective date. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows. Consolidation — In February 2015, the FASB issued Accounting Standards Update 2015-02, “Amendments to the Consolidation Analysis.” This standard amends the consolidation model used in determining whether a reporting entity should consolidate the financial results of certain of its partially- and wholly-owned subsidiaries. All of our subsidiaries are subject to reevaluation under the revised consolidation model. Specifically, the amendments (i) modify the evaluation of whether limited partnerships and similar legal entities are voting interest entities or VIEs, (ii) eliminate the presumption that a general partner should consolidate the financial results of a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships and (iv) provide an exception for certain types of entities. This standard is effective for fiscal periods beginning after December 15, 2015, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard. Debt Issuance Costs — In April 2015, the FASB issued Accounting Standards Update 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” The standard requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, which is consistent with the presentation of debt discounts. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period and requires retrospective adoption with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard. Cloud Computing Arrangements — In April 2015, the FASB issued Accounting Standards Update 2015-05, “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” This standard provides guidance regarding whether a cloud computing arrangement represents a software license or a service contract. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods and allows for either prospective or retrospective adoption with early adoption permitted. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows. Inventory — In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” This standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective adoption with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.
Basis of Interim Presentation	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, 2014 , included in our 2014 Form 10-K. The results for interim periods are not 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 mark-to-market gains and losses from commodity and interest rate derivative contracts.
Use of Estimates in Preparation of Financial Statements	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	Reclassifications — We have reclassified certain prior year amounts for comparative purposes. These reclassifications did not have a material impact on our financial condition, results of operations or cash flows.
Cash and Cash Equivalents	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.
Restricted Cash	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 are expected to 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.
Derivatives	We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses 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. 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 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 only apply hedge accounting to our interest rate derivative instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate swaps 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 interest rate hedging instruments are recognized currently in earnings as a component of interest expense. 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, interest rate and environmental product 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 mark-to-market gain/loss as a component of operating revenues (for power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, environmental product 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. 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.
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.

Basis of Presentation and Sum20

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	6 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Schedule of Components of Restricted Cash	The table below represents the components of our restricted cash as of June 30, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 Current Non-Current Total Current Non-Current Total Debt service $ 16 $ 25 $ 41 $ 10 $ 25 $ 35 Rent reserve — — — 4 — 4 Construction/major maintenance 50 19 69 54 17 71 Security/project/insurance 93 4 97 127 5 132 Other 3 — 3 — 2 2 Total $ 162 $ 48 $ 210 $ 195 $ 49 $ 244
Schedule of Property, Plant and Equipment	Property, Plant and Equipment, Net — At June 30, 2015 and December 31, 2014 , the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions): June 30, 2015 December 31, 2014 Depreciable Lives Buildings, machinery and equipment $ 16,422 $ 16,059 3 – 47 Years Geothermal properties 1,320 1,294 13 – 58 Years Other 208 203 3 – 47 Years 17,950 17,556 Less: Accumulated depreciation 5,236 4,984 12,714 12,572 Land 121 120 Construction in progress 312 498 Property, plant and equipment, net $ 13,147 $ 13,190

Variable Interest Entities an21

Variable Interest Entities and Unconsolidated Investments in Power Plants (Tables)	6 Months Ended
	Jun. 30, 2015
Variable Interest Entities and Unconsolidated Investments [Abstract]
Schedule of Equity Method Investments	At June 30, 2015 and December 31, 2014 , our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions): Ownership Interest as of June 30, 2015 June 30, 2015 December 31, 2014 Greenfield LP 50% $ 78 $ 78 Whitby 50% 9 17 Total investments in power plants $ 87 $ 95
Income (Loss) 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, 2015 2014 2015 2014 Greenfield LP $ (4 ) $ — $ (6 ) $ (5 ) Whitby (3 ) (4 ) (6 ) (8 ) Total $ (7 ) $ (4 ) $ (12 ) $ (13 )
Condensed Financial Statements [Table Text Block]	Aggregated summarized financial data for the six months ended June 30, 2015 and 2014 are set forth below (in millions): Condensed Combined Statements of Operations of Our Unconsolidated Subsidiaries (Unaudited) Six Months Ended June 30, 2015 2014 Revenues $ 98 $ 149 Operating expenses 66 111 Income from operations 32 38 Interest expense, net of interest income 10 12 Other (income) expense, net (1 ) — Net income $ 23 $ 26

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	Our debt at June 30, 2015 and December 31, 2014 , was as follows (in millions): June 30, 2015 December 31, 2014 Senior Unsecured Notes $ 3,450 $ 2,800 First Lien Term Loans 2,787 2,799 First Lien Notes 1,928 2,075 Project financing, notes payable and other 1,737 1,810 CCFC Term Loans 1,588 1,596 Capital lease obligations 201 202 Subtotal 11,691 11,282 Less: Current maturities 198 199 Total long-term debt $ 11,493 $ 11,083
Senior Unsecured Notes	The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions): June 30, 2015 December 31, 2014 2023 Senior Unsecured Notes $ 1,250 $ 1,250 2024 Senior Unsecured Notes 650 — 2025 Senior Unsecured Notes 1,550 1,550 Total Senior Unsecured Notes $ 3,450 $ 2,800
First Lien Term Loans	The amounts outstanding under our First Lien Term Loans are summarized in the table below (in millions): June 30, 2015 December 31, 2014 2018 First Lien Term Loans $ — $ 1,597 2019 First Lien Term Loan 812 816 2020 First Lien Term Loan 384 386 2022 First Lien Term Loan 1,591 — Total First Lien Term Loans $ 2,787 $ 2,799
First Lien Notes	The amounts outstanding under our First Lien Notes are summarized in the table below (in millions): June 30, 2015 December 31, 2014 2022 First Lien Notes $ 745 $ 745 2023 First Lien Notes (1) 693 840 2024 First Lien Notes 490 490 Total First Lien Notes $ 1,928 $ 2,075 ____________ (1) On February 3, 2015, we repurchased approximately $147 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, as described in further detail above.
Schedule of Line of Credit Facilities	The table below represents amounts issued under our letter of credit facilities at June 30, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 Corporate Revolving Facility (1) $ 179 $ 223 CDHI 244 214 Various project financing facilities 219 207 Total $ 642 $ 644 ____________ (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, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 Fair Value Carrying Value Fair Value Carrying Value Senior Unsecured Notes $ 3,347 $ 3,450 $ 2,832 $ 2,800 First Lien Term Loans 2,768 2,787 2,769 2,799 First Lien Notes 2,059 1,928 2,247 2,075 Project financing, notes payable and other (1) 1,660 1,629 1,734 1,688 CCFC Term Loans 1,564 1,588 1,540 1,596 Total $ 11,398 $ 11,382 $ 11,122 $ 10,958 ____________ (1) Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

