Calpine (CPNLQ) 10-Q 28 Apr 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	Apr. 24, 2017
Entity Information [Line Items]
Entity Registrant Name	CALPINE CORP
Entity Central Index Key	916,457
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		360,793,424

Consolidated Condensed Statemen

Consolidated Condensed Statements of Operations - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Operating revenues:
Commodity revenue	$ 2,063	$ 1,585
Mark-to-market gain	214	25
Other revenue	4	5
Operating revenues	2,281	1,615
Operating expenses:
Commodity expense	1,533	1,006
Mark-to-market loss	159	120
Fuel and purchased energy expense	1,692	1,126
Plant operating expense	282	255
Depreciation and amortization expense	206	180
Sales, general and other administrative expense	40	38
Other operating expenses	20	20
Total operating expenses	2,240	1,619
Gain on sale of assets, net	(27)	0
(Income) from unconsolidated subsidiaries	(4)	(7)
Income from operations	72	3
Interest expense	159	157
Debt extinguishment costs	24	0
Other (income) expense, net	2	5
Loss before income taxes	(113)	(159)
Income tax expense (benefit)	(61)	35
Net income (loss)	(52)	(194)
Net income attributable to the noncontrolling interest	(4)	(4)
Net loss attributable to Calpine	$ (56)	$ (198)
Basic and diluted loss per common share attributable to Calpine:
Weighted average number of shares outstanding, basic	354,682	353,501
Earnings per share, basic and diluted	$ (0.16)	$ (0.56)

Consolidated Condensed Stateme3

Consolidated Condensed Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Net loss	$ (52)	$ (194)
Cash flow hedging activities:
Loss on cash flow hedges before reclassification adjustment for cash flow hedges realized in net loss	(15)	(23)
Reclassification adjustment for loss on cash flow hedges realized in net loss	11	11
Foreign currency translation gain	2	12
Income tax expense	0	0
Other comprehensive loss	(2)	0
Comprehensive loss	(54)	(194)
Comprehensive (income) attributable to the noncontrolling interest	(4)	(2)
Comprehensive loss attributable to Calpine	$ (58)	$ (196)

Consolidated Condensed Balance

Consolidated Condensed Balance Sheets - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents ($63 and $79 attributable to VIEs)	$ 243	$ 418
Accounts receivable, net of allowance of $8 and $6	765	839
Inventories	535	581
Margin deposits and other prepaid expense	364	441
Restricted cash, current ($99 and $109 attributable to VIEs)	162	173
Derivative assets, current	1,387	1,725
Current assets held for sale (nil and $134 attributable to VIEs)	0	210
Other current assets	65	45
Total current assets	3,521	4,432
Property, plant and equipment, net ($4,164 and $3,979 attributable to VIEs)	13,009	13,013
Restricted cash, net of current portion ($15 and $14 attributable to VIEs)	15	15
Investments in unconsolidated subsidiaries	92	99
Long-term derivative assets	670	543
Goodwill	233	187
Finite-Lived Intangible Assets, Net	635	650
Other assets ($60 and $63 attributable to VIEs)	401	378
Total assets	18,576	19,317
Current liabilities:
Accounts payable	655	671
Accrued interest payable	125	125
Debt, current portion ($176 and $176 attributable to VIEs)	608	748
Derivative liabilities, current	1,273	1,630
Other current liabilities	459	528
Total current liabilities	3,120	3,702
Debt, net of current portion ($2,900 and $2,944 attributable to VIEs)	11,344	11,431
Long-term derivative liabilities	550	476
Other long-term liabilities	280	369
Total liabilities	15,294	15,978
Commitments and contingencies (see Note 11)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding	0	0
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 361,833,256 and 359,627,113 shares issued, respectively, and 360,797,377 and 359,061,764 shares outstanding, respectively	0	0
Treasury stock, at cost, 1,035,879 and 565,349 shares, respectively	(13)	(7)
Additional paid-in capital	9,633	9,625
Accumulated deficit	(6,269)	(6,213)
Accumulated other comprehensive loss	(139)	(137)
Total Calpine stockholders’ equity	3,212	3,268
Noncontrolling interest	70	71
Total stockholders’ equity	3,282	3,339
Total liabilities and stockholders’ equity	$ 18,576	$ 19,317

Consolidated Condensed Balance5

Consolidated Condensed Balance Sheets (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Cash and cash equivalents ($63 and $79 attributable to VIEs)	$ 243	$ 418
Accounts receivable, net of allowance of $8 and $6	8	6
Restricted cash, current ($99 and $109 attributable to VIEs)	162	173
Current assets held for sale (nil and $134 attributable to VIEs)	0	210
Property, plant and equipment, net ($4,164 and $3,979 attributable to VIEs)	13,009	13,013
Restricted cash, net of current portion ($15 and $14 attributable to VIEs)	15	15
Other assets ($60 and $63 attributable to VIEs)	401	378
Debt, current portion ($176 and $176 attributable to VIEs)	608	748
Debt, net of current portion ($2,900 and $2,944 attributable to VIEs)	$ 11,344	$ 11,431
Preferred Stock, Par or Stated Value Per Share	$ 0.001	$ 0.001
Preferred Stock, Shares Authorized	100,000,000	100,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.001	$ 0.001
Common Stock, Shares Authorized	1,400,000,000	1,400,000,000
Common Stock, Shares, Issued	361,833,256	359,627,113
Common Stock, Shares, Outstanding	360,797,377	359,061,764
Treasury Stock, Shares	1,035,879	565,349
Variable Interest Entity, Primary Beneficiary [Member]
Cash and cash equivalents ($63 and $79 attributable to VIEs)	$ 63	$ 79
Restricted cash, current ($99 and $109 attributable to VIEs)	99	109
Current assets held for sale (nil and $134 attributable to VIEs)	0	134
Property, plant and equipment, net ($4,164 and $3,979 attributable to VIEs)	4,164	3,979
Restricted cash, net of current portion ($15 and $14 attributable to VIEs)	15	14
Other assets ($60 and $63 attributable to VIEs)	60	63
Debt, current portion ($176 and $176 attributable to VIEs)	176	176
Debt, net of current portion ($2,900 and $2,944 attributable to VIEs)	$ 2,900	$ 2,944

Consolidated Condensed Stateme6

Consolidated Condensed Statements of Cash Flows - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities:
Net loss		$ (52)	$ (194)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization(1)	[1]	265	226
Debt extinguishment costs		6	0
Income tax expense (benefit)		(61)	35
Gain on sale of assets, net		(27)	0
Mark-to-market activity, net	[2]	(55)	94
(Income) from unconsolidated subsidiaries		(4)	(7)
Return on investments from unconsolidated subsidiaries		13	0
Stock-based compensation expense		8	9
Other		0	(4)
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable		82	87
Derivative instruments, net		(21)	(12)
Other assets		24	(19)
Accounts payable and accrued expenses		(104)	(202)
Other liabilities		20	18
Net cash provided by operating activities		94	31
Cash flows from investing activities:
Purchases of property, plant and equipment		(91)	(133)
Proceeds from sale of Osprey Energy Center		162	0
Decrease in restricted cash		11	43
Other		16	6
Net cash used in investing activities		(13)	(611)
Cash flows from financing activities:
Borrowings under First Lien Term Loans		396	0
Repayment of CCFC Term Loans and First Lien Term Loans		(161)	(13)
Repurchase of First Lien Notes		(453)	0
Proceeds from Lines of Credit		25	0
Repayments of project financing, notes payable and other		(44)	(56)
Distribution to noncontrolling interest holder		(6)	(2)
Financing costs		(8)	(7)
Shares repurchased for tax withholding on stock-based awards		(6)	(5)
Other		1	1
Net cash used in financing activities		(256)	(82)
Net decrease in cash and cash equivalents		(175)	(662)
Cash and cash equivalents, beginning of period		418	906
Cash and cash equivalents, end of period		243	244
Cash paid during the period for:
Interest, net of amounts capitalized		141	150
Income taxes		3	2
Supplemental disclosure of non-cash investing activities:
Change in capital expenditures included in accounts payable		0	15
Granite Ridge Energy Center [Member]
Cash flows from investing activities:
Payments to Acquire Businesses, Net of Cash Acquired		0	(527)
North American Power [Member]
Cash flows from investing activities:
Payments to Acquire Businesses, Net of Cash Acquired		$ (111)	$ 0
[1]	Includes amortization recorded in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts.
[2]	In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2017
Accounting Policies [Abstract]
Summary of significant accounting policies	Basis of Presentation and Summary of Significant Accounting Policies We are a 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 and Mid-Atlantic regions (included in our East segment) of the U.S. We sell 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 and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. 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 also purchase power for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants. Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2016 , included in our 2016 Form 10-K. The results for interim periods are not indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues and expenses, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts. Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates. 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 cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. 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 and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows. The table below represents the components of our restricted cash as of March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 December 31, 2016 Current Non-Current Total Current Non-Current Total Debt service $ 12 $ 7 $ 19 $ 11 $ 8 $ 19 Construction/major maintenance 48 6 54 45 6 51 Security/project/insurance 99 — 99 114 — 114 Other 3 2 5 3 1 4 Total $ 162 $ 15 $ 177 $ 173 $ 15 $ 188 Property, Plant and Equipment, Net — At March 31, 2017 and December 31, 2016 , the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions): March 31, 2017 December 31, 2016 Depreciable Lives Buildings, machinery and equipment $ 16,481 $ 16,468 3 – 46 Years Geothermal properties 1,460 1,377 13 – 58 Years Other 237 259 3 – 46 Years 18,178 18,104 Less: Accumulated depreciation 5,975 5,865 12,203 12,239 Land 116 116 Construction in progress 690 658 Property, plant and equipment, net $ 13,009 $ 13,013 Capitalized Interest — The total amount of interest capitalized was $7 million and $4 million for the three months ended March 31, 2017 and 2016 , respectively. Goodwill — The change in goodwill during the three months ended March 31, 2017 was as follows (in millions): West Texas East Total Goodwill at December 31, 2016 $ 68 $ 31 $ 88 $ 187 Acquisition of North American Power — — 49 49 Calpine Solutions purchase price allocation adjustment (1 ) — (2 ) (3 ) Goodwill at March 31, 2017 $ 67 $ 31 $ 135 $ 233 Related Party — Under the Accounts Receivables Sales Program, at March 31, 2017 and December 31, 2016 , we had $179 million and $211 million , respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables and $40 million and $32 million , respectively, in notes receivable from Calpine Receivables which were recorded on our Consolidated Condensed Balance Sheets. During the three months ended March 31, 2017 , we sold an aggregate of $542 million in trade accounts receivable and recorded $546 million in proceeds. For a further discussion of the Accounts Receivable Sales Program and Calpine Receivables, see Notes 2 and 5 in our 2016 Form 10-K. New Accounting Standards and Disclosure Requirements Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding revenue recognition. The standard allows for either full retrospective or modified retrospective adoption. In August 2015, the FASB deferred the effective date of Accounting Standards Update 2014-09 for public entities by one year, such that the standard will become effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The standard permits entities to adopt early, but only as of the original effective date. In March 2016, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. In May 2016, the FASB issued Accounting Standards Update 2016-12 “Narrow-Scope Improvements and Practical Expedients” which addresses assessing the collectability of a contract, the presentation of sales taxes and other taxes collected from customers, non-cash consideration and completed contracts and contract modifications at transition. We expect to adopt the standard in the first quarter of 2018 using the modified retrospective transition approach; however, our method of adoption may change as we complete our assessment of the standard. We are currently evaluating the effect the revenue recognition standards will have on our revenue contracts such as our PPAs and tolling agreements; however, we do not anticipate the adoption of this standard will have a material effect on our financial condition, results of operations or cash flows. Upon adoption, we intend to elect the practical expedient that would allow an entity to recognize revenue in the amount to which the entity has the right to invoice to the extent we determine that we have a right to consideration from the customer in an amount that corresponds directly with the value provided based on our performance completed to date. Inventory — In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” The standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. This standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective adoption with early adoption permitted. We adopted Accounting Standards Update 2015-11 in the first quarter of 2017 which did not have a material effect on our financial condition, results of operations or cash flows. Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified retrospective adoption with early adoption permitted. We expect to adopt the standard in the first quarter of 2019. We have completed our initial evaluation of the standard and believe that the key changes that will affect us relate to our accounting for operating leases that are currently off-balance sheet and tolling contracts which we currently account for as operating leases. Additionally, we are evaluating the potential effects of the removal of the real estate guidance currently applicable to lessors that will be abrogated under Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” We are also considering electing the practical expedient in our implementation of the standard; however, this may change as we complete our assessment of the standard. Statement of Cash Flows — In August 2016, the FASB issued Accounting Standards Update 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” The standard addresses several matters of diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows including the presentation of debt extinguishment costs and distributions received from equity method investments. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and allows for retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. Restricted Cash — In November 2016, the FASB issued Accounting Standards Update 2016-18, “Restricted Cash.” The standard requires restricted cash to be included with cash and cash equivalents when reconciling the beginning and ending amounts in the statement of cash flows and also requires disclosures regarding the nature of restrictions on cash, cash equivalents and restricted cash. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and requires for retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. Intangibles – Goodwill and Other — In January 2017, the FASB issued Accounting Standards Update 2017-04, “Simplifying the Test for Goodwill Impairment.” The standard eliminates the second step in the goodwill impairment test which requires an entity to determine the implied fair value of the reporting unit’s goodwill. Instead, an entity should recognize an impairment loss if the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, with the impairment loss not to exceed the amount of goodwill allocated to the reporting unit. The standard is effective for annual and interim goodwill impairment tests conducted in fiscal years beginning after December 15, 2019, with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.

Acquisition (Notes)

Acquisition (Notes)	3 Months Ended
	Mar. 31, 2017
Business Combinations [Abstract]
Mergers, acquisitions and dispositions disclosures	Acquisitions and Divestitures Acquisition of North American Power On January 17, 2017, we, through an indirect, wholly-owned subsidiary, completed the purchase of 100% of the outstanding limited liability company membership interests in North American Power for approximately $105 million , excluding working capital and other adjustments. North American Power is a growing retail energy supplier for homes and small businesses and is primarily concentrated in the Northeast U.S. where Calpine has a substantial power generation presence and where Champion Energy has a substantial retail sales footprint that is enhanced by the addition of North American Power, which has been integrated into our Champion Energy retail platform. We funded the acquisition with cash on hand and the purchase price is allocated to the net assets of the business including intangible assets for the value of customer relationships and goodwill. The goodwill recorded associated with our acquisition of North American Power is deductible for tax purposes. The pro forma incremental effect of North American Power on our results of operations for each of the three months ended March 31, 2017 and 2016 is not material. Acquisition of Calpine Solutions, formerly Noble Solutions We did not record any material adjustments to the preliminary purchase price allocation during the three months ended March 31, 2017 associated with our acquisition of Calpine Solutions on December 1, 2016. Acquisition of Granite Ridge Energy Center On February 5, 2016, we, through our indirect, wholly-owned subsidiary Calpine Granite Holdings, LLC, completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), from Granite Ridge Holdings, LLC, for approximately $500 million , excluding working capital and other adjustments. The purchase price allocation was finalized during the first quarter of 2017 and did not result in any material adjustments or the recognition of goodwill. Sale of Osprey Energy Center On January 3, 2017, we completed the sale of the Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million , excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. We recorded a gain on sale of assets, net of approximately $27 million during the three months ended March 31, 2017 associated with the sale of the Osprey Energy Center. Sale of South Point Energy Center As a result of the denial by the Nevada Public Utility Commission of the sale of South Point Energy Center to Nevada Power Company in February 2017, we terminated the corresponding asset sale agreement in the first quarter of 2017. We are currently assessing our options related to South Point Energy Center; however, we do not anticipate that the termination of the asset sale agreement will have a material effect on our financial condition, results of operations or cash flows. During the first quarter of 2017, we reclassified the assets of South Point Energy Center from current assets held for sale to held and used which are measured at fair value as a component of property, plant and equipment, net.

Variable Interest Entities and

Variable Interest Entities and Unconsolidated Investments in Power Plants	3 Months Ended
	Mar. 31, 2017
Variable Interest Entities and Unconsolidated Investments [Abstract]
Variable interest entities and unconsolidated investments in power plants	Variable Interest Entities and Unconsolidated Investments We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the three months ended March 31, 2017 . See Note 5 in our 2016 Form 10-K for further information regarding our VIEs. VIE Disclosures Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 8,988 MW and 9,491 MW at March 31, 2017 and December 31, 2016 , respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil during each of the three months ended March 31, 2017 and 2016 . Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are 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. In December 2016, we acquired Calpine Receivables, a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. Calpine Receivables is a VIE as we have determined that we do not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, we have determined that we are not the primary beneficiary of Calpine Receivables as we do not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls management of default. Thus, we do not consolidate Calpine Receivables in our Consolidated Financial Statements and use the equity method of accounting to record our net interest in Calpine Receivables. We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Condensed Balance Sheets. At March 31, 2017 and December 31, 2016 , our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions): Ownership Interest as of March 31, 2017 March 31, 2017 December 31, 2016 Greenfield LP 50% $ 78 $ 73 Whitby 50% 4 16 Calpine Receivables 100% 10 10 Total investments in unconsolidated subsidiaries $ 92 $ 99 Our risk of loss related to our investments in Greenfield LP, Whitby and Calpine Receivables is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At March 31, 2017 and December 31, 2016 , Greenfield LP’s debt was approximately $256 million and $ 259 million , respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $128 million and $ 130 million at March 31, 2017 and December 31, 2016 , respectively. Our equity interest in the net income from our investments in unconsolidated subsidiaries for the three months ended March 31, 2017 and 2016 , is recorded in (income) from unconsolidated subsidiaries. We did not have any income or receive any distributions from our investment in Calpine Receivables for the three months ended March 31, 2017 . The following table sets forth details of our (income) from unconsolidated subsidiaries for the periods indicated (in millions): Three Months Ended March 31, 2017 2016 Greenfield LP $ (2 ) $ (4 ) Whitby (2 ) (3 ) Total $ (4 ) $ (7 ) Distributions from Greenfield LP were nil during each of the three months ended March 31, 2017 and 2016 . Distributions from Whitby were $13 million and nil during the three months ended March 31, 2017 and 2016 , respectively.

Debt

Debt	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Debt	Debt Our debt at March 31, 2017 and December 31, 2016 , was as follows (in millions): March 31, 2017 December 31, 2016 Senior Unsecured Notes $ 3,413 $ 3,412 First Lien Term Loans 3,405 3,165 First Lien Notes 1,841 2,290 Project financing, notes payable and other 1,561 1,597 CCFC Term Loans 1,550 1,553 Capital lease obligations 157 162 Corporate Revolving Facility 25 — Subtotal 11,952 12,179 Less: Current maturities 608 748 Total long-term debt $ 11,344 $ 11,431 Our effective interest rate on our consolidated debt, excluding the effects of capitalized interest and mark-to-market gains (losses) on interest rate hedging instruments, decreased to 5.4% for the three months ended March 31, 2017 , from 5.5% for the same period in 2016. The issuance of our 2019 First Lien Term Loan in February 2017 and a portion of our 2023 First Lien Term Loans in May 2016 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Notes and First Lien Term Loans with debt carrying lower interest rates. Senior Unsecured Notes The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions): March 31, 2017 December 31, 2016 2023 Senior Unsecured Notes $ 1,237 $ 1,237 2024 Senior Unsecured Notes 643 643 2025 Senior Unsecured Notes 1,533 1,532 Total Senior Unsecured Notes $ 3,413 $ 3,412 First Lien Term Loans The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions): March 31, 2017 December 31, 2016 2017 First Lien Term Loan (1) $ 393 $ 537 2019 First Lien Term Loan 389 — 2023 First Lien Term Loans 1,070 1,071 2024 First Lien Term Loan 1,553 1,557 Total First Lien Term Loans $ 3,405 $ 3,165 ____________ (1) On March 16, 2017, we used cash on hand to repay $150 million of our outstanding 2017 First Lien Term Loan. During the first quarter of 2017, we recorded approximately $3 million in debt extinguishment costs related to the partial repayment of our 2017 First Lien Term Loan. On February 3, 2017, we entered into a $400 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.5% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the 2019 First Lien Term Loan credit agreement), plus an applicable margin of 0.75% , or (ii) LIBOR plus 1.75% per annum (with no LIBOR floor) and matures on December 31, 2019. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2019 First Lien Term Loans is payable at the end of each quarter (beginning with the quarter ending June 2017) with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount of the 2019 First Lien Term Loan, which is structured as original issue discount and recorded approximately $8 million in debt issuance costs during the first quarter of 2017 related to the issuance of our 2019 First Lien Term Loan. The 2019 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as our First Lien Term Loans and First Lien Notes. We used the proceeds from the 2019 First Lien Term Loan, together with cash on hand, to redeem the remaining 2023 First Lien Notes. First Lien Notes The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions): March 31, 2017 December 31, 2016 2022 First Lien Notes $ 739 $ 739 2023 First Lien Notes (1) — 450 2024 First Lien Notes 485 485 2026 First Lien Notes 617 616 Total First Lien Notes $ 1,841 $ 2,290 ____________ (1) On March 6, 2017, we used cash on hand along with the proceeds from our 2019 First Lien Term Loan to redeem the remaining $453 million of our 2023 First Lien Notes, plus accrued and unpaid interest. During the first quarter of 2017, we recorded approximately $21 million in debt extinguishment costs related to the redemption of our 2023 First Lien Notes. Corporate Revolving Facility and Other Letter of Credit Facilities The table below represents amounts issued under our letter of credit facilities at March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 December 31, 2016 Corporate Revolving Facility (1) $ 471 $ 535 CDHI 237 250 Various project financing facilities 183 206 Total $ 891 $ 991 ____________ (1) The Corporate Revolving Facility represents our primary revolving facility. Fair Value of Debt We record our debt instruments based on contractual terms, net of any applicable premium or discount. The following table details the fair values and carrying values of our debt instruments at March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 December 31, 2016 Fair Value Carrying Value Fair Value Carrying Value Senior Unsecured Notes $ 3,435 $ 3,413 $ 3,343 $ 3,412 First Lien Term Loans 3,480 3,405 3,244 3,165 First Lien Notes 1,931 1,841 2,349 2,290 Project financing, notes payable and other (1) 1,505 1,469 1,543 1,506 CCFC Term Loans 1,567 1,550 1,567 1,553 Corporate Revolving Facility 25 25 — — Total $ 11,943 $ 11,703 $ 12,046 $ 11,926 ____________ (1) Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP. We measure the fair value of our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loans using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.

Assets and Liabilities with Rec

Assets and Liabilities with Recurring Fair Value Measurements	3 Months Ended
	Mar. 31, 2017
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [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 and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do not have any cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Certain of our cash equivalents 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 and customers for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. 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 customers and the effect 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 hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. 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 primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect 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 March 31, 2017 and December 31, 2016 , by level within the fair value hierarchy: Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2017 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 166 $ — $ — $ 166 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,259 — — 1,259 Commodity forward contracts (2) — 359 402 761 Interest rate hedging instruments — 37 — 37 Total assets $ 1,425 $ 396 $ 402 $ 2,223 Liabilities: Commodity instruments: Commodity exchange traded futures and swaps contracts 1,298 — — 1,298 Commodity forward contracts (2) — 410 60 470 Interest rate hedging instruments — 55 — 55 Total liabilities $ 1,298 $ 465 $ 60 $ 1,823 Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2016 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 153 $ — $ — $ 153 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,542 — — 1,542 Commodity forward contracts (2) — 231 466 697 Interest rate hedging instruments — 29 — 29 Total assets $ 1,695 $ 260 $ 466 $ 2,421 Liabilities: Commodity instruments: Commodity exchange traded futures and swaps contracts 1,570 — — 1,570 Commodity forward contracts (2) — 411 67 478 Interest rate hedging instruments — 58 — 58 Total liabilities $ 1,570 $ 469 $ 67 $ 2,106 ___________ (1) As of March 31, 2017 and December 31, 2016 , we had cash equivalents of $36 million and $26 million included in cash and cash equivalents and $130 million and $127 million included in restricted cash, respectively. (2) Includes OTC swaps and options and retail contracts. At March 31, 2017 and December 31, 2016 , the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at March 31, 2017 and December 31, 2016 : Quantitative Information about Level 3 Fair Value Measurements March 31, 2017 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ 324 Discounted cash flow Market price (per MWh) $ 8.00 — $92.00 /MWh Power Congestion Products $ 11 Discounted cash flow Market price (per MWh) $ (7.52 ) — $4.54 /MWh Natural Gas Contracts $ 60 Discounted cash flow Market price (per MMBtu) $ 1.79 — $6.24 /MMBtu December 31, 2016 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ 360 Discounted cash flow Market price (per MWh) $ 9.60 — $86.34 /MWh Power Congestion Products $ 12 Discounted cash flow Market price (per MWh) $ (7.52 ) — $13.62 /MWh Natural Gas Contracts $ 17 Discounted cash flow Market price (per MMBtu) $ 1.95 — $5.66 /MMBtu The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions): Three Months Ended March 31, 2017 2016 Balance, beginning of period $ 399 $ (46 ) Realized and mark-to-market gains (losses): Included in net income: Included in operating revenues (1) 113 (22 ) Included in fuel and purchased energy expense (2) 13 (14 ) Purchases and settlements: Purchases — 2 Settlements (26 ) (4 ) Transfers in and/or out of level 3 (3) : Transfers into level 3 (4) (7 ) — Transfers out of level 3 (5) (150 ) 19 Balance, end of period $ 342 $ (65 ) Change in unrealized gains (losses) relating to instruments still held at end of period $ 126 $ (36 ) ___________ (1) For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations. (2) For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations. (3) We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three months ended March 31, 2017 and 2016 . (4) There were $7 million and nil in losses transferred out of level 2 into level 3 for the three months ended March 31, 2017 and 2016 , respectively, due to changes in market liquidity in various power markets. (5) We had $150 million in gains and $(19) million in losses transferred out of level 3 into level 2 for the three months ended March 31, 2017 and 2016 , respectively, due to changes in market liquidity in various power markets.

Derivative Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [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, fuel oil, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels. We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading results were not material for each of the three months ended March 31, 2017 and 2016 . Interest Rate Hedging Instruments — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate hedging instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of March 31, 2017 , the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 9 years. As of March 31, 2017 and December 31, 2016 , the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions): Derivative Instruments Notional Amounts March 31, 2017 December 31, 2016 Power (MWh) (78 ) (86 ) Natural gas (MMBtu) 779 613 Environmental credits (Tonnes) 16 16 Interest rate hedging instruments $ 4,600 (1) $ 3,721 ___________ (1) We entered into interest rate hedging instruments during the first quarter of 2017 to hedge approximately $1.0 billion of variable rate debt for 2018 through 2020 and approximately $500 million of variable rate debt for 2021 through 2022. We also extended the tenor of certain interest rate hedging instruments which effectively places a ceiling on LIBOR on $2.5 billion of variable rate corporate debt through 2020 and $1.25 billion of variable rate corporate debt in 2021. 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. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of March 31, 2017 , was $24 million for which we have posted collateral of $2 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 nil related to our derivative liabilities would be required and that no counterparty could request immediate, full settlement. Accounting for Derivative Instruments We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities. Cash Flow Hedges — We only apply hedge accounting to our interest rate hedging instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects 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, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for physical and financial power and Heat Rate and commodity option activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense. Derivatives Included on Our Consolidated Condensed Balance Sheets The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 Commodity Instruments Interest Rate Hedging Instruments Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 1,386 $ 1 $ 1,387 Long-term derivative assets 634 36 670 Total derivative assets $ 2,020 $ 37 $ 2,057 Current derivative liabilities $ 1,246 $ 27 $ 1,273 Long-term derivative liabilities 522 28 550 Total derivative liabilities $ 1,768 $ 55 $ 1,823 Net derivative assets (liabilities) $ 252 $ (18 ) $ 234 December 31, 2016 Commodity Interest Rate Hedging Instruments Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 1,724 $ 1 $ 1,725 Long-term derivative assets 515 28 543 Total derivative assets $ 2,239 $ 29 $ 2,268 Current derivative liabilities $ 1,602 $ 28 $ 1,630 Long-term derivative liabilities 446 30 476 Total derivative liabilities $ 2,048 $ 58 $ 2,106 Net derivative assets (liabilities) $ 191 $ (29 ) $ 162 March 31, 2017 December 31, 2016 Fair Value of Derivative Assets Fair Value of Derivative Liabilities Fair Value of Derivative Assets Fair Value of Derivative Liabilities Derivatives designated as cash flow hedging instruments: Interest rate hedging instruments $ 37 $ 55 $ 29 $ 58 Total derivatives designated as cash flow hedging instruments $ 37 $ 55 $ 29 $ 58 Derivatives not designated as hedging instruments: Commodity instruments $ 2,020 $ 1,768 $ 2,239 $ 2,048 Total derivatives not designated as hedging instruments $ 2,020 $ 1,768 $ 2,239 $ 2,048 Total derivatives $ 2,057 $ 1,823 $ 2,268 $ 2,106 We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets Gross Amounts Presented on our Consolidated Condensed Balance Sheets Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets Margin/Cash (Received) Posted (1) Net Amount Derivative assets: Commodity exchange traded futures and swaps contracts $ 1,259 $ (1,253 ) $ (6 ) $ — Commodity forward contracts 761 (172 ) (11 ) 578 Interest rate hedging instruments 37 (5 ) — 32 Total derivative assets $ 2,057 $ (1,430 ) $ (17 ) $ 610 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,298 ) $ 1,253 $ 45 $ — Commodity forward contracts (470 ) 172 52 (246 ) Interest rate hedging instruments (55 ) 5 — (50 ) Total derivative (liabilities) $ (1,823 ) $ 1,430 $ 97 $ (296 ) Net derivative assets (liabilities) $ 234 $ — $ 80 $ 314 December 31, 2016 Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets Gross Amounts Presented on our Consolidated Condensed Balance Sheets Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets Margin/Cash (Received) Posted (1) Net Amount Derivative assets: Commodity exchange traded futures and swaps contracts $ 1,542 $ (1,521 ) $ (21 ) $ — Commodity forward contracts 697 (165 ) (11 ) 521 Interest rate hedging instruments 29 — — 29 Total derivative assets $ 2,268 $ (1,686 ) $ (32 ) $ 550 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,570 ) $ 1,521 $ 49 $ — Commodity forward contracts (478 ) 165 55 (258 ) Interest rate hedging instruments (58 ) — — (58 ) Total derivative (liabilities) $ (2,106 ) $ 1,686 $ 104 $ (316 ) Net derivative assets (liabilities) $ 162 $ — $ 72 $ 234 ____________ (1) Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 for a further discussion of our collateral. Derivatives Included on Our Consolidated Condensed Statements of Operations Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our earnings. The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions): Three Months Ended March 31, 2017 2016 Realized gain (loss) (1)(2) Commodity derivative instruments $ 29 $ 118 Total realized gain (loss) $ 29 $ 118 Mark-to-market gain (loss) (3) Commodity derivative instruments $ 55 $ (95 ) Interest rate hedging instruments — 1 Total mark-to-market gain (loss) $ 55 $ (94 ) Total activity, net $ 84 $ 24 ___________ (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. (2) Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power. (3) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. Three Months Ended March 31, 2017 2016 Realized and mark-to-market gain (loss) (1) Derivatives contracts included in operating revenues (2)(3) $ 223 $ 204 Derivatives contracts included in fuel and purchased energy expense (2)(3) (139 ) (181 ) Interest rate hedging instruments included in interest expense (4) — 1 Total activity, net $ 84 $ 24 ___________ (1) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure. (2) Does not include the realized value associated with derivative instruments that settle through physical delivery. (3) Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power. (4) In addition to changes in market value on interest rate hedging instruments not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness. Derivatives Included in OCI and AOCI The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions): Three Months Ended March 31, Three Months Ended March 31, Gain (Loss) Recognized in OCI (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) (3) 2017 2016 2017 2016 Affected Line Item on the Consolidated Condensed Statements of Operations Interest rate hedging instruments (1)(2) $ (4 ) $ (12 ) $ (11 ) $ (11 ) Interest expense ____________ (1) We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three months ended March 31, 2017 and 2016 . (2) We recorded an income tax expense of nil for each of the three months ended March 31, 2017 and 2016 , in AOCI related to our cash flow hedging activities. (3) Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $94 million and $90 million at March 31, 2017 and December 31, 2016 , respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $8 million and $8 million at March 31, 2017 and December 31, 2016 , respectively. We estimate that pre-tax net losses of $38 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	3 Months Ended
	Mar. 31, 2017
Use of Collateral [Abstract]
Use of Collateral [Text Block]	Use of Collateral We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of our interest rate hedging instruments 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 March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 December 31, 2016 Margin deposits (1) $ 284 $ 350 Natural gas and power prepayments 24 25 Total margin deposits and natural gas and power prepayments with our counterparties (2) $ 308 $ 375 Letters of credit issued $ 738 $ 798 First priority liens under power and natural gas agreements 217 206 First priority liens under interest rate hedging instruments 53 55 Total letters of credit and first priority liens with our counterparties $ 1,008 $ 1,059 Margin deposits posted with us by our counterparties (1)(3) $ 9 $ 16 Letters of credit posted with us by our counterparties 37 43 Total margin deposits and letters of credit posted with us by our counterparties $ 46 $ 59 ___________ (1) Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements. (2) At March 31, 2017 and December 31, 2016 , $298 million and $366 million , respectively, were included in margin deposits and other prepaid expense and $10 million and $9 million , respectively, were included in other assets on our Consolidated Condensed Balance Sheets. (3) Included in other current liabilities on our Consolidated Condensed Balance Sheets. Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Income Tax Expense (Benefit) The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions): Three Months Ended March 31, 2017 2016 Income tax expense (benefit) $ (61 ) $ 35 Effective tax rate 52 % (21 )% Our income tax rates do not bear a customary relationship to statutory income tax rates primarily as a result of the effect of our NOLs, changes in unrecognized tax benefits and valuation allowances. For the three months ended March 31, 2017 and 2016 , our income tax expense (benefit) is largely comprised of discrete tax items and estimated state and foreign income taxes in jurisdictions where we do not have NOLs or valuation allowances. During the three months ended March 31, 2017 , we recorded an income tax benefit of $17 million associated with a favorable adjustment to our reserve for uncertain tax positions. See Note 10 in our 2016 Form 10-K for further information regarding our NOLs. Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to IRS examination regardless of when the NOLs occurred. Any adjustment of state or federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs. We are currently subject to U.S. federal income tax examination for the year ended December 31, 2015 . 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. Unrecognized Tax Benefits — At March 31, 2017 , we had unrecognized tax benefits of $48 million . If recognized, $10 million of our unrecognized tax benefits could affect the annual effective tax rate and $38 million , related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no effect on our effective tax rate. We had accrued interest and penalties of $3 million for income tax matters at March 31, 2017 . We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Condensed Statements of Operations. We believe that it is reasonably possible that a decrease within the range of nil and $7 million in unrecognized tax benefits could occur within the next twelve months primarily related to foreign tax issues.

Earnings (Loss) per Share

Earnings (Loss) per Share	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Earnings Per Share [Text Block]	Loss per Share We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. As we incurred a net loss for the three months ended March 31, 2017 and 2016 , diluted loss per share for each period is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. We excluded the following items from diluted earnings per common share for the three months ended March 31, 2017 and 2016 , because they were anti-dilutive (shares in thousands): Three Months Ended March 31, 2017 2016 Share-based awards 4,743 4,468

Stock-Based Compensation

Stock-Based Compensation	3 Months Ended
	Mar. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [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 March 31, 2017 , 84,221 shares and 878,194 shares remain available for future grants under the Director Plan and the Equity Plan, respectively. Equity Classified Share-Based Awards Stock-based compensation expense recognized for our equity classified share-based awards was $8 million and $ 7 million for the three months ended March 31, 2017 and 2016 , 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 three months ended March 31, 2017 and 2016 . At March 31, 2017 , there was unrecognized compensation cost of $ 40 million related to restricted stock and $ 6 million related to options which is expected to be recognized over a weighted average period of 2.0 years for restricted stock and 2.6 years for options. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans when stock options are exercised and for other share-based awards. A summary of all of our non-qualified stock option activity for the Equity Plan for the three months ended March 31, 2017 , is as follows: Number of Shares Weighted Average Exercise Price Weighted Average Remaining Term (in years) Aggregate Intrinsic Value (in millions) Outstanding — December 31, 2016 2,697,136 $ 13.59 3.0 $ 2 Granted 1,460,909 $ 11.69 Forfeited 15,721 $ 11.69 Expired 6,200 $ 17.50 Outstanding — March 31, 2017 4,136,124 $ 12.92 5.2 $ 1 Exercisable — March 31, 2017 2,690,936 $ 13.58 2.7 $ 1 Vested and expected to vest – March 31, 2017 3,930,873 $ 12.98 5.0 $ 1 The fair value of options granted during the three months ended March 31, 2017 , 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: 2017 Expected term (in years) (1) 7.32 Risk-free interest rate (2) 2.25 % Expected volatility (3) 40 % Dividend yield (4) — Weighted average grant-date fair value (per option) $ 5.38 ___________ (1) Expected term calculated using historical exercise data. (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 three months ended March 31, 2017 , is as follows: Number of Restricted Stock Awards Weighted Average Grant-Date Fair Value Nonvested — December 31, 2016 4,869,648 $ 15.83 Granted 2,546,223 $ 11.70 Forfeited 340,080 $ 14.28 Vested 1,465,907 $ 17.13 Nonvested — March 31, 2017 5,609,884 (1 ) $ 13.71 ___________ (1) Includes 49,897 shares of restricted stock and restricted stock units outstanding under the Director Plan and 5,559,987 shares of restricted stock and restricted stock units outstanding under the Equity Plan. The total fair value of our restricted stock and restricted stock units that vested during the three months ended March 31, 2017 and 2016 was approximately $ 17 million and $ 15 million , respectively. Liability Classified Share-Based Awards During the first quarter of 2017, 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 total shareholder return over the three-year performance period of January 1, 2017 through December 31, 2019. 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 nil and $ 2 million for the three months ended March 31, 2017 and 2016 , respectively. A summary of our performance share unit activity for the three months ended March 31, 2017 , is as follows: Number of Performance Share Units Weighted Average Grant-Date Fair Value Nonvested — December 31, 2016 890,587 $ 17.90 Granted 472,278 $ 10.69 Forfeited 54,638 $ 18.38 Vested (1) 5,810 $ 14.81 Nonvested — March 31, 2017 1,302,417 $ 15.28 ___________ (1) In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date. For a further discussion of the Calpine Equity Incentive Plans, see Note 12 in our 2016 Form 10-K.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Litigation We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows. On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows. Environmental Matters We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material effect on our financial condition, results of operations or cash flows or that would significantly change our operations. California Air Resources Board. On November 8, 2016, Russell City Energy Center, LLC received a notice of violation for exceeding CARB’s annual emission limits for Sulfur Hexafluoride (“SF 6 ”) due to a leak of SF 6 during 2015 from one of the high voltage circuit breakers located in the Russell City Energy Center switchyard. SF 6 is a gas used as an electrical insulator in high voltage circuit breakers and is a GHG. A monetary penalty has not yet been imposed by CARB. The liability we may ultimately incur with respect to this matter has not been determined, but it is not expected to be material. Guarantees and Indemnifications 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 March 31, 2017 , 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. There have been no material changes to our guarantees and indemnifications from those disclosed in Note 15 of our 2016 Form 10-K.

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2017
Segment Reporting [Abstract]
Segment Information	Segment Information We assess our business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. At March 31, 2017 , our reportable segments were West (including geothermal), Texas and East (including Canada). The results of our retail subsidiaries are reflected in the segment which corresponds with the geographic area in which the retail sales occur. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result in changes to the composition of our geographic segments. Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions): Three Months Ended March 31, 2017 West Texas East Consolidation and Elimination Total Revenues from external customers $ 712 $ 799 $ 770 $ — $ 2,281 Intersegment revenues 2 3 2 (7 ) — Total operating revenues $ 714 $ 802 $ 772 $ (7 ) $ 2,281 Commodity Margin $ 221 $ 148 $ 189 $ — $ 558 Add: Mark-to-market commodity activity, net and other (1) 77 (30 ) (8 ) (8 ) 31 Less: Plant operating expense 97 96 96 (7 ) 282 Depreciation and amortization expense 91 62 53 — 206 Sales, general and other administrative expense 13 17 10 — 40 Other operating expenses 9 3 9 (1 ) 20 (Gain) on sale of assets, net — — (27 ) — (27 ) (Income) from unconsolidated subsidiaries — — (4 ) — (4 ) Income (loss) from operations 88 (60 ) 44 — 72 Interest expense 159 Debt extinguishment costs and other (income) expense, net 26 Loss before income taxes $ (113 ) Three Months Ended March 31, 2016 West Texas East Consolidation and Elimination Total Revenues from external customers $ 424 $ 532 $ 659 $ — $ 1,615 Intersegment revenues 2 3 3 (8 ) — Total operating revenues $ 426 $ 535 $ 662 $ (8 ) $ 1,615 Commodity Margin $ 197 $ 153 $ 230 $ — $ 580 Add: Mark-to-market commodity activity, net and other (1) 46 (110 ) (21 ) (6 ) (91 ) Less: Plant operating expense 91 86 84 (6 ) 255 Depreciation and amortization expense 69 53 58 — 180 Sales, general and other administrative expense 10 16 12 — 38 Other operating expenses 8 2 10 — 20 (Income) from unconsolidated subsidiaries — — (7 ) — (7 ) Income (loss) from operations 65 (114 ) 52 — 3 Interest expense 157 Other (income) expense, net 5 Loss before income taxes $ (159 ) _________ (1) Includes $(22) million and $ (22) million of lease levelization and $60 million and $ 27 million of amortization expense for the three months ended March 31, 2017 and 2016 , respectively.

Basis of Presentation and Sum19

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2017
Accounting Policies [Abstract]
Basis of interim presentation	Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2016 , included in our 2016 Form 10-K. The results for interim periods are not indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues and expenses, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts.
Use of estimates in preparation of financial statements	Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Cash and cash equivalents	Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects.
Restricted cash	Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. 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 and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows.
Consolidation, Variable Interest Entity, Policy	We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are 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. In December 2016, we acquired Calpine Receivables, a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. Calpine Receivables is a VIE as we have determined that we do not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, we have determined that we are not the primary beneficiary of Calpine Receivables as we do not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls management of default. Thus, we do not consolidate Calpine Receivables in our Consolidated Financial Statements and use the equity method of accounting to record our net interest in Calpine Receivables. We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Condensed Balance Sheets. We consolidate all of our VIEs where we have determined that we are the primary beneficiary.
Fair Value of Financial Instruments	We measure the fair value of our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loans using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy. Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do not have any cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Certain of our cash equivalents 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 and customers for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. 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 customers and the effect 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 hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. 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 primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect 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.
Derivatives	We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities. Cash Flow Hedges — We only apply hedge accounting to our interest rate hedging instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects 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, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for physical and financial power and Heat Rate and commodity option activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense. We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty.
Commitments and contingencies	On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows.
New accounting pronouncements, policy	Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding revenue recognition. The standard allows for either full retrospective or modified retrospective adoption. In August 2015, the FASB deferred the effective date of Accounting Standards Update 2014-09 for public entities by one year, such that the standard will become effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The standard permits entities to adopt early, but only as of the original effective date. In March 2016, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. In May 2016, the FASB issued Accounting Standards Update 2016-12 “Narrow-Scope Improvements and Practical Expedients” which addresses assessing the collectability of a contract, the presentation of sales taxes and other taxes collected from customers, non-cash consideration and completed contracts and contract modifications at transition. We expect to adopt the standard in the first quarter of 2018 using the modified retrospective transition approach; however, our method of adoption may change as we complete our assessment of the standard. We are currently evaluating the effect the revenue recognition standards will have on our revenue contracts such as our PPAs and tolling agreements; however, we do not anticipate the adoption of this standard will have a material effect on our financial condition, results of operations or cash flows. Upon adoption, we intend to elect the practical expedient that would allow an entity to recognize revenue in the amount to which the entity has the right to invoice to the extent we determine that we have a right to consideration from the customer in an amount that corresponds directly with the value provided based on our performance completed to date. Inventory — In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” The standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. This standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective adoption with early adoption permitted. We adopted Accounting Standards Update 2015-11 in the first quarter of 2017 which did not have a material effect on our financial condition, results of operations or cash flows. Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified retrospective adoption with early adoption permitted. We expect to adopt the standard in the first quarter of 2019. We have completed our initial evaluation of the standard and believe that the key changes that will affect us relate to our accounting for operating leases that are currently off-balance sheet and tolling contracts which we currently account for as operating leases. Additionally, we are evaluating the potential effects of the removal of the real estate guidance currently applicable to lessors that will be abrogated under Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” We are also considering electing the practical expedient in our implementation of the standard; however, this may change as we complete our assessment of the standard. Statement of Cash Flows — In August 2016, the FASB issued Accounting Standards Update 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” The standard addresses several matters of diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows including the presentation of debt extinguishment costs and distributions received from equity method investments. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and allows for retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. Restricted Cash — In November 2016, the FASB issued Accounting Standards Update 2016-18, “Restricted Cash.” The standard requires restricted cash to be included with cash and cash equivalents when reconciling the beginning and ending amounts in the statement of cash flows and also requires disclosures regarding the nature of restrictions on cash, cash equivalents and restricted cash. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and requires for retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. Intangibles – Goodwill and Other — In January 2017, the FASB issued Accounting Standards Update 2017-04, “Simplifying the Test for Goodwill Impairment.” The standard eliminates the second step in the goodwill impairment test which requires an entity to determine the implied fair value of the reporting unit’s goodwill. Instead, an entity should recognize an impairment loss if the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, with the impairment loss not to exceed the amount of goodwill allocated to the reporting unit. The standard is effective for annual and interim goodwill impairment tests conducted in fiscal years beginning after December 15, 2019, with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.

Basis of Presentation and Sum20

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2017
Accounting Policies [Abstract]
Schedule of components of restricted cash	The table below represents the components of our restricted cash as of March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 December 31, 2016 Current Non-Current Total Current Non-Current Total Debt service $ 12 $ 7 $ 19 $ 11 $ 8 $ 19 Construction/major maintenance 48 6 54 45 6 51 Security/project/insurance 99 — 99 114 — 114 Other 3 2 5 3 1 4 Total $ 162 $ 15 $ 177 $ 173 $ 15 $ 188
Schedule of property, plant and equipment	Property, Plant and Equipment, Net — At March 31, 2017 and December 31, 2016 , the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions): March 31, 2017 December 31, 2016 Depreciable Lives Buildings, machinery and equipment $ 16,481 $ 16,468 3 – 46 Years Geothermal properties 1,460 1,377 13 – 58 Years Other 237 259 3 – 46 Years 18,178 18,104 Less: Accumulated depreciation 5,975 5,865 12,203 12,239 Land 116 116 Construction in progress 690 658 Property, plant and equipment, net $ 13,009 $ 13,013
Schedule of Goodwill	Goodwill — The change in goodwill during the three months ended March 31, 2017 was as follows (in millions): West Texas East Total Goodwill at December 31, 2016 $ 68 $ 31 $ 88 $ 187 Acquisition of North American Power — — 49 49 Calpine Solutions purchase price allocation adjustment (1 ) — (2 ) (3 ) Goodwill at March 31, 2017 $ 67 $ 31 $ 135 $ 233

Variable Interest Entities an21

Variable Interest Entities and Unconsolidated Investments in Power Plants (Tables)	3 Months Ended
	Mar. 31, 2017
Variable Interest Entities and Unconsolidated Investments [Abstract]
Schedule of equity method investments	At March 31, 2017 and December 31, 2016 , our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions): Ownership Interest as of March 31, 2017 March 31, 2017 December 31, 2016 Greenfield LP 50% $ 78 $ 73 Whitby 50% 4 16 Calpine Receivables 100% 10 10 Total investments in unconsolidated subsidiaries $ 92 $ 99
Income (loss) from unconsolidated investments in power plants	The following table sets forth details of our (income) from unconsolidated subsidiaries for the periods indicated (in millions): Three Months Ended March 31, 2017 2016 Greenfield LP $ (2 ) $ (4 ) Whitby (2 ) (3 ) Total $ (4 ) $ (7 )

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2017
Debt Disclosure [Abstract]
Schedule of long-term debt instruments	Our debt at March 31, 2017 and December 31, 2016 , was as follows (in millions): March 31, 2017 December 31, 2016 Senior Unsecured Notes $ 3,413 $ 3,412 First Lien Term Loans 3,405 3,165 First Lien Notes 1,841 2,290 Project financing, notes payable and other 1,561 1,597 CCFC Term Loans 1,550 1,553 Capital lease obligations 157 162 Corporate Revolving Facility 25 — Subtotal 11,952 12,179 Less: Current maturities 608 748 Total long-term debt $ 11,344 $ 11,431
Senior Unsecured Notes	The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions): March 31, 2017 December 31, 2016 2023 Senior Unsecured Notes $ 1,237 $ 1,237 2024 Senior Unsecured Notes 643 643 2025 Senior Unsecured Notes 1,533 1,532 Total Senior Unsecured Notes $ 3,413 $ 3,412
First Lien Term Loans	The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions): March 31, 2017 December 31, 2016 2017 First Lien Term Loan (1) $ 393 $ 537 2019 First Lien Term Loan 389 — 2023 First Lien Term Loans 1,070 1,071 2024 First Lien Term Loan 1,553 1,557 Total First Lien Term Loans $ 3,405 $ 3,165 ____________ (1) On March 16, 2017, we used cash on hand to repay $150 million of our outstanding 2017 First Lien Term Loan. During the first quarter of 2017, we recorded approximately $3 million in debt extinguishment costs related to the partial repayment of our 2017 First Lien Term Loan.
First Lien Notes	The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions): March 31, 2017 December 31, 2016 2022 First Lien Notes $ 739 $ 739 2023 First Lien Notes (1) — 450 2024 First Lien Notes 485 485 2026 First Lien Notes 617 616 Total First Lien Notes $ 1,841 $ 2,290 ____________ (1) On March 6, 2017, we used cash on hand along with the proceeds from our 2019 First Lien Term Loan to redeem the remaining $453 million of our 2023 First Lien Notes, plus accrued and unpaid interest. During the first quarter of 2017, we recorded approximately $21 million in debt extinguishment costs related to the redemption of our 2023 First Lien Notes.
Schedule of line of credit facilities	The table below represents amounts issued under our letter of credit facilities at March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 December 31, 2016 Corporate Revolving Facility (1) $ 471 $ 535 CDHI 237 250 Various project financing facilities 183 206 Total $ 891 $ 991 ____________ (1) The Corporate Revolving Facility represents our primary revolving facility.
Schedule of carrying values and estimated fair values of debt instruments	The following table details the fair values and carrying values of our debt instruments at March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 December 31, 2016 Fair Value Carrying Value Fair Value Carrying Value Senior Unsecured Notes $ 3,435 $ 3,413 $ 3,343 $ 3,412 First Lien Term Loans 3,480 3,405 3,244 3,165 First Lien Notes 1,931 1,841 2,349 2,290 Project financing, notes payable and other (1) 1,505 1,469 1,543 1,506 CCFC Term Loans 1,567 1,550 1,567 1,553 Corporate Revolving Facility 25 25 — — Total $ 11,943 $ 11