Calpine (CPNLQ) 10-K 13 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Cover (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 11, 2015	Jun. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	CALPINE CORP
Entity Central Index Key	916457
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding		376,193,256
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$9,891

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenues:
Commodity revenue	$7,595	$6,374	$5,417
Mark to Market Gain Loss on Derivatives included in Operating Revenues	419	-86	48
Other revenue	16	13	13
Operating revenues	8,030	6,301	5,478
Operating expenses:
Commodity expense	4,815	3,808	2,894
Mark to Market Gain Loss on Derivatives Included in Fuel and Purchased Energy Expense	77	-72	130
Fuel and purchased energy expense	4,892	3,736	3,024
Plant operating expense	969	895	922
Depreciation and amortization expense	603	593	562
Sales, general and other administrative expense	144	136	140
Other operating expenses	88	81	78
Total operating expenses	6,696	5,441	4,726
Impairment losses	123	16	0
(Gain) on sale of assets, net	-753	0	-222
(Income) from unconsolidated investments in power plants	-25	-30	-28
Income from operations	1,989	874	1,002
Interest expense	645	696	736
Loss on interest rate derivatives	0	0	14
Interest (income)	-6	-6	-11
Debt extinguishment costs	346	144	30
Other (income) expense, net	21	20	15
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	983	20	218
Income tax expense	22	2	19
Net income	961	18	199
Net income attributable to the noncontrolling interest	-15	-4	0
Net income attributable to Calpine	$946	$14	$199
Basic earnings per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in shares)	404,837	440,666	467,752
Net income (loss) per common share attributable to Calpine — basic (in dollars per share)	$2.34	$0.03	$0.43
Diluted earnings per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in shares)	409,360	444,773	471,343
Net income (loss) per common share attributable to Calpine — diluted (in dollars per share)	$2.31	$0.03	$0.42

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net income	$961	$18	$199
Cash flow hedging activities:
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income	-48	35	-61
Reclassification adjustment for (gain) loss on cash flow hedges realized in net income	46	51	-20
Unrealized actuarial gains (losses) arising during period	-4	4	-1
Foreign currency translation gain (loss)	-13	-10	3
Income tax (expense) benefit	0	-3	9
Other comprehensive income (loss)	-19	77	-70
Comprehensive income	942	95	129
Comprehensive (income) loss attributable to the noncontrolling interest	-14	-13	6
Comprehensive income attributable to Calpine	$928	$82	$135

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Current assets:
Cash and cash equivalents ($229 and $242 attributable to VIEs)	$717	$941
Accounts receivable, net of allowance of $4 and $5	648	552
Inventory	447	364
Prepaid Expense and Other Assets, Current	148	309
Restricted cash, current ($106 and $100 attributable to VIEs)	195	203
Derivative Instruments and Hedges, Assets	2,058	445
Other current assets	7	42
Total current assets	4,220	2,856
Property, plant and equipment, net ($4,342 and $4,191 attributable to VIEs)	13,190	12,995
Restricted cash, net of current portion ($48 and $68 attributable to VIEs)	49	69
Investments in power plants	95	93
Long-term derivative assets	439	105
Other assets ($164 and $195 attributable to VIEs)	385	441
Total assets	18,378	16,559
Current liabilities:
Accounts payable	580	462
Accrued interest payable	165	162
Debt, current portion ($150 and $140 attributable to VIEs)	199	204
Derivative liabilities, current	1,782	451
Other current liabilities	473	252
Total current liabilities	3,199	1,531
Debt, net of current portion ($3,242 and $2,923 attributable to VIEs)	11,083	10,908
Long-term derivative liabilities	444	243
Other long-term liabilities	221	309
Total liabilities	14,947	12,991
Commitments and contingencies (see Note 15)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding at December 31, 2014 and 2013	0	0
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 502,287,022 shares issued and 381,921,264 shares outstanding at December 31, 2014, and 497,841,056 shares issued and 429,038,988 shares outstanding at December 31, 2013	1	1
Treasury stock, at cost, 120,365,758 and 68,802,068 shares, respectively	-2,345	-1,230
Additional paid-in capital	12,440	12,389
Accumulated deficit	-6,540	-7,486
Accumulated other comprehensive loss	-178	-160
Total Calpine stockholders’ equity	3,378	3,514
Noncontrolling interest	53	54
Total stockholders’ equity	3,431	3,568
Total liabilities and stockholders’ equity	$18,378	$16,559

Consolidated_Balance_Sheets_Co

Consolidated Balance Sheets Consolidated Balance Sheets Parentheticals (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
Cash and cash equivalents ($229 and $242 attributable to VIEs)	$717	$941
Accounts receivable, net of allowance of $4 and $5	4	5
Restricted cash, current ($106 and $100 attributable to VIEs)	195	203
Property, plant and equipment, net ($4,342 and $4,191 attributable to VIEs)	13,190	12,995
Restricted cash, net of current portion ($48 and $68 attributable to VIEs)	49	69
Other assets ($164 and $195 attributable to VIEs)	385	441
Debt, current portion ($150 and $140 attributable to VIEs)	199	204
Debt, net of current portion ($3,242 and $2,923 attributable to VIEs)	11,083	10,908
Preferred Stock, par value (in dollars per share)	$0.00	$0.00
Preferred Stock, authorized shares (in shares)	100,000,000	100,000,000
Preferred Stock, issued shares (in shares)	0	0
Preferred Stock, outstanding shares (in shares)	0	0
Common Stock, par value (in dollars per share)	$0.00	$0.00
Common Stock, authorized shares (in shares)	1,400,000,000	1,400,000,000
Common Stock, issued shares (in shares)	502,287,022	497,841,056
Common Stock, outstanding shares (in shares)	381,921,264	429,038,988
Treasury Stock, shares (in shares)	120,365,758	68,802,068
Variable Interest Entity, Primary Beneficiary [Member]
Cash and cash equivalents ($229 and $242 attributable to VIEs)	229	242
Restricted cash, current ($106 and $100 attributable to VIEs)	106	100
Property, plant and equipment, net ($4,342 and $4,191 attributable to VIEs)	4,342	4,191
Restricted cash, net of current portion ($48 and $68 attributable to VIEs)	48	68
Other assets ($164 and $195 attributable to VIEs)	164	195
Debt, current portion ($150 and $140 attributable to VIEs)	150	140
Debt, net of current portion ($3,242 and $2,923 attributable to VIEs)	$3,242	$2,923

Consolidated_Statements_of_Sto

Consolidated Statements of Stockholders Equity (USD $)	Total	Common Stock [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]
In Millions
Balance at Dec. 31, 2011	$4,364	$1	($125)	$12,305	($7,699)	($164)	$46
Treasury stock transactions	-469	0	-469	0	0	0	0
Stock-based compensation expense	25	0	0	25	0	0	0
Option exercises	5	0	0	5	0	0	0
Payments to Noncontrolling Interests	0
Other	2	0	0	0	0	0	2
Net income	199	0	0	0	199	0	0
Other comprehensive income (loss)	-70	0	0	0	0	-64	-6
Balance at Dec. 31, 2012	4,056	1	-594	12,335	-7,500	-228	42
Treasury stock transactions	-636	0	-636	0	0	0	0
Stock-based compensation expense	34	0	0	34	0	0	0
Option exercises	20	0	0	20	0	0	0
Payments to Noncontrolling Interests	0
Other	-1	0	0	0	0	0	-1
Net income	18	0	0	0	14	0	4
Other comprehensive income (loss)	77	0	0	0	0	68	9
Balance at Dec. 31, 2013	3,568	1	-1,230	12,389	-7,486	-160	54
Treasury stock transactions	-1,115	0	-1,115	0	0	0	0
Stock-based compensation expense	31	0	0	31	0	0	0
Option exercises	20	0	0	20	0	0	0
Payments to Noncontrolling Interests	-15	0	0	0	0	0	15
Net income	961	0	0	0	946	0	15
Other comprehensive income (loss)	-19	0	0	0	0	-18	-1
Balance at Dec. 31, 2014	$3,431	$1	($2,345)	$12,440	($6,540)	($178)	$53

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Cash flows from operating activities:
Net income	$961		$18		$199
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense(1)	649	[1]	638	[1]	605	[1]
Debt extinguishment costs	36		43		0
Deferred income taxes	5		14		1
Impairment losses	123		16		0
(Gain) on sale of assets, net	-753		0		-222
Mark-to-market activity, net	-353	[2]	12	[2]	-72	[2]
(Income) from unconsolidated investments in power plants	-25		-30		-28
Return on unconsolidated investments in power plants	13		25		24
Stock-based compensation expense	36		36		25
Other	-4		1		11
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable	-87		-113		159
Derivative instruments, net	-63		-7		-52
Other assets	151		-148		-57
Accounts payable and accrued expenses	185		-1		-86
Settlement of non-hedging interest rate swaps	0		0		156
Other liabilities	-20		45		-10
Net cash provided by operating activities	854		549		653
Cash flows from investing activities:
Purchases of property, plant and equipment	-492		-575		-637
Proceeds from sale of power plants, interests and other	1,573		1		825
Purchase of Bosque, Fore River and Guadalupe Energy Centers	-1,197		0		-432
Settlement of non-hedging interest rate swaps	0		0		-156
(Increase) decrease in restricted cash	28		-18		-59
Purchases of deferred transmission credits	0		0		-12
Other	4		-1		1
Net cash used in investing activities	-84		-593		-470
Cash flows from financing activities:
Proceeds from Issuance of Secured Debt	420		1,587		835
Repayments of Secured Debt	-45		-1,031		-19
Proceeds from Issuance of Unsecured Debt	2,800		0		0
Borrowings under First Lien Notes	0		1,234		0
Repayments of First Lien Notes	-2,920		-1,550		-590
Borrowings from project financing, notes payable and other	79		182		389
Repayments of project financing, notes payable and other	-178		-66		-289
Payments to Noncontrolling Interests	-15		0		0
Financing costs	-56		-53		-20
Stock repurchases	-1,100		-623		-463
Proceeds from exercises of stock options	20		20		5
Other	1		1		1
Net cash used in financing activities	-994		-299		-151
Net increase (decrease) in cash and cash equivalents	-224		-343		32
Cash and cash equivalents, beginning of period	941		1,284		1,252
Cash and cash equivalents, end of period	717		941		1,284
Cash paid during the period for:
Interest, net of amounts capitalized	610		672		719
Income taxes	23		24		16
Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable	3		27		19
Additions to property, plant and equipment through assumption of long-term note payable	0		0		8
Additions to property, plant and equipment through capital leases	$19		$0		$5
[1]	Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated 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.

Organization_and_Operations

Organization and Operations	12 Months Ended
	Dec. 31, 2014
Organization and Operations [Abstract]
Organization and Operations	Organization and Operations
	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.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies
	Basis of Presentation and Principles of Consolidation
	Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and include the accounts of all majority-owned subsidiaries that are not VIEs and all VIEs where we have determined we are the primary beneficiary. Intercompany transactions have been eliminated in consolidation.
	Equity Method Investments — We use the equity method of accounting to record our net interests in VIEs where we have determined that we are not the primary beneficiary, which include Greenfield LP, a 50% partnership interest, and Whitby, a 50% partnership interest. Our share of net income (loss) is calculated according to our equity ownership percentage or according to the terms of the applicable partnership agreement. See Note 5 for further discussion of our VIEs and unconsolidated investments.
	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.
	Jointly-Owned Plants — Certain of our subsidiaries own undivided interests in jointly-owned plants. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. We are responsible for our subsidiaries’ share of operating costs and direct expenses and include our proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of our Consolidated Financial Statements. The following table summarizes our proportionate ownership interest in jointly-owned power plants:
	As of December 31, 2014		Ownership Interest		Property, Plant & Equipment		Accumulated Depreciation			Construction in Progress
	(in millions, except percentages)
	Freestone Energy Center		75	%	$	389	$	(140	)	$	—
	Hidalgo Energy Center		78.5	%	$	257	$	(104	)	$	—
	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 Financial Statements. Actual results could differ from those estimates.
	Fair Value of Financial Instruments and Derivatives
	The carrying values of accounts receivable, accounts payable and other receivables and payables approximate their respective fair values due to their short-term maturities. See Note 6 for disclosures regarding the fair value of our debt instruments and Note 7 for disclosures regarding the fair values of our derivative instruments and margin deposits and certain of our cash balances.
	Concentrations of Credit Risk
	Financial instruments that potentially subject us to credit risk consist of cash and cash equivalents, restricted cash, accounts and notes receivable and derivative financial instruments. Certain of our cash and cash equivalents, as well as our restricted cash balances, are invested in money market accounts with investment banks that are not FDIC insured. We place our cash and cash equivalents and restricted cash in what we believe to be creditworthy financial institutions and certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Additionally, we actively monitor the credit risk of our counterparties, including our receivable, commodity and derivative transactions. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the U.S. We generally have not collected collateral for accounts receivable from utilities and end-user customers; however, we may require collateral in the future. For financial and commodity derivative counterparties, we evaluate the net accounts receivable, accounts payable and fair value of commodity contracts and may require security deposits, cash margin or letters of credit to be posted if our exposure reaches a certain level or their credit rating declines.
	Our counterparties primarily consist of three categories of entities who participate in the wholesale energy markets:
	•	financial institutions and trading companies;
	•	regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers; and
	•	oil, natural gas, chemical and other energy-related industrial companies.
	We have concentrations of credit risk with a few of our customers relating to our sales of power, steam and hedging, optimization and trading activities. We have exposure to trends within the energy industry, including declines in the creditworthiness of our counterparties for our commodity and derivative transactions. Currently, certain of our counterparties within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty credit risk and monitors our net exposure with each counterparty on a daily basis. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a counterparty credit risk threshold which is determined based on each counterparty’s credit rating and evaluation of their financial statements. We utilize these thresholds to determine the need for additional collateral or restriction of activity with the counterparty. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties are performing and financially settling timely according to their respective agreements.
	Cash and Cash Equivalents
	We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts, which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At December 31, 2014 and 2013, we had cash and cash equivalents of $257 million and $292 million, respectively, that were subject to such project finance facilities and lease agreements.
	Restricted Cash
	Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Balance Sheets and Statements of Cash Flows.
	The table below represents the components of our restricted cash as of December 31, 2014 and 2013 (in millions):
		2014								2013
		Current			Non-Current		Total			Current		Non-Current		Total
	Debt service	$	10		$	25	$	35		$	11	$	41	$	52
	Rent reserve	4			—		4			3		—		3
	Construction/major maintenance	54			17		71			35		20		55
	Security/project/insurance	127			5		132			151		6		157
	Other	—			2		2			3		2		5
	Total	$	195		$	49	$	244		$	203	$	69	$	272
	Accounts Receivable and Payable
	Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest. Receivable balances greater than 30 days past due are individually reviewed for collectability, and if deemed uncollectible, are charged off against the allowance account after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best estimate to determine the required allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations. We review the adequacy of our reserves and allowances quarterly.
	The accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging and optimization activities. Some of these receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a right of offset and settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off balance sheet credit exposure related to our customers.
	Inventory
	Inventory primarily consists of spare parts, stored natural gas and fuel oil, environmental products and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
	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 previously subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility as collateral under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity hedge agreements” under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. The first priority liens have been granted in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. Our interest rate swap agreements relate to hedges of certain of our project financings collateralized by first priority liens on the underlying assets. See Note 9 for a further discussion on our amounts and use of collateral.
	Deferred Financing Costs
	Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the related debt using a method that approximates the effective interest rate method. However, when the timing of debt transactions involve contemporaneous exchanges of cash between us and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, deferred financing costs are accounted for depending on whether the transaction qualifies as an extinguishment or modification, which requires us to either write-off the original deferred financing costs and capitalize the new issuance costs, or continue to amortize the original deferred financing costs and immediately expense the new issuance costs.
	Property, Plant and Equipment, Net
	Property, plant, and equipment items are recorded at cost. We capitalize costs incurred in connection with the construction of power plants, the development of geothermal properties and the refurbishment of major turbine generator equipment. When capital improvements to leased power plants meet our capitalization criteria they are capitalized as leasehold improvements and amortized over the shorter of the term of the lease or the economic life of the capital improvement. We expense maintenance when the service is performed for work that does not meet our capitalization criteria. Our current capital expenditures at our Geysers Assets are those incurred for proven reserves and reservoir replenishment (primarily water injection), pipeline and power generation assets and drilling of “development wells” as all drilling activity has been performed within the known boundaries of the steam reservoir. We have capitalized costs incurred during ownership consisting of additions, certain replacements or repairs when the repairs appreciably extend the life, increase the capacity or improve the efficiency or safety of the property. Such costs are expensed when they do not meet the above criteria. We purchased our Geysers Assets as a proven steam reservoir and all well costs, except well workovers and routine repairs and maintenance, have been capitalized since our purchase date.
	We depreciate our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis where we own the power plant or have a favorable option to purchase the power plant or take ownership of the power plant at conclusion of the lease term and approximately 0.15% of the depreciable costs basis for rotable equipment. For our Geysers Assets, we typically assume no salvage values. We use the component depreciation method for our natural gas-fired power plant rotable parts and our information technology equipment and the composite depreciation method for most of all of the other natural gas-fired power plant asset groups and Geysers Assets.
	Generally, upon normal retirement of assets under the composite depreciation method, the costs of such assets are retired against accumulated depreciation and no gain or loss is recorded. For the retirement of assets under the component depreciation method, generally, the costs and related accumulated depreciation of such assets are removed from our Consolidated Balance Sheets and a gain or loss is recorded as plant operating expense.
	Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)
	We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.
	In order to estimate future cash flows, we consider historical cash flows, existing and future contracts and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
	When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
	Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
	In August 2014, we executed a term sheet with Duke Energy Florida, Inc. related to our Osprey Energy Center for a new PPA with a term of 27 months, after which Duke Energy Florida, Inc. would purchase our Osprey Energy Center subject to an asset sale agreement that was executed in the fourth quarter of 2014 and remains subject to federal and state regulatory approval. As a result, we conducted an impairment review of our Osprey Energy Center during the third quarter of 2014. We estimated fair value of our Osprey Energy Center under a modified market approach using the discounted cash flows under the PPA and the sale proceeds to be received, which incorporated a market participant's fair value of the power plant. We recorded an impairment loss of approximately $123 million which was recorded as a separate line item on our Consolidated Statements of Operations for the year ended December 31, 2014. We recorded an impairment loss of $16 million during the year ended December 31, 2013 related to a power plant in our West segment. During 2012, we did not record any impairment losses.
	Asset Retirement Obligation
	We record all known asset retirement obligations for which the liability’s fair value can be reasonably estimated. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At December 31, 2014 and 2013, our asset retirement obligation liabilities were $47 million and $44 million, respectively, primarily relating to land leases upon which our power plants are built and the requirement that the property meet specific conditions upon its return.
	Revenue Recognition
	Our operating revenues are comprised of the following:
	•	power and steam revenue consisting of fixed and variable capacity payments, which are not related to generation including capacity payments received from RTO and ISO capacity auctions, variable payments for power and steam, which are related to generation, host steam and RECs from our Geysers Assets, other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues and realized settlements from our marketing, hedging, optimization and trading activities;
	•	mark-to-market revenues from derivative instruments as a result of our marketing, hedging, optimization and trading activities; and
	•	other service revenues.
	Power and Steam
	Physical Commodity Contracts — We recognize revenue primarily from the sale of power and steam thermal energy for sale to our customers for use in industrial or other heating operations upon transmission and delivery to the customer.
	We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the value inherent in our generation. We apply lease accounting to contracts that meet the definition of a lease and accrual accounting treatment to those contracts that are either exempt from derivative accounting or do not meet the definition of a derivative instrument. Additionally, we determine whether the financial statement presentation of revenues should be on a gross or net basis.
	With respect to our physical executory contracts, where we act as a principal, we take title of the commodities and assume the risks and rewards of ownership by receiving the natural gas and using the natural gas in our operations to generate and deliver the power. Where we act as principal, we record settlement of our physical commodity contracts on a gross basis. Where we do not take title of the commodities but receive a net variable payment to convert natural gas into power and steam in a tolling operation, we record the variable payment as revenue but do not record any fuel and purchased energy expense.
Capacity payments, RMR Contracts, RECs, resource adequacy and other ancillary revenues, unless qualified as a lease, are recognized when contractually earned and consist of revenues received from our customers either at the market price or a contract price.
Realized and Mark-to-Market Revenues from Commodity Derivative Instruments
Realized Settlements of Commodity Derivative Instruments — The realized value of power commodity sales and purchase contracts that are net settled or settled as gross sales and purchases, but could have been net settled, are reflected on a net basis and are included in Commodity revenue on our Consolidated Statements of Operations.
Mark-to-Market Gain (Loss) — The changes in the mark-to-market value of power-based commodity derivative instruments are reflected on a net basis as a separate component of operating revenues.
Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize certain components of these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2014, are as follows (in millions):
2015	$	561
2016	495
2017	433
2018	396
2019	357
Thereafter	1,380
Total	$	3,622
Accounting for Derivative Instruments
We enter into a variety of derivative instruments including both exchange traded and OTC power and natural gas forwards, options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) and interest rate swaps. 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 are designated under the normal purchase normal sale exemption. Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes are not available from sources external to us, in which case we rely on internally developed price estimates. See Note 8 for further discussion on our accounting for derivatives.
Fuel and Purchased Energy Expense
Fuel and purchased energy expense is comprised of the cost of natural gas and fuel oil purchased from third parties for the purposes of consumption in our power plants as fuel, and the cost of power and natural gas purchased from third parties for our marketing, hedging and optimization activities and realized settlements and mark-to-market gains and losses resulting from general market price movements against certain derivative natural gas contracts including financial natural gas transactions economically hedging anticipated future power sales that 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.
Realized and Mark-to-Market Expenses from Commodity Derivative Instruments
Realized Settlements of Commodity Derivative Instruments — The realized value of natural gas purchase and sales commodity contracts that are net settled are reflected on a net basis and included in Commodity expense on our Consolidated Statements of Operations. Power purchase commodity contracts that result in the physical delivery of power, and that also supplement our power generation, are reflected on a gross basis and are included in Commodity expense on our Consolidated Statements of Operations.
Mark-to-Market (Gain) Loss — The changes in the mark-to-market value of natural gas-based commodity derivative instruments are reflected on a net basis as a separate component of fuel and purchased energy expense.
Plant Operating Expense
Plant operating expense primarily includes employee expenses, utilities, chemicals, repairs and maintenance (including equipment failure and major maintenance), insurance and property taxes. We recognize these expenses when the service is performed or in the period in which the expense relates.
Income Taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis and tax credit and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that includes the enactment date.
We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. See Note 10 for a further discussion on our income taxes.
Earnings per Share
Basic earnings per share is calculated using the weighted average shares outstanding during the period and includes restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock. Diluted earnings per share is calculated by adjusting the weighted average shares outstanding by the dilutive effect of share-based awards using the treasury stock method. See Note 11 for a further discussion of our earnings per share.
Stock-Based Compensation
We use the Black-Scholes option-pricing model or the Monte Carlo simulation model to estimate the fair value of our employee stock options on the grant date. For our restricted stock and restricted stock units, we use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Our performance share units are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. See Note 12 for a further discussion of our stock-based compensation.
Treasury Stock
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock.     Upon retirement of treasury stock, the amounts in excess of par value are charged entirely to additional paid-in capital. See Note 14 for a further discussion of treasury stock.
New Accounting Standards and Disclosure Requirements
Income Taxes — In July 2013, the FASB issued Accounting Standards Update 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists”. The provisions of the standard require an unrecognized tax benefit to be presented as a reduction to a deferred tax asset in the financial statements for a NOL carryforward, a similar tax loss, or a tax credit carryforward except in circumstances when the carryforward or tax loss is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes. When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. We adopted Accounting Standards Update 2013-11 in the first quarter of 2014 which did not have a material impact on our financial condition, results of operations or cash flows.
Financial Reporting of Discontinued Operations — In April 2014, the FASB issued Accounting Standards Update 2014-08, “Presentation of Financial Statements and Property, Plant, and Equipment”. The update limits discontinued operations reporting to disposals that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The standard also requires new disclosures related to components reported as discontinued operations, as well as components of an entity that were sold and do not meet the criteria for discontinued operations reporting. The new financial statement presentation provisions relating to this standard are prospective and effective for interim and annual periods beginning after December 15, 2014, 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.
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 creates a five-step model for revenue recognition that requires companies to exercise judgment when considering contract terms and relevant facts and circumstances. The five-step model includes (1) identifying the contract, (2) identifying the separate performance obligations in the contract, (3) determining the transaction price, (4) allocating the transaction price to the separate performance obligations and (5) recognizing revenue when each performance obligation has been satisfied. The standard also requires expanded disclosures surrounding revenue recognition. The standard is 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. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows.
Going Concern — In August 2014, the FASB issued Accounting Standards Update 2014-15, “Presentation of Financial Statements — Going Concern”. This standard requires an entity’s management to assess the entity’s ability to continue as a going concern every reporting period including interim periods and requires additional disclosures if conditions or events raise substantial doubt about an entity’s ability to continue as a going concern. The standard is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter with early adoption permitted. We early adopted this standard during the fourth quarter of 2014 which did not have a material impact on our financial condition, results of operations or cash flows.

Acquisitions_Divestitures_and_

Acquisitions, Divestitures and Discontinued Operations Acquisitions and Divestitures (Notes)	12 Months Ended
	Dec. 31, 2014
Discontinued Operations and Disposal Groups [Abstract]
Mergers, Acquisitions and Dispositions Disclosures [Text Block]	Acquisitions and Divestitures
	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. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market. Built in 2003, Fore River Energy Center is located in North Weymouth, Massachusetts and features two combustion turbines, two heat recovery steam generators and one steam turbine. One turbine features dual-fuel capability that will enable it to run this winter on either natural gas or fuel oil, depending on market conditions, with the other turbine scheduled to be modified to be dual-fuel capable by winter 2016. The purchase price was funded with cash on hand and primarily allocated to property, plant and equipment. 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. The pro forma incremental impact of Fore River Energy Center on our results of operations for each of the years ended December 31, 2014 and 2013 is not material.
	Acquisition of Guadalupe Energy Center
	On February 26, 2014, we, through our indirect, wholly-owned subsidiary Calpine Guadalupe GP, LLC, completed the purchase of a power plant owned by MinnTex Power Holdings, LLC with a nameplate capacity of 1,050 MW, for approximately $625 million, excluding working capital adjustments. The addition of this modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment, which is one of our core markets. The 110-acre site, located in Guadalupe County, Texas, which is northeast of San Antonio, Texas, includes two 525 MW generation blocks, each consisting of two GE 7FA combustion turbines, two heat recovery steam generators and one GE steam turbine. We also paid $15 million to acquire rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker. We funded the acquisition with $425 million in incremental CCFC Term Loans and cash on hand. See Note 6 for a further description of the incremental CCFC Term Loans. The purchase price was primarily allocated to property, plant and equipment and was finalized during the third quarter of 2014 which did not result in any material adjustments to the preliminary purchase price allocation nor the recognition of any goodwill. The pro forma incremental impact of Guadalupe Energy Center on our results of operations for each of the years ended December 31, 2014 and 2013 is not material.
	Acquisition of Bosque Energy Center
	On November 7, 2012, we, through our indirect, wholly-owned subsidiary Calpine Bosque Energy Center, LLC, completed the purchase of a power plant with a nameplate capacity of 800 MW owned by Bosque Power Co., LLC, for approximately $432 million. The modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment and is located in Central Texas near the unincorporated community of Laguna Park in Bosque County. The site includes a 250 MW generation block with one natural-gas turbine, one heat recovery steam generator and one steam turbine that achieved COD in June 2001 and a 550 MW generation block with two natural-gas turbines that went online in June 2000 as well as two heat recovery steam generators and one steam turbine that achieved COD in June 2011. We funded the $432 million purchase price with cash on hand. The purchase price, which was finalized in 2013, was primarily allocated to property, plant and equipment. We did not record any goodwill as a result of this acquisition.
	Sale of Six Power Plants
	On July 3, 2014, we completed the sale of six of our power plants in our East segment to NatGen Southeast Power LLC, a wholly-owned subsidiary of LS Power Equity Partners III. The purchase and sale agreement, dated April 17, 2014, stipulates the sale of 100% of the limited liability company interests in (i) Mobile Energy LLC, (ii) Santa Rosa Energy Center, LLC, (iii) Carville Energy, LLC, (iv) Decatur Energy Center, LLC, (v) Columbia Energy LLC and (vi) Calpine Oneta Power, LLC and thereby sell assets comprising 3,498 MW of combined-cycle generation capacity in Oklahoma, Louisiana, Alabama, Florida and South Carolina for a sale price of approximately $1.57 billion in cash, plus approximately $2 million for working capital and other adjustments at closing. In accordance with the purchase and sale agreement, we have paid $12 million for certain maintenance events at December 31, 2014 and may also be required to make up to $4 million in future cash payments for planned maintenance. The divestiture of these power plants has better aligned our asset base with our strategic focus on competitive wholesale markets.
	We recorded a gain on sale of assets, net of approximately $753 million during the third quarter of 2014 and will use existing federal and state NOLs to almost entirely offset the projected taxable gains from the sale. The sale of the six power plants did not meet the criteria for treatment as discontinued operations.
	The six power plants included in the transaction are as follows:
	Plant Name		Plant Capacity		Location
	Oneta Energy Center		1,134	MW	Coweta, OK
	Carville Energy Center(1)		501	MW	St. Gabriel, LA
	Decatur Energy Center		795	MW	Decatur, AL
	Hog Bayou Energy Center		237	MW	Mobile, AL
	Santa Rosa Energy Center		225	MW	Pace, FL
	Columbia Energy Center(1)		606	MW	Calhoun County, SC
	Total		3,498	MW
	___________
	-1	Indicates combined-cycle cogeneration power plant.
	Sale of Riverside Energy Center
	Our 603 MW Riverside Energy Center had a PPA that provided WP&L an option to purchase the power plant and plant-related assets upon written notice of exercise prior to May 31, 2012. On May 18, 2012, WP&L exercised their option to purchase Riverside Energy Center, LLC, one of our VIEs which owned Riverside Energy Center. The sale closed on December 31, 2012 for approximately $402 million, and we recorded a pre-tax gain of approximately $7 million, which is included in (gain) on sale of assets, net on our Consolidated Statements of Operations. We used the sale proceeds for our capital allocation activities and for general corporate purposes. The sale of Riverside Energy Center did not meet the criteria for treatment as discontinued operations.
	Sale of Broad River
	On December 27, 2012, we, through our indirect, wholly-owned subsidiary Calpine Power Company, completed the sale of 100% of our ownership interest in each of the Broad River Entities for approximately $423 million. This transaction resulted in the disposition of our Broad River power plant, an 847 MW natural gas-fired, peaking power plant located in Gaffney, South Carolina, and includes a five-year consulting agreement with the buyer. We recorded a pre-tax gain of approximately $215 million in December 2012, which is included in (gain) on sale of assets, net on our Consolidated Statements of Operations. We used the sale proceeds for our capital allocation activities and for general corporate purposes. The sale of the Broad River Entities did not meet the criteria for treatment as discontinued operations.

Property_Plant_and_Equipment_N

Property, Plant and Equipment, Net	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment, Net [Abstract]
Property, Plant and Equipment, Net	Property, Plant and Equipment, Net
	As of December 31, 2014 and 2013, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
		2014		2013		Depreciable Lives
	Buildings, machinery and equipment	$	16,059	$	15,838	3 – 47 Years
	Geothermal properties	1,294		1,265		13 – 59 Years
	Other	203		164		3 – 47 Years
		17,556		17,267
	Less: Accumulated depreciation	4,984		4,897
		12,572		12,370
	Land	120		103
	Construction in progress	498		522
	Property, plant and equipment, net	$	13,190	$	12,995
	We have various debt instruments that are collateralized by our property, plant and equipment. See Note 6 for a discussion of such instruments.
	Buildings, Machinery and Equipment
	This component primarily includes power plants and related equipment. Included in buildings, machinery and equipment are assets under capital leases. See Note 6 for further information regarding these assets under capital leases.
	Geothermal Properties
	This component primarily includes power plants and related equipment associated with our Geysers Assets.
	Other
	This component primarily includes software and emission reduction credits that are power plant specific and not available to be sold.
	Capitalized Interest
	The total amount of interest capitalized was $19 million, $38 million and $38 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Variable_Interest_Entities_and

Variable Interest Entities and Unconsolidated Investments	12 Months Ended
	Dec. 31, 2014
Variable Interest Entities and Unconsolidated Investments [Abstract]
Variable Interest Entities and Unconsolidated Investments	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 year ended December 31, 2014. We have the following types of VIEs consolidated in our financial statements:
	Subsidiaries with Project Debt — All of our subsidiaries with project debt not guaranteed by Calpine have PPAs that provide financial support and are thus considered VIEs. We retain ownership and absorb the full risk of loss and potential for reward once the project debt is paid in full. Actions by the lender to assume control of collateral can occur only under limited circumstances such as upon the occurrence of an event of default, which we have determined to be unlikely. See Note 6 for further information regarding our project debt and Note 2 for information regarding our restricted cash balances.
	Subsidiaries with PPAs — Certain of our majority owned subsidiaries have PPAs that limit the risk and reward of our ownership and thus constitute a VIE.
	VIE with a Purchase Option — OMEC has an agreement that provides a third party a fixed price option to purchase power plant assets exercisable in the year 2019. This purchase option limits the risk and reward of our ownership and, thus, constitutes a VIE.
	Consolidation of VIEs
	We consolidate our VIEs where we determine that we have both the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE. We have determined that we hold the obligation to absorb losses and receive benefits in all of our VIEs where we hold the majority equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following primary activities which we believe to have a significant impact on a power plant’s financial performance: operations and maintenance, plant dispatch, and fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our majority-owned VIEs.
	Under our consolidation policy and under U.S. GAAP we also:
	•	perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and
	•	evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE’s economic performance or when there are other changes in the powers held by individual variable interest holders.
	Noncontrolling Interest — We own a 75% interest in Russell City Energy Company, LLC, one of our VIEs, which is also 25% owned by a third party. We fully consolidate this entity in our Consolidated Financial Statements and account for the third party ownership interest as a noncontrolling interest.
	VIE Disclosures
	Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 10,365 MW and 9,427 MW, at December 31, 2014 and 2013, 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 $47 million, nil and $20 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	U.S. GAAP requires separate disclosure on the face of our Consolidated Balance Sheets of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In determining which assets of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where Calpine Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), and where our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation and where the amounts were material to our financial statements.
	Unconsolidated VIEs and Investments in Power Plants
	We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are also VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. 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 Balance Sheets. At December 31, 2014 and 2013, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):
		Ownership Interest as of December 31, 2014		2014				2013
	Greenfield LP	50%		$	78			$	76
	Whitby	50%		17				17
	Total investments in power plants			$	95			$	93
	Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Balance Sheets. At December 31, 2014 and 2013, equity method investee debt was approximately $342 million and $395 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $171 million and $198 million at December 31, 2014 and 2013, respectively.
	Our equity interest in the net income from Greenfield LP and Whitby for the years ended December 31, 2014, 2013 and 2012, is recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our (income) from unconsolidated investments in power plants and distributions for the years indicated (in millions):
		(Income) from Unconsolidated											Distributions
		Investments in Power Plants
		2014				2013				2012			2014		2013		2012
	Greenfield LP	$	(10	)		$	(16	)		$	(17	)	$	—	$	18	$	22
	Whitby	(15		)		(14		)		(11		)	13		9		7
	Total	$	(25	)		$	(30	)		$	(28	)	$	13	$	27	$	29
	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 years ended December 31, 2013 and 2012, based upon the relationship of our equity income from our investment in these subsidiaries, when combined, to our consolidated net income before taxes. Aggregated summarized financial data for our unconsolidated subsidiaries is set forth below (in millions):
	Condensed Combined Balance Sheets
	of Our Unconsolidated Subsidiaries
	December 31, 2014 and 2013
		2014				2013
	Assets:
	Cash and cash equivalents	$	58			$	57
	Current assets	28				25
	Property, plant and equipment, net	532				588
	Other assets	2				2
	Total assets	$	620			$	672
	Liabilities:
	Current maturities of long-term debt	$	21			$	23
	Current liabilities	28				44
	Long-term debt	321				372
	Long-term derivative liabilities	51				35
	Total liabilities	421				474
	Member's interest	199				198
	Total liabilities and member's interest	$	620			$	672
	Condensed Combined Statements of Operations
	of Our Unconsolidated Subsidiaries
	For the Years Ended December 31, 2014, 2013 and 2012
		2014				2013				2012
	Revenues	$	239			$	207			$	247
	Operating expenses	168				128				171
	Income from operations	71				79				76
	Interest expense, net of interest income	23				24				27
	Other (income) expense, net	—				(3		)		(2		)
	Net income	$	48			$	58			$	51

Debt

Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt	Debt
	Our debt at December 31, 2014 and 2013, was as follows (in millions):
		2014		2013
	First Lien Notes	$	2,075	$	4,989
	Senior Unsecured Notes	2,800		—
	First Lien Term Loans	2,799		2,828
	Project financing, notes payable and other	1,810		1,901
	CCFC Term Loans	1,596		1,191
	Capital lease obligations	202		203
	Subtotal	11,282		11,112
	Less: Current maturities	199		204
	Total long-term debt	$	11,083	$	10,908
	Our debt agreements contain covenants which could permit lenders to accelerate the repayment of our debt by providing notice, the lapse of time, or both, if certain events of default remain uncured after any applicable grace period. We were in compliance with all of the covenants in our debt agreements at December 31, 2014.
	Annual Debt Maturities
	Contractual annual principal repayments or maturities of debt instruments as of December 31, 2014, are as follows (in millions):
	2015	$	199
	2016	205
	2017	562
	2018	1,730
	2019	1,217
	Thereafter	7,393
	Subtotal	11,306
	Less: Discount	24
	Total debt	$	11,282
	First Lien Notes
	Our First Lien Notes are summarized in the table below (in millions, except for interest rates):
		Outstanding at December 31,				Weighted Average
						Effective Interest Rates(3)
		2014		2013		2014		2013
	2019 First Lien Notes(1)	$	—	$	320	—	%	8.2	%
	2020 First Lien Notes(1)	—		875		—		8.2
	2021 First Lien Notes(1)	—		1,600		—		7.7
	2022 First Lien Notes	745		744		6.3		6.2
	2023 First Lien Notes(2)	840		960		8		8
	2024 First Lien Notes	490		490		6		5.9
	Total First Lien Notes	$	2,075	$	4,989
	____________
	-1	The 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes were repaid during the third quarter of 2014 with the proceeds from the issuance of our Senior Unsecured Notes, together with cash on hand, which are described in further detail below.
	-2	In December 2014, we used cash on hand to redeem 10% of the original aggregate principal amount of our 2023 First Lien Notes, plus accrued and unpaid interest. On February 3, 2015, we additionally repurchased approximately $150 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, which is described in further detail below.
	-3	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
	Our First Lien Notes are secured equally and ratably with indebtedness incurred under our First Lien Term Loans and Corporate Revolving Facility, subject to certain exceptions and permitted liens, on substantially all of our and certain of the guarantors’ existing and future assets. Additionally, our First Lien Notes rank equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee our First Lien Notes.
	Subject to certain qualifications and exceptions, our First Lien Notes will, among other things, limit our ability and the ability of the guarantors to:
	•	incur or guarantee additional first lien indebtedness;
	•	enter into certain types of commodity hedge agreements that can be secured by first lien collateral;
	•	enter into sale and leaseback transactions;
	•	create or incur liens; and
	•	consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries on a combined basis.
	Senior Unsecured Notes
	Our Senior Unsecured Notes are summarized in the table below (in millions, except for interest rates):
		Outstanding at December 31,				Weighted Average
						Effective Interest Rates(1)
		2014		2013		2014		2013
	2023 Senior Unsecured Notes	$	1,250	$	—	5.6	%	—	%
	2025 Senior Unsecured Notes	1,550		—		5.9		—
	Total Senior Unsecured Notes	$	2,800	$	—
	____________
	-1	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
	On July 22, 2014, we issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering. The 2023 Senior Unsecured Notes bear interest at 5.375% per annum and the 2025 Senior Unsecured Notes bear interest at 5.75% per annum, in each case payable semi-annually on April 15 and October 15 of each year, beginning on April 15, 2015. The 2023 Senior Unsecured Notes mature on January 15, 2023 and the 2025 Senior Unsecured Notes mature on January 15, 2025. Our Senior Unsecured Notes were issued at par.
	Our Senior Unsecured Notes are:
	•	general unsecured obligations of Calpine;
	•	rank equally in right of payment with all of Calpine’s existing and future senior indebtedness;
	•	effectively subordinated to Calpine’s secured indebtedness to the extent of the value of the collateral securing such indebtedness;
	•	structurally subordinated to any existing and future indebtedness and other liabilities of Calpine’s subsidiaries; and
	•	senior in right of payment to any of Calpine’s subordinated indebtedness.
We used the net proceeds received from the issuance of our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes, together with cash on hand, to repurchase our outstanding 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes during the third quarter of 2014. We recorded approximately $42 million in deferred financing costs and approximately $340 million in debt extinguishment costs during the third quarter of 2014 related to the repayment of our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes.
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 covenant, 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 and to repurchase approximately $150 million of our 2023 First Lien Notes.
First Lien Term Loans
Our First Lien Term Loans are summarized in the table below (in millions, except for interest rates):
	Outstanding at December 31,				Weighted Average
					Effective Interest Rates(1)
	2014		2013		2014		2013
2018 First Lien Term Loans	$	1,597	$	1,614	4.3	%	4.3	%
2019 First Lien Term Loan	816		824		4.4		4.5
2020 First Lien Term Loan	386		390		4.3		4.3
Total First Lien Term Loans	$	2,799	$	2,828
____________
-1	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
Our First Lien Term Loans provide for senior secured term loan facilities and bear interest, at our option, at either (i) the base rate, equal to the higher of the Federal Funds effective rate plus 0.5% per annum or the Prime Rate (as such terms are defined in the First Lien Term Loans credit agreements), plus an applicable margin of 2.0%, or (ii) LIBOR plus 3.0% per annum subject to a LIBOR floor of 1.0%. An aggregate amount equal to 0.25% of the aggregate principal amount of the First Lien Term Loans will be payable at the end of each quarter with the remaining balance payable on the maturity date. The First Lien Term Loans are subject to certain qualifications and exceptions, similar to our First Lien Notes. The 2018 First Lien Term Loans have a maturity date of April 1, 2018. The 2019 First Lien Term Loan and 2020 First Lien Term Loan carries substantially the same terms as the 2018 First Lien Term Loans and matures on October 9, 2019 and October 31, 2020, respectively.
Project Financing, Notes Payable and Other
The components of our project financing, notes payable and other are (in millions, except for interest rates):
	Outstanding at				Weighted Average
	December 31,				Effective Interest Rates(1)
	2014		2013		2014		2013
Russell City due 2023	$	591	$	593	6.2	%	4.9	%
Steamboat due 2017	407		418		6.9		6.8
OMEC due 2019	325		335		6.9		6.9
Los Esteros due 2023	275		305		3.1		3.4
Pasadena(2)	122		135		8.9		8.9
Bethpage Energy Center 3 due 2020-2025(3)	82		88		7		7
Gilroy note payable due 2014	—		15		—		11.2
Other	8		12		—		—
Total	$	1,810	$	1,901
_____________
-1	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount or premium.
-2	Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.
-3	Represents a weighted average of first and second lien loans for the weighted average effective interest rates.
Our project financings are collateralized solely by the capital stock or partnership interests, physical assets, contracts and/or cash flows attributable to the entities that own the power plants. The lenders’ recourse under these project financings is limited to such collateral.
CCFC Term Loans
Our CCFC Term Loans are summarized in the table below (in millions, except for interest rates):
	Outstanding at December 31,				Weighted Average
					Effective Interest Rates(1)
	2014		2013		2014		2013
CCFC Term Loans	$	1,596	$	1,191	3.4	%	3.3	%
____________
-1	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
On May 3, 2013, CCFC entered into a credit agreement providing for a first lien senior secured term loan facility comprised of (i) a $900 million 7-year term loan and (ii) a $300 million 8.5-year term loan. The CCFC Term Loans bear interest, at CCFC’s option, at either (i) the Base Rate, equal to the higher of the Federal Funds Effective Rate plus 0.50% per annum or the Prime Rate (as such terms are defined in the Credit Agreement), plus an applicable margin of (a) 1.25% per annum with respect to the 7-year term loan and (b) 1.50% per annum with respect to the 8.5-year term loan, or (ii) LIBOR plus (a) 2.25% per annum with respect to the 7-year term loan and (b) 2.50% per annum with respect to the 8.5-year term loan (in each case subject to a LIBOR floor of 0.75%). The term loans were offered to investors at an issue price equal to 99.75% of face value.
An amount equal to 0.25% of the aggregate principal amount of the CCFC Term Loans are payable at the end of each quarter commencing in September 2013, with the remaining balance payable on the relevant maturity date (May 3, 2020 with respect to the 7-year term loan and January 31, 2022 with respect to the 8.5-year term loan). CCFC may elect from time to time to convert all or a portion of the CCFC Term Loans from LIBOR loans to Base Rate loans or vice versa. In addition, CCFC may at any time, and from time to time, prepay the term loans, in whole or in part, without premium or penalty, upon irrevocable notice to the administrative agent.
In February 2014, we executed an amendment to the credit agreement associated with the CCFC Term Loans, which allowed us to issue $425 million in incremental CCFC Term Loans to fund a portion of the purchase price paid in connection with the closing of our acquisition of Guadalupe Energy Center on February 26, 2014. Guadalupe Energy Center was purchased by Calpine Guadalupe GP, LLC, a wholly-owned subsidiary of CCFC. The incremental term loans carry substantially the same terms and conditions as the $300 million in aggregate principal amount of CCFC Term Loans issued in June 2013. The incremental term loans were offered to investors at an issue price equal to 98.75% of face value.
The CCFC Term Loans are secured by certain real and personal property of CCFC consisting primarily of seven natural gas-fired power plants. The CCFC Term Loans are not guaranteed by Calpine Corporation and are without recourse to Calpine Corporation or any of our non-CCFC subsidiaries or assets; however, CCFC generates the majority of its cash flows from an intercompany tolling agreement with Calpine Energy Services, L.P. and has various service agreements in place with other subsidiaries of Calpine Corporation.
Capital Lease Obligations
The following is a schedule by year of future minimum lease payments under capital leases and a failed sale-leaseback transaction related to our Pasadena Power Plant together with the present value of the net minimum lease payments as of December 31, 2014 (in millions):
	Sale-Leaseback Transactions(1)		Capital Lease		Total
2015	$	25	$	47	$	72
2016	25		41		66
2017	17		39		56
2018	21		38		59
2019	21		20		41
Thereafter	85		151		236
Total minimum lease payments	194		336		530
Less: Amount representing interest	72		134		206
Present value of net minimum lease payments	$	122	$	202	$	324
____________
-1	Amounts are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes payable and other amounts above.
The primary types of property leased by us are power plants and related equipment. The leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. The remaining lease terms range up to 34 years (including lease renewal options). Some of the lease agreements contain customary restrictions on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project financing agreements. At December 31, 2014 and 2013, the asset balances for the leased assets totaled approximately $933 million and $862 million with accumulated amortization of $395 million and $343 million, respectively. Amortization of assets under capital leases is recorded in depreciation and amortization expense on our Consolidated Statements of Operations. See Note 15 for discussion of capital leases guaranteed by Calpine Corporation.
Corporate Revolving Facility and Other Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at December 31, 2014 and 2013 (in millions):
	2014		2013
Corporate Revolving Facility	$	223	$	242
CDHI	214		218
Various project financing facilities	207		170
Total	$	644	$	630
On July 30, 2014, we executed Amendment No. 2 to the Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.
The Corporate Revolving Facility represents our primary revolving facility. Borrowings under the Corporate Revolving Facility bear interest, at our option, at either a base rate or LIBOR rate. Base rate borrowings shall be at the base rate, plus an applicable margin ranging from 1.00% to 1.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is defined as the higher of (i) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50% and (ii) the rate the administrative agent announces from time to time as its prime per annum rate. LIBOR rate borrowings shall be at the British Bankers’ Association Interest Settlement Rates for the interest period as selected by us as a one, two, three, six or, if agreed by all relevant lenders, nine or twelve month interest period, plus an applicable margin ranging from 2.00% to 2.25%. Interest payments are due on the last business day of each calendar quarter for base rate loans and the earlier of (i) the last day of the interest period selected or (ii) each day that is three months (or a whole multiple thereof) after the first day for the interest period selected for LIBOR rate loans. Letter of credit fees for issuances of letters of credit include fronting fees equal to that percentage per annum as may be separately agreed upon between us and the issuing lenders and a participation fee for the lenders equal to the applicable interest margin for LIBOR rate borrowings. Drawings under letters of credit shall be repaid within two business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We incur an unused commitment fee ranging from 0.25% to 0.50% on the unused amount of commitments under the Corporate Revolving Facility.
The Corporate Revolving Facility does not contain any requirements for mandatory prepayments, except in the case of certain designated asset sales in excess of $3.0 billion in the aggregate. However, we may voluntarily repay, in whole or in part, the Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be reborrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility without premium or penalty. The Corporate Revolving Facility matures on June 27, 2018.
The Corporate Revolving Facility is guaranteed and secured by each of our current domestic subsidiaries that was a guarantor under the First Lien Credit Facility and will also be additionally guaranteed by our future domestic subsidiaries that are required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving Facility ranks equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a minimum cash interest coverage ratio and a maximum net leverage ratio.
CDHI
We have a $300 million letter of credit facility related to CDHI. During the first quarter of 2014, we amended our CDHI letter of credit facility to lower our fees and extend the maturity to January 2, 2018.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount. We did not elect to apply the alternative U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. The following table details the fair values and carrying values of our debt instruments at December 31, 2014 and 2013 (in millions):
	2014				2013
	Fair Value		Carrying		Fair Value			Carrying
			Value					Value
First Lien Notes	$	2,247	$	2,075	$	5,317		$	4,989
Senior Unsecured Notes	2,832		2,800		—			—
First Lien Term Loans	2,769		2,799		2,845			2,828
Project financing, notes payable and other(1)	1,734		1,688		1,772			1,766
CCFC Term Loans	1,540		1,596		1,179			1,191
Total	$	11,122	$	10,958	$	11,113		$	10,774
____________
-1	Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
We measure the fair value of our First Lien Notes, Senior Unsecured Notes, First Lien Term Loans 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_Re

Assets and Liabilities with Recurring Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
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 Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Our cash equivalents are classified within level 1 of the fair value hierarchy.
	Margin Deposits and Margin Deposits Posted with Us by Our Counterparties — Margin deposits and margin deposits posted with us by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits posted with us by our counterparties are generally cash and cash equivalents and are classified within level 1 of the fair value hierarchy.
	Derivatives — The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate swaps. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future.
	We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs.
	The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and the impact of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.
	Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange.
	Our level 2 fair value derivative instruments primarily consist of interest rate swaps and OTC power and natural gas forwards for which market-based pricing inputs are observable. Generally, we obtain our level 2 pricing inputs from market sources such as the Intercontinental Exchange and Bloomberg. To the extent we obtain prices from brokers in the marketplace, we have procedures in place to ensure that prices represent executable prices for market participants. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
	Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions. Complex or structured transactions are tailored to our or our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. OTC options are valued using industry-standard models, including the Black-Scholes option-pricing model. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs.
	Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013, by level within the fair value hierarchy:
		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
		Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2013
		Level 1			Level 2				Level 3			Total
		(in millions)
	Assets:
	Cash equivalents(1)	$	1,134		$	—			$	—		$	1,134
	Margin deposits	261			—				—			261
	Commodity instruments:
	Commodity exchange traded futures and swaps contracts	434			—				—			434
	Commodity forward contracts(2)	—			75				32			107
	Interest rate swaps	—			9				—			9
	Total assets	$	1,829		$	84			$	32		$	1,945
	Liabilities:
	Margin deposits posted with us by our counterparties	$	5		$	—			$	—		$	5
	Commodity instruments:
	Commodity exchange traded futures and swaps contracts	495			—				—			495
	Commodity forward contracts(2)	—			52				18			70
	Interest rate swaps	—			129				—			129
	Total liabilities	$	500		$	181			$	18		$	699
	___________
	-1	As of December 31, 2014 and 2013, we had cash equivalents of $679 million and $889 million included in cash and cash equivalents and $217 million and $245 million included in restricted cash, respectively.
	-2	Includes OTC swaps and options.
	At December 31, 2014 and 2013, 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; however, given the nature of our net derivative position, we do not believe that a significant change in market commodity prices would have a material impact on our level 3 net fair value. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at December 31, 2014 and 2013:
			Quantitative Information about Level 3 Fair Value Measurements
			31-Dec-14
			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
			Quantitative Information about Level 3 Fair Value Measurements
			31-Dec-13
			Fair Value, Net Asset					Significant Unobservable
			(Liability)			Valuation Technique		Input		Range
			(in millions)
	Power Contracts		$	7		Discounted cash flow		Market price (per MWh)		$28.92 — $53.15/MWh
Power Congestion Products		$	7		Discounted cash flow		Market price (per MWh)		$(8.79) — $11.53/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 years ended December 31, 2014, 2013 and 2012 (in millions):
	2014			2013				2012
Balance, beginning of period	$	14		$	16			$	17
Realized and mark-to-market gains:
Included in net income:
Included in operating revenues(1)	70			5				8
Included in fuel and purchased energy expense(2)	5			—				—
Purchases, issuances and settlements:
Purchases	6			6				3
Issuances	—			(2		)		(1		)
Settlements	(10		)	(11		)		(11		)
Transfers in and/or out of level 3(3):
Transfers into level 3(4)	—			—				—
Transfers out of level 3(5)	—			—				—
Balance, end of period	$	85		$	14			$	16
Change in unrealized gains relating to instruments still held at end of period	$	75		$	5			$	8
___________
-1	For power contracts and other power-related products, included on our Consolidated Statements of Operations.
-2	For natural gas contracts, swaps and options, included on our Consolidated 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 during the years ended December 31, 2014, 2013 and 2012.
-4	There were no transfers out of level 2 into level 3 for the years ended December 31, 2014, 2013 and 2012.
-5	There were no transfers out of level 3 for the years ended December 31, 2014, 2013 and 2012.

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2014
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, as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management, related to our commodity derivative portfolio which exposes us to certain market risks that are segregated from the market risks of our underlying asset portfolio. 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 years ended December 31, 2014, 2013 and 2012.
	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 December 31, 2014, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 9 years.
	As of December 31, 2014 and 2013, 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
			2014				2013
	Power (MWh)		(62		)		(29		)
	Natural gas (MMBtu)		291				448
	Interest rate swaps		$	1,431			$	1,527
	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 December 31, 2014, was $19 million for which we have posted collateral of $11 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 $5 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 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 (in the case of settlements for our interest rate swaps formerly hedging our First Lien Credit Facility term loans) on our Consolidated Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
	Cash Flow Hedges — We report the effective portion of the mark-to-market gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense (for interest rate swaps except as discussed below). If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction impacts earnings or until it is determined that the forecasted transaction is probable of not occurring.
	Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, 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 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 (for interest rate swaps except as discussed below).
	Interest Rate Swaps Formerly Hedging our First Lien Credit Facility — On March 26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and recorded the fair value of the swaps totaling approximately $156 million. Approximately $14 million of the settlement amount was recorded as a component of loss on interest rate derivatives on our Consolidated Statement of Operations for the year ended December 31, 2012, and approximately $142 million reflected the realization of losses recorded in prior periods.
	Derivatives Included on Our Consolidated Balance Sheet
	The following tables present the fair values of our derivative instruments recorded on our Consolidated Balance Sheets by location and hedge type at December 31, 2014 and 2013 (in millions):
		31-Dec-14
		Commodity				Interest Rate				Total
		Instruments				Swaps				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 assets (liabilities)	$	381			$	(110	)		$	271
		31-Dec-13
		Commodity				Interest Rate				Total
		Instruments				Swaps				Derivative
										Instruments
	Balance Sheet Presentation
	Current derivative assets	$	445			$	—			$	445
	Long-term derivative assets	96				9				105
	Total derivative assets	$	541			$	9			$	550
	Current derivative liabilities	$	404			$	47			$	451
	Long-term derivative liabilities	161				82				243
	Total derivative liabilities	$	565			$	129			$	694
	Net derivative assets (liabilities)	$	(24	)		$	(120	)		$	(144	)
		December 31, 2014								December 31, 2013
		Fair Value				Fair Value				Fair Value				Fair Value
		of Derivative				of Derivative				of Derivative				of Derivative
		Assets				Liabilities				Assets				Liabilities
	Derivatives designated as cash flow hedging instruments:
	Interest rate swaps	$	4			$	112			$	9			$	115
	Total derivatives designated as cash flow hedging instruments	$	4			$	112			$	9			$	115
	Derivatives not designated as hedging instruments:
	Commodity instruments	$	2,493			$	2,112			$	541			$	565
	Interest rate swaps	—				2				—				14
	Total derivatives not designated as hedging instruments	$	2,493			$	2,114			$	541			$	579
	Total derivatives	$	2,497			$	2,226			$	550			$	694
	We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated 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 December 31, 2014 and 2013 (in millions):
			31-Dec-14
			Gross Amounts Not Offset on the Consolidated Balance Sheets
			Gross Amounts Presented on our Consolidated Balance Sheets				Derivative Asset (Liability) not Offset on the Consolidated 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
		31-Dec-13
		Gross Amounts Not Offset on the Consolidated Balance Sheets
		Gross Amounts Presented on our Consolidated Balance Sheets				Derivative Asset (Liability) not Offset on the Consolidated Balance Sheets				Margin/Cash (Received) Posted (1)				Net Amount
Derivative assets:
Commodity exchange traded futures and swaps contracts		$	434			$	(420	)		$	(14	)		$	—
Commodity forward contracts		107				(60		)		—				47
Interest rate swaps		9				—				—				9
Total derivative assets		$	550			$	(480	)		$	(14	)		$	56
Derivative (liabilities):
Commodity exchange traded futures and swaps contracts		$	(495	)		$	420			$	75			$	—
Commodity forward contracts		(70		)		60				1				(9		)
Interest rate swaps		(129		)		—				—				(129		)
Total derivative (liabilities)		$	(694	)		$	480			$	76			$	(138	)
Net derivative assets (liabilities)		$	(144	)		$	—			$	62			$	(82	)
____________
-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 9 for a further discussion of our collateral.
Derivatives Included on Our Consolidated 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 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 Statements of Operations for the years ended December 31, 2014, 2013 and 2012 (in millions):
	2014				2013				2012
Realized gain (loss)(1)
Commodity derivative instruments	$	110			$	86			$	387
Interest rate swaps	—				—				(157		)
Total realized gain (loss)	$	110			$	86			$	230
Mark-to-market gain (loss)(2)
Commodity derivative instruments	$	342			$	(14	)		$	(82	)
Interest rate swaps	11				2				154
Total mark-to-market gain (loss)	$	353			$	(12	)		$	72
Total activity, net	$	463			$	74			$	302
___________
-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.
	2014				2013				2012
Realized and mark-to-market gain (loss)
Derivatives contracts included in operating revenues	$	384			$	(119	)		$	187
Derivatives contracts included in fuel and purchased energy expense	68				191				118
Interest rate swaps included in interest expense	11				2				11
Loss on interest rate derivatives	—				—				(14		)
Total activity, net	$	463			$	74			$	302
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 years ended December 31, 2014, 2013 and 2012 (in millions):
	Gains (Loss) Recognized  in												Gain (Loss) Reclassified  from
	OCI (Effective Portion)(3)												AOCI into Income (Effective
													Portion)(4)
	2014				2013				2012				2014				2013				2012			Affected Line Item on the Consolidated Statements of Operations
Commodity derivative instruments(1):
Power derivative instruments	$	—			$	—			$	(97	)		$	—			$	—			$	118		Commodity revenue
Natural gas derivative instruments	—				—				59				—				—				(66		)	Commodity expense
Interest rate swaps(2)	(2		)		86				(43		)		(46		)	(5)	(51		)	(5)	(32		)	Interest expense
Total(3)	$	(2	)		$	86			$	(81	)		$	(46	)		$	(51	)		$	20
____________
-1	There were no commodity derivative instruments designated as cash flow hedges during the year ended December 31, 2014 and 2013. We recorded a gain on hedge ineffectiveness of $2 million related to our commodity derivative instruments designated as cash flow hedges during the year ended December 31, 2012.
-2	We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the years ended December 31, 2014, 2013 and 2012.
-3	We recorded income tax expense of nil and $3 million for the years ended December 31, 2014 and 2013, respectively, and an income tax benefit of $11 million for the year ended December 31, 2012, in AOCI related to our cash flow hedging activities.
-4	Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $149 million, $148 million and $222 million at December 31, 2014, 2013 and 2012, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $12 million, $11 million and $20 million at December 31, 2014, 2013 and 2012, respectively.
-5	Includes a loss of $10 million and $12 million that was reclassified from AOCI to interest expense for the years ended December 31, 2014 and 2013, respectively, 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	12 Months Ended
	Dec. 31, 2014
Use of Collateral [Abstract]
Use of Collateral	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 December 31, 2014 and 2013 (in millions):
		2014		2013
	Margin deposits(1)	$	96	$	261
	Natural gas and power prepayments	22		28
	Total margin deposits and natural gas and power prepayments with our counterparties(2)	$	118	$	289
	Letters of credit issued	$	450	$	488
	First priority liens under power and natural gas agreements	48		31
	First priority liens under interest rate swap agreements	116		132
	Total letters of credit and first priority liens with our counterparties	$	614	$	651
	Margin deposits posted with us by our counterparties(1)(3)	$	47	$	5
	Letters of credit posted with us by our counterparties	61		2
	Total margin deposits and letters of credit posted with us by our counterparties	$	108	$	7
	___________
	-1	Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated 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 8 for further discussion of our derivative instruments subject to master netting arrangements.
	-2	At December 31, 2014 and 2013, $109 million and $272 million, respectively, were included in margin deposits and other prepaid expense and $9 million and $17 million, respectively, were included in other assets on our Consolidated Balance Sheets.
	-3	Included in other current liabilities on our Consolidated 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	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes
	Income Tax Expense
	The jurisdictional components of income from continuing operations before income tax expense, attributable to Calpine, for the years ended December 31, 2014, 2013 and 2012, are as follows (in millions):
		2014				2013				2012
	U.S.	$	942			$	(13	)		$	194
	International	26				29				24
	Total	$	968			$	16			$	218
	The components of income tax expense from continuing operations for the years ended December 31, 2014, 2013 and 2012, consisted of the following (in millions):
		2014				2013				2012
	Current:
	Federal	$	(1	)		$	(2	)		$	(12	)
	State	19				(9		)		16
	Foreign	(1		)		(1		)		14
	Total current	17				(12		)		18
	Deferred:
	Federal	—				1				11
	State	(1		)		4				(5		)
	Foreign	6				9				(5		)
	Total deferred	5				14				1
	Total income tax expense	$	22			$	2			$	19
	For the years ended December 31, 2014, 2013 and 2012, our income tax rates did not bear a customary relationship to statutory income tax rates, primarily as a result of the impact of our valuation allowance, state income taxes and changes in unrecognized tax benefits. A reconciliation of the federal statutory rate of 35% to our effective rate from continuing operations for the years ended December 31, 2014, 2013 and 2012, is as follows:
		2014			2013			2012
	Federal statutory tax expense (benefit) rate	35	%		35	%		35	%
	State tax expense (benefit), net of federal benefit	1.9			(69.8	)		3.2
	Depletion in excess of basis	(0.3	)		(14.7	)		(0.2	)
	Federal refunds	—			—			(4.7	)
	Valuation allowances against future tax benefits	(35.8	)		89.8			(30.3	)
	Valuation allowance related to foreign taxes	—			(19.8	)		(8.2	)
	Distributions from foreign affiliates and foreign taxes	1.2			(10.8	)		3.7
	Intraperiod allocation	—			4.5			4.6
	Change in unrecognized tax benefits	(0.4	)		(30.1	)		5.1
	Disallowed compensation	0.1			11.7			0.4
	Stock-based compensation	0.1			8.6			0.2
	Lobbying contributions	0.1			3.3			0.3
	Other differences	0.4			4.8			(0.4	)
	Effective income tax expense rate	2.3	%		12.5	%		8.7	%
	Deferred Tax Assets and Liabilities
	The components of deferred income taxes as of December 31, 2014 and 2013, are as follows (in millions):
		2014				2013
	Deferred tax assets:
	NOL and credit carryforwards	$	2,873			$	3,120
	Taxes related to risk management activities and derivatives	61				60
	Reorganization items and impairments	216				262
	Foreign capital losses	16				18
	Other differences	—				104
	Deferred tax assets before valuation allowance	3,166				3,564
	Valuation allowance	(1,836		)		(2,246		)
	Total deferred tax assets	1,330				1,318
	Deferred tax liabilities:
	Property, plant and equipment	(1,305		)		(1,310		)
	Other differences	(21		)		—
	Total deferred tax liabilities	(1,326		)		(1,310		)
	Net deferred tax asset	4				8
	Less: Current portion deferred tax asset (liability)	(14		)		12
	Less: Non-current deferred tax asset	19				7
	Deferred income tax liability, non-current	$	(1	)		$	(11	)
	Intraperiod Tax Allocation — In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of a tax expense (benefit) to continuing operations due to current OCI gains (losses) with a partial offsetting amount recognized in OCI. The following table details the effects of our intraperiod tax allocations for the years ended December 31, 2014, 2013 and 2012 (in millions).
		2014				2013				2012
	Intraperiod tax allocation expense included in continuing operations	$	—			$	1			$	9
	Intraperiod tax allocation benefit included in OCI	$	—			$	(1	)		$	(9	)
	NOL Carryforwards — As of December 31, 2014, our NOL carryforwards consisted primarily of federal NOL carryforwards of approximately $6.9 billion, which expire between 2023 and 2033, and NOL carryforwards in 22 states and the District of Columbia totaling approximately $4.0 billion, which expire between 2015 and 2034, substantially all of which are offset with a full valuation allowance. We also have approximately $800 million in foreign NOLs, which expire between 2026 and 2034, substantially all of which are offset with a full valuation allowance. The NOL carryforwards available are subject to limitations on their annual usage. Under federal and applicable state income tax laws, a corporation is generally permitted to deduct from taxable income in any year NOLs carried forward from prior years subject to certain time limitations as prescribed by the taxing authorities.
	Deferred tax assets relating to tax benefits of employee stock-based compensation do not reflect stock options exercised and restricted stock that vested between 2011 and 2014. Some stock option exercises and restricted stock vestings result in tax deductions in excess of previously recorded deferred tax benefits based on the equity award value at the grant date. Although these additional tax benefits or “windfalls” are reflected in NOL carryforwards pursuant to accounting for stock-based compensation under U.S. GAAP, the additional tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable, which will not occur for Calpine until a future period. Accordingly, since the tax benefit does not reduce our current taxes payable for the years ended December 31, 2014 and 2013 due to NOL carryforwards, these windfall tax benefits are not reflected in our NOLs in deferred tax assets at December 31, 2014 and 2013. The cumulative windfall balance included in federal and state NOL carryforwards, but not reflected in gross deferred tax assets as of December 31, 2014 and 2013 were $37 million and $25 million for federal, respectively, and $21 million and $16 million for state, respectively.
	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.
	Canadian Tax Audits — In January 2013, we received an adjusted reassessment on one of two transfer pricing issues that we were disputing with the Canadian Revenue Authority (“CRA”). We proposed a settlement of the adjusted reassessment with the CRA and the CRA accepted our proposal. The adjustment to our transfer pricing increased taxable income and was offset by existing NOLs to which a valuation allowance had been applied and did not have a material impact on our Consolidated Financial Statements.
On January 28, 2014, we received a letter from the CRA which informed us that they did not agree with our transfer price on the second issue and proposed an increase to taxable income for tax years 2006 and 2007. On June 6, 2014, we proposed a settlement, and on June 14, 2014, the CRA accepted our proposal. The adjustment to our transfer price increased taxable income for one of our Canadian affiliates and was offset by existing NOLs to which a valuation allowance had been applied. As part of the settlement, we agreed to pay some interest and withholding taxes which did not have a material impact on our Consolidated Financial Statements.
Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies.
As of December 31, 2014, we have provided a valuation allowance of approximately $1.8 billion on certain federal, state and foreign tax jurisdiction deferred tax assets to reduce the amount of these assets to the extent necessary to result in an amount that is more likely than not to be realized. The net change in our valuation allowance was a decrease of $410 million for the year ended December 31, 2014 and $114 million for the year ended December 31, 2012 and an increase of $24 million for the year ended December 31, 2013, respectively; all primarily related to income generated in these periods.
As a result of a recent favorable response to an IRS letter ruling request, during the first quarter of 2014, we made an election which increased the tax basis of certain assets resulting in an increase to our net state deferred tax assets by approximately $18 million with a corresponding decrease in our state income tax expense.
Tangible Property Regulations — On September 13, 2013, the United States Treasury Department and the IRS issued final regulations providing comprehensive guidance on the tax treatment of costs incurred to acquire, repair or improve tangible property. The final regulations are generally effective for taxable years beginning on or after January 1, 2014. On January 24, 2014, the IRS issued procedural guidance pursuant to which taxpayers will be granted automatic consent to change their tax accounting methods to comply with the final regulations. These regulations did not have a material impact on our financial condition, results of operations or cash flows.
Unrecognized Tax Benefits
At December 31, 2014, we had unrecognized tax benefits of $56 million. If recognized, $13 million of our unrecognized tax benefits could impact the annual effective tax rate and $43 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact to our effective tax rate. We had accrued interest and penalties of $11 million and $13 million for income tax matters at December 31, 2014 and 2013, respectively. We recognize interest and penalties related to unrecognized tax benefits in income tax expense on our Consolidated Statements of Operations and recorded $(2) million, $(11) million and $4 million for the years ended December 31, 2014, 2013 and 2012, respectively.
A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2014, 2013 and 2012, is as follows (in millions):
	2014				2013				2012
Balance, beginning of period	$	(68	)		$	(92	)		$	(74	)
Increases related to prior year tax positions	(4		)		(7		)		(19		)
Decreases related to prior year tax positions	8				8				1
Decreases related to settlements	8				10				—
Decrease related to lapse of statute of limitations	—				13				—
Balance, end of period	$	(56	)		$	(68	)		$	(92	)
U.S. Federal Income Tax Refund
In 2004, we deducted a portion of our foreign dividends as allowed by the IRC when we filed our federal income tax return. Upon further review and analysis, we determined our foreign dividends should have been offset against our current 2004 operating loss. In 2009, we filed an amended federal income tax return that reflected this change and would result in a refund of approximately $10 million. This amended federal return has been under audit by the IRS since it was filed. In October 2012, the IRS approved our amended tax return, and we received a refund of approximately $13 million which included approximately $3 million in accrued interest. The benefit of this refund is reflected in our Consolidated Financial Statements in the fourth quarter of 2012.

Earnings_Loss_per_Share

Earnings (Loss) per Share	12 Months Ended
	Dec. 31, 2014
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 years ended December 31, 2014, 2013 and 2012, are as follows (shares in thousands):
		2014	2013	2012
	Diluted weighted average shares calculation:
	Weighted average shares outstanding (basic)	404,837	440,666	467,752
	Share-based awards	4,523	4,107	3,591
	Weighted average shares outstanding (diluted)	409,360	444,773	471,343
	We excluded the following items from diluted earnings per common share for the years ended December 31, 2014, 2013 and 2012, because they were anti-dilutive (shares in thousands):
		2014	2013	2012
	Share-based awards	2,859	5,062	10,302

StockBased_Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2014
Stock-Based Compensation [Abstract]
Stock-Based Compensation	Stock-Based Compensation
	Calpine Equity Incentive Plans
	The Calpine Equity Incentive Plans provide for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. The equity awards may include incentive or non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance compensation awards and other share-based awards. The equity awards granted under the Calpine Equity Incentive Plans include both graded and cliff vesting awards which vest over periods between one and five years, contain contractual terms between approximately five and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. At December 31, 2014, there were 567,000 and 40,533,000 shares of our common stock authorized for issuance to participants under the Director Plan and the Equity Plan, respectively. At December 31, 2014, 186,816 shares and 13,077,526 shares remain available for future issuance under the Director Plan and the Equity Plan, respectively.
	Equity Classified Share-Based Awards
	We use the Black-Scholes option-pricing model or the Monte Carlo simulation model, as appropriate, to estimate the fair value of our employee stock options on the grant date, which takes into account the exercise price and expected term of the stock option, the current price of the underlying stock and its expected volatility, expected dividends on the stock and the risk-free interest rate for the expected term of the stock option as of the grant date. For our restricted stock and restricted stock units, we use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Stock-based compensation expense is recognized over the period in which the related employee services are rendered. The service period is generally presumed to begin on the grant date and end when the equity award is fully vested. We use the graded vesting attribution method to recognize fair value of the equity award over the service period. For example, the graded vesting attribution method views one three-year restricted stock grant with annual graded vesting as three separate sub-grants, each representing 33 1/3% of the total number of shares of restricted stock granted. The first sub-grant vests over one year, the second sub-grant vests over two years and the third sub-grant vests over three years. A three-year restricted stock grant with cliff vesting is viewed as one grant vesting over three years.
	Stock-based compensation expense recognized for our equity classified share-based awards was $31 million, $34 million and $25 million for the years ended December 31, 2014, 2013 and 2012, respectively. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the years ended December 31, 2014, 2013 and 2012. At December 31, 2014, there was unrecognized compensation cost of $26 million related to restricted stock which is expected to be recognized over a weighted average period of 1.1 years. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans and employment inducement options when stock options are exercised and for other share-based awards.
	A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the year ended December 31, 2014, is as follows:
		Number of		Weighted Average			Weighted	Aggregate
		Shares		Exercise Price			Average	Intrinsic Value
							Remaining	(in millions)
							Term
							(in years)
	Outstanding — December 31, 2013	14,114,289		$	18.25		3.1	$	36
	Granted	—		$	—
	Exercised	2,951,947		$	16.2
	Forfeited	69,122		$	15.81
	Expired	6,900		$	17.69
	Outstanding — December 31, 2014	11,086,320		$	18.82		2	$	43
	Exercisable — December 31, 2014	10,336,806		$	19.07		1.7	$	38
	Vested and expected to vest – December 31, 2014	11,076,617		$	18.82		2	$	43
	The total intrinsic value of our employee stock options exercised was $21 million, $22 million and $1 million for the years ended December 31, 2014, 2013 and 2012, respectively. The total cash proceeds received from our employee stock options exercised was $20 million, $20 million and $5 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	There were no stock options granted during the year ended December 31, 2014. The fair value of options granted during the years ended December 31, 2013 and 2012, was determined on the grant date using the Black-Scholes option-pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table.
		2013			2012
	Expected term (in years)(1)	6.5			6.5
	Risk-free interest rate(2)	1.4		%	1.2 – 1.6		%
	Expected volatility(3)	25.6		%	27.0 – 30.5		%
	Dividend yield(4)	—			—
	Weighted average grant-date fair value (per option)	$	5.31		$	5.18
	___________
	-1	Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data to provide a reasonable basis to estimate the expected term.
	-2	Zero Coupon U.S. Treasury rate or equivalent based on expected term.
	-3	Volatility calculated using the implied volatility of our exchange traded stock options.
	-4	We have never paid cash dividends on our common stock, and we do not anticipate any cash dividend payments on our common stock in the near future.
	A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the year ended December 31, 2014, is as follows:
		Number of		Weighted
		Restricted		Average
		Stock Awards		Grant-Date
				Fair Value
	Nonvested — December 31, 2013	4,431,841		$	16.45
	Granted	1,885,049		$	19.34
	Forfeited	430,059		$	17.67
	Vested	1,684,963		$	15.51
	Nonvested — December 31, 2014	4,201,868		$	18.01
	The total fair value of our restricted stock and restricted stock units that vested during the years ended December 31, 2014, 2013 and 2012, was approximately $35 million, $25 million and $20 million, respectively.
	Liability Classified Share-Based Awards
	During the first quarter of 2014, our Board of Directors approved the award of performance share units to certain senior management employees. These performance share units will be settled in cash with payouts based on the relative performance of Calpine’s TSR over the three-year performance period of January 1, 2014 through December 31, 2016 compared with the TSR performance of the S&P 500 companies over the same period. The performance share units vest on the last day of the performance period and will be settled in cash; thus, these awards are liability classified and are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was $5 million and $2 million for the years ended December 31, 2014 and 2013, respectively.
	A summary of our performance share unit activity for the year ended December 31, 2014, is as follows:
		Number of		Weighted
		Performance Share Units		Average
				Grant-Date
				Fair Value
	Nonvested — December 31, 2013	449,798		$	21.25
	Granted	461,393		$	22.56
	Forfeited	28,400		$	21.87
	Vested(1)	15,312		$	21.25
	Nonvested — December 31, 2014	867,479		$	21.93
	___________
	-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.

Defined_Contribution_and_Defin

Defined Contribution and Defined Benefit Plans	12 Months Ended
	Dec. 31, 2014
Defined Contribution and Defined Benefit Plans [Abstract]
Defined Contribution and Defined Benefit Plans	Defined Contribution and Defined Benefit Plans
	We maintain two defined contribution savings plans that are intended to be tax exempt under Sections 401(a) and 501(a) of the IRC. Our non-union plan generally covers employees who are not covered by a collective bargaining agreement, and our union plan covers employees who are covered by a collective bargaining agreement. We recorded expenses for these plans of approximately $12 million, $11 million and $12 million for the years ended December 31, 2014, 2013 and 2012, respectively. Employer matching contributions are 100% of the first 5% of compensation a participant defers for the non-union plan. The employee deferral limit is 75% of eligible compensation under both plans.
	We also maintain a defined benefit pension plan whereby retirement benefits are primarily a function of age attained, years of participation, years of service, vesting and level of compensation. As of December 31, 2014 and 2013, our pension assets, liabilities and related costs were not material to us. As of December 31, 2014 and 2013, there were approximately $15 million and $14 million in plan assets and approximately $24 million and $20 million in pension liabilities, respectively. Our net pension liability recorded on our Consolidated Balance Sheets as of December 31, 2014 and 2013, was approximately $9 million and $6 million, respectively. For the years ended December 31, 2014, 2013 and 2012, we recognized net periodic benefit costs of approximately $1 million, $2 million and $1 million, respectively. Our net periodic benefit cost is included in plant operating expense on our Consolidated Statements of Operations. As of December 31, 2014 and 2013, the total amount recognized in AOCI for actuarial losses related to pension obligation was approximately $5 million and $1 million, respectively.
	In making our estimates of our pension obligation and related costs, we utilize discount rates, rates of compensation increases and rates of return on our assets that we believe are reasonable. Due to relatively small size of our pension liability (which is not considered material), significant changes in these assumptions would not have a material effect on our pension liability. During 2014 and 2013, we made contributions of approximately $2 million and $1 million, respectively, and estimated contributions to the pension plan are expected to be approximately $1 million in 2015. Estimated future benefit payments to participants in each of the next five years are expected to be approximately $1 million in each year.

Capital_Structure

Capital Structure	12 Months Ended
	Dec. 31, 2014
Capital Structure [Abstract]
Capital Structure	Capital Structure
	Common Stock
	Our authorized common stock consists of 1.4 billion shares of Calpine Corporation common stock. Common stock issued as of December 31, 2014 and 2013, was 502,287,022 shares and 497,841,056 shares, respectively, at a par value of $0.001 per share. Common stock outstanding as of December 31, 2014 and 2013, was 381,921,264 shares and 429,038,988 shares, respectively. The table below summarizes our common stock activity for the years ended December 31, 2014, 2013 and 2012.
		Shares	Shares		Shares
		Issued	Held in		Outstanding
			Treasury
	Balance, December 31, 2011	490,468,815	(8,725,077	)	481,743,738
	Shares issued under Calpine Equity Incentive Plans	2,026,285	(284,376	)	1,741,909
	Share repurchase program	—	(26,436,677	)	(26,436,677	)
	Balance, December 31, 2012	492,495,100	(35,446,130	)	457,048,970
	Shares issued under Calpine Equity Incentive Plans	5,345,956	(2,323,828	)	3,022,128
	Share repurchase program	—	(31,032,110	)	(31,032,110	)
	Balance, December 31, 2013	497,841,056	(68,802,068	)	429,038,988
	Shares issued under Calpine Equity Incentive Plans	4,445,966	(1,879,167	)	2,566,799
	Share repurchase program	—	(49,684,523	)	(49,684,523	)
	Balance, December 31, 2014	502,287,022	(120,365,758	)	381,921,264
	Treasury Stock
	As of December 31, 2014 and 2013, we had treasury stock of 120,365,758 shares and 68,802,068 shares, respectively, with a cost of $2.3 billion and $1.2 billion, respectively. During 2014, we repurchased a total of 36.5 million shares of our outstanding common stock for approximately $789 million at an average price of $21.62 per share, excluding the shareholder transaction described below. In 2015, through the filing of this Report, we have repurchased a total of 5.8 million shares of our outstanding common stock for approximately $125 million at an average price of $21.68 per share. Our treasury stock also consists of our common stock withheld to satisfy federal, state and local income tax withholding requirements for vested employee restricted stock awards and net share employee stock options exercises under the Equity Plan. All treasury stock is held at cost.
	Shareholder Transaction
	On July 8, 2014, we entered into a share repurchase agreement, at the prevailing market price, with a shareholder that beneficially owned slightly less than 10% of our outstanding common stock to purchase 13,213,372 shares of our common stock for the aggregate purchase price of $311,464,283 in a private transaction. We used cash on hand to fund the transaction which settled on July 10, 2014, and the repurchased shares have been returned to treasury stock.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies
	Long-Term Service Agreements
	As of December 31, 2014, the total estimated commitments for LTSAs associated with turbines were approximately $189 million. These commitments are payable over the terms of the respective agreements, which range from 1 to 11 years. LTSA future commitment estimates are based on the stated payment terms in the contracts at the time of execution and are subject to an annual inflationary adjustment. Certain of these agreements have terms that allow us to cancel the contracts for a fee. If we cancel such contracts, the estimated commitments remaining for LTSAs would be reduced.
	Power Plant, Land and Other Operating Leases
	We have entered into certain long-term operating leases for power plants, extending through 2020, which include renewal options or purchase options at fair value and contain customary restrictions on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project finance agreements. Payments on our operating leases, which may contain escalation clauses or step rent provisions, are recognized on a straight-line basis. Certain capital improvements associated with leased power plants may be deemed to be leasehold improvements and are amortized over the shorter of the term of the lease or the economic life of the capital improvement. We have also entered into various land and other operating leases for ground facilities and operations, which extend through 2069. Future minimum rent payments under these lease agreements, including renewal options and rent escalation clauses, are as follows (in millions):
		Initial		2015			2016			2017			2018			2019			Thereafter			Total
		Year
	Land and other operating leases	various		$	15		$	16		$	15		$	15		$	15		$	201		$	277
	Power plant operating leases:
	Greenleaf	1998		$	4		$	—		$	—		$	—		$	—		$	—		$	4
	KIAC	2000		23			22			22			22			30			—			119
	Total power plant leases			$	27		$	22		$	22		$	22		$	30		$	—		$	123
	Total leases			$	42		$	38		$	37		$	37		$	45		$	201		$	400
	During the years ended December 31, 2014, 2013 and 2012, rent expense for power plant, land and other operating leases amounted to $46 million, $47 million and $51 million, respectively.
	Production Royalties and Leases
	We are obligated under numerous geothermal leases and right-of-way, easement and surface agreements. The geothermal leases generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement and surface agreements are based on flat rates or adjusted based on consumer price index changes and are not material. Under the terms of most geothermal leases, the royalties accrue as a percentage of power revenues. Certain properties also have net profits and overriding royalty interests that are in addition to the land base lease royalties. Some lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level. Production royalties for geothermal power plants for the years ended December 31, 2014, 2013 and 2012, were $28 million, $27 million and $22 million, respectively.
	Office Leases
	We lease our corporate and regional offices under noncancelable operating leases extending through 2020. Future minimum lease payments under these leases are as follows (in millions):
	2015	$	11
	2016	10
	2017	9
	2018	9
	2019	8
	Thereafter	8
	Total	$	55
	Lease payments are subject to adjustments for our pro rata portion of annual increases or decreases in building operating costs. During the years ended December 31, 2014, 2013 and 2012, rent expense for noncancelable operating leases was $11 million, $12 million and $12 million, respectively.
	Natural Gas Purchases
	We enter into natural gas purchase contracts of various terms with third parties to supply natural gas to our natural gas-fired power plants. The majority of our purchases are made in the spot market or under index-priced contracts. These contracts are accounted for as executory contracts and therefore not recognized as liabilities on our Consolidated Balance Sheet. At December 31, 2014, we had future commitments for the purchase, transportation, or storage of commodities as detailed below (in millions):
	2015	$	390
	2016	297
	2017	193
	2018	152
	2019	109
	Thereafter	622
	Total	$	1,763
	Guarantees and Indemnifications
	As part of our normal business operations, we enter into various agreements providing, or otherwise arranging, financial or performance assurance to third parties on behalf of our subsidiaries in the ordinary course of such subsidiaries’ respective business. Such arrangements include guarantees, standby letters of credit and surety bonds for power and natural gas purchase and sale arrangements and contracts associated with the development, construction, operation and maintenance of our fleet of power plants. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes.
	At December 31, 2014, guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and guarantees of subsidiary operating lease payments and their respective expiration dates were as follows (in millions):
	Guarantee Commitments		2015			2016			2017			2018			2019			Thereafter			Total
	Guarantee of subsidiary debt(1)		$	37		$	36		$	26		$	31		$	30		$	148		$	308
	Standby letters of credit(2)(3)(5)		572			14			20			—			—			38			644
	Surety bonds(4)(5)(6)		—			—			—			—			—			4			4
	Guarantee of subsidiary operating lease payments(5)		4			—			—			—			—			—			4
	Total		$	613		$	50		$	46		$	31		$	30		$	190		$	960
	____________
	-1	Represents Calpine Corporation guarantees of certain power plant capital leases and related interest. All guaranteed capital leases are recorded on our Consolidated Balance Sheets.
	-2	The standby letters of credit disclosed above represent those disclosed in Note 6.
	-3	Letters of credit are renewed annually and as such all amounts are reflected in the year of letter of credit expiration. The related commercial obligations extend for multiple years, therefore, renewal of the letter of credit will likely follow the term of the associated commercial obligation.
	-4	The majority of surety bonds do not have expiration or cancellation dates.
	-5	These are contingent off balance sheet obligations.
	-6	As of December 31, 2014, $2 million of cash collateral is outstanding related to these bonds.
	We routinely arrange for the issuance of letters of credit and various forms of surety bonds to third parties in support of our subsidiaries’ contractual arrangements of the types described above and may guarantee the operating performance of some of our partially-owned subsidiaries up to our ownership percentage. The letters of credit issued under various credit facilities support risk management and other operational and construction activities. In the event a subsidiary were to fail to perform its obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make payment to the third party, we would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of one to ten days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety bonds, such liabilities are included on our Consolidated Balance Sheets.
	Commercial Agreements — In connection with the purchase and sale of power, natural gas and emission allowances to and from third parties with respect to the operation of our power plants, we may be required to guarantee a portion of the obligations of certain of our subsidiaries. These guarantees may include future payment obligations and effectively guarantee our future performance under certain agreements.
	Asset Acquisition and Disposition Agreements — In connection with our purchase and sale agreements, we have frequently provided for indemnification to the counterparty for liabilities incurred as a result of a breach of a representation, warranty or covenant by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction.
	Other — Additionally, we and our subsidiaries from time to time assume other guarantee and indemnification obligations in conjunction with other transactions such as parts supply agreements, construction agreements, maintenance and service agreements and equipment lease agreements. These guarantee and indemnification obligations may include indemnification from personal injury or other claims by our employees as well as future payment obligations and effectively guarantee our future performance under certain agreements.
	Our potential exposure under guarantee and indemnification obligations can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Our total maximum exposure under our guarantee and indemnification obligations is not estimable due to uncertainty as to whether claims will be made or how any potential claim will be resolved. As of December 31, 2014, there are no material outstanding claims related to our guarantee and indemnification obligations and we do not anticipate that we will be required to make any material payments under our guarantee and indemnification obligations.
	Litigation
	We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings will have a material adverse effect on our financial condition, results of operations or cash flows.
	On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows.
	Environmental Matters
	We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material impact on our financial condition, results of operations or cash flows or that would significantly change our operations.
	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 reserved its rights to assert any penalty claims associated with this violation and RCEC reserved its rights to assert any defenses to such claims in future proceedings.

Segment_and_Significant_Custom

Segment and Significant Customer Information	12 Months Ended
	Dec. 31, 2014
Segment and Significant Customer Information [Abstract]
Segment and Significant Customer Information
		Segment and Significant Customer 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 from what was formerly our Southeast segment. Thus, at December 31, 2014, our reportable segments were West (including geothermal), Texas and East (including Canada). We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result.
	Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions).
		Year Ended December 31, 2014
		West			Texas			East			Consolidation			Total
											and
											Elimination
	Revenues from external customers	$	2,352		$	3,229		$	2,449		$	—		$	8,030
	Intersegment revenues	6			23			47			(76		)	—
	Total operating revenues	$	2,358		$	3,252		$	2,496		$	(76	)	$	8,030
	Commodity Margin(1)	$	1,050		$	760		$	949		$	—		$	2,759
	Add: Mark-to-market commodity activity, net and other(2)	220			142			48			(31		)	379
	Less:
	Plant operating expense	385			313			302			(31		)	969
	Depreciation and amortization expense	245			191			168			(1		)	603
	Sales, general and other administrative expense	41			64			39			—			144
	Other operating expenses	50			5			32			1			88
	Impairment loss	—			—			123			—			123
	(Gain) on sale of assets, net	—			—			(753		)	—			(753		)
	(Income) from unconsolidated investments in power plants	—			—			(25		)	—			(25		)
	Income from operations	549			329			1,111			—			1,989
	Interest expense, net of interest income													639
	Debt extinguishment costs and other (income) expense, net													367
	Income before income taxes													$	983
		Year Ended December 31, 2013
		West			Texas			East			Consolidation			Total
											and
											Elimination
	Revenues from external customers	$	1,937		$	2,347		$	2,017		$	—		$	6,301
	Intersegment revenues	5			(4		)	117			(118		)	—
	Total operating revenues	$	1,942		$	2,343		$	2,134		$	(118	)	$	6,301
	Commodity Margin(1)	$	1,020		$	632		$	916		$	—		$	2,568
	Add: Mark-to-market commodity activity, net and other(2)	(50		)	51			27			(31		)	(3		)
	Less:
	Plant operating expense	365			269			292			(31		)	895
	Depreciation and amortization expense	227			165			203			(2		)	593
	Sales, general and other administrative expense	37			56			42			1			136
	Other operating expenses	45			3			33			—			81
	Impairment loss	16			—			—			—			16
	(Income) from unconsolidated investments in power plants	—			—			(30		)	—			(30		)
	Income from operations	280			190			403			1			874
	Interest expense, net of interest income													690
	Debt extinguishment costs and other (income) expense, net													164
	Income before income taxes													$	20
		Year Ended December 31, 2012
		West			Texas			East			Consolidation			Total
											and
											Elimination
	Revenues from external customers	$	1,668		$	1,857		$	1,953		$	—		$	5,478
	Intersegment revenues	10			61			38			(109		)	—
	Total operating revenues	$	1,678		$	1,918		$	1,991		$	(109	)	$	5,478
	Commodity Margin(1)(3)(4)	$	994		$	570		$	974		$	—		$	2,538
	Add: Mark-to-market commodity activity, net and other(2)	(93		)	87			(47		)	(31		)	(84		)
	Less:
	Plant operating expense	368			247			337			(30		)	922
	Depreciation and amortization expense	203			142			219			(2		)	562
	Sales, general and other administrative expense	36			47			57			—			140
	Other operating expenses	42			5			34			(3		)	78
	(Gain) on sale of assets, net	—			—			(222		)	—			(222		)
	(Income) from unconsolidated investments in power plants	—			—			(28		)	—			(28		)
	Income from operations	252			216			530			4			1,002
	Interest expense, net of interest income													725
	Loss on interest rate derivatives													14
Debt extinguishment costs and other (income) expense, net													45
Loss before income taxes													$	218
__________
-1	Our East segment includes Commodity Margin of $81 million, $152 million and $131 million for the years ended December 31, 2014, 2013 and 2012, respectively, related to the six power plants in our East segment that were sold in July 2014.
-2	Includes $(5) million, $6 million and $1 million of lease levelization and $14 million, $14 million and $14 million of amortization expense for the years ended December 31, 2014, 2013 and 2012, respectively.
-3	Our East segment includes Commodity Margin of $52 million for the year ended December 31, 2012, related to Broad River, which was sold in December 2012.
-4	Our East segment includes Commodity Margin of $73 million for the year ended December 31, 2012, related to Riverside Energy Center, LLC, which was sold in December 2012.
Significant Customers
For the years ended December 31, 2014 and 2012, we had only one significant customer, PJM Settlement, Inc. that individually accounted for more than 10% of our annual consolidated revenues. For the year ended December 31, 2013, we had two significant customers, PJM Settlement, Inc. and PG&E, that individually accounted for more than 10% of our annual consolidated revenues. Our revenues from PJM Settlement, Inc. for the years ended December 31, 2014, 2013 and 2012 were approximately $1.0 billion, $820 million and $713 million respectively, and were attributed to our East segment. Our revenues from PG&E was approximately $694 million for the year ended December 31, 2013, which was attributed to our West segment.

Quarterly_Consolidated_Financi

Quarterly Consolidated Financial Data (unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly Consolidated Financial Data (unaudited)	Quarterly Consolidated Financial Data (unaudited)
	Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including, but not limited to, our restructuring activities (including asset sales), the completion of development projects, the timing and amount of curtailment of operations under the terms of certain PPAs, the degree of risk management and marketing, hedging, optimization and trading activities, energy commodity market prices and variations in levels of production. Furthermore, the majority of the dollar value of capacity payments under certain of our PPAs are received during the months of May through October.
		Quarter Ended
		December 31			September 30		June 30			March 31
		(in millions, except per share amounts)
	2014
	Operating revenues	$	1,939		$	2,187	$	1,939		$	1,965
	Income from operations	$	390		$	1,126	$	329		$	144
	Net income (loss) attributable to Calpine	$	210		$	614	$	139		$	(17	)
	Net income (loss) per common share attributable to Calpine — Basic	$	0.55		$	1.54	$	0.33		$	(0.04	)
	Net income (loss) per common share attributable to Calpine — Diluted	$	0.54		$	1.52	$	0.33		$	(0.04	)
	2013
	Operating revenues	$	1,438		$	2,050	$	1,572		$	1,241
	Income from operations	$	151		$	597	$	122		$	4
	Net income (loss) attributable to Calpine	$	(97	)	$	306	$	(70	)	$	(125	)
	Net income (loss) per common share attributable to Calpine — Basic	$	(0.23	)	$	0.7	$	(0.16	)	$	(0.28	)
	Net income (loss) per common share attributable to Calpine — Diluted	$	(0.23	)	$	0.7	$	(0.16	)	$	(0.28	)

Schedule_of_Valuation_and_Qual

Schedule of Valuation and Qualifying Accounts Disclosure	12 Months Ended
	Dec. 31, 2014
Valuation and Qualifying Accounts [Abstract]
Schedule of Valuation and Qualifying Accounts Disclosure	CALPINE CORPORATION AND SUBSIDIARIES
	SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
	Description	Balance at		Charged to			Charged to Other Accounts			Deductions(1)			Balance at
		Beginning		Expense									End of Year
		of Year
		(in millions)
	Year Ended December 31, 2014
	Allowance for doubtful accounts	$	5	$	(1	)	$	—		$	—		$	4
	Deferred tax asset valuation allowance	2,246		(410		)	—			—			1,836
	Year Ended December 31, 2013
	Allowance for doubtful accounts	$	6	$	4		$	(5	)	$	—		$	5
	Deferred tax asset valuation allowance	2,222		24			—			—			2,246
	Year Ended December 31, 2012
	Allowance for doubtful accounts	$	13	$	(1	)	$	(1	)	$	(5	)	$	6
	Deferred tax asset valuation allowance	2,336		(114		)	—			—			2,222
	_____________
	-1	Represents write-offs of accounts considered to be uncollectible and previously reserved.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Summary of Significant Accounting Policies [Abstract]
Consolidation	Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and include the accounts of all majority-owned subsidiaries that are not VIEs and all VIEs where we have determined we are the primary beneficiary. Intercompany transactions have been eliminated in consolidation.
Equity Method Investments	We use the equity method of accounting to record our net interests in VIEs where we have determined that we are not the primary beneficiary, which include Greenfield LP, a 50% partnership interest, and Whitby, a 50% partnership interest. Our share of net income (loss) is calculated according to our equity ownership percentage or according to the terms of the applicable partnership agreement. See Note 5 for further discussion of our VIEs and unconsolidated investments.
	We consolidate our VIEs where we determine that we have both the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE. We have determined that we hold the obligation to absorb losses and receive benefits in all of our VIEs where we hold the majority equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following primary activities which we believe to have a significant impact on a power plant’s financial performance: operations and maintenance, plant dispatch, and fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our majority-owned VIEs.
	Under our consolidation policy and under U.S. GAAP we also:
	•	perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and
	•	evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE’s economic performance or when there are other changes in the powers held by individual variable interest holders.
Reclassification	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.
Jointly-Owned Plants [Policy Text Block]	Certain of our subsidiaries own undivided interests in jointly-owned plants. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. We are responsible for our subsidiaries’ share of operating costs and direct expenses and include our proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of our Consolidated 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 Financial Statements. Actual results could differ from those estimates.
Fair Value of Financial Instruments and Derivatives	The carrying values of accounts receivable, accounts payable and other receivables and payables approximate their respective fair values due to their short-term maturities. See Note 6 for disclosures regarding the fair value of our debt instruments and Note 7 for disclosures regarding the fair values of our derivative instruments and margin deposits and certain of our cash balances.
Concentrations of Credit Risk	Financial instruments that potentially subject us to credit risk consist of cash and cash equivalents, restricted cash, accounts and notes receivable and derivative financial instruments. Certain of our cash and cash equivalents, as well as our restricted cash balances, are invested in money market accounts with investment banks that are not FDIC insured. We place our cash and cash equivalents and restricted cash in what we believe to be creditworthy financial institutions and certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Additionally, we actively monitor the credit risk of our counterparties, including our receivable, commodity and derivative transactions. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the U.S. We generally have not collected collateral for accounts receivable from utilities and end-user customers; however, we may require collateral in the future. For financial and commodity derivative counterparties, we evaluate the net accounts receivable, accounts payable and fair value of commodity contracts and may require security deposits, cash margin or letters of credit to be posted if our exposure reaches a certain level or their credit rating declines.
	Our counterparties primarily consist of three categories of entities who participate in the wholesale energy markets:
	•	financial institutions and trading companies;
	•	regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers; and
	•	oil, natural gas, chemical and other energy-related industrial companies.
	We have concentrations of credit risk with a few of our customers relating to our sales of power, steam and hedging, optimization and trading activities. We have exposure to trends within the energy industry, including declines in the creditworthiness of our counterparties for our commodity and derivative transactions. Currently, certain of our counterparties within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty credit risk and monitors our net exposure with each counterparty on a daily basis. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a counterparty credit risk threshold which is determined based on each counterparty’s credit rating and evaluation of their financial statements. We utilize these thresholds to determine the need for additional collateral or restriction of activity with the counterparty. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties are performing and financially settling timely according to their respective agreements.
Cash and Cash Equivalents	We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts, which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At December 31, 2014 and 2013, we had cash and cash equivalents of $257 million and $292 million, respectively, that were subject to such project finance facilities and lease agreements.
Restricted Cash	Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Balance Sheets and Statements of Cash Flows.
Accounts Receivable and Payable	Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest. Receivable balances greater than 30 days past due are individually reviewed for collectability, and if deemed uncollectible, are charged off against the allowance account after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best estimate to determine the required allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations. We review the adequacy of our reserves and allowances quarterly.
	The accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging and optimization activities. Some of these receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a right of offset and settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off balance sheet credit exposure related to our customers.
Inventory	Inventory primarily consists of spare parts, stored natural gas and fuel oil, environmental products and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
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 previously subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility as collateral under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity hedge agreements” under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. The first priority liens have been granted in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. Our interest rate swap agreements relate to hedges of certain of our project financings collateralized by first priority liens on the underlying assets. See Note 9 for a further discussion on our amounts and use of collateral.
Deferred Financing Costs	Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the related debt using a method that approximates the effective interest rate method. However, when the timing of debt transactions involve contemporaneous exchanges of cash between us and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, deferred financing costs are accounted for depending on whether the transaction qualifies as an extinguishment or modification, which requires us to either write-off the original deferred financing costs and capitalize the new issuance costs, or continue to amortize the original deferred financing costs and immediately expense the new issuance costs.
Property, Plant and Equipment, Net	Property, plant, and equipment items are recorded at cost. We capitalize costs incurred in connection with the construction of power plants, the development of geothermal properties and the refurbishment of major turbine generator equipment. When capital improvements to leased power plants meet our capitalization criteria they are capitalized as leasehold improvements and amortized over the shorter of the term of the lease or the economic life of the capital improvement. We expense maintenance when the service is performed for work that does not meet our capitalization criteria. Our current capital expenditures at our Geysers Assets are those incurred for proven reserves and reservoir replenishment (primarily water injection), pipeline and power generation assets and drilling of “development wells” as all drilling activity has been performed within the known boundaries of the steam reservoir. We have capitalized costs incurred during ownership consisting of additions, certain replacements or repairs when the repairs appreciably extend the life, increase the capacity or improve the efficiency or safety of the property. Such costs are expensed when they do not meet the above criteria. We purchased our Geysers Assets as a proven steam reservoir and all well costs, except well workovers and routine repairs and maintenance, have been capitalized since our purchase date.
	We depreciate our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis where we own the power plant or have a favorable option to purchase the power plant or take ownership of the power plant at conclusion of the lease term and approximately 0.15% of the depreciable costs basis for rotable equipment. For our Geysers Assets, we typically assume no salvage values. We use the component depreciation method for our natural gas-fired power plant rotable parts and our information technology equipment and the composite depreciation method for most of all of the other natural gas-fired power plant asset groups and Geysers Assets.
	Generally, upon normal retirement of assets under the composite depreciation method, the costs of such assets are retired against accumulated depreciation and no gain or loss is recorded. For the retirement of assets under the component depreciation method, generally, the costs and related accumulated depreciation of such assets are removed from our Consolidated Balance Sheets and a gain or loss is recorded as plant operating expense.
Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)	We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.
	In order to estimate future cash flows, we consider historical cash flows, existing and future contracts and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
	When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
	Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
	In August 2014, we executed a term sheet with Duke Energy Florida, Inc. related to our Osprey Energy Center for a new PPA with a term of 27 months, after which Duke Energy Florida, Inc. would purchase our Osprey Energy Center subject to an asset sale agreement that was executed in the fourth quarter of 2014 and remains subject to federal and state regulatory approval. As a result, we conducted an impairment review of our Osprey Energy Center during the third quarter of 2014. We estimated fair value of our Osprey Energy Center under a modified market approach using the discounted cash flows under the PPA and the sale proceeds to be received, which incorporated a market participant's fair value of the power plant. We recorded an impairment loss of approximately $123 million which was recorded as a separate line item on our Consolidated Statements of Operations for the year ended December 31, 2014. We recorded an impairment loss of $16 million during the year ended December 31, 2013 related to a power plant in our West segment. During 2012, we did not record any impairment losses.
Asset Retirement Obligation	We record all known asset retirement obligations for which the liability’s fair value can be reasonably estimated. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. At December 31, 2014 and 2013, our asset retirement obligation liabilities were $47 million and $44 million, respectively, primarily relating to land leases upon which our power plants are built and the requirement that the property meet specific conditions upon its return.
Revenue Recognition	Our operating revenues are comprised of the following:
	•	power and steam revenue consisting of fixed and variable capacity payments, which are not related to generation including capacity payments received from RTO and ISO capacity auctions, variable payments for power and steam, which are related to generation, host steam and RECs from our Geysers Assets, other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues and realized settlements from our marketing, hedging, optimization and trading activities;
	•	mark-to-market revenues from derivative instruments as a result of our marketing, hedging, optimization and trading activities; and
	•	other service revenues.
	Power and Steam
	Physical Commodity Contracts — We recognize revenue primarily from the sale of power and steam thermal energy for sale to our customers for use in industrial or other heating operations upon transmission and delivery to the customer.
	We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the value inherent in our generation. We apply lease accounting to contracts that meet the definition of a lease and accrual accounting treatment to those contracts that are either exempt from derivative accounting or do not meet the definition of a derivative instrument. Additionally, we determine whether the financial statement presentation of revenues should be on a gross or net basis.
	With respect to our physical executory contracts, where we act as a principal, we take title of the commodities and assume the risks and rewards of ownership by receiving the natural gas and using the natural gas in our operations to generate and deliver the power. Where we act as principal, we record settlement of our physical commodity contracts on a gross basis. Where we do not take title of the commodities but receive a net variable payment to convert natural gas into power and steam in a tolling operation, we record the variable payment as revenue but do not record any fuel and purchased energy expense.
	Capacity payments, RMR Contracts, RECs, resource adequacy and other ancillary revenues, unless qualified as a lease, are recognized when contractually earned and consist of revenues received from our customers either at the market price or a contract price.
	Realized and Mark-to-Market Revenues from Commodity Derivative Instruments
	Realized Settlements of Commodity Derivative Instruments — The realized value of power commodity sales and purchase contracts that are net settled or settled as gross sales and purchases, but could have been net settled, are reflected on a net basis and are included in Commodity revenue on our Consolidated Statements of Operations.
	Mark-to-Market Gain (Loss) — The changes in the mark-to-market value of power-based commodity derivative instruments are reflected on a net basis as a separate component of operating revenues.
Lease, Policy [Policy Text Block]	We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize certain components of these contract revenues on a straight-line basis over the term of the contract.
Accounting for Derivative Instruments	We enter into a variety of derivative instruments including both exchange traded and OTC power and natural gas forwards, options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) and interest rate swaps. 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 are designated under the normal purchase normal sale exemption. Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes are not available from sources external to us, in which case we rely on internally developed price estimates. See Note 8 for further discussion on our accounting for derivatives.
Fuel and Purchased Energy Expense	Fuel and purchased energy expense is comprised of the cost of natural gas and fuel oil purchased from third parties for the purposes of consumption in our power plants as fuel, and the cost of power and natural gas purchased from third parties for our marketing, hedging and optimization activities and realized settlements and mark-to-market gains and losses resulting from general market price movements against certain derivative natural gas contracts including financial natural gas transactions economically hedging anticipated future power sales that 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.
	Realized and Mark-to-Market Expenses from Commodity Derivative Instruments
	Realized Settlements of Commodity Derivative Instruments — The realized value of natural gas purchase and sales commodity contracts that are net settled are reflected on a net basis and included in Commodity expense on our Consolidated Statements of Operations. Power purchase commodity contracts that result in the physical delivery of power, and that also supplement our power generation, are reflected on a gross basis and are included in Commodity expense on our Consolidated Statements of Operations.
	Mark-to-Market (Gain) Loss — The changes in the mark-to-market value of natural gas-based commodity derivative instruments are reflected on a net basis as a separate component of fuel and purchased energy expense.
Plant Operating Expense	Plant operating expense primarily includes employee expenses, utilities, chemicals, repairs and maintenance (including equipment failure and major maintenance), insurance and property taxes. We recognize these expenses when the service is performed or in the period in which the expense relates.
Income Taxes	Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis and tax credit and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that includes the enactment date.
	We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. See Note 10 for a further discussion on our income taxes.
Earnings (Loss) per Share	Basic earnings per share is calculated using the weighted average shares outstanding during the period and includes restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock. Diluted earnings per share is calculated by adjusting the weighted average shares outstanding by the dilutive effect of share-based awards using the treasury stock method. See Note 11 for a further discussion of our earnings per share.
Stock-Based Compensation	We use the Black-Scholes option-pricing model or the Monte Carlo simulation model to estimate the fair value of our employee stock options on the grant date. For our restricted stock and restricted stock units, we use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Our performance share units are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. See Note 12 for a further discussion of our stock-based compensation.
Treasury Stock [Policy Text Block]	Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock.     Upon retirement of treasury stock, the amounts in excess of par value are charged entirely to additional paid-in capital.
Commitments and Contingencies, Policy [Policy Text Block]	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.
New Accounting Pronouncements, Policy [Policy Text Block]	Income Taxes — In July 2013, the FASB issued Accounting Standards Update 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists”. The provisions of the standard require an unrecognized tax benefit to be presented as a reduction to a deferred tax asset in the financial statements for a NOL carryforward, a similar tax loss, or a tax credit carryforward except in circumstances when the carryforward or tax loss is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes. When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. We adopted Accounting Standards Update 2013-11 in the first quarter of 2014 which did not have a material impact on our financial condition, results of operations or cash flows.
	Financial Reporting of Discontinued Operations — In April 2014, the FASB issued Accounting Standards Update 2014-08, “Presentation of Financial Statements and Property, Plant, and Equipment”. The update limits discontinued operations reporting to disposals that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The standard also requires new disclosures related to components reported as discontinued operations, as well as components of an entity that were sold and do not meet the criteria for discontinued operations reporting. The new financial statement presentation provisions relating to this standard are prospective and effective for interim and annual periods beginning after December 15, 2014, 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.
	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 creates a five-step model for revenue recognition that requires companies to exercise judgment when considering contract terms and relevant facts and circumstances. The five-step model includes (1) identifying the contract, (2) identifying the separate performance obligations in the contract, (3) determining the transaction price, (4) allocating the transaction price to the separate performance obligations and (5) recognizing revenue when each performance obligation has been satisfied. The standard also requires expanded disclosures surrounding revenue recognition. The standard is 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. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows.
	Going Concern — In August 2014, the FASB issued Accounting Standards Update 2014-15, “Presentation of Financial Statements — Going Concern”. This standard requires an entity’s management to assess the entity’s ability to continue as a going concern every reporting period including interim periods and requires additional disclosures if conditions or events raise substantial doubt about an entity’s ability to continue as a going concern. The standard is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter with early adoption permitted. We early adopted this standard during the fourth quarter of 2014 which did not have a material impact on our financial condition, results of operations or cash flows.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Summary of Significant Accounting Policies [Abstract]
Schedule of Jointly Owned Utility Plants [Table Text Block]	Jointly-Owned Plants — Certain of our subsidiaries own undivided interests in jointly-owned plants. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. We are responsible for our subsidiaries’ share of operating costs and direct expenses and include our proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of our Consolidated Financial Statements. The following table summarizes our proportionate ownership interest in jointly-owned power plants:
	As of December 31, 2014		Ownership Interest			Property, Plant & Equipment				Accumulated Depreciation				Construction in Progress
	(in millions, except percentages)
	Freestone Energy Center		75	%		$	389			$	(140	)		$	—
	Hidalgo Energy Center		78.5	%		$	257			$	(104	)		$	—
Schedule of Components of Restricted Cash	Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Balance Sheets and Statements of Cash Flows.
	The table below represents the components of our restricted cash as of December 31, 2014 and 2013 (in millions):
		2014												2013
		Current				Non-Current				Total				Current				Non-Current				Total
	Debt service	$	10			$	25			$	35			$	11			$	41			$	52
	Rent reserve	4				—				4				3				—				3
	Construction/major maintenance	54				17				71				35				20				55
	Security/project/insurance	127				5				132				151				6				157
	Other	—				2				2				3				2				5
	Total	$	195			$	49			$	244			$	203			$	69			$	272
Schedule of Total Contractual Future Minimum Lease Receipts	Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize certain components of these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2014, are as follows (in millions):
	2015	$	561
	2016	495
	2017	433
	2018	396
	2019	357
	Thereafter	1,380
	Total	$	3,622
	Future minimum rent payments under these lease agreements, including renewal options and rent escalation clauses, are as follows (in millions):
		Initial		2015				2016				2017				2018				2019				Thereafter		Total
		Year
	Land and other operating leases	various		$	15			$	16			$	15			$	15			$	15			$	201	$	277
	Power plant operating leases:
	Greenleaf	1998		$	4			$	—			$	—			$	—			$	—			$	—	$	4
	KIAC	2000		23				22				22				22				30				—		119
	Total power plant leases			$	27			$	22			$	22			$	22			$	30			$	—	$	123
	Total leases			$	42			$	38			$	37			$	37			$	45			$	201	$	400

Acquisitions_Divestitures_and_1

Acquisitions, Divestitures and Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2014
Six Power Plants Disposed [Abstract]
Six power plants disposed of [Table Text Block]	The six power plants included in the transaction are as follows:
	Plant Name		Plant Capacity		Location
	Oneta Energy Center		1,134	MW	Coweta, OK
	Carville Energy Center(1)		501	MW	St. Gabriel, LA
	Decatur Energy Center		795	MW	Decatur, AL
	Hog Bayou Energy Center		237	MW	Mobile, AL
	Santa Rosa Energy Center		225	MW	Pace, FL
	Columbia Energy Center(1)		606	MW	Calhoun County, SC
	Total		3,498	MW
	___________
	-1	Indicates combined-cycle cogeneration power plant.

Property_Plant_and_Equipment_N1

Property, Plant and Equipment, Net (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment, Net [Abstract]
Property, Plant and Equipment	As of December 31, 2014 and 2013, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
		2014		2013		Depreciable Lives
	Buildings, machinery and equipment	$	16,059	$	15,838	3 – 47 Years
	Geothermal properties	1,294		1,265		13 – 59 Years
	Other	203		164		3 – 47 Years
		17,556		17,267
	Less: Accumulated depreciation	4,984		4,897
		12,572		12,370
	Land	120		103
	Construction in progress	498		522
	Property, plant and equipment, net	$	13,190	$	12,995

Variable_Interest_Entities_and1

Variable Interest Entities and Unconsolidated Investments (Tables)	12 Months Ended
	Dec. 31, 2014
Variable Interest Entities and Unconsolidated Investments [Abstract]
Schedule of Condensed Financial Statements	Aggregated summarized financial data for our unconsolidated subsidiaries is set forth below (in millions):
	Condensed Combined Balance Sheets
	of Our Unconsolidated Subsidiaries
	December 31, 2014 and 2013
		2014				2013
	Assets:
	Cash and cash equivalents	$	58			$	57
	Current assets	28				25
	Property, plant and equipment, net	532				588
	Other assets	2				2
	Total assets	$	620			$	672
	Liabilities:
	Current maturities of long-term debt	$	21			$	23
	Current liabilities	28				44
	Long-term debt	321				372
	Long-term derivative liabilities	51				35
	Total liabilities	421				474
	Member's interest	199				198
	Total liabilities and member's interest	$	620			$	672
	Condensed Combined Statements of Operations
	of Our Unconsolidated Subsidiaries
	For the Years Ended December 31, 2014, 2013 and 2012
		2014				2013				2012
	Revenues	$	239			$	207			$	247
	Operating expenses	168				128				171
	Income from operations	71				79				76
	Interest expense, net of interest income	23				24				27
	Other (income) expense, net	—				(3		)		(2		)
	Net income	$	48			$	58			$	51
Schedule of Equity Method Investments	At December 31, 2014 and 2013, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):
		Ownership Interest as of December 31, 2014		2014				2013
	Greenfield LP	50%		$	78			$	76
	Whitby	50%		17				17
	Total investments in power plants			$	95			$	93
Income (Loss) From Unconsolidated Investments in Power Plants and Distributions	Our equity interest in the net income from Greenfield LP and Whitby for the years ended December 31, 2014, 2013 and 2012, is recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our (income) from unconsolidated investments in power plants and distributions for the years indicated (in millions):
		(Income) from Unconsolidated											Distributions
		Investments in Power Plants
		2014				2013				2012			2014		2013		2012
	Greenfield LP	$	(10	)		$	(16	)		$	(17	)	$	—	$	18	$	22
	Whitby	(15		)		(14		)		(11		)	13		9		7
	Total	$	(25	)		$	(30	)		$	(28	)	$	13	$	27	$	29

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	Our debt at December 31, 2014 and 2013, was as follows (in millions):
		2014		2013
	First Lien Notes	$	2,075	$	4,989
	Senior Unsecured Notes	2,800		—
	First Lien Term Loans	2,799		2,828
	Project financing, notes payable and other	1,810		1,901
	CCFC Term Loans	1,596		1,191
	Capital lease obligations	202		203
	Subtotal	11,282		11,112
	Less: Current maturities	199		204
	Total long-term debt	$	11,083	$	10,908
Schedule of Maturities of Long-term Debt	Contractual annual principal repayments or maturities of debt instruments as of December 31, 2014, are as follows (in millions):
	2015	$	199
	2016	205
	2017	562
	2018	1,730
	2019	1,217
	Thereafter	7,393
	Subtotal	11,306
	Less: Discount	24
	Total debt	$	11,282
First Lien Notes	Our First Lien Notes are summarized in the table below (in millions, except for interest rates):
		Outstanding at December 31,				Weighted Average
						Effective Interest Rates(3)
		2014		2013		2014		2013
	2019 First Lien Notes(1)	$	—	$	320	—	%	8.2	%
	2020 First Lien Notes(1)	—		875		—		8.2
	2021 First Lien Notes(1)	—		1,600		—		7.7
	2022 First Lien Notes	745		744		6.3		6.2
	2023 First Lien Notes(2)	840		960		8		8
	2024 First Lien Notes	490		490		6		5.9
	Total First Lien Notes	$	2,075	$	4,989
	____________
	-1	The 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes were repaid during the third quarter of 2014 with the proceeds from the issuance of our Senior Unsecured Notes, together with cash on hand, which are described in further detail below.
	-2	In December 2014, we used cash on hand to redeem 10% of the original aggregate principal amount of our 2023 First Lien Notes, plus accrued and unpaid interest. On February 3, 2015, we additionally repurchased approximately $150 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, which is described in further detail below.
	-3	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
Senior Unsecured Notes [Table Text Block]	Our Senior Unsecured Notes are summarized in the table below (in millions, except for interest rates):
		Outstanding at December 31,				Weighted Average
						Effective Interest Rates(1)
		2014		2013		2014		2013
	2023 Senior Unsecured Notes	$	1,250	$	—	5.6	%	—	%
	2025 Senior Unsecured Notes	1,550		—		5.9		—
	Total Senior Unsecured Notes	$	2,800	$	—
	____________
	-1	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
First Lien Term Loans	Our First Lien Term Loans are summarized in the table below (in millions, except for interest rates):
		Outstanding at December 31,				Weighted Average
						Effective Interest Rates(1)
		2014		2013		2014		2013
	2018 First Lien Term Loans	$	1,597	$	1,614	4.3	%	4.3	%
	2019 First Lien Term Loan	816		824		4.4		4.5
	2020 First Lien Term Loan	386		390		4.3		4.3
	Total First Lien Term Loans	$	2,799	$	2,828
	____________
	-1	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
Project Financing Notes Payable and Other	The components of our project financing, notes payable and other are (in millions, except for interest rates):
		Outstanding at				Weighted Average
		December 31,				Effective Interest Rates(1)
		2014		2013		2014		2013
	Russell City due 2023	$	591	$	593	6.2	%	4.9	%
	Steamboat due 2017	407		418		6.9		6.8
	OMEC due 2019	325		335		6.9		6.9
	Los Esteros due 2023	275		305		3.1		3.4
	Pasadena(2)	122		135		8.9		8.9
	Bethpage Energy Center 3 due 2020-2025(3)	82		88		7		7
	Gilroy note payable due 2014	—		15		—		11.2
	Other	8		12		—		—
	Total	$	1,810	$	1,901
	_____________
	-1	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount or premium.
	-2	Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.
	-3	Represents a weighted average of first and second lien loans for the weighted average effective interest rates.
CCFC Notes and CCFC Term Loans [Table Text Block]	Our CCFC Term Loans are summarized in the table below (in millions, except for interest rates):
		Outstanding at December 31,				Weighted Average
						Effective Interest Rates(1)
		2014		2013		2014		2013
	CCFC Term Loans	$	1,596	$	1,191	3.4	%	3.3	%
	____________
	-1	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
Schedule of Future Minimum Lease Payments for Capital Leases	The following is a schedule by year of future minimum lease payments under capital leases and a failed sale-leaseback transaction related to our Pasadena Power Plant together with the present value of the net minimum lease payments as of December 31, 2014 (in millions):
		Sale-Leaseback Transactions(1)		Capital Lease		Total
	2015	$	25	$	47	$	72
	2016	25		41		66
	2017	17		39		56
	2018	21		38		59
	2019	21		20		41
	Thereafter	85		151		236
	Total minimum lease payments	194		336		530
	Less: Amount representing interest	72		134		206
	Present value of net minimum lease payments	$	122	$	202	$	324
	____________
	-1	Amounts are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes payable and other amounts above.
Schedule of Line of Credit Facilities	The table below represents amounts issued under our letter of credit facilities at December 31, 2014 and 2013 (in millions):
		2014		2013
	Corporate Revolving Facility	$	223	$	242
	CDHI	214		218
	Various project financing facilities	207		170
	Total	$	644	$	630
Fair Value, by Balance Sheet Grouping	The following table details the fair values and carrying values of our debt instruments at December 31, 2014 and 2013 (in millions):
		2014				2013
		Fair Value		Carrying		Fair Value			Carrying
				Value					Value
	First Lien Notes	$	2,247	$	2,075	$	5,317		$	4,989
	Senior Unsecured Notes	2,832		2,800		—			—
	First Lien Term Loans	2,769		2,799		2,845			2,828
	Project financing, notes payable and other(1)	1,734		1,688		1,772			1,766
	CCFC Term Loans	1,540		1,596		1,179			1,191
	Total	$	11,122	$	10,958	$	11,113		$	10,774
	____________
	-1	Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

Assets_and_Liabilities_with_Re1

Assets and Liabilities with Recurring Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value, Option, Quantitative Disclosures [Line Items]
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 December 31, 2014 and 2013, by level within the fair value hierarchy:
		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
		Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2013
		Level 1			Level 2				Level 3			Total
		(in millions)
	Assets:
	Cash equivalents(1)	$	1,134		$	—			$	—		$	1,134
	Margin deposits	261			—				—			261
	Commodity instruments:
	Commodity exchange traded futures and swaps contracts	434			—				—			434
	Commodity forward contracts(2)	—			75				32			107
	Interest rate swaps	—			9				—			9
	Total assets	$	1,829		$	84			$	32		$	1,945
	Liabilities:
	Margin deposits posted with us by our counterparties	$	5		$	—			$	—		$	5
	Commodity instruments:
	Commodity exchange traded futures and swaps contracts	495			—				—			495
	Commodity forward contracts(2)	—			52				18			70
	Interest rate swaps	—			129				—			129
	Total liabilities	$	500		$	181			$	18		$	699
	___________
	-1	As of December 31, 2014 and 2013, we had cash equivalents of $679 million and $889 million included in cash and cash equivalents and $217 million and $245 million included in restricted cash, respectively.
	-2	Includes OTC swaps and options.
Fair Value Inputs, Assets, Quantitative Information [Table Text Block]	The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at December 31, 2014 and 2013:
			Quantitative Information about Level 3 Fair Value Measurements
			31-Dec-14
			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
			Quantitative Information about Level 3 Fair Value Measurements
			31-Dec-13
			Fair Value, Net Asset					Significant Unobservable
			(Liability)			Valuation Technique		Input		Range
			(in millions)
	Power Contracts		$	7		Discounted cash flow		Market price (per MWh)		$28.92 — $53.15/MWh
	Power Congestion Products		$	7		Discounted cash flow		Market price (per MWh)		$(8.79) — $11.53/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 years ended December 31, 2014, 2013 and 2012 (in millions):
		2014			2013				2012
	Balance, beginning of period	$	14		$	16			$	17
	Realized and mark-to-market gains:
	Included in net income:
	Included in operating revenues(1)	70			5				8
	Included in fuel and purchased energy expense(2)	5			—				—
	Purchases, issuances and settlements:
	Purchases	6			6				3
	Issuances	—			(2		)		(1		)
	Settlements	(10		)	(11		)		(11		)
	Transfers in and/or out of level 3(3):
	Transfers into level 3(4)	—			—				—
	Transfers out of level 3(5)	—			—				—
	Balance, end of period	$	85		$	14			$	16
	Change in unrealized gains relating to instruments still held at end of period	$	75		$	5			$	8
	___________
	-1	For power contracts and other power-related products, included on our Consolidated Statements of Operations.
	-2	For natural gas contracts, swaps and options, included on our Consolidated 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 during the years ended December 31, 2014, 2013 and 2012.
	-4	There were no transfers out of level 2 into level 3 for the years ended December 31, 2014, 2013 and 2012.
	-5	There were no transfers out of level 3 for the years ended December 31, 2014, 2013 and 2012.

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions	As of December 31, 2014 and 2013, 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
			2014				2013
	Power (MWh)		(62		)		(29		)
	Natural gas (MMBtu)		291				448
	Interest rate swaps		$	1,431			$	1,527
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following tables present the fair values of our derivative instruments recorded on our Consolidated Balance Sheets by location and hedge type at December 31, 2014 and 2013 (in millions):
		31-Dec-14
		Commodity				Interest Rate				Total
		Instruments				Swaps				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 assets (liabilities)	$	381			$	(110	)		$	271
		31-Dec-13
		Commodity				Interest Rate				Total
		Instruments				Swaps				Derivative
										Instruments
	Balance Sheet Presentation
	Current derivative assets	$	445			$	—			$	445
	Long-term derivative assets	96				9				105
	Total derivative assets	$	541			$	9			$	550
	Current derivative liabilities	$	404			$	47			$	451
	Long-term derivative liabilities	161				82				243
	Total derivative liabilities	$	565			$	129			$	694
	Net derivative assets (liabilities)	$	(24	)		$	(120	)		$	(144	)
Derivative Instrument by Accounting Designation
		December 31, 2014								December 31, 2013
		Fair Value				Fair Value				Fair Value				Fair Value
		of Derivative				of Derivative				of Derivative				of Derivative
		Assets				Liabilities				Assets				Liabilities
	Derivatives designated as cash flow hedging instruments:
	Interest rate swaps	$	4			$	112			$	9			$	115
	Total derivatives designated as cash flow hedging instruments	$	4			$	112			$	9			$	115
	Derivatives not designated as hedging instruments:
	Commodity instruments	$	2,493			$	2,112			$	541			$	565
	Interest rate swaps	—				2				—				14
	Total derivatives not designated as hedging instruments	$	2,493			$	2,114			$	541			$	579
	Total derivatives	$	2,497			$	2,226			$	550			$	694
Offsetting Assets [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 December 31, 2014 and 2013 (in millions):
			31-Dec-14
			Gross Amounts Not Offset on the Consolidated Balance Sheets
			Gross Amounts Presented on our Consolidated Balance Sheets				Derivative Asset (Liability) not Offset on the Consolidated 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
			31-Dec-13
			Gross Amounts Not Offset on the Consolidated Balance Sheets
			Gross Amounts Presented on our Consolidated Balance Sheets				Derivative Asset (Liability) not Offset on the Consolidated Balance Sheets				Margin/Cash (Received) Posted (1)				Net Amount
	Derivative assets:
	Commodity exchange traded futures and swaps contracts		$	434			$	(420	)		$	(14	)		$	—
	Commodity forward contracts		107				(60		)		—				47
	Interest rate swaps		9				—				—				9
	Total derivative assets		$	550			$	(480	)		$	(14	)		$	56
	Derivative (liabilities):
	Commodity exchange traded futures and swaps contracts		$	(495	)		$	420			$	75			$	—
	Commodity forward contracts		(70		)		60				1				(9		)
	Interest rate swaps		(129		)		—				—				(129		)
	Total derivative (liabilities)		$	(694	)		$	480			$	76			$	(138	)
	Net derivative assets (liabilities)		$	(144	)		$	—			$	62			$	(82	)
	____________
	-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 9 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 Statements of Operations for the years ended December 31, 2014, 2013 and 2012 (in millions):
		2014				2013				2012
	Realized gain (loss)(1)
	Commodity derivative instruments	$	110			$	86			$	387
	Interest rate swaps	—				—				(157		)
	Total realized gain (loss)	$	110			$	86			$	230
	Mark-to-market gain (loss)(2)
	Commodity derivative instruments	$	342			$	(14	)		$	(82	)
	Interest rate swaps	11				2				154
	Total mark-to-market gain (loss)	$	353			$	(12	)		$	72
	Total activity, net	$	463			$	74			$	302
	___________
	-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 [Table Text Block]
		2014				2013				2012
	Realized and mark-to-market gain (loss)
	Derivatives contracts included in operating revenues	$	384			$	(119	)		$	187
	Derivatives contracts included in fuel and purchased energy expense	68				191				118
	Interest rate swaps included in interest expense	11				2				11
	Loss on interest rate derivatives	—				—				(14		)
	Total activity, net	$	463			$	74			$	302
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 years ended December 31, 2014, 2013 and 2012 (in millions):
		Gains (Loss) Recognized  in												Gain (Loss) Reclassified  from
		OCI (Effective Portion)(3)												AOCI into Income (Effective
														Portion)(4)
		2014				2013				2012				2014				2013				2012			Affected Line Item on the Consolidated Statements of Operations
	Commodity derivative instruments(1):
	Power derivative instruments	$	—			$	—			$	(97	)		$	—			$	—			$	118		Commodity revenue
	Natural gas derivative instruments	—				—				59				—				—				(66		)	Commodity expense
	Interest rate swaps(2)	(2		)		86				(43		)		(46		)	(5)	(51		)	(5)	(32		)	Interest expense
	Total(3)	$	(2	)		$	86			$	(81	)		$	(46	)		$	(51	)		$	20
	____________
	-1	There were no commodity derivative instruments designated as cash flow hedges during the year ended December 31, 2014 and 2013. We recorded a gain on hedge ineffectiveness of $2 million related to our commodity derivative instruments designated as cash flow hedges during the year ended December 31, 2012.
	-2	We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the years ended December 31, 2014, 2013 and 2012.
	-3	We recorded income tax expense of nil and $3 million for the years ended December 31, 2014 and 2013, respectively, and an income tax benefit of $11 million for the year ended December 31, 2012, in AOCI related to our cash flow hedging activities.
	-4	Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $149 million, $148 million and $222 million at December 31, 2014, 2013 and 2012, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $12 million, $11 million and $20 million at December 31, 2014, 2013 and 2012, respectively.
	-5	Includes a loss of $10 million and $12 million that was reclassified from AOCI to interest expense for the years ended December 31, 2014 and 2013, respectively, where the hedged transactions are no longer expected to occur.

Use_of_Collateral_Tables

Use of Collateral (Tables)	12 Months Ended
	Dec. 31, 2014
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 December 31, 2014 and 2013 (in millions):
		2014		2013
	Margin deposits(1)	$	96	$	261
	Natural gas and power prepayments	22		28
	Total margin deposits and natural gas and power prepayments with our counterparties(2)	$	118	$	289
	Letters of credit issued	$	450	$	488
	First priority liens under power and natural gas agreements	48		31
	First priority liens under interest rate swap agreements	116		132
	Total letters of credit and first priority liens with our counterparties	$	614	$	651
	Margin deposits posted with us by our counterparties(1)(3)	$	47	$	5
	Letters of credit posted with us by our counterparties	61		2
	Total margin deposits and letters of credit posted with us by our counterparties	$	108	$	7
	___________
	-1	Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated 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 8 for further discussion of our derivative instruments subject to master netting arrangements.
	-2	At December 31, 2014 and 2013, $109 million and $272 million, respectively, were included in margin deposits and other prepaid expense and $9 million and $17 million, respectively, were included in other assets on our Consolidated Balance Sheets.
	-3	Included in other current liabilities on our Consolidated Balance Sheets.

Income_Taxes_Income_Taxes_Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Income before Income Tax, Domestic and Foreign	The jurisdictional components of income from continuing operations before income tax expense, attributable to Calpine, for the years ended December 31, 2014, 2013 and 2012, are as follows (in millions):
		2014				2013				2012
	U.S.	$	942			$	(13	)		$	194
	International	26				29				24
	Total	$	968			$	16			$	218
Schedule of Components of Income Tax Expense (Benefit)	The components of income tax expense from continuing operations for the years ended December 31, 2014, 2013 and 2012, consisted of the following (in millions):
		2014				2013				2012
	Current:
	Federal	$	(1	)		$	(2	)		$	(12	)
	State	19				(9		)		16
	Foreign	(1		)		(1		)		14
	Total current	17				(12		)		18
	Deferred:
	Federal	—				1				11
	State	(1		)		4				(5		)
	Foreign	6				9				(5		)
	Total deferred	5				14				1
	Total income tax expense	$	22			$	2			$	19
Schedule of Effective Income Tax Rate Reconciliation	A reconciliation of the federal statutory rate of 35% to our effective rate from continuing operations for the years ended December 31, 2014, 2013 and 2012, is as follows:
		2014			2013			2012
	Federal statutory tax expense (benefit) rate	35	%		35	%		35	%
	State tax expense (benefit), net of federal benefit	1.9			(69.8	)		3.2
	Depletion in excess of basis	(0.3	)		(14.7	)		(0.2	)
	Federal refunds	—			—			(4.7	)
	Valuation allowances against future tax benefits	(35.8	)		89.8			(30.3	)
	Valuation allowance related to foreign taxes	—			(19.8	)		(8.2	)
	Distributions from foreign affiliates and foreign taxes	1.2			(10.8	)		3.7
	Intraperiod allocation	—			4.5			4.6
	Change in unrecognized tax benefits	(0.4	)		(30.1	)		5.1
	Disallowed compensation	0.1			11.7			0.4
	Stock-based compensation	0.1			8.6			0.2
	Lobbying contributions	0.1			3.3			0.3
	Other differences	0.4			4.8			(0.4	)
	Effective income tax expense rate	2.3	%		12.5	%		8.7	%
Schedule of Deferred Tax Assets and Liabilities	The components of deferred income taxes as of December 31, 2014 and 2013, are as follows (in millions):
		2014				2013
	Deferred tax assets:
	NOL and credit carryforwards	$	2,873			$	3,120
	Taxes related to risk management activities and derivatives	61				60
	Reorganization items and impairments	216				262
	Foreign capital losses	16				18
	Other differences	—				104
	Deferred tax assets before valuation allowance	3,166				3,564
	Valuation allowance	(1,836		)		(2,246		)
	Total deferred tax assets	1,330				1,318
	Deferred tax liabilities:
	Property, plant and equipment	(1,305		)		(1,310		)
	Other differences	(21		)		—
	Total deferred tax liabilities	(1,326		)		(1,310		)
	Net deferred tax asset	4				8
	Less: Current portion deferred tax asset (liability)	(14		)		12
	Less: Non-current deferred tax asset	19				7
	Deferred income tax liability, non-current	$	(1	)		$	(11	)
Schedule of Income Tax Expense (Benefit) Intraperiod Tax Allocation	The following table details the effects of our intraperiod tax allocations for the years ended December 31, 2014, 2013 and 2012 (in millions).
		2014				2013				2012
	Intraperiod tax allocation expense included in continuing operations	$	—			$	1			$	9
	Intraperiod tax allocation benefit included in OCI	$	—			$	(1	)		$	(9	)
Schedule of Income Tax Contingencies	A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2014, 2013 and 2012, is as follows (in millions):
		2014				2013				2012
	Balance, beginning of period	$	(68	)		$	(92	)		$	(74	)
	Increases related to prior year tax positions	(4		)		(7		)		(19		)
	Decreases related to prior year tax positions	8				8				1
	Decreases related to settlements	8				10				—
	Decrease related to lapse of statute of limitations	—				13				—
	Balance, end of period	$	(56	)		$	(68	)		$	(92	)

Earnings_Loss_per_Share_Tables

Earnings (Loss) per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings (Loss) per Share [Abstract]
Schedule of Weighted Average Number of Shares	Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the years ended December 31, 2014, 2013 and 2012, are as follows (shares in thousands):
		2014	2013	2012
	Diluted weighted average shares calculation:
	Weighted average shares outstanding (basic)	404,837	440,666	467,752
	Share-based awards	4,523	4,107	3,591
	Weighted average shares outstanding (diluted)	409,360	444,773	471,343
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	We excluded the following items from diluted earnings per common share for the years ended December 31, 2014, 2013 and 2012, because they were anti-dilutive (shares in thousands):
		2014	2013	2012
	Share-based awards	2,859	5,062	10,302

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Stock-Based Compensation [Abstract]
Schedule of Share-based Compensation, Activity [Table Text Block]	A summary of our performance share unit activity for the year ended December 31, 2014, is as follows:
		Number of		Weighted
		Performance Share Units		Average
				Grant-Date
				Fair Value
	Nonvested — December 31, 2013	449,798		$	21.25
	Granted	461,393		$	22.56
	Forfeited	28,400		$	21.87
	Vested(1)	15,312		$	21.25
	Nonvested — December 31, 2014	867,479		$	21.93
	___________
	-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.
Schedule of Non-Qualified Stock Option Activity	A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the year ended December 31, 2014, is as follows:
		Number of		Weighted Average			Weighted	Aggregate
		Shares		Exercise Price			Average	Intrinsic Value
							Remaining	(in millions)
							Term
							(in years)
	Outstanding — December 31, 2013	14,114,289		$	18.25		3.1	$	36
	Granted	—		$	—
	Exercised	2,951,947		$	16.2
	Forfeited	69,122		$	15.81
	Expired	6,900		$	17.69
	Outstanding — December 31, 2014	11,086,320		$	18.82		2	$	43
	Exercisable — December 31, 2014	10,336,806		$	19.07		1.7	$	38
	Vested and expected to vest – December 31, 2014	11,076,617		$	18.82		2	$	43
Schedule of Assumptions Used to Estimate Fair Value for Options	Certain assumptions were used in order to estimate fair value for options as noted in the following table.
		2013			2012
	Expected term (in years)(1)	6.5			6.5
	Risk-free interest rate(2)	1.4		%	1.2 – 1.6		%
	Expected volatility(3)	25.6		%	27.0 – 30.5		%
	Dividend yield(4)	—			—
	Weighted average grant-date fair value (per option)	$	5.31		$	5.18
	___________
	-1	Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data to provide a reasonable basis to estimate the expected term.
	-2	Zero Coupon U.S. Treasury rate or equivalent based on expected term.
	-3	Volatility calculated using the implied volatility of our exchange traded stock options.
	-4	We have never paid cash dividends on our common stock, and we do not anticipate any cash dividend payments on our common stock in the near future
Schedule of Restricted Stock and Restricted Stock Unit Activity	A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the year ended December 31, 2014, is as follows:
		Number of		Weighted
		Restricted		Average
		Stock Awards		Grant-Date
				Fair Value
	Nonvested — December 31, 2013	4,431,841		$	16.45
	Granted	1,885,049		$	19.34
	Forfeited	430,059		$	17.67
	Vested	1,684,963		$	15.51
	Nonvested — December 31, 2014	4,201,868		$	18.01

Capital_Structure_Tables

Capital Structure (Tables)	12 Months Ended
	Dec. 31, 2014
Capital Structure [Abstract]
Schedule of Common Stock Activity	The table below summarizes our common stock activity for the years ended December 31, 2014, 2013 and 2012.
		Shares	Shares		Shares
		Issued	Held in		Outstanding
			Treasury
	Balance, December 31, 2011	490,468,815	(8,725,077	)	481,743,738
	Shares issued under Calpine Equity Incentive Plans	2,026,285	(284,376	)	1,741,909
	Share repurchase program	—	(26,436,677	)	(26,436,677	)
	Balance, December 31, 2012	492,495,100	(35,446,130	)	457,048,970
	Shares issued under Calpine Equity Incentive Plans	5,345,956	(2,323,828	)	3,022,128
	Share repurchase program	—	(31,032,110	)	(31,032,110	)
	Balance, December 31, 2013	497,841,056	(68,802,068	)	429,038,988
	Shares issued under Calpine Equity Incentive Plans	4,445,966	(1,879,167	)	2,566,799
	Share repurchase program	—	(49,684,523	)	(49,684,523	)
	Balance, December 31, 2014	502,287,022	(120,365,758	)	381,921,264

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Power Plant and Land and Other Operating Leases	Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S. GAAP. Generally, we levelize certain components of these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2014, are as follows (in millions):
	2015	$	561
	2016	495
	2017	433
	2018	396
	2019	357
	Thereafter	1,380
	Total	$	3,622
	Future minimum rent payments under these lease agreements, including renewal options and rent escalation clauses, are as follows (in millions):
		Initial		2015			2016			2017			2018			2019			Thereafter			Total
		Year
	Land and other operating leases	various		$	15		$	16		$	15		$	15		$	15		$	201		$	277
	Power plant operating leases:
	Greenleaf	1998		$	4		$	—		$	—		$	—		$	—		$	—		$	4
	KIAC	2000		23			22			22			22			30			—			119
	Total power plant leases			$	27		$	22		$	22		$	22		$	30		$	—		$	123
	Total leases			$	42		$	38		$	37		$	37		$	45		$	201		$	400
Schedule of Future Minimum Lease Payments for Office and Equipment Leases	Future minimum lease payments under these leases are as follows (in millions):
	2015	$	11
	2016	10
	2017	9
	2018	9
	2019	8
	Thereafter	8
	Total	$	55
Schedule Of Future Minimum Payments For Commodities [Table Text Block]	At December 31, 2014, we had future commitments for the purchase, transportation, or storage of commodities as detailed below (in millions):
	2015	$	390
	2016	297
	2017	193
	2018	152
	2019	109
	Thereafter	622
	Total	$	1,763
Schedule of Guarantor Obligations	At December 31, 2014, guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and guarantees of subsidiary operating lease payments and their respective expiration dates were as follows (in millions):
	Guarantee Commitments		2015			2016			2017			2018			2019			Thereafter			Total
	Guarantee of subsidiary debt(1)		$	37		$	36		$	26		$	31		$	30		$	148		$	308
	Standby letters of credit(2)(3)(5)		572			14			20			—			—			38			644
	Surety bonds(4)(5)(6)		—			—			—			—			—			4			4
	Guarantee of subsidiary operating lease payments(5)		4			—			—			—			—			—			4
	Total		$	613		$	50		$	46		$	31		$	30		$	190		$	960
	____________
	-1	Represents Calpine Corporation guarantees of certain power plant capital leases and related interest. All guaranteed capital leases are recorded on our Consolidated Balance Sheets.
	-2	The standby letters of credit disclosed above represent those disclosed in Note 6.
	-3	Letters of credit are renewed annually and as such all amounts are reflected in the year of letter of credit expiration. The related commercial obligations extend for multiple years, therefore, renewal of the letter of credit will likely follow the term of the associated commercial obligation.
	-4	The majority of surety bonds do not have expiration or cancellation dates.
	-5	These are contingent off balance sheet obligations.
	-6	As of December 31, 2014, $2 million of cash collateral is outstanding related to these bonds.

Segment_and_Significant_Custom1

Segment and Significant Customer Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment and Significant Customer Information [Abstract]
Schedule of Financial Data for Segments	The tables below show our financial data for our segments for the periods indicated (in millions).
		Year Ended December 31, 2014
		West			Texas			East			Consolidation			Total
											and
											Elimination
	Revenues from external customers	$	2,352		$	3,229		$	2,449		$	—		$	8,030
	Intersegment revenues	6			23			47			(76		)	—
	Total operating revenues	$	2,358		$	3,252		$	2,496		$	(76	)	$	8,030
	Commodity Margin(1)	$	1,050		$	760		$	949		$	—		$	2,759
	Add: Mark-to-market commodity activity, net and other(2)	220			142			48			(31		)	379
	Less:
	Plant operating expense	385			313			302			(31		)	969
	Depreciation and amortization expense	245			191			168			(1		)	603
	Sales, general and other administrative expense	41			64			39			—			144
	Other operating expenses	50			5			32			1			88
	Impairment loss	—			—			123			—			123
	(Gain) on sale of assets, net	—			—			(753		)	—			(753		)
	(Income) from unconsolidated investments in power plants	—			—			(25		)	—			(25		)
	Income from operations	549			329			1,111			—			1,989
	Interest expense, net of interest income													639
	Debt extinguishment costs and other (income) expense, net													367
	Income before income taxes													$	983
		Year Ended December 31, 2013
		West			Texas			East			Consolidation			Total
											and
											Elimination
	Revenues from external customers	$	1,937		$	2,347		$	2,017		$	—		$	6,301
	Intersegment revenues	5			(4		)	117			(118		)	—
	Total operating revenues	$	1,942		$	2,343		$	2,134		$	(118	)	$	6,301
	Commodity Margin(1)	$	1,020		$	632		$	916		$	—		$	2,568
	Add: Mark-to-market commodity activity, net and other(2)	(50		)	51			27			(31		)	(3		)
	Less:
	Plant operating expense	365			269			292			(31		)	895
	Depreciation and amortization expense	227			165			203			(2		)	593
	Sales, general and other administrative expense	37			56			42			1			136
	Other operating expenses	45			3			33			—			81
	Impairment loss	16			—			—			—			16
	(Income) from unconsolidated investments in power plants	—			—			(30		)	—			(30		)
	Income from operations	280			190			403			1			874
	Interest expense, net of interest income													690
	Debt extinguishment costs and other (income) expense, net													164
	Income before income taxes													$	20
		Year Ended December 31, 2012
		West			Texas			East			Consolidation			Total
											and
											Elimination
	Revenues from external customers	$	1,668		$	1,857		$	1,953		$	—		$	5,478
	Intersegment revenues	10			61			38			(109		)	—
	Total operating revenues	$	1,678		$	1,918		$	1,991		$	(109	)	$	5,478
	Commodity Margin(1)(3)(4)	$	994		$	570		$	974		$	—		$	2,538
	Add: Mark-to-market commodity activity, net and other(2)	(93		)	87			(47		)	(31		)	(84		)
	Less:
	Plant operating expense	368			247			337			(30		)	922
	Depreciation and amortization expense	203			142			219			(2		)	562
	Sales, general and other administrative expense	36			47			57			—			140
	Other operating expenses	42			5			34			(3		)	78
	(Gain) on sale of assets, net	—			—			(222		)	—			(222		)
	(Income) from unconsolidated investments in power plants	—			—			(28		)	—			(28		)
	Income from operations	252			216			530			4			1,002
	Interest expense, net of interest income													725
	Loss on interest rate derivatives													14
	Debt extinguishment costs and other (income) expense, net													45
	Loss before income taxes													$	218
	__________
-1	Our East segment includes Commodity Margin of $81 million, $152 million and $131 million for the years ended December 31, 2014, 2013 and 2012, respectively, related to the six power plants in our East segment that were sold in July 2014.
-2	Includes $(5) million, $6 million and $1 million of lease levelization and $14 million, $14 million and $14 million of amortization expense for the years ended December 31, 2014, 2013 and 2012, respectively.
-3	Our East segment includes Commodity Margin of $52 million for the year ended December 31, 2012, related to Broad River, which was sold in December 2012.
-4	Our East segment includes Commodity Margin of $73 million for the year ended December 31, 2012, related to Riverside Energy Center, LLC, which was sold in December 2012.

Quarterly_Consolidated_Financi1

Quarterly Consolidated Financial Data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Consolidated Financial Data (unaudited)
		Quarter Ended
		December 31			September 30		June 30			March 31
		(in millions, except per share amounts)
	2014
	Operating revenues	$	1,939		$	2,187	$	1,939		$	1,965
	Income from operations	$	390		$	1,126	$	329		$	144
	Net income (loss) attributable to Calpine	$	210		$	614	$	139		$	(17	)
	Net income (loss) per common share attributable to Calpine — Basic	$	0.55		$	1.54	$	0.33		$	(0.04	)
	Net income (loss) per common share attributable to Calpine — Diluted	$	0.54		$	1.52	$	0.33		$	(0.04	)
	2013
	Operating revenues	$	1,438		$	2,050	$	1,572		$	1,241
	Income from operations	$	151		$	597	$	122		$	4
	Net income (loss) attributable to Calpine	$	(97	)	$	306	$	(70	)	$	(125	)
	Net income (loss) per common share attributable to Calpine — Basic	$	(0.23	)	$	0.7	$	(0.16	)	$	(0.28	)
	Net income (loss) per common share attributable to Calpine — Diluted	$	(0.23	)	$	0.7	$	(0.16	)	$	(0.28	)

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Cash and Cash Equivalents Items [Line Items]
Current	$195	$203
Non-current	49	69
Total	244	272
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]
Cash and cash equivalents subject to project finance facilities and lease agreements	257	292
Property, plant and equipment, salvage value (as a percent)	10.00%
Property, plant and equipment, salvage value of rotables (as a percent)	0.15%
Osprey Energy Center Agreement Term	0 years 27 months
Impairment losses	123	16	0
Asset retirement obligations	47	44
Freestone Energy Center [Member]
Jointly Owned Plants [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share	75.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	389
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	-140
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Hidalgo Energy Center [Member]
Jointly Owned Plants [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share	78.50%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	257
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	-104
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Debt Service
Restricted Cash and Cash Equivalents Items [Line Items]
Current	10	11
Non-current	25	41
Total	35	52
Rent Reserve [Member]
Restricted Cash and Cash Equivalents Items [Line Items]
Current	4	3
Non-current	0	0
Total	4	3
Construction Major Maintenance
Restricted Cash and Cash Equivalents Items [Line Items]
Current	54	35
Non-current	17	20
Total	71	55
Security Project Insurance
Restricted Cash and Cash Equivalents Items [Line Items]
Current	127	151
Non-current	5	6
Total	132	157
Other
Restricted Cash and Cash Equivalents Items [Line Items]
Current	0	3
Non-current	2	2
Total	$2	$5
Greenfield [Member]
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]
Ownership percentage in equity method investment	50.00%
Whitby [Member]
Basis Of Presentation and Summary of Significant Accounting Policies (Textuals) [Abstract]
Ownership percentage in equity method investment	50.00%

Summary_of_Significant_Account4

Summary of Significant Accounting Policies Contractual Future Minimum Lease Receipt Table (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Summary of Significant Accounting Policies [Abstract]
Operating Leases, Future Minimum Payments Receivable, Current	$561
Operating Leases, Future Minimum Payments Receivable, in Two Years	495
Operating Leases, Future Minimum Payments Receivable, in Three Years	433
Operating Leases, Future Minimum Payments Receivable, in Four Years	396
Operating Leases, Future Minimum Payments Receivable, in Five Years	357
Operating Leases, Future Minimum Payments Receivable, Thereafter	1,380
Operating Leases, Future Minimum Payments Receivable	$3,622

Acquisitions_Divestitures_and_2

Acquisitions, Divestitures and Discontinued Operations (Textuals) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 27, 2012	Jul. 03, 2014	Sep. 30, 2014
	MW	MW				MW
Business Acquisition [Line Items]
Power generation capacity	10,365	9,427
(Gain) on sale of power plants, net	$753	$0	$222
Fore River Energy Center [Member]
Business Acquisition [Line Items]
Power generation capacity	809
Business Acquisition, Purchase Price Allocation, Assets Acquired	530
Guadalupe Energy Center [Member]
Business Acquisition [Line Items]
Power generation capacity	1,050
Business Acquisition, Purchase Price Allocation, Assets Acquired	625
Guadalupe Expansion Capacity [Member]
Business Acquisition [Line Items]
Power generation capacity	400
Business Acquisition, Purchase Price Allocation, Assets Acquired	15
Bosque Energy Center [Member]
Business Acquisition [Line Items]
Power generation capacity		800
Business Acquisition, Purchase Price Allocation, Assets Acquired		432
Block one power generation capacity		250
Block two power generation capacity		550
Riverside Energy Center [Member]
Business Acquisition [Line Items]
Power generation capacity		603
Proceeds from Sale of Productive Assets		402
Gain (Loss) on Disposition of Assets		7
Broad River Energy Center [Member]
Business Acquisition [Line Items]
Power generation capacity		847
Proceeds from Sale of Productive Assets		423
Gain (Loss) on Disposition of Assets		215
Ownership percentage before divestiture of business				100.00%
Incremental CCFC Term Loans [Member]
Business Acquisition [Line Items]
Debt Instrument, Face Amount	425
Six Power Plants [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Productive Assets	1,570
Number of power plants disposed of	6
Ownership percentage before divestiture of business					100.00%
Working Capital Adjustment to Sale price	2
Cost of Property Repairs and Maintenance	12
Business Combination, Contingent Consideration, Liability	4
(Gain) on sale of power plants, net	$753
Oneta Energy Center [Member]
Business Acquisition [Line Items]
Power generation capacity						1,134
Carville Energy Center [Member]
Business Acquisition [Line Items]
Power generation capacity						501	[1]
Decatur Energy Center [Member]
Business Acquisition [Line Items]
Power generation capacity						795
Hog Bayou Energy Center [Member]
Business Acquisition [Line Items]
Power generation capacity						237
Santa Rosa Energy Center [Member]
Business Acquisition [Line Items]
Power generation capacity						225
Columbia Energy Center [Member]
Business Acquisition [Line Items]
Power generation capacity						606	[1]
Six Power Plants [Member]
Business Acquisition [Line Items]
Power generation capacity						3,498
[1]	Indicates combined-cycle cogeneration power plant.

Property_Plant_and_Equipment_N2

Property, Plant and Equipment, Net (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Buildings, machinery and equipment	$16,059	$15,838
Geothermal properties	1,294	1,265
Other	203	164
Property, Plant and Equipment, Gross	17,556	17,267
Less: Accumulated depreciation	4,984	4,897
Property, Plant and Equipment, Gross, Less Accumulated Depreciation	12,572	12,370
Land	120	103
Construction in progress	498	522
Property, plant and equipment, net	13,190	12,995
Interest Costs, Capitalized During Period	$19	$38	$38
Building, Machinery and Equipment, Gross [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	3 years
Building, Machinery and Equipment, Gross [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	47 years
Geothermal Properties, Gross [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	13 years
Geothermal Properties, Gross [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	59 years
Property, Plant and Equipment, Other Types [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	3 years
Property, Plant and Equipment, Other Types [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Estimated Useful Lives	47 years

Variable_Interest_Entities_and2

Variable Interest Entities and Unconsolidated Investments (Unconsolidated VIEs) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Equity Method Investments Included on Balance Sheet [Abstract]
Equity Method Investments	$95	$93
Greenfield [Member]
Equity Method Investments Included on Balance Sheet [Abstract]
Equity Method Investments	78	76
Equity Method Investment, Ownership Percentage	50.00%
Whitby [Member]
Equity Method Investments Included on Balance Sheet [Abstract]
Equity Method Investments	$17	$17
Equity Method Investment, Ownership Percentage	50.00%

Variable_Interest_Entities_and3

Variable Interest Entities and Unconsolidated Investments (Unconsolidated Investements) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
(Income) from unconsolidated investments in power plants	($25)	($30)	($28)
Distributions from Equity Method Investments	13	27	29
Greenfield [Member]
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
(Income) from unconsolidated investments in power plants	-10	-16	-17
Distributions from Equity Method Investments	0	18	22
Whitby [Member]
Income Loss from Unconsolidated Investments in Power Plants and Distributions [Line Items]
(Income) from unconsolidated investments in power plants	-15	-14	-11
Distributions from Equity Method Investments	$13	$9	$7

Variable_Interest_Entities_and4

Variable Interest Entities and Unconsolidated Investments (Equity Method Investment Summarized Financial Information) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity Method Investment, Summarized Financial Information, Assets [Abstract]
Equity Method Investment Summarized Financial Information Cash and Cash Equivalents	$58	$57
Equity Method Investment, Summarized Financial Information, Current Assets	28	25
Equity Method Investment, Summarized Financial Information, Property, Plant and Equipment, net	532	588
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	2	2
Equity Method Investment, Summarized Financial Information, Assets	620	672
Equity Method Investment, Summarized Financial Information, Liabilities [Abstract]
Equity Method Investment, Summarized Financial Information, Current Maturities of Long-term Debt	21	23
Equity Method Investment, Summarized Financial Information, Current Liabilities	28	44
Equity Method Investment, Summarized Financial Information, Long-Term Debt	321	372
Equity Method Investment, Summarized Financial Information, Long-term Derivative Liabilities	51	35
Equity Method Investment, Summarized Financial Information, Liabilities	421	474
Equity Method Investment Summarized Financial Information, Equity [Abstract]
Equity Method Investment Summarized Financial Information, Equity	199	198
Equity Method Investment, Summarized Financial Information, Liabilities and Equity	620	672
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss) [Abstract]
Equity Method Investment, Summarized Financial Information, Revenue	239	207	247
Equity Method Investment, Summarized Financial Information, Cost of Sales	168	128	171
Equity Method Investment, Summarized Financial Information, Gross Profit (Loss)	71	79	76
Equity Method Investment Summarized Financial Information Interest (Income) Expense	23	24	27
Equity Method Investment Summarized Financial Information Other (Income) Expense Net	0	-3	-2
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	$48	$58	$51

Variable_Interest_Entities_and5

Variable Interest Entities and Unconsolidated Investments (VIE Textuals) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MW	MW
Schedule of Equity Method Investments [Line Items]
Power generation capacity	10,365	9,427
Variable Interest Entity, Financial or Other Support, Amount	$47,000,000	$0	$20,000,000
Equity Method Investment, Summarized Financial Information, Debt	342,000,000	395,000,000
Prorata Share of Equity Method Investment, Summarized Financial Information, Debt	$171,000,000	$198,000,000
Russell City Energy [Member]
Schedule of Equity Method Investments [Line Items]
Minority Interest Ownership Percentage By Noncontrolling Third Party Owners	25.00%
Equity Method Investment, Ownership Percentage	75.00%
Inland Empire Energy Center [Member]
Schedule of Equity Method Investments [Line Items]
Power generation capacity	775
Put Option Exercise Period	2,025
Minimum [Member] | Inland Empire Energy Center [Member]
Schedule of Equity Method Investments [Line Items]
Call Option Exercise Period	2,017
Maximum [Member] | Inland Empire Energy Center [Member]
Schedule of Equity Method Investments [Line Items]
Call Option Exercise Period	2,024
Greenfield [Member]
Schedule of Equity Method Investments [Line Items]
Power generation capacity	1,038
Equity Method Investment, Ownership Percentage	50.00%
Whitby [Member]
Schedule of Equity Method Investments [Line Items]
Power generation capacity	50
Equity Method Investment, Ownership Percentage	50.00%

Debt_Debt_Details

Debt (Debt) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	$11,282	$11,112
Debt, current portion	199	204
Debt, net of current portion	11,083	10,908
Corporate Debt Securities [Member]
Debt Instrument [Line Items]
Long-term Debt	2,075	4,989
Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	2,800	0
Loans Payable [Member]
Debt Instrument [Line Items]
Long-term Debt	2,799	2,828
Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Long-term Debt	1,810	1,901
Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	1,596	1,191
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Long-term Debt	$202	$203

Debt_Annual_Debt_Marturities_D

Debt (Annual Debt Marturities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Long-term Debt, Fiscal Year Maturity [Abstract]
2015	$199
2016	205
2017	562
2018	1,730
2019	1,217
Thereafter	7,393
Total debt, gross	11,306
Less: Discount	24
Debt and Capital Lease Obligations	$11,282	$11,112

Debt_Debt_First_Lien_Notes_Det

Debt Debt (First Lien Notes) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
First Lien Notes 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt	$0	[1]	$320	[1]
Debt Instrument, Interest Rate, Effective Percentage	0.00%	[2]	8.20%	[2]
First Lien Notes 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt	0	[1]	875	[1]
Debt Instrument, Interest Rate, Effective Percentage	0.00%	[2]	8.20%	[2]
First Lien Notes 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt	0	[1]	1,600	[1]
Debt Instrument, Interest Rate, Effective Percentage	0.00%	[2]	7.70%	[2]
2022 First Lien Notes [Member]
Debt Instrument [Line Items]
Long-term Debt	745		744
Debt Instrument, Interest Rate, Effective Percentage	6.30%	[2]	6.20%	[2]
First Lien Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	840	[3]	960	[3]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	10.00%
Debt Instrument, Interest Rate, Effective Percentage	8.00%	[2]	8.00%	[2]
2024 First Lien Notes [Member]
Debt Instrument [Line Items]
Long-term Debt	490		490
Debt Instrument, Interest Rate, Effective Percentage	6.00%	[2]	5.90%	[2]
Corporate Debt Securities [Member]
Debt Instrument [Line Items]
Long-term Debt	$2,075		$4,989
[1]	The 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes were repaid during the third quarter of 2014 with the proceeds from the issuance of our Senior Unsecured Notes, together with cash on hand, which are described in further detail below.
[2]	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
[3]	In December 2014, we used cash on hand to redeem 10% of the original aggregate principal amount of our 2023 First Lien Notes, plus accrued and unpaid interest. On February 3, 2015, we additionally repurchased approximately $150 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, which is described in further detail below.

Debt_Senior_Unsecured_Notes_De

Debt Senior Unsecured Notes (Details) (USD $)	12 Months Ended					3 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Sep. 30, 2014	Feb. 03, 2015
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt	($346,000,000)		($144,000,000)		($30,000,000)
Senior Unsecured Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	1,250,000,000		0
Debt Instrument, Interest Rate, Effective Percentage	5.60%	[1]	0.00%	[1]
Debt Instrument, Face Amount						1,250,000,000
Debt Instrument, Interest Rate, Stated Percentage						5.38%
Senior Unsecured Notes 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt	1,550,000,000		0
Debt Instrument, Interest Rate, Effective Percentage	5.90%	[1]	0.00%	[1]
Debt Instrument, Face Amount						1,550,000,000
Debt Instrument, Interest Rate, Stated Percentage						5.75%
Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	2,800,000,000		0
2019, 2020 and 2021 First Lien Notes [Member]
Debt Instrument [Line Items]
Deferred Finance Costs, Net						42,000,000
Gains (Losses) on Extinguishment of Debt						-340,000,000
First Lien Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	840,000,000	[2]	960,000,000	[2]
Debt Instrument, Interest Rate, Effective Percentage	8.00%	[1]	8.00%	[1]
Subsequent Event [Member] | Senior Unsecured Notes 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount							650,000,000
Debt Instrument, Interest Rate, Stated Percentage							5.50%
Subsequent Event [Member] | First Lien Notes 2023 [Member] | Early Redemption Amount [Member]
Debt Instrument [Line Items]
Long-term Debt							$150,000,000
[1]	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
[2]	In December 2014, we used cash on hand to redeem 10% of the original aggregate principal amount of our 2023 First Lien Notes, plus accrued and unpaid interest. On February 3, 2015, we additionally repurchased approximately $150 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, which is described in further detail below.

Debt_Debt_First_Lien_Term_Loan

Debt Debt (First Lien Term Loans) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
First Lien Term Loans 2018 [Member]
Debt Instrument [Line Items]
Long-term Debt	$1,597		$1,614
Debt Instrument, Interest Rate, Effective Percentage	4.30%	[1]	4.30%	[1]
First Lien Term Loan 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt	816		824
Debt Instrument, Interest Rate, Effective Percentage	4.40%	[1]	4.50%	[1]
2020 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Long-term Debt	386		390
Debt Instrument, Interest Rate, Effective Percentage	4.30%	[1]	4.30%	[1]
Loans Payable [Member]
Debt Instrument [Line Items]
Long-term Debt	$2,799		$2,828
[1]	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.

Debt_CCFC_Term_Loans_Details

Debt CCFC Term Loans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Incremental CCFC Term Loans [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$425
Long Term Debt net of Original Issuance Disount	98.75%
Secured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	1,596		1,191
Debt Instrument, Interest Rate, Effective Percentage	3.40%	[1]	3.30%	[1]
Term loan interest rate spread option Federal Funds effective rate	0.50%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	0.75%
Long Term Debt net of Original Issuance Disount	99.75%
Percentage of the principal amount of the Term Loan to be paid quarterly	0.25%
CCFC Term Loan B-1 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			900
Term Loan Period	7 years
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum	2.25%
Term loan interest rate spread option Prime Rate	1.25%
CCFC Term Loan B-2 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$300
Term Loan Period	8 years 6 months
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum	2.50%
Term loan interest rate spread option Prime Rate	1.50%
[1]	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.

Debt_Project_Financing_Notes_P

Debt (Project Financing, Notes Payable and Others) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Russell City Project [Member]
Debt Instrument [Line Items]
Long-term Debt	$591		$593
Debt Instrument, Interest Rate, Effective Percentage	6.20%	[1]	4.90%	[1]
Steamboat [Member]
Debt Instrument [Line Items]
Long-term Debt	407		418
Debt Instrument, Interest Rate, Effective Percentage	6.90%	[1]	6.80%	[1]
OMEC [Member]
Debt Instrument [Line Items]
Long-term Debt	325		335
Debt Instrument, Interest Rate, Effective Percentage	6.90%	[1]	6.90%	[1]
Los Esteros Project [Member]
Debt Instrument [Line Items]
Long-term Debt	275		305
Debt Instrument, Interest Rate, Effective Percentage	3.10%	[1]	3.40%	[1]
Pasadena [Member]
Debt Instrument [Line Items]
Long-term Debt	122	[2]	135	[2]
Debt Instrument, Interest Rate, Effective Percentage	8.90%	[1],[2]	8.90%	[1],[2]
Bethpage [Member]
Debt Instrument [Line Items]
Long-term Debt	82	[3]	88	[3]
Debt Instrument, Interest Rate, Effective Percentage	7.00%	[1],[3]	7.00%	[1],[3]
Gilroy note payable [Member]
Debt Instrument [Line Items]
Long-term Debt	0		15
Debt Instrument, Interest Rate, Effective Percentage	0.00%	[1]	11.20%	[1]
Other Debt Obligations [Member]
Debt Instrument [Line Items]
Long-term Debt	8		12
Debt Instrument, Interest Rate, Effective Percentage	0.00%	[1]	0.00%	[1]
Project Financing Total [Member]
Debt Instrument [Line Items]
Long-term Debt	$1,810		$1,901
[1]	Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount or premium.
[2]	Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.
[3]	Represents a weighted average of first and second lien loans for the weighted average effective interest rates.

Debt_Capital_Lease_Obligations

Debt (Capital Lease Obligations) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Minimum Lease Payments, Sale Leaseback Transactions, Fiscal Year Maturity [Abstract]
Minimum Lease Payments, Sale Leaseback Transactions, within One Year	$25	[1]
Minimum Lease Payments, Sale Leaseback Transactions, within Two Years	25	[1]
Minimum Lease Payments, Sale Leaseback Transactions, within Three Years	17	[1]
Minimum Lease Payments, Sale Leaseback Transactions, within Four Years	21	[1]
Minimum Lease Payments, Sale Leaseback Transactions, within Five Years	21	[1]
Minimum Lease Payments, Sale Leaseback Transactions, Thereafter	85	[1]
Minimum Lease Payments, Sale Leaseback Transactions	194	[1]
Interest Portion of Minimum Lease Payments, Sale Leaseback Transactions	72	[1]
Present Value of Future Minimum Lease Payments, Sale Leaseback Transactions	122	[1]
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Capital Leases, Future Minimum Payments Due, Current	47
Capital Leases, Future Minimum Payments Due in Two Years	41
Capital Leases, Future Minimum Payments Due in Three Years	39
Capital Leases, Future Minimum Payments Due in Four Years	38
Capital Leases, Future Minimum Payments Due in Five Years	20
Capital Leases, Future Minimum Payments Due Thereafter	151
Capital Leases, Future Minimum Payments Due	336
Capital Leases, Future Minimum Payments, Interest Included in Payments	134
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	202
Total Leases Future Minimum Payments [Abstract]
Total Leases, Future Minimum Payments Due, Current	72
Total Leases, Future Minimum Payments Due in Two Years	66
Total Leases, Future Minimum Payments Due in Three Years	56
Total Leases, Future Minimum Payments Due in Four Years	59
Total Leases, Future Minimum Payments Due in Five Years	41
Total Leases, Future Minimum Payments Due Thereafter	236
Total Leases, Future Minimum Payments Due	530
Total Leases, Future Minimum Payments, Interest Included in Payments	206
Total Leases, Future Minimum Payments, Present Value of Net Minimum Payments	$324
[1]	Amounts are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes payable and other amounts above.

Debt_Corporate_Revolving_Facil

Debt (Corporate Revolving Facility and other Letters of Credit Facilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Line of Credit Facility [Line Items]
Line of Credit Facility, Fair Value of Amount Outstanding	$644	$630
Corporate Revolving Facility [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Fair Value of Amount Outstanding	223	242
CDH [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Fair Value of Amount Outstanding	214	218
Various Project Financing Facilities [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Fair Value of Amount Outstanding	$207	$170

Debt_Fair_Value_of_Debt_Detail

Debt (Fair Value of Debt) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	$2,247		$5,317
Senior Unsecured Notes, Fair Value Disclosure	2,832		0
Loans Payable, Fair Value Disclosure	2,769		2,845
Notes Payable, Other Payables, Disclosure	1,734	[1]	1,772	[1]
Subsidiaries Term Loan	1,540		1,179
Debt Excluding Capital Leases	11,122		11,113
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Notes Payable, Fair Value Disclosure	2,075		4,989
Senior Unsecured Notes, Fair Value Disclosure	2,800		0
Loans Payable, Fair Value Disclosure	2,799		2,828
Notes Payable, Other Payables, Disclosure	1,688	[1]	1,766	[1]
Subsidiaries Term Loan	1,596		1,191
Debt Excluding Capital Leases	$10,958		$10,774
[1]	Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

Debt_Textuals_Details

Debt (Textuals) (Details) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt	($346,000,000)	($144,000,000)	($30,000,000)
Maximum Remaining Lease Term	34 years
Lease Assets, Historical Cost	933,000,000	862,000,000
Lease Assets, Accumulated Depreciation	395,000,000	343,000,000
First Lien Term Loans [Member]
Debt Instrument [Line Items]
Term loan interest rate spread option Federal Funds effective rate	0.50%
Term loan interest rate spread option Prime Rate	2.00%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum	3.00%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	1.00%
Percentage of principal amount of Term Loan to be paid quarterly	0.25%
Corporate Revolving Facility [Member]
Debt Instrument [Line Items]
Percentage added to Federal Funds Effective Rate to arrive at base rate	0.50%
Repayment time for drawings under letters of credit	2 days
Excess amount of asset sales requiring mandatory prepayments	3,000,000,000
Corporate Revolving Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Applicable margin range percentage above base rate	1.00%
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates	2.00%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.25%
Corporate Revolving Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Applicable margin range percentage above base rate	1.25%
Applicable Margin Range Percentage Above British Bankers' Association Interest Settlement Rates	2.25%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
CDHI [Member]
Debt Instrument [Line Items]
Letter of Credit Total	300,000,000
One Month [Member] | Corporate Revolving Facility [Member]
Debt Instrument [Line Items]
Interest periods for LIBOR rate borrowings	1 month
Two Months [Member] | Corporate Revolving Facility [Member]
Debt Instrument [Line Items]
Interest periods for LIBOR rate borrowings	2 months
Three Months [Member] | Corporate Revolving Facility [Member]
Debt Instrument [Line Items]
Interest periods for LIBOR rate borrowings	3 months
Six Months [Member] | Corporate Revolving Facility [Member]
Debt Instrument [Line Items]
Interest periods for LIBOR rate borrowings	6 months
Nine Months [Member] | Corporate Revolving Facility [Member]
Debt Instrument [Line Items]
Interest periods for LIBOR rate borrowings	9 months
Twelve Months [Member] | Corporate Revolving Facility [Member]
Debt Instrument [Line Items]
Interest periods for LIBOR rate borrowings	12 months
Corporate Revolving Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Increase (Decrease), Net				500,000,000
Line of Credit Facility, Maximum Borrowing Capacity				$1,500,000,000

Assets_and_Liabilities_with_Re2

Assets and Liabilities with Recurring Fair Value Measurements (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	$896	[1]	$1,134	[1]
Margin Deposit Assets	96	[2]	261	[2]
Commodity futures contracts	2,134		434
Commodity forward contracts	359	[3]	107	[3]
Interest rate swaps	4		9
Total assets	3,489		1,945
Security Deposit Liability	47	[2],[4]	5	[2],[4]
Commodity futures contracts	1,870		495
Commodity forward contracts	242	[3]	70	[3]
Interest rate swaps	114		129
Total liabilities	2,273		699
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	896	[1]	1,134	[1]
Margin Deposit Assets	96		261
Commodity futures contracts	2,134		434
Commodity forward contracts	0	[3]	0	[3]
Interest rate swaps	0		0
Total assets	3,126		1,829
Security Deposit Liability	47		5
Commodity futures contracts	1,870		495
Commodity forward contracts	0	[3]	0	[3]
Interest rate swaps	0		0
Total liabilities	1,917		500
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[1]	0	[1]
Margin Deposit Assets	0		0
Commodity futures contracts	0		0
Commodity forward contracts	195	[3]	75	[3]
Interest rate swaps	4		9
Total assets	199		84
Security Deposit Liability	0		0
Commodity futures contracts	0		0
Commodity forward contracts	163	[3]	52	[3]
Interest rate swaps	114		129
Total liabilities	277		181
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[1]	0	[1]
Margin Deposit Assets	0		0
Commodity futures contracts	0		0
Commodity forward contracts	164	[3]	32	[3]
Interest rate swaps	0		0
Total assets	164		32
Security Deposit Liability	0		0
Commodity futures contracts	0		0
Commodity forward contracts	79	[3]	18	[3]
Interest rate swaps	0		0
Total liabilities	$79		$18
[1]	As of December 31, 2014 and 2013, we had cash equivalents of $679 million and $889 million included in cash and cash equivalents and $217 million and $245 million included in restricted cash, respectively.
[2]	Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated 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 8 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 Balance Sheets.

Assets_and_Liabilities_with_Re3

Assets and Liabilities with Recurring Fair Value Measurements Quantitative Information about Level 3 Fair Value Measurements (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Quantitative Information about Level 3 fair Value Measurements [Line Items]
Derivative, Fair Value, Net	$271,000,000	($144,000,000)
Physical Power [Member]
Quantitative Information about Level 3 fair Value Measurements [Line Items]
Derivative, Fair Value, Net	74,000,000	7,000,000
Natural Gas [Member]
Quantitative Information about Level 3 fair Value Measurements [Line Items]
Derivative, Fair Value, Net	5,000,000	0
Power Congestion Products [Member]
Quantitative Information about Level 3 fair Value Measurements [Line Items]
Derivative, Fair Value, Net	9,000,000	7,000,000
Minimum [Member] | Physical Power [Member]
Quantitative Information about Level 3 fair Value Measurements [Line Items]
Fair Value Inputs Quantitative Information	14	28.92
Minimum [Member] | Natural Gas [Member]
Quantitative Information about Level 3 fair Value Measurements [Line Items]
Fair Value Inputs Quantitative Information	1	0
Minimum [Member] | Power Congestion Products [Member]
Quantitative Information about Level 3 fair Value Measurements [Line Items]
Fair Value Inputs Quantitative Information	-19.56	-8.79
Maximum [Member] | Physical Power [Member]
Quantitative Information about Level 3 fair Value Measurements [Line Items]
Fair Value Inputs Quantitative Information	122.79	53.15
Maximum [Member] | Natural Gas [Member]
Quantitative Information about Level 3 fair Value Measurements [Line Items]
Fair Value Inputs Quantitative Information	10.86	0
Maximum [Member] | Power Congestion Products [Member]
Quantitative Information about Level 3 fair Value Measurements [Line Items]
Fair Value Inputs Quantitative Information	$19.56	$11.53

Assets_and_Liabilities_with_Re4

Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period	$14		$16		$17
Included in net income:
Included in operating revenues	70	[1]	5	[1]	8	[1]
Included in fuel and purchased energy expense	5	[2]	0	[2]	0	[2]
Purchases, issuances and settlements:
Purchases	6		6		3
Issuances	0		-2		-1
Settlements	-10		-11		-11
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount	0		0		0
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount	0		0		0
Transfers into level 3	0	[3],[4]	0	[3],[4]	0	[3],[4]
Transfers out of level 3	0	[4],[5]	0	[4],[5]	0	[4],[5]
Balance, end of period	85		14		16
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	75		5		8
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) [Abstract]
Cash Equivalents Included In Cash And Cash Equivalents, Fair Value Disclosure	679		889
Cash Equivalents Included In Restricted Cash, Fair Value Disclosure	$217		$245
[1]	For power contracts and other power-related products, included on our Consolidated Statements of Operations.
[2]	For natural gas contracts, swaps and options, included on our Consolidated Statements of Operations.
[3]	There were no transfers out of level 2 into level 3 for the years ended December 31, 2014, 2013 and 2012.
[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 during the years ended December 31, 2014, 2013 and 2012.
[5]	There were no transfers out of level 3 for the years ended December 31, 2014, 2013 and 2012.

Derivative_Instruments_Details

Derivative Instruments (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
	MWh	MWh
Power [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	-62	-29
Natural Gas [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	291	448
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Notional Amount	1,431	1,527

Derivative_Instruments_Details1

Derivative Instruments (Details 2) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivatives, Fair Value [Line Items]
Derivative Instruments and Hedges, Assets	$2,058	$445
Long-term derivative assets	439	105
Total derivative assets	2,497	550
Derivative liabilities, current	1,782	451
Long-term derivative liabilities	444	243
Derivative Liability, Fair Value, Gross Liability	2,226	694
Net derivative assets (liabilities)	271	-144
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	4	9
Derivative Liability, Fair Value, Gross Liability	112	115
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	2,493	541
Derivative Liability, Fair Value, Gross Liability	2,114	579
Energy Related Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, current	2,058	445
Derivative Asset, Noncurrent	435	96
Total derivative assets	2,493	541
Derivative Liability, Current	1,738	404
Derivative Liability, Noncurrent	374	161
Derivative Liability, Fair Value, Gross Liability	2,112	565
Net derivative assets (liabilities)	381	-24
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	2,493	541
Derivative Liability, Fair Value, Gross Liability	2,112	565
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, current	0	0
Derivative Asset, Noncurrent	4	9
Total derivative assets	4	9
Derivative Liability, Current	44	47
Derivative Liability, Noncurrent	70	82
Derivative Liability, Fair Value, Gross Liability	114	129
Net derivative assets (liabilities)	-110	-120
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	4	9
Derivative Liability, Fair Value, Gross Liability	112	115
Interest Rate Swap [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	0	0
Derivative Liability, Fair Value, Gross Liability	$2	$14

Derivative_Instruments_Details2

Derivative Instruments (Details 3) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Sale of Derivatives									$110	[1]	$86	[1]	$230	[1]
Unrealized Gain (Loss) on Derivatives									353	[2]	-12	[2]	72	[2]
Derivatives contracts included in operating revenues	1,939	2,187	1,939	1,965	1,438	2,050	1,572	1,241	8,030		6,301		5,478
Derivatives contracts included in fuel and purchased energy									4,892		3,736		3,024
Interest expense									645		696		736
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments									0		0		-14
Gain (Loss) on Derivative Instruments, Net, Pretax									463		74		302
Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Sale of Derivatives									110	[1]	86	[1]	387	[1]
Unrealized Gain (Loss) on Derivatives									342	[2]	-14	[2]	-82	[2]
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Sale of Derivatives									0	[1]	0	[1]	-157	[1]
Unrealized Gain (Loss) on Derivatives									11	[2]	2	[2]	154	[2]
Interest expense									11		2		11
Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives contracts included in operating revenues									384		-119		187
Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives contracts included in fuel and purchased energy									$68		$191		$118
[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_Details3

Derivative Instruments (Details 4) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Gains (Loss) Recognized in OCI (Effective Portion)	($2)	[1]	$86	[1]	($81)	[1]
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)	-46	[1]	-51	[1]	20	[1]
Power Derivative Instruments [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gains (Loss) Recognized in OCI (Effective Portion)	0	[1],[2]	0	[1],[2]	-97	[1],[2]
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)	0	[2],[3]	0	[2],[3]	118	[2],[3]
Natural Gas Derivative Instruments [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gains (Loss) Recognized in OCI (Effective Portion)	0	[1],[2]	0	[1],[2]	59	[1],[2]
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)	0	[2],[3]	0	[2],[3]	-66	[2],[3]
Interest Expense [Member] | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gains (Loss) Recognized in OCI (Effective Portion)	-2	[1],[4]	86	[1],[4]	-43	[1],[4]
Gain (Loss) Reclassified from AOCI into Income (EffectivePortion)	($46)	[3],[4],[5]	($51)	[3],[4],[5]	($32)	[3],[4]
[1]	We recorded income tax expense of nil and $3 million for the years ended December 31, 2014 and 2013, respectively, and an income tax benefit of $11 million for the year ended December 31, 2012, in AOCI related to our cash flow hedging activities.
[2]	There were no commodity derivative instruments designated as cash flow hedges during the year ended December 31, 2014 and 2013. We recorded a gain on hedge ineffectiveness of $2 million related to our commodity derivative instruments designated as cash flow hedges during the year ended December 31, 2012.
[3]	Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $149 million, $148 million and $222 million at December 31, 2014, 2013 and 2012, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $12 million, $11 million and $20 million at December 31, 2014, 2013 and 2012, respectively.
[4]	We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the years ended December 31, 2014, 2013 and 2012.
[5]	Includes a loss of $10 million and $12 million that was reclassified from AOCI to interest expense for the years ended December 31, 2014 and 2013, respectively, where the hedged transactions are no longer expected to occur.

Derivative_Instruments_Textual

Derivative Instruments (Textuals) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Maximum length of time hedging using interest rate derivative instruments	9 years
Derivative, Net Liability Position, Aggregate Fair Value	$19
Collateral Already Posted, Aggregate Fair Value	11
Additional Collateral, Aggregate Fair Value	5
Other Comprehensive Income Loss Derivatives Qualifying As Hedges Tax	0	3	11
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	-2
(Gain) Loss on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net	10	12
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	-46
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments	0	0	-14
Gain Loss On Interest Rate Derivative Instruments Not Designated As Hedging Instruments, Unrealized			14
Gain Loss On Interest Rate Derivative Instruments Not Designated As Hedging Instruments, Realized			142
Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments			156
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	-149	-148	-222
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	($12)	($11)	($20)

Derivative_Instruments_Detail_

Derivative Instruments (Detail 5) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$2,497		$550
Derivative Asset, Not Offset, Policy Election Deduction	-2,087		-480
Derivative, Collateral, Obligation to Return Cash	-269	[1]	-14	[1]
Derivative Asset, Fair Value, Amount Offset Against Collateral	141		56
Derivative Liability, Fair Value, Gross Liability	-2,226		-694
Derivative Liability, Not Offset, Policy Election Deduction	2,087		480
Derivative, Collateral, Right to Reclaim Cash	15	[1]	76	[1]
Derivative Liability, Fair Value, Amount Offset Against Collateral	-124		-138
Net derivative assets (liabilities)	271		-144
Derivative Fair Value, Amount Not Offset Against Collateral, Net	0		0
Derivative, Collateral, Right to Reclaim Cash, Net	-254	[1]	62	[1]
Derivative, Fair Value, Amount Offset Against Collateral, Net	17		-82
Commodity Exchange Traded Futures and Swaps Contracts [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,134		434
Derivative Asset, Not Offset, Policy Election Deduction	-1,865		-420
Derivative, Collateral, Obligation to Return Cash	-269	[1]	-14	[1]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		0
Derivative Liability, Fair Value, Gross Liability	-1,870		-495
Derivative Liability, Not Offset, Policy Election Deduction	1,865		420
Derivative, Collateral, Right to Reclaim Cash	5	[1]	75	[1]
Derivative Liability, Fair Value, Amount Offset Against Collateral	0		0
Commodity Forward Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	359		107
Derivative Asset, Not Offset, Policy Election Deduction	-222		-60
Derivative, Collateral, Obligation to Return Cash	0	[1]	0	[1]
Derivative Asset, Fair Value, Amount Offset Against Collateral	137		47
Derivative Liability, Fair Value, Gross Liability	-242		-70
Derivative Liability, Not Offset, Policy Election Deduction	222		60
Derivative, Collateral, Right to Reclaim Cash	10	[1]	1	[1]
Derivative Liability, Fair Value, Amount Offset Against Collateral	-10		-9
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	4		9
Derivative Asset, Not Offset, Policy Election Deduction	0		0
Derivative, Collateral, Obligation to Return Cash	0	[1]	0	[1]
Derivative Asset, Fair Value, Amount Offset Against Collateral	4		9
Derivative Liability, Fair Value, Gross Liability	-114		-129
Derivative Liability, Not Offset, Policy Election Deduction	0		0
Derivative, Collateral, Right to Reclaim Cash	0	[1]	0	[1]
Derivative Liability, Fair Value, Amount Offset Against Collateral	-114		-129
Net derivative assets (liabilities)	($110)		($120)
[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 9 for a further discussion of our collateral.

Use_of_Collateral_Details

Use of Collateral (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Use of Collateral [Abstract]
Margin Deposit Assets	$96	[1]	$261	[1]
Natural gas and power prepayments	22		28
Total margin deposits and natural gas and power prepayments with our counterparties	118	[2]	289	[2]
Letters of credit issued	450		488
First priority liens under power and natural gas agreements	48		31
First priority liens under interest rate swap agreements	116		132
Total letters of credit and first priority liens with our counterparties	614		651
Security Deposit Liability	47	[1],[3]	5	[1],[3]
Letters of credit posted with us by our counterparties	61		2
Total margin deposits and letters of credit posted with us by our counterparties	108		7
Use of Collateral (Textuals) [Abstract]
Margin And Prepayment Amounts Included In Other Assets	9		17
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses	$109		$272
[1]	Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated 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 8 for further discussion of our derivative instruments subject to master netting arrangements.
[2]	At December 31, 2014 and 2013, $109 million and $272 million, respectively, were included in margin deposits and other prepaid expense and $9 million and $17 million, respectively, were included in other assets on our Consolidated Balance Sheets.
[3]	Included in other current liabilities on our Consolidated Balance Sheets.

Income_Taxes_Income_Tax_Expens

Income Taxes (Income Tax Expense (Benefit)) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
U.S.	$942	($13)	$194
International	26	29	24
Total	$968	$16	$218

Income_Taxes_Components_of_Inc

Income Taxes (Components of Income Tax Expense (Benefit)) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Federal	($1)	($2)	($12)
State	19	-9	16
Foreign	-1	-1	14
Total current	17	-12	18
Federal	0	1	11
State	-1	4	-5
Foreign	6	9	-5
Total deferred	5	14	1
Total income tax expense (benefit)	$22	$2	$19

Income_Taxes_Effective_Income_

Income Taxes (Effective Income Tax Expense (Benefit) Rate) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax [Line Items]
Federal statutory tax expense (benefit) rate	35.00%	35.00%	35.00%
State tax expense (benefit), net of federal benefit	1.90%	-69.80%	3.20%
Depletion in excess of basis	-0.30%	-14.70%	-0.20%
Effective Income Tax Rate Reconciliation, Tax Settlements, Domestic	0.00%	0.00%	-4.70%
Valuation allowances	-35.80%	89.80%	-30.30%
Effective Income Tax Rate Reconciliation Change in Deferred Tax Assets, Valuation Allowance Due to Foreign Taxes	0.00%	-19.80%	-8.20%
Foreign taxes	1.20%	-10.80%	3.70%
Intraperiod allocation	0.00%	4.50%	4.60%
Change in unrecognized tax benefits	-0.40%	-30.10%	5.10%
Effective Income Tax Rate Reconciliation Nondeductible Expense Disallowed Compensation	0.10%	11.70%	0.40%
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Percent	0.10%	8.60%	0.20%
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Other, Percent	0.10%	3.30%	0.30%
Permanent differences and other items	0.40%	4.80%	-0.40%
Effective income tax expense (benefit) rate	2.30%	12.50%	8.70%

Income_Taxes_Deferred_Tax_Asse

Income Taxes (Deferred Tax Assets and Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Income Tax Disclosure [Abstract]
NOL and credit carryforwards	$2,873	$3,120
Taxes related to risk management activities and derivatives	61	60
Reorganization items and impairments	216	262
Foreign capital losses	16	18
Other differences	0	104
Deferred tax assets before valuation allowance	3,166	3,564
Valuation allowance	-1,836	-2,246
Total deferred tax assets	1,330	1,318
Deferred tax liabilities: property, plant and equipment	-1,305	-1,310
Deferred Tax Liabilities, Other	-21	0
Deferred Tax Liabilities, Gross	-1,326	-1,310
Net deferred tax asset (liability)	4	8
Less: Current portion deferred tax asset (liability)	-14	12
Less: Non-current deferred tax asset	19	7
Deferred income tax liability, net of current	($1)	($11)

Income_Taxes_Schedule_of_Incom

Income Taxes (Schedule of Income Tax Expense (Benefit) Intraperiod Tax Allocation) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Continuing Operations [Member]
Income Tax [Line Items]
Deferred income tax liability, net of current	$0	$1	$9
Other Comprehensive Income (Loss) [Member]
Income Tax [Line Items]
Deferred income tax liability, net of current	$0	($1)	($9)

Income_Taxes_Income_Tax_Contin

Income Taxes (Income Tax Contingencies) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Balance, beginning of period	($68)	($92)	($74)
Increases related to prior year tax positions	-4	-7	-19
Decreases related to prior year tax positions	8	8	1
Settlements	8	10	0
Decrease related to lapse of statute of limitations	0	13	0
Balance, end of period	($56)	($68)	($92)

Income_Taxes_Textuals_Details

Income Taxes (Textuals) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Intraperiod income tax [Line Items]
Number of States for NOL Carryforwards	22
Federal statutory tax expense (benefit) rate	35.00%	35.00%	35.00%
Income Tax Disclosure (Textuals) [Abstract]
Unrecognized Tax Benefits	$56,000,000	$68,000,000	$92,000,000	$74,000,000
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	13,000,000
Unrecognized Tax Benefits Resulting in Net Operating Loss Carryforward	43,000,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	11,000,000	13,000,000
Valuation allowance	1,836,000,000	2,246,000,000
Valuation Allowance, Deferred Tax Asset, Change in Amount	410,000,000	24,000,000	114,000,000
Miscellaneous increase in state, Deferred Tax Assets	18,000,000
Tax refund due to foreign dividend income treatment	10,000,000
Tax refund plus accrued interest due to foreign dividend income treatment	13,000,000
Accrued interest on foreign dividend refund	3,000,000
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	-2,000,000	-11,000,000	4,000,000
Federal [Domain]
Income Tax Disclosure (Textuals) [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	37,000,000	25,000,000
State and Local Jurisdiction [Member]
Income Tax Disclosure (Textuals) [Abstract]
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	21,000,000	16,000,000
Expiration date 2014 through 2034 [Member]
Income Tax Disclosure (Textuals) [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	4,000,000,000
Expiration date 2026 and 2034 [Member]
Income Tax Disclosure (Textuals) [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Foreign	800,000,000
Expiration date 2023 through 2034 [Member]
Intraperiod income tax [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	$6,900,000,000

Earnings_Loss_per_Share_Detail

Earnings (Loss) per Share (Details)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Diluted weighted average shares calculation:
Weighted average shares outstanding (basic)	404,837	440,666	467,752
Share-based awards	4,523	4,107	3,591
Weighted average shares outstanding (in shares)	409,360	444,773	471,343
Items excluded from diluted earnings (loss) per common share
Share-based awards	2,859	5,062	10,302

StockBased_Compensation_Detail

Stock-Based Compensation (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	$21,000,000		$22,000,000		$1,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options Outstanding, Beginning balance, Number	14,114,289
Options Outstanding, Beginning balance, Weighted Average Exercise Price	$18.25
Options Ouststanding, Beginning balance, Weighted Average Remaining Term (in years)	2 years 0 months 0 days		3 years 1 month 6 days
Options Outstanding, Beginning balance, Aggregate Intrinsic Value (in $ millions)	36,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price	$0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	2,951,947
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price	$16.20
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	69,122
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price	$15.81
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period	6,900
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price	$17.69
Options Outstanding, Ending balance, Number	11,086,320		14,114,289
Options Outstanding, Ending balance, Weighted Average Exercise Price	$18.82		$18.25
Options Ouststanding, Ending balance, Weighted Average Remaining Term (in years)	2 years 0 months 0 days		3 years 1 month 6 days
Options Outstanding, Ending balance, Aggregate Intrinsic Value (in $ millions)	43,000,000		36,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	10,336,806
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$19.07
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	1 year 8 months 12 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	38,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number	11,076,617
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price	$18.82
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term	2 years 0 months 0 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	43,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term			6 years 6 months 0 days	[1]	6 years 6 months 0 days	[1]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate			1.40%	[2]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate			25.60%	[3]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate			0.00%	[4]	0.00%	[4]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value			$5.31		$5.18
Disclosure of Compensation Related Costs Share-based Payments (Textuals) [Abstract]
Vesting period for graded and cliff vesting options - minimum	1 year
Vesting period for graded and cliff vesting options - maximum	5 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Minimum Range	5 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Maximum Range	10 years
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized for Directors	567,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized for Employees	40,533,000
Vest Term of First Sub Grant	1 year
Vest Term of the Second Sub-Grant	2 years
Vest Term of the Third Sub-Grant	3 years
Grants in Option Grants with Three Year Cliff Vesting	1 year
Vesting term of option grants with three year cliff vesting	3 years
Stock-based compensation expense	31,000,000		34,000,000		25,000,000
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options	20,000,000		20,000,000		5,000,000
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards	5,000,000		2,000,000
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate			1.20%	[2]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate			27.00%	[3]
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate			1.60%	[2]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate			30.50%	[3]
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	35,000,000		25,000,000		20,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$26,000,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 1 month 6 days
Restricted Stock and Stock Unit Activity [Abstract]
Nonvested Restricted Stock, Beginning balance, Number	4,431,841
Nonvested Restricted Stock, Beginning balance, Weighted Average Grant Date Fair Value	$16.45
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	1,885,049
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$19.34
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	430,059
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period, Weighted Average Grant Date Fair Value	$17.67
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	1,684,963
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$15.51
Nonvested Restricted Stock, Ending balance, Number	4,201,868		4,431,841
Nonvested Restricted Stock, Ending balance, Weighted Average Grant Date Fair Value	$18.01		$16.45
Performance Shares [Member]
Restricted Stock and Stock Unit Activity [Abstract]
Nonvested Restricted Stock, Beginning balance, Number	449,798
Nonvested Restricted Stock, Beginning balance, Weighted Average Grant Date Fair Value	$21.25
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	461,393
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$22.56
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	28,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period, Weighted Average Grant Date Fair Value	$21.87
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	15,312	[5]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$21.25
Nonvested Restricted Stock, Ending balance, Number	867,479
Nonvested Restricted Stock, Ending balance, Weighted Average Grant Date Fair Value	$21.93
Director Plan [Member]
Disclosure of Compensation Related Costs Share-based Payments (Textuals) [Abstract]
Common Stock, Capital Shares Reserved for Future Issuance	186,816
Equity Plan [Member]
Disclosure of Compensation Related Costs Share-based Payments (Textuals) [Abstract]
Common Stock, Capital Shares Reserved for Future Issuance	13,077,526
[1]	Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise data to provide a reasonable basis to estimate the expected term.
[2]	Zero Coupon U.S. Treasury rate or equivalent based on expected term.
[3]	Volatility calculated using the implied volatility of our exchange traded stock options.
[4]	We have never paid cash dividends on our common stock, and we do not anticipate any cash dividend payments on our common stock in the near future
[5]	(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.

Defined_Contribution_and_Defin1

Defined Contribution and Defined Benefit Plans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Contribution and Defined Benefit Plans [Abstract]
Defined Contribution Plan, Cost Recognized	$12	$11	$12
Employer Matching Contribution Percentage	100.00%
Deferral Election Percentage For Employer Matching Contribution	5.00%
Employee Deferral Limit Percentage	75.00%
Defined Benefit Plan, Assets for Plan Benefits	15	14
Pension and Other Postretirement Defined Benefit Plans, Liabilities	24	20
Defined Benefit Plan, Amounts Recognized in Balance Sheet	9	6
Defined Benefit Plan, Net Periodic Benefit Cost	1	2	1
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	5	1
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	2	1
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	1
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$1

Capital_Structure_Details

Capital Structure (Details) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2015	Dec. 31, 2011
Class of Stock [Line Items]
Shares issued under Calpine Equity Incentive Plans	2,566,799	3,022,128	1,741,909
Share repurchase program	-49,684,523	-31,032,110	26,436,677
Total common shares outstanding, ending balance	-381,921,264	-429,038,988	-457,048,970		-481,743,738
Common Stock, authorized shares (in shares)	-1,400,000,000	-1,400,000,000
Common Stock, issued shares (in shares)	-502,287,022	-497,841,056
Common Stock, par value (in dollars per share)	($0.00)	($0.00)
Common Stock, outstanding shares (in shares)	-381,921,264	-429,038,988
Treasury Stock, Shares (in shares)	120,365,758	68,802,068
Treasury Stock, Value	$2,345,000,000	$1,230,000,000
Treasury Stock, Value, Acquired, Cost Method	-1,115,000,000	-636,000,000	-469,000,000
Shareholder Transaction
Shareholder Ownership Percentage	10.00%
Common Stock Purchased from Shareholder	13,213,372
Purchase Price of Common Stock Purchased from Shareholder	311,464,283
Shares Issued [Member]
Class of Stock [Line Items]
Shares issued under Calpine Equity Incentive Plans	4,445,966	5,345,956	2,026,285
Share repurchase program	0	0	0
Total common shares outstanding, ending balance	-502,287,022	-497,841,056	-492,495,100		-490,468,815
Treasury Stock [Member]
Class of Stock [Line Items]
Shares issued under Calpine Equity Incentive Plans	1,879,167	2,323,828	284,376
Share repurchase program	-49,684,523	-31,032,110	26,436,677
Total common shares outstanding, ending balance	-120,365,758	-68,802,068	-35,446,130		-8,725,077
Share Repurchases in 2014 [Member]
Class of Stock [Line Items]
Share repurchase program	-36,471,151
Treasury Stock, Value, Acquired, Cost Method	-789,000,000
Treasury Stock Acquired, Average Cost Per Share	$21.62
Subsequent Event [Member] | 2014 Through Filing Date [Member]
Class of Stock [Line Items]
Share repurchase program				-5,772,440
Treasury Stock, Value, Acquired, Cost Method				($125,000,000)
Treasury Stock Acquired, Average Cost Per Share				$21.68

Commitments_and_Contingencies_1

Commitments and Contingencies (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments and Contingencies [Line Items]
Guarantor Obligations, Current Carrying Value	$2
Outstanding claims related to guarantees	0
Royalty Expense	28	27	22
LTSA [Member]
Unrecorded Unconditional Purchase Obligation
Unrecorded Unconditional Purchase Obligation	189
Term of Unrecorded Unconditional Purchase Obligation Lower Limit	1 year
Term of Unrecorded Unconditional Purchase Obligation Upper Limit	11 years
Electric Generation Equipment [Member]
Commitments and Contingencies [Line Items]
Operating Leases, Rent Expense, Net	46	47	51
Office Equipment [Member]
Commitments and Contingencies [Line Items]
Operating Leases, Rent Expense, Net	$11	$12	$12

Commitments_and_Contingencies_2

Commitments and Contingencies (Schedules of Future Minimum Rental Payments) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Land and Other Operating Leases [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due	$277
Operating Leases, Future Minimum Payments Due, Current	15
Operating Leases, Future Minimum Payments, Due in Two Years	16
Operating Leases, Future Minimum Payments, Due in Three Years	15
Operating Leases, Future Minimum Payments, Due in Four Years	15
Operating Leases, Future Minimum Payments, Due in Five Years	15
Operating Leases, Future Minimum Payments, Due Thereafter	201
Greenleaf [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due	4
KIAC [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due	119
Operating Leases, Future Minimum Payments Due, Current	23
Operating Leases, Future Minimum Payments, Due in Two Years	22
Operating Leases, Future Minimum Payments, Due in Three Years	22
Operating Leases, Future Minimum Payments, Due in Four Years	22
Operating Leases, Future Minimum Payments, Due in Five Years	30
Operating Leases, Future Minimum Payments, Due Thereafter	0
Total Power Plant Leases [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due	123
Operating Leases, Future Minimum Payments Due, Current	27
Operating Leases, Future Minimum Payments, Due in Two Years	22
Operating Leases, Future Minimum Payments, Due in Three Years	22
Operating Leases, Future Minimum Payments, Due in Four Years	22
Operating Leases, Future Minimum Payments, Due in Five Years	30
Operating Leases, Future Minimum Payments, Due Thereafter	0
Operting Lease Assets Total [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due	400
Operating Leases, Future Minimum Payments Due, Current	42
Operating Leases, Future Minimum Payments, Due in Two Years	38
Operating Leases, Future Minimum Payments, Due in Three Years	37
Operating Leases, Future Minimum Payments, Due in Four Years	37
Operating Leases, Future Minimum Payments, Due in Five Years	45
Operating Leases, Future Minimum Payments, Due Thereafter	201
Office Equipment [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due	55
Operating Leases, Future Minimum Payments Due, Current	11
Operating Leases, Future Minimum Payments, Due in Two Years	10
Operating Leases, Future Minimum Payments, Due in Three Years	9
Operating Leases, Future Minimum Payments, Due in Four Years	9
Operating Leases, Future Minimum Payments, Due in Five Years	8
Operating Leases, Future Minimum Payments, Due Thereafter	8
Greenleaf [Member]
Operating Leased Assets [Line Items]
Guarantee Obligations Balance On First Anniversary	4	[1]
Guarantee Obligations Balance On Second Anniversary	0	[1]
Guarantee Obligations Balance On Third Anniversary	0	[1]
Guarantee Obligations Balance On Fourth Anniversary	0	[1]
Guarantee Obligations Balance On Fifth Anniversary	0	[1]
Guarantee Obligations Due After Five Years	0	[1]
Natural Gas [Member]
Operating Leased Assets [Line Items]
Operating Leases, Future Minimum Payments Due	1,763
Operating Leases, Future Minimum Payments Due, Current	390
Operating Leases, Future Minimum Payments, Due in Two Years	297
Operating Leases, Future Minimum Payments, Due in Three Years	193
Operating Leases, Future Minimum Payments, Due in Four Years	152
Operating Leases, Future Minimum Payments, Due in Five Years	109
Operating Leases, Future Minimum Payments, Due Thereafter	$622
[1]	These are contingent off balance sheet obligations.

Commitments_and_Contingencies_3

Commitments and Contingencies (Schedule of Guarantor Obligations) (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Loans Payable [Member]
Guarantor Obligations [Line Items]
Guarantee Obligations Balance On First Anniversary	$37	[1]
Guarantee Obligations Balance On Second Anniversary	36	[1]
Guarantee Obligations Balance On Third Anniversary	26	[1]
Guarantee Obligations Balance On Fourth Anniversary	31	[1]
Guarantee Obligations Balance On Fifth Anniversary	30	[1]
Guarantee Obligations Due After Five Years	148	[1]
Guarantor Obligations, Maximum Exposure, Undiscounted	308	[1]
Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Guarantee Obligations Balance On First Anniversary	572	[2],[3],[4]
Guarantee Obligations Balance On Second Anniversary	14	[2],[3],[4]
Guarantee Obligations Balance On Third Anniversary	20	[2],[3],[4]
Guarantee Obligations Balance On Fourth Anniversary	0	[2],[3],[4]
Guarantee Obligations Balance On Fifth Anniversary	0	[2],[3],[4]
Guarantee Obligations Due After Five Years	38	[2],[3],[4]
Guarantor Obligations, Maximum Exposure, Undiscounted	644	[2],[3],[4]
Surety Bonds [Member]
Guarantor Obligations [Line Items]
Guarantee Obligations Balance On First Anniversary	0	[2],[5],[6]
Guarantee Obligations Balance On Second Anniversary	0	[2],[5],[6]
Guarantee Obligations Balance On Third Anniversary	0	[2],[5],[6]
Guarantee Obligations Balance On Fourth Anniversary	0	[2],[5],[6]
Guarantee Obligations Balance On Fifth Anniversary	0	[2],[5],[6]
Guarantee Obligations Due After Five Years	4	[2],[5],[6]
Guarantor Obligations, Maximum Exposure, Undiscounted	4	[2],[5],[6]
Greenleaf [Member]
Guarantor Obligations [Line Items]
Guarantee Obligations Balance On First Anniversary	4	[2]
Guarantee Obligations Balance On Second Anniversary	0	[2]
Guarantee Obligations Balance On Third Anniversary	0	[2]
Guarantee Obligations Balance On Fourth Anniversary	0	[2]
Guarantee Obligations Balance On Fifth Anniversary	0	[2]
Guarantee Obligations Due After Five Years	0	[2]
Guarantor Obligations, Maximum Exposure, Undiscounted	4	[2]
Gurantee Obligations Total [Member]
Guarantor Obligations [Line Items]
Guarantee Obligations Balance On First Anniversary	613
Guarantee Obligations Balance On Second Anniversary	50
Guarantee Obligations Balance On Third Anniversary	46
Guarantee Obligations Balance On Fourth Anniversary	31
Guarantee Obligations Balance On Fifth Anniversary	30
Guarantee Obligations Due After Five Years	190
Guarantor Obligations, Maximum Exposure, Undiscounted	$960
[1]	Represents Calpine Corporation guarantees of certain power plant capital leases and related interest. All guaranteed capital leases are recorded on our Consolidated Balance Sheets.
[2]	These are contingent off balance sheet obligations.
[3]	Letters of credit are renewed annually and as such all amounts are reflected in the year of letter of credit expiration. The related commercial obligations extend for multiple years, therefore, renewal of the letter of credit will likely follow the term of the associated commercial obligation.
[4]	The standby letters of credit disclosed above represent those disclosed in Note 6.
[5]	The majority of surety bonds do not have expiration or cancellation dates.
[6]	As of December 31, 2014, $2 million of cash collateral is outstanding related to these bonds.

Segment_and_Significant_Custom2

Segment and Significant Customer Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues	$1,939	$2,187	$1,939	$1,965	$1,438	$2,050	$1,572	$1,241	$8,030		$6,301		$5,478
Commodity Margin									2,759	[1]	2,568	[1]	2,538	[1],[2],[3]
Mark-to-Market Commodity Activity, Net and Other Revenue									379	[4]	-3	[4]	-84	[4]
Plant operating expense									969		895		922
Depreciation and amortization expense									603		593		562
Sales, general and other administrative expense									144		136		140
Other Cost and Expense, Operating									88		81		78
Impairment losses									123		16		0
Gain (Loss) on Disposition of Assets									-753		0		-222
(Income) from unconsolidated investments in power plants									-25		-30		-28
Income from operations	390	1,126	329	144	151	597	122	4	1,989		874		1,002
Interest expense, net of interest income									639		690		725
Loss on interest rate derivatives									0		0		14
Debt Extinguishment Costs and Other (Income) Expense, Net									367		164		45
Income before income taxes									983		20		218
Commodity Margin for Six Southeast Power Plants Sold									81		152		131
Lease levelization									-5		6		1
Contract amortization									14		14		14
Commodity Margin Broad River Energy Center													52
Commodity Margin Riverside Energy Center													73
Number of significant customers									one		two
West [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									2,358		1,942		1,678
Commodity Margin									1,050	[1]	1,020	[1]	994	[1],[2],[3]
Mark-to-Market Commodity Activity, Net and Other Revenue									220	[4]	-50	[4]	-93	[4]
Plant operating expense									385		365		368
Depreciation and amortization expense									245		227		203
Sales, general and other administrative expense									41		37		36
Other Cost and Expense, Operating									50		45		42
Impairment losses									0		16
Gain (Loss) on Disposition of Assets									0				0
(Income) from unconsolidated investments in power plants									0		0		0
Income from operations									549		280		252
Texas [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									3,252		2,343		1,918
Commodity Margin									760	[1]	632	[1]	570	[1],[2],[3]
Mark-to-Market Commodity Activity, Net and Other Revenue									142	[4]	51	[4]	87	[4]
Plant operating expense									313		269		247
Depreciation and amortization expense									191		165		142
Sales, general and other administrative expense									64		56		47
Other Cost and Expense, Operating									5		3		5
Impairment losses									0		0
Gain (Loss) on Disposition of Assets									0				0
(Income) from unconsolidated investments in power plants									0		0		0
Income from operations									329		190		216
East [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									2,496		2,134		1,991
Commodity Margin									949	[1]	916	[1]	974	[1],[2],[3]
Mark-to-Market Commodity Activity, Net and Other Revenue									48	[4]	27	[4]	-47	[4]
Plant operating expense									302		292		337
Depreciation and amortization expense									168		203		219
Sales, general and other administrative expense									39		42		57
Other Cost and Expense, Operating									32		33		34
Impairment losses									123		0
Gain (Loss) on Disposition of Assets									-753				-222
(Income) from unconsolidated investments in power plants									-25		-30		-28
Income from operations									1,111		403		530
Geography Consolidation and Elimination [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									-76		-118		-109
Commodity Margin									0		0		0
Mark-to-Market Commodity Activity, Net and Other Revenue									-31		-31		-31
Plant operating expense									-31		-31		-30
Depreciation and amortization expense									-1		-2		-2
Sales, general and other administrative expense									0		1		0
Other Cost and Expense, Operating									1		0		-3
Impairment losses									0		0
Gain (Loss) on Disposition of Assets									0				0
(Income) from unconsolidated investments in power plants									0		0		0
Income from operations									0		1		4
PJM Settlement, Inc. [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									1,024		820		713
Pacific Gas & Electric Company [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues											694
Operating Segments [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									8,030		6,301		5,478
Operating Segments [Member] | West [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									2,352		1,937		1,668
Operating Segments [Member] | Texas [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									3,229		2,347		1,857
Operating Segments [Member] | East [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									2,449		2,017		1,953
Operating Segments [Member] | Geography Consolidation and Elimination [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									0		0		0
Intersegment Eliminations [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									0		0		0
Intersegment Eliminations [Member] | West [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									6		5		10
Intersegment Eliminations [Member] | Texas [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									23		-4		61
Intersegment Eliminations [Member] | East [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									47		117		38
Intersegment Eliminations [Member] | Geography Consolidation and Elimination [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues									($76)		($118)		($109)
[1]	Our East segment includes Commodity Margin of $81 million, $152 million and $131 million for the years ended December 31, 2014, 2013 and 2012, respectively, related to the six power plants in our East segment that were sold in July 2014.
[2]	Our East segment includes Commodity Margin of $73 million for the year ended December 31, 2012, related to Riverside Energy Center, LLC, which was sold in December 2012.
[3]	Our East segment includes Commodity Margin of $52 million for the year ended December 31, 2012, related to Broad River, which was sold in December 2012.
[4]	Includes $(5) million, $6 million and $1 million of lease levelization and $14 million, $14 million and $14 million of amortization expense for the years ended December 31, 2014, 2013 and 2012, respectively.

Quarterly_Consolidated_Financi2

Quarterly Consolidated Financial Data (unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$1,939	$2,187	$1,939	$1,965	$1,438	$2,050	$1,572	$1,241	$8,030	$6,301	$5,478
Income (loss) from operations	390	1,126	329	144	151	597	122	4	1,989	874	1,002
Net income (loss) attributable to Calpine	$210	$614	$139	($17)	($97)	$306	($70)	($125)	$946	$14	$199
Net income (loss) per common share attributable to Calpine — basic (in dollars per share)	$0.55	$1.54	$0.33	($0.04)	($0.23)	$0.70	($0.16)	($0.28)	$2.34	$0.03	$0.43
Net income (loss) per common share attributable to Calpine — diluted (in dollars per share)	$0.54	$1.52	$0.33	($0.04)	($0.23)	$0.70	($0.16)	($0.28)	$2.31	$0.03	$0.42

Schedule_of_Valuation_and_Qual1

Schedule of Valuation and Qualifying Accounts Disclosure (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Allowance for Doubtful Accounts [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Year	$5		$6		$13
Charged to Expense	-1		4		-1
Deductions	0	[1]	0	[1]	-5	[1]
Charged to Other Accounts	0		-5		-1
Balance at End of Year	4		5		6
Deferred Tax Asset Valuation Allowance [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Year	2,246		2,222		2,336
Charged to Expense	-410		24		-114
Deductions	0	[1]	0	[1]	0	[1]
Charged to Other Accounts	0		0		0
Balance at End of Year	$1,836		$2,246		$2,222
[1]	Represents write-offs of accounts considered to be uncollectible and previously reserved.