Assets and Liabilities with R23

Assets and Liabilities with Recurring Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Measurements [Abstract]
Fair Value, Measurement Inputs, Disclosure	The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2015 and December 31, 2014 , by level within the fair value hierarchy: Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2015 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 577 $ — $ — $ 577 Margin deposits 103 — — 103 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,684 — — 1,684 Commodity forward contracts (2) — 284 273 557 Interest rate swaps — 3 — 3 Total assets $ 2,364 $ 287 $ 273 $ 2,924 Liabilities: Margin deposits posted with us by our counterparties $ 53 $ — $ — $ 53 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,506 — — 1,506 Commodity forward contracts (2) — 219 30 249 Interest rate swaps — 105 — 105 Total liabilities $ 1,559 $ 324 $ 30 $ 1,913 Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2014 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 896 $ — $ — $ 896 Margin deposits 96 — — 96 Commodity instruments: Commodity exchange traded futures and swaps contracts 2,134 — — 2,134 Commodity forward contracts (2) — 195 164 359 Interest rate swaps — 4 — 4 Total assets $ 3,126 $ 199 $ 164 $ 3,489 Liabilities: Margin deposits posted with us by our counterparties $ 47 $ — $ — $ 47 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,870 — — 1,870 Commodity forward contracts (2) — 163 79 242 Interest rate swaps — 114 — 114 Total liabilities $ 1,917 $ 277 $ 79 $ 2,273 ___________ (1) As of June 30, 2015 and December 31, 2014 , we had cash equivalents of $367 million and $679 million included in cash and cash equivalents and $210 million and $217 million included in restricted cash, respectively. (2) Includes OTC swaps and options.
Fair Value Inputs, Assets, Quantitative Information	The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at June 30, 2015 and December 31, 2014 : Quantitative Information about Level 3 Fair Value Measurements June 30, 2015 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ 237 Discounted cash flow Market price (per MWh) $12.68 — $121.40/MWh Power Congestion Products $ 7 Discounted cash flow Market price (per MWh) $(19.56) — $19.56/MWh December 31, 2014 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ 74 Discounted cash flow Market price (per MWh) $14.00 — $122.79/MWh Natural Gas Contracts $ 5 Discounted cash flow Market price (per MMBtu) $1.00 — $10.86/MMBtu Power Congestion Products $ 9 Discounted cash flow Market price (per MWh) $(19.56) — $19.56/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, 2015 2014 2015 2014 Balance, beginning of period $ 203 $ 8 $ 85 $ 14 Realized and mark-to-market gains (losses): Included in net income: Included in operating revenues (1) 45 (7 ) 176 (15 ) Included in fuel and purchased energy expense (2) — — 2 6 Purchases and settlements: Purchases 2 — 4 — Settlements (10 ) (3 ) (21 ) (6 ) Transfers in and/or out of level 3 (3) : Transfers into level 3 (4) — 2 — — Transfers out of level 3 (5) 3 (9 ) (3 ) (8 ) Balance, end of period $ 243 $ (9 ) $ 243 $ (9 ) Change in unrealized gains (losses) relating to instruments still held at end of period $ 45 $ (7 ) $ 178 $ (9 ) ___________ (1) For power contracts and other power-related products, 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, 2015 and 2014 . (4) There were no transfers out of level 2 into level 3 for each of the three and six months ended June 30, 2015 and for the six months ended June 30, 2014. We had $2 million in gains transferred out of level 2 into level 3 for the three months ended June 30, 2014, due to changes in market liquidity in various power markets. (5) We had $3 million in losses and $(9) million in gains transferred out of level 3 into level 2 for the three months ended June 30, 2015 and 2014, respectively, and $(3) million and $(8) million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2015 and 2014 , respectively, due to changes in market liquidity in various power markets.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Instruments [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions	As of June 30, 2015 and December 31, 2014 , the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions): Derivative Instruments Notional Amounts June 30, 2015 December 31, 2014 Power (MWh) (99 ) (62 ) Natural gas (MMBtu) 874 291 Environmental credits (Tonnes) 3 — Interest rate swaps $ 1,411 $ 1,431
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location [Table Text Block]	The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at June 30, 2015 and December 31, 2014 (in millions): June 30, 2015 Commodity Instruments Interest Rate Swaps Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 1,607 $ — $ 1,607 Long-term derivative assets 634 3 637 Total derivative assets $ 2,241 $ 3 $ 2,244 Current derivative liabilities $ 1,365 $ 42 $ 1,407 Long-term derivative liabilities 390 63 453 Total derivative liabilities $ 1,755 $ 105 $ 1,860 Net derivative asset (liabilities) $ 486 $ (102 ) $ 384 December 31, 2014 Commodity Interest Rate Swaps Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 2,058 $ — $ 2,058 Long-term derivative assets 435 4 439 Total derivative assets $ 2,493 $ 4 $ 2,497 Current derivative liabilities $ 1,738 $ 44 $ 1,782 Long-term derivative liabilities 374 70 444 Total derivative liabilities $ 2,112 $ 114 $ 2,226 Net derivative asset (liabilities) $ 381 $ (110 ) $ 271
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	June 30, 2015 December 31, 2014 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 $ 3 $ 105 $ 4 $ 112 Total derivatives designated as cash flow hedging instruments $ 3 $ 105 $ 4 $ 112 Derivatives not designated as hedging instruments: Commodity instruments $ 2,241 $ 1,755 $ 2,493 $ 2,112 Interest rate swaps — — — 2 Total derivatives not designated as hedging instruments $ 2,241 $ 1,755 $ 2,493 $ 2,114 Total derivatives $ 2,244 $ 1,860 $ 2,497 $ 2,226
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, 2015 and December 31, 2014 (in millions): June 30, 2015 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 $ 1,684 $ (1,506 ) $ (178 ) $ — Commodity forward contracts 557 (231 ) (9 ) 317 Interest rate swaps 3 — — 3 Total derivative assets $ 2,244 $ (1,737 ) $ (187 ) $ 320 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,506 ) $ 1,506 $ — $ — Commodity forward contracts (249 ) 231 9 (9 ) Interest rate swaps (105 ) — — (105 ) Total derivative (liabilities) $ (1,860 ) $ 1,737 $ 9 $ (114 ) Net derivative assets (liabilities) $ 384 $ — $ (178 ) $ 206 December 31, 2014 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 $ 2,134 $ (1,865 ) $ (269 ) $ — Commodity forward contracts 359 (222 ) — 137 Interest rate swaps 4 — — 4 Total derivative assets $ 2,497 $ (2,087 ) $ (269 ) $ 141 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,870 ) $ 1,865 $ 5 $ — Commodity forward contracts (242 ) 222 10 (10 ) Interest rate swaps (114 ) — — (114 ) Total derivative (liabilities) $ (2,226 ) $ 2,087 $ 15 $ (124 ) Net derivative assets (liabilities) $ 271 $ — $ (254 ) $ 17 ____________ (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 7 for a further discussion of our collateral.
Realized Unrealized Gain Loss by Instrument	The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market 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, 2015 2014 2015 2014 Realized gain (loss) (1) Commodity derivative instruments $ 104 $ 18 $ 163 $ (21 ) Total realized gain (loss) $ 104 $ 18 $ 163 $ (21 ) Mark-to-market gain (loss) (2) Commodity derivative instruments $ (1 ) $ 141 $ 69 $ 68 Interest rate swaps — 1 1 2 Total mark-to-market gain (loss) $ (1 ) $ 142 $ 70 $ 70 Total activity, net $ 103 $ 160 $ 233 $ 49 ___________ (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 mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, 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, 2015 2014 2015 2014 Realized and mark-to-market gain (loss) Derivatives contracts included in operating revenues $ 115 $ 158 $ 234 $ (79 ) Derivatives contracts included in fuel and purchased energy expense (12 ) 1 (2 ) 126 Interest rate swaps included in interest expense — 1 1 2 Total activity, net $ 103 $ 160 $ 233 $ 49
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)(4) 2015 2014 2015 2014 Affected Line Item on the Consolidated Condensed Statements of Operations Interest rate swaps (1)(2) $ 14 $ (9 ) $ (12 ) $ (13 ) Interest expense 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)(4) 2015 2014 2015 2014 Affected Line Item on the Consolidated Condensed Statements of Operations Interest rate swaps (1)(2) $ 8 $ (9 ) $ (24 ) $ (26 ) Interest expense ____________ (1) 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, 2015 and 2014 . (2) We recorded an income tax expense of nil for each of the three and six months ended June 30, 2015 and 2014, in AOCI related to our cash flow hedging activities. (3) Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $142 million and $149 million at June 30, 2015 and December 31, 2014 , respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $11 million and $12 million at June 30, 2015 and December 31, 2014 , respectively. (4) Includes a loss of $5 million and $10 million for the three and six months ended June 30, 2014, respectively, that was reclassified from AOCI to interest expense, where the hedged transactions are no longer expected to occur.

Use of Collateral (Tables)

Use of Collateral (Tables)	6 Months Ended
	Jun. 30, 2015
Use of Collateral [Abstract]
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, 2015 and December 31, 2014 (in millions): June 30, 2015 December 31, 2014 Margin deposits (1) $ 103 $ 96 Natural gas and power prepayments 25 22 Total margin deposits and natural gas and power prepayments with our counterparties (2) $ 128 $ 118 Letters of credit issued $ 452 $ 450 First priority liens under power and natural gas agreements 24 48 First priority liens under interest rate swap agreements 106 116 Total letters of credit and first priority liens with our counterparties $ 582 $ 614 Margin deposits posted with us by our counterparties (1)(3) $ 53 $ 47 Letters of credit posted with us by our counterparties 52 61 Total margin deposits and letters of credit posted with us by our counterparties $ 105 $ 108 ___________ (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 6 for further discussion of our derivative instruments subject to master netting arrangements. (2) At June 30, 2015 and December 31, 2014 , $114 million and $109 million , respectively, were included in margin deposits and other prepaid expense and $14 million and $9 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 (Tabl

Income Taxes Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The table below shows our consolidated income tax expense (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, 2015 2014 2015 2014 Income tax expense (benefit) $ 5 $ 15 $ 4 $ (4 ) Effective tax rate 21 % 10 % 31 % (3 )%

Earnings (Loss) per Share (Tabl

Earnings (Loss) per Share (Tables)	6 Months Ended
	Jun. 30, 2015
Earnings (Loss) per Share [Abstract]
Schedule of Weighted Average Number of Shares [Table Text Block]	Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the three and six months ended June 30, 2015 and 2014 , are as follows (shares in thousands): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Diluted weighted average shares calculation: Weighted average shares outstanding (basic) 366,975 416,507 369,938 418,296 Share-based awards 2,971 4,841 3,466 4,401 Weighted average shares outstanding (diluted) 369,946 421,348 373,404 422,697
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	We excluded the following items from diluted earnings per common share for the three and six months ended June 30, 2015 and 2014 , because they were anti-dilutive (shares in thousands): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Share-based awards 5,042 2,854 5,042 5,066

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
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, 2015 , is as follows: Number of Restricted Stock Awards Weighted Average Grant-Date Fair Value Nonvested — December 31, 2014 4,201,868 $ 18.01 Granted 1,572,761 $ 21.42 Forfeited 157,807 $ 19.40 Vested 1,577,169 $ 16.52 Nonvested — June 30, 2015 4,039,653 $ 19.86
Schedule of Share-based Compensation, Activity [Table Text Block]	A summary of our performance share unit activity for the six months ended June 30, 2015 , is as follows: Number of Performance Share Units Weighted Average Grant-Date Fair Value Nonvested — December 31, 2014 867,479 $ 21.93 Granted 365,667 $ 23.91 Forfeited 45,654 $ 22.09 Vested (1) 8,254 $ 22.56 Nonvested — June 30, 2015 1,179,238 $ 22.53 ___________ (1) In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date.

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
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, 2015 West Texas East Consolidation Total Revenues from external customers $ 421 $ 570 $ 451 $ — $ 1,442 Intersegment revenues — 5 2 (7 ) — Total operating revenues $ 421 $ 575 $ 453 $ (7 ) $ 1,442 Commodity Margin $ 240 $ 170 $ 247 $ — $ 657 Add: Mark-to-market commodity activity, net and other (1) (14 ) 10 30 (7 ) 19 Less: Plant operating expense 120 82 77 (7 ) 272 Depreciation and amortization expense 65 50 45 — 160 Sales, general and other administrative expense 6 15 9 — 30 Other operating expenses 10 2 8 — 20 (Income) from unconsolidated investments in power plants — — (7 ) — (7 ) Income from operations 25 31 145 — 201 Interest expense, net of interest income 157 Debt modification costs and other (income) expense, net 18 Income before income taxes $ 26 Three Months Ended June 30, 2014 West Texas East Consolidation Total Revenues from external customers $ 487 $ 960 $ 492 $ — $ 1,939 Intersegment revenues 1 3 27 (31 ) — Total operating revenues $ 488 $ 963 $ 519 $ (31 ) $ 1,939 Commodity Margin (2) $ 228 $ 177 $ 227 $ — $ 632 Add: Mark-to-market commodity activity, net and other (1) 21 184 (24 ) (8 ) 173 Less: Plant operating expense 95 83 103 (7 ) 274 Depreciation and amortization expense 58 48 40 1 147 Sales, general and other administrative expense 7 18 12 1 38 Other operating expenses 15 1 9 (4 ) 21 (Income) from unconsolidated investments in power plants — — (4 ) — (4 ) Income from operations 74 211 43 1 329 Interest expense, net of interest income 167 Other (income) expense, net 6 Income before income taxes $ 156 Six Months Ended June 30, 2015 West Texas East Consolidation and Elimination Total Revenues from external customers $ 936 $ 1,151 $ 1,001 $ — $ 3,088 Intersegment revenues 2 8 4 (14 ) — Total operating revenues $ 938 $ 1,159 $ 1,005 $ (14 ) $ 3,088 Commodity Margin $ 458 $ 319 $ 415 $ — $ 1,192 Add: Mark-to-market commodity activity, net and other (3) 105 51 (22 ) (14 ) 120 Less: Plant operating expense 226 171 149 (14 ) 532 Depreciation and amortization expense 132 99 87 — 318 Sales, general and other administrative expense 16 32 19 — 67 Other operating expenses 20 4 16 — 40 (Income) from unconsolidated investments in power plants — — (12 ) — (12 ) Income from operations 169 64 134 — 367 Interest expense, net of interest income 310 Debt modification and extinguishment costs and other (income) expense, net 39 Income before income taxes $ 18 Six Months Ended June 30, 2014 West Texas East Consolidation and Elimination Total Revenues from external customers $ 978 $ 1,607 $ 1,319 $ — $ 3,904 Intersegment revenues 3 15 44 (62 ) — Total operating revenues $ 981 $ 1,622 $ 1,363 $ (62 ) $ 3,904 Commodity Margin (2) $ 430 $ 298 $ 549 $ — $ 1,277 Add: Mark-to-market commodity activity, net and other (3) 50 138 (35 ) (17 ) 136 Less: Plant operating expense 200 173 182 (16 ) 539 Depreciation and amortization expense 118 90 91 1 300 Sales, general and other administrative expense 17 30 24 — 71 Other operating expenses 27 3 16 (3 ) 43 (Income) from unconsolidated investments in power plants — — (13 ) — (13 ) Income from operations 118 140 214 1 473 Interest expense, net of interest income 332 Debt extinguishment costs and other (income) expense, net 17 Income before income taxes $ 124 _________ (1) Includes $ (18) million and $ (27) million of lease levelization and $ 3 million and $ 3 million of amortization expense for the three months ended June 30, 2015 and 2014 , respectively. (2) Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was $ 42 million and $ 81 million for the three and six months ended June 30, 2014 , respectively. (3) Includes $ (42) million and $ (56) million of lease levelization and $ 7 million and $ 7 million of amortization expense for the six months ended June 30, 2015 and 2014 , respectively.

Basis of Presentation and Sum30

Basis of Presentation and Summary of Significant Accounting Policies (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Accounting Policies [Line Items]
Current	$ 162		$ 162		$ 195
Non-current	48		48		49
Total	210		210		244
Interest Costs Capitalized	4	$ 6	$ 9	$ 12
Treasury Stock, Shares, Acquired			22.1
Treasury Stock, Value, Acquired, Cost Method			$ 454
Treasury Stock Acquired, Average Cost Per Share			$ 20.50
Adjustments Related to Tax Withholding for Share-based Compensation			$ 11
Debt Service
Accounting Policies [Line Items]
Current	16		16		10
Non-current	25		25		25
Total	41		41		35
Rent Reserve
Accounting Policies [Line Items]
Current	0		0		4
Non-current	0		0		0
Total	0		0		4
Construction Major Maintenance
Accounting Policies [Line Items]
Current	50		50		54
Non-current	19		19		17
Total	69		69		71
Security Project Insurance
Accounting Policies [Line Items]
Current	93		93		127
Non-current	4		4		5
Total	97		97		132
Other
Accounting Policies [Line Items]
Current	3		3		0
Non-current	0		0		2
Total	$ 3		$ 3		$ 2
Geothermal Properties, Gross [Member] | Minimum [Member]
Accounting Policies [Line Items]
Property, Plant and Equipment, Estimated Useful Lives			13 years
Geothermal Properties, Gross [Member] | Maximum [Member]
Accounting Policies [Line Items]
Property, Plant and Equipment, Estimated Useful Lives			58 years
Property, Plant and Equipment, Other Types [Member] | Minimum [Member]
Accounting Policies [Line Items]
Property, Plant and Equipment, Estimated Useful Lives			3 years
Property, Plant and Equipment, Other Types [Member] | Maximum [Member]
Accounting Policies [Line Items]
Property, Plant and Equipment, Estimated Useful Lives			47 years
Building, Machinery and Equipment, Gross [Member] | Minimum [Member]
Accounting Policies [Line Items]
Property, Plant and Equipment, Estimated Useful Lives			3 years
Building, Machinery and Equipment, Gross [Member] | Maximum [Member]
Accounting Policies [Line Items]
Property, Plant and Equipment, Estimated Useful Lives			47 years

Basis of Presentation and Sum31

Basis of Presentation and Summary of Significant Accounting Policies Property, Plant and Equipment, Net (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Buildings, machinery and equipment	$ 16,422	$ 16,059
Geothermal properties	1,320	1,294
Other	208	203
Property, Plant and Equipment, Gross	17,950	17,556
Less: Accumulated depreciation	5,236	4,984
Property, Plant and Equipment, Gross, Less Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	12,714	12,572
Land	121	120
Construction in progress	312	498
Property, plant and equipment, net	$ 13,147	$ 13,190

Acquisition (Details)

Acquisition (Details) $ in Millions	Jul. 20, 2015USD ($)MWh	Jun. 30, 2015MW	Dec. 31, 2014USD ($)MW
Business Acquisition [Line Items]
Power generation capacity		10,266	10,365
Fore River Energy Center [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | $			$ 530
Power generation capacity			809
Subsequent Event [Member]
Business Acquisition [Line Items]
Electricity Sales Volume | MWh	22,000,000
Subsequent Event [Member] | Champion Energy Holding, LLC [Member]
Business Acquisition [Line Items]
Ownership Percentage of Acquiree	75.00%
Subsequent Event [Member] | EDF Trading North America, LLC [Member]
Business Acquisition [Line Items]
Ownership Percentage of Acquiree	25.00%
Subsequent Event [Member] | Champion Energy Marketing, LLC [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | $	$ 240

Variable Interest Entities an33

Variable Interest Entities and Unconsolidated Investments in Power Plants (Unconsolidated VIEs) (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 87	$ 95
Greenfield [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 78	78
Equity Method Investment, Ownership Percentage	50.00%
Whitby [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 9	$ 17
Equity Method Investment, Ownership Percentage	50.00%

Variable Interest Entities an34

Variable Interest Entities and Unconsolidated Investments in Power Plants (Income from Unconsolidated Investements 10-Q) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
(Income) from unconsolidated investments in power plants	$ (7)	$ (4)	$ (12)	$ (13)
Greenfield [Member]
(Income) from unconsolidated investments in power plants	(4)	0	(6)	(5)
Whitby [Member]
(Income) from unconsolidated investments in power plants	$ (3)	$ (4)	$ (6)	$ (8)

Variable Interest Entities an35

Variable Interest Entities and Unconsolidated Investments in Power Plants (VIE Texuals) (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)yrMW	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)yrMW	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)MW
Variable Interest Entity [Line Items]
Power generation capacity | MW	10,266		10,266		10,365
Variable Interest Entity, Financial or Other Support, Amount	$ 0	$ 0	$ 0	$ 40
Equity Method Investment, Summarized Financial Information, Debt	312		312		$ 342
Prorata Share of Equity Method Investment, Summarized Financial Information, Debt	$ 156		$ 156		$ 171
Greenfield [Member]
Variable Interest Entity [Line Items]
Power generation capacity | MW	1,038		1,038
Equity Method Investment, Ownership Percentage	50.00%		50.00%
Distribution from equity method investee	$ 0	$ 0	$ 0	$ 0
Whitby [Member]
Variable Interest Entity [Line Items]
Power generation capacity | MW	50		50
Equity Method Investment, Ownership Percentage	50.00%		50.00%
Distribution from equity method investee	$ 13		$ 13
Inland Empire Energy Center [Member]
Variable Interest Entity [Line Items]
Power generation capacity | MW	775		775
Put Option Exercise Period | yr	2,025		2,025
Inland Empire Energy Center [Member] | Minimum [Member]
Variable Interest Entity [Line Items]
Call Option Exercise Period | yr	2,017		2,017
Inland Empire Energy Center [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Call Option Exercise Period | yr	2,024		2,024

Variable Interest Entities an36

Variable Interest Entities and Unconsolidated Investments in Power Plants Condensed Financial Statements (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating revenues	$ 1,442	$ 1,939	$ 3,088	$ 3,904
Costs and Expenses	1,248	1,614	2,733	3,444
Income from operations	201	329	367	473
Net income (loss)	21	141	14	128
Interest expense, net of interest income	157	167	310	332
Other (income) expense, net	$ 5	$ 6	7	16
Greenfield and Whitby [Member]
Operating revenues			98	149
Costs and Expenses			66	111
Income from operations			32	38
Net income (loss)			23	26
Interest expense, net of interest income			10	12
Other (income) expense, net			$ (1)	$ 0

Debt (Debt) (Details)

Debt (Debt) (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	$ 11,691	$ 11,282
Debt, Current	198	199
Long-term Debt, Excluding Current Maturities	11,493	11,083
Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	3,450	2,800
Loans Payable [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	2,787	2,799
Corporate Debt Securities [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	1,928	2,075
Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	1,737	1,810
Secured Debt [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	1,588	1,596
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	$ 201	$ 202

Debt Senior Unsecured Notes (De

Debt Senior Unsecured Notes (Details) - Debt Instrument, Name [Domain] - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term Debt	$ 11,398	$ 11,122
Senior Unsecured Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	1,250	1,250
Senior Unsecured Notes 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt	650	0
Senior Unsecured Notes 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt	1,550	1,550
Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 3,450	$ 2,800

Debt (First Lien Term Loans) (D

Debt (First Lien Term Loans) (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term Debt	$ 11,398	$ 11,122
First Lien Term Loans 2018 [Member]
Debt Instrument [Line Items]
Long-term Debt	0	1,597
First Lien Term Loan 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt	812	816
2020 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Long-term Debt	384	386
2022 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Long-term Debt	1,591	0
First Lien Term Loans [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 2,787	$ 2,799

Debt (First Lien Notes) (Detail

Debt (First Lien Notes) (Details) - Debt Instrument, Name [Domain] - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term Debt		$ 11,398	$ 11,122
2022 First Lien Notes [Member]
Debt Instrument [Line Items]
Long-term Debt		745	745
First Lien Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	693	840
2024 First Lien Notes [Member]
Debt Instrument [Line Items]
Long-term Debt		490	490
Corporate Debt Securities [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 1,928	$ 2,075
[1]	On February 3, 2015, we repurchased approximately $147 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, as described in further detail above.

Debt (Letter of Credit) (Detail

Debt (Letter of Credit) (Details) - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount		$ 642	$ 644
Corporate Revolving Facility [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount	[1]	179	223
CDH [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount		244	214
Various Project Financing Facilities [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount		$ 219	$ 207
[1]	The Corporate Revolving Facility represents our primary revolving facility.

Debt (Fair Value of Debt) (Deta

Debt (Fair Value of Debt) (Details) - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		$ 11,398	$ 11,122
Unsecured Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		3,450	2,800
Loans Payable [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		2,787	2,799
Corporate Debt Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		1,928	2,075
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		11,382	10,958
Reported Value Measurement [Member] | Unsecured Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		3,450	2,800
Reported Value Measurement [Member] | Loans Payable [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		2,787	2,799
Reported Value Measurement [Member] | Corporate Debt Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		1,928	2,075
Reported Value Measurement [Member] | Notes Payable, Other Payable excluding Capital Leases [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	[1]	1,629	1,688
Reported Value Measurement [Member] | Secured Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		1,588	1,596
Fair Value, Inputs, Level 2 [Member] | Unsecured Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		3,347	2,832
Fair Value, Inputs, Level 2 [Member] | Loans Payable [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		2,768	2,769
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		2,059	2,247
Fair Value, Inputs, Level 2 [Member] | Secured Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		1,564	1,540
Fair Value, Inputs, Level 3 [Member] | Notes Payable, Other Payable excluding Capital Leases [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	[1]	$ 1,660	$ 1,734
[1]	Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

Debt (Debt Textuals) (Details)

Debt (Debt Textuals) (Details) - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Effective Percentage		5.50%		6.10%	5.50%	6.10%
Long-term Debt		$ 11,398			$ 11,398		$ 11,122
Gains (Losses) on Extinguishment of Debt		(13)		$ 0	(32)	$ (1)
Senior Unsecured Notes 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 650
Debt Instrument, Interest Rate, Stated Percentage			5.50%
Long-term Debt		650			650		0
Deferred Finance Costs, Net			$ 9
First Lien Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	693			693		840
Gains (Losses) on Extinguishment of Debt			(19)
2022 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 1,600			1,600
Percentage of the principal amount of the 2022 First Lien Term Loan to be paid quarterly		0.25%
Debt Issuance Cost		$ 13
Long-term Debt		1,591			1,591		$ 0
Deferred Finance Costs, Net		$ 6			$ 6
Early Redemption Amount [Member] | First Lien Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt			$ 147
Federal Funds Effective Rate [Member] | 2022 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.50%
Eurodollar Rate For A One Month Interest Period [Member] | 2022 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.00%
Prime Rate Or The Eurodollar Rate For a One Month Interest Period [Member] | 2022 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
London Interbank Offered Rate (LIBOR) [Member] | 2022 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.75%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum		0.75%
[1]	On February 3, 2015, we repurchased approximately $147 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, as described in further detail above.

Assets and Liabilities with R44

Assets and Liabilities with Recurring Fair Value Measurements Fair Value Hierarchy (Details) - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	$ 577	$ 896
Margin deposits	[2]	103	96
Commodity futures contracts		1,684	2,134
Commodity forward contracts	[3]	557	359
Interest Rate Derivative Assets, Fair Value		3	4
Total assets		2,924	3,489
Margin deposits held by us posted by our counterparties	[2],[4]	53	47
Commodity futures contracts		1,506	1,870
Commodity forward contracts	[3]	249	242
Interest Rate Derivative Liabilities At Fair Value		105	114
Liabilities, Fair Value Disclosure		1,913	2,273
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	577	896
Margin deposits		103	96
Commodity futures contracts		1,684	2,134
Commodity forward contracts	[3]	0	0
Interest Rate Derivative Assets, Fair Value		0	0
Total assets		2,364	3,126
Margin deposits held by us posted by our counterparties		53	47
Commodity futures contracts		1,506	1,870
Commodity forward contracts	[3]	0	0
Interest Rate Derivative Liabilities At Fair Value		0	0
Liabilities, Fair Value Disclosure		1,559	1,917
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	0	0
Margin deposits		0	0
Commodity futures contracts		0	0
Commodity forward contracts	[3]	284	195
Interest Rate Derivative Assets, Fair Value		3	4
Total assets		287	199
Margin deposits held by us posted by our counterparties		0	0
Commodity futures contracts		0	0
Commodity forward contracts	[3]	219	163
Interest Rate Derivative Liabilities At Fair Value		105	114
Liabilities, Fair Value Disclosure		324	277
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	0	0
Margin deposits		0	0
Commodity futures contracts		0	0
Commodity forward contracts	[3]	273	164
Interest Rate Derivative Assets, Fair Value		0	0
Total assets		273	164
Margin deposits held by us posted by our counterparties		0	0
Commodity futures contracts		0	0
Commodity forward contracts	[3]	30	79
Interest Rate Derivative Liabilities At Fair Value		0	0
Liabilities, Fair Value Disclosure		$ 30	$ 79
[1]	As of June 30, 2015 and December 31, 2014, we had cash equivalents of $367 million and $679 million included in cash and cash equivalents and $210 million and $217 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 6 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 R45

Assets and Liabilities with Recurring Fair Value Measurements Quantitative Info on Level 3 (Details) - USD ($)	Jun. 30, 2015	Dec. 31, 2014
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Fair Value, Net	$ 384,000,000	$ 271,000,000
Power Contracts [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Fair Value, Net	237,000,000	74,000,000
Power Contracts [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information	12.68	14
Power Contracts [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information	121.40	122.79
Natural Gas [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Fair Value, Net		5,000,000
Natural Gas [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information		1
Natural Gas [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information		10.86
Power Congestion Products [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Fair Value, Net	7,000,000	9,000,000
Power Congestion Products [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information	(19.56)	(19.56)
Power Congestion Products [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information	$ 19.56	$ 19.56

Assets and Liabilities with R46

Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
Fair Value Measurement [Domain]
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) [Abstract]
Cash and Cash Equivalents, at Carrying Value		$ 367		$ 367		$ 679
Restricted Cash and Cash Equivalents		210		210		217
Balance, beginning of period		203	$ 8	85	$ 14
Included in operating revenues	[1]	45	(7)	176	(15)
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Gain (Loss) Included In Fuel And Purchased Energy Expense	[2]	0	0	2	6
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases		2	0	4	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements		(10)	(3)	(21)	(6)
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount		0	0	0	0
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount		0	0	0	0
Transfers into level 3	[3],[4]	0	2	0	0
Transfers out of Level 3	[4],[5]	3	(9)	(3)	(8)
Balance, end of period		243	(9)	243	(9)
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)		45	(7)	178	(9)
Cash and Cash Equivalents, at Carrying Value		422	$ 442	422	$ 442	717	$ 941
Restricted Cash and Cash Equivalents		$ 210		$ 210		$ 244
[1]	For power contracts and other power-related products, 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, 2015 and for the six months ended June 30, 2014. We had $2 million in gains transferred out of level 2 into level 3 for the three months ended June 30, 2014, due to changes in market liquidity in various power markets.
[4]	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, 2015 and 2014.
[5]	We had $3 million in losses and $(9) million in gains transferred out of level 3 into level 2 for the three months ended June 30, 2015 and 2014, respectively, and $(3) million and $(8) million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2015 and 2014, respectively, due to changes in market liquidity in various power markets.

Derivative Instruments (Details

Derivative Instruments (Details) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015USD ($)MWhMMBTUt	Dec. 31, 2014USD ($)MWhMMBTUt
Power [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	(99)	(62)
Natural Gas [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	874	291
Environmental Credits [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Mass | t	3	0
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount | $	$ 1,411	$ 1,431

Derivative Instruments (Detai48

Derivative Instruments (Details 2) (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative assets, current	$ 1,607	$ 2,058
Long-term derivative assets	637	439
Total derivative assets	2,244	2,497
Derivative liabilities, current	1,407	1,782
Long-term derivative liabilities	453	444
Total derivative liabilities	1,860	2,226
Derivative, Fair Value, Net	384	271
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	3	4
Total derivative liabilities	105	112
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	2,241	2,493
Total derivative liabilities	1,755	2,114
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, current	0	0
Derivative Assets, Noncurrent	3	4
Total derivative assets	3	4
Current derivative liabilities	42	44
Derivative Liabilities, Noncurrent	63	70
Total derivative liabilities	105	114
Derivative, Fair Value, Net	(102)	(110)
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	3	4
Total derivative liabilities	105	112
Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	0	0
Total derivative liabilities	0	2
Energy Related Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, current	1,607	2,058
Derivative Assets, Noncurrent	634	435
Total derivative assets	2,241	2,493
Current derivative liabilities	1,365	1,738
Derivative Liabilities, Noncurrent	390	374
Total derivative liabilities	1,755	2,112
Derivative, Fair Value, Net	486	381
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	2,241	2,493
Total derivative liabilities	$ 1,755	$ 2,112

Derivative Instruments (Detai49

Derivative Instruments (Details 3) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Summary of Derivative Instruments by Risk Exposure [Abstract]
Power contracts included in operating revenues		$ 1,442	$ 1,939	$ 3,088	$ 3,904
Natural gas contracts included in fuel and purchased energy expense		766	1,134	1,776	2,491
Interest expense		158	169	312	335
Gain (Loss) on Derivative Instruments, Net, Pretax		103	160	233	49
Gain (Loss) on Sale of Derivatives	[1]	104	18	163	(21)
Mark-to-market gain (loss)	[2]	(1)	142	70	70
Power [Member]
Summary of Derivative Instruments by Risk Exposure [Abstract]
Power contracts included in operating revenues		115	158	234	(79)
Interest Rate Swap [Member]
Summary of Derivative Instruments by Risk Exposure [Abstract]
Interest expense		0	1	1	2
Mark-to-market gain (loss)	[2]	0	1	1	2
Energy Related Derivative [Member]
Summary of Derivative Instruments by Risk Exposure [Abstract]
Gain (Loss) on Sale of Derivatives	[1]	104	18	163	(21)
Mark-to-market gain (loss)	[2]	(1)	141	69	68
Natural Gas [Member]
Summary of Derivative Instruments by Risk Exposure [Abstract]
Natural gas contracts included in fuel and purchased energy expense		$ (12)	$ 1	$ (2)	$ 126
[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 mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

Derivative Instruments (Detai50

Derivative Instruments (Details 4) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Interest expense		$ 158	$ 169	$ 312	$ 335
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gains (Loss) Recognized in OCI (Effective Portion)	[1],[2]	14	(9)	8	(9)
Interest expense		0	1	1	2
Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Interest expense	[1],[2],[3],[4]	$ (12)	$ (13)	$ (24)	$ (26)
[1]	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, 2015 and 2014.
[2]	We recorded an income tax expense of nil for each of the three and six months ended June 30, 2015 and 2014, in AOCI related to our cash flow hedging activities.
[3]	Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $142 million and $149 million at June 30, 2015 and December 31, 2014, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $11 million and $12 million at June 30, 2015 and December 31, 2014, respectively.
[4]	Includes a loss of $5 million and $10 million for the three and six months ended June 30, 2014, respectively, that was reclassified from AOCI to interest expense, where the hedged transactions are no longer expected to occur.

Derivative Instruments (Textual

Derivative Instruments (Textuals) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	$ 0	$ 0	$ 0	$ 0
Derivative Instruments (Textuals) [Abstract]
Maximum length of time hedging using interest rate derivative instruments			8 years
Derivative, Net Liability Position, Aggregate Fair Value	12		$ 12
Collateral Already Posted, Aggregate Fair Value	9		9
Additional Collateral, Aggregate Fair Value	14		14
(Gain) Loss on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net		$ 5		$ 10
Cash Flow Hedge (Gain) Loss to be Reclassified within Twelve Months			46
Parent [Member]
Derivatives, Fair Value [Line Items]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	142		142		$ 149
Noncontrolling Interest [Member]
Derivatives, Fair Value [Line Items]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	$ 11		$ 11		$ 12

Derivative Instruments (Detail

Derivative Instruments (Detail 5) (Details) - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 2,244	$ 2,497
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		(1,737)	(2,087)
Derivative, Collateral, Obligation to Return Cash	[1]	(187)	(269)
Derivative Liability, Fair Value, Gross Liability		(1,860)	(2,226)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		1,737	2,087
Derivative, Collateral, Right to Reclaim Cash	[1]	9	15
Derivative, Fair Value, Net		384	271
Derivative Fair Value, Amount Not Offset Against Collateral, Net		0	0
Margin/Cash (Received) Posted Subject to Master Netting Arrangement	[1]	(178)	(254)
Derivative Asset, Fair Value, Amount Offset Against Collateral		320	141
Derivative Liability, Fair Value, Amount Offset Against Collateral		(114)	(124)
Derivative, Fair Value, Amount Offset Against Collateral, Net		206	17
Commodity Exchange Traded Futures and Swaps Contracts [Member]
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,684	2,134
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		(1,506)	(1,865)
Derivative, Collateral, Obligation to Return Cash	[1]	(178)	(269)
Derivative Liability, Fair Value, Gross Liability		(1,506)	(1,870)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		1,506	1,865
Derivative, Collateral, Right to Reclaim Cash	[1]	0	5
Derivative Asset, Fair Value, Amount Offset Against Collateral		0	0
Derivative Liability, Fair Value, Amount Offset Against Collateral		0	0
Commodity Forward Contract [Member]
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
Derivative Asset, Fair Value, Gross Asset		557	359
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		(231)	(222)
Derivative, Collateral, Obligation to Return Cash	[1]	(9)	0
Derivative Liability, Fair Value, Gross Liability		(249)	(242)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		231	222
Derivative, Collateral, Right to Reclaim Cash	[1]	9	10
Derivative Asset, Fair Value, Amount Offset Against Collateral		317	137
Derivative Liability, Fair Value, Amount Offset Against Collateral		(9)	(10)
Interest Rate Swap [Member]
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
Derivative Asset, Fair Value, Gross Asset		3	4
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		0	0
Derivative, Collateral, Obligation to Return Cash	[1]	0	0
Derivative Liability, Fair Value, Gross Liability		(105)	(114)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		0	0
Derivative, Collateral, Right to Reclaim Cash	[1]	0	0
Derivative, Fair Value, Net		(102)	(110)
Derivative Asset, Fair Value, Amount Offset Against Collateral		3	4
Derivative Liability, Fair Value, Amount Offset Against Collateral		$ (105)	$ (114)
[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 7 for a further discussion of our collateral.

Use of Collateral (Details)

Use of Collateral (Details) - USD ($) $ in Millions		Jun. 30, 2015	Dec. 31, 2014
Use of Collateral [Abstract]
Margin deposits	[1]	$ 103	$ 96
Natural gas and power prepayments		25	22
Total margin deposits and natural gas and power prepayments with our counterparties	[2]	128	118
Letters of credit issued		452	450
First priority liens under power and natural gas agreements		24	48
First priority liens under interest rate swap agreements		106	116
Total letters of credit and first priority liens with our counterparties		582	614
Margin deposits held by us posted by our counterparties	[1],[3]	53	47
Letters of credit posted with us by our counterparties		52	61
Total margin deposits and letters of credit posted with us by our counterparties		105	108
Use of Collateral (Textuals) [Abstract]
Margin And Prepayment Amounts Included In Other Assets		14	9
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses		$ 114	$ 109
[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 6 for further discussion of our derivative instruments subject to master netting arrangements.
[2]	At June 30, 2015 and December 31, 2014, $114 million and $109 million, respectively, were included in margin deposits and other prepaid expense and $14 million and $9 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 Expens

Income Taxes (Income Tax Expense (Benefit)) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Tax Contingency [Line Items]
Income tax (expense) benefit	$ (5)	$ (15)	$ (4)	$ 4
Effective Income Tax Rate, Continuing Operations	21.00%	10.00%	31.00%	(3.00%)
Unrecognized Tax Benefits	$ 54		$ 54
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	13		13
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	11		11
Unrecognized Tax Benefit Related to Deferred Tax Asset	$ 41		$ 41

Earnings (Loss) per Share (Deta

Earnings (Loss) per Share (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Share-based awards	5,042	2,854	5,042	5,066

Earnings (Loss) per Share Recon

Earnings (Loss) per Share Reconcilation of Basic to Diluted Weighted Average Shares Outstanding (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Reconciliation of Basic to Diluted Weighted Average Shares [Abstract]
Weighted average shares of common stock outstanding (in thousands)	366,975	416,507	369,938	418,296
Weighted Average Number Diluted Shares Outstanding Adjustment	2,971	4,841	3,466	4,401
Weighted average shares of common stock outstanding (in thousands)	369,946	421,348	373,404	422,697

Stock-Based Compensation (Summa

Stock-Based Compensation (Summary restricted stock and restricted stock unit activity) (Details) - Restricted Stock [Member] - $ / shares	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
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	4,039,653	4,201,868
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 19.86	$ 18.01
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	1,572,761
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 21.42
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	157,807
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 19.40
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	1,577,169
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 16.52

Stock-Based Compensation (Stock

Stock-Based Compensation (Stock Based Compensation Textuals) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 7	$ 8	$ 16	$ 17
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards	(6)	$ 4	(4)	5
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	$ 38		38
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1 year 6 months
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value			$ 33	$ 30

Stock-Based Compensation Liabil

Stock-Based Compensation Liability Based Stock Compensation (Details) - Performance Shares [Member] - $ / shares		6 Months Ended
		Jun. 30, 2015	Dec. 31, 2014
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		1,179,238	867,479
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 22.53	$ 21.93
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		365,667
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 23.91
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period		45,654
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 22.09
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	[1]	8,254
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		$ 22.56
[1]	In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date.

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions		3 Months Ended				6 Months Ended
		Jun. 30, 2015		Jun. 30, 2014		Jun. 30, 2015		Jun. 30, 2014
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		$ 1,442		$ 1,939		$ 3,088		$ 3,904
Commodity Margin		657		632	[1]	1,192		1,277	[1]
Add: Mark-to-market commodity activity, net and other		19	[1]	173	[2]	120	[3]	136	[3]
Plant operating expense		272		274		532		539
Depreciation and amortization expense		160		147		318		300
Sales, general and other administrative expense		30		38		67		71
Other operating expenses		20		21		40		43
(Income) loss from unconsolidated investments in power plants		(7)		(4)		(12)		(13)
Income from operations		201		329		367		473
Interest expense, net of interest income		157		167		310		332
Debt extinguishment costs and other (income) expense, net		18		6		39		17
Income before income taxes		26		156		18		124
Lease levelization		(18)		(27)		(42)		(56)
Contract amortization		3		3		7		7
West [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		421		488		938		981
Commodity Margin		240		228	[1]	458		430	[1]
Add: Mark-to-market commodity activity, net and other		(14)	[1]	21	[2]	105	[3]	50	[3]
Plant operating expense		120		95		226		200
Depreciation and amortization expense		65		58		132		118
Sales, general and other administrative expense		6		7		16		17
Other operating expenses		10		15		20		27
(Income) loss from unconsolidated investments in power plants		0		0		0		0
Income from operations		25		74		169		118
Texas [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		575		963		1,159		1,622
Commodity Margin		170		177	[1]	319		298	[1]
Add: Mark-to-market commodity activity, net and other		10	[1]	184	[2]	51	[3]	138	[3]
Plant operating expense		82		83		171		173
Depreciation and amortization expense		50		48		99		90
Sales, general and other administrative expense		15		18		32		30
Other operating expenses		2		1		4		3
(Income) loss from unconsolidated investments in power plants		0		0		0		0
Income from operations		31		211		64		140
East [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		453		519		1,005		1,363
Commodity Margin		247		227	[1]	415		549	[1]
Add: Mark-to-market commodity activity, net and other		30	[1]	(24)	[2]	(22)	[3]	(35)	[3]
Plant operating expense		77		103		149		182
Depreciation and amortization expense		45		40		87		91
Sales, general and other administrative expense		9		12		19		24
Other operating expenses		8		9		16		16
(Income) loss from unconsolidated investments in power plants		(7)		(4)		(12)		(13)
Income from operations		145		43		134		214
Geography Consolidation and Elimination [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		(7)		(31)		(14)		(62)
Commodity Margin		0		0	[1]	0		0	[1]
Add: Mark-to-market commodity activity, net and other		(7)	[1]	(8)	[2]	(14)	[3]	(17)	[3]
Plant operating expense		(7)		(7)		(14)		(16)
Depreciation and amortization expense		0		1		0		1
Sales, general and other administrative expense		0		1		0		0
Other operating expenses		0		(4)		0		(3)
(Income) loss from unconsolidated investments in power plants		0		0		0		0
Income from operations		0		1		0		1
Six Power Plants [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Commodity Margin	[2]			42				81
Operating Segments [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		1,442		1,939		3,088		3,904
Operating Segments [Member] | West [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		421		487		936		978
Operating Segments [Member] | Texas [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		570		960		1,151		1,607
Operating Segments [Member] | East [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		451		492		1,001		1,319
Operating Segments [Member] | Geography Consolidation and Elimination [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		0		0		0		0
Intersegment Eliminations [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		0		0		0		0
Intersegment Eliminations [Member] | West [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		0		1		2		3
Intersegment Eliminations [Member] | Texas [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		5		3		8		15
Intersegment Eliminations [Member] | East [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		2		27		4		44
Intersegment Eliminations [Member] | Geography Consolidation and Elimination [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		$ (7)		$ (31)		$ (14)		$ (62)
Six Power Plants [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Number of power plants disposed								6
[1]	Commodity Margin related to the six power plants sold in our East segment on July 3, 2014, was $42 million and $81 million for the three and six months ended June 30, 2014
[2]	Includes $(18) million and $(27) million of lease levelization and $3 million and $3 million of amortization expense for the three months ended June 30, 2015 and 2014, respectively.
[3]	Includes $(42) million and $(56) million of lease levelization and $7 million and $7 million of amortization expense for the six months ended June 30, 2015 and 2014, respectively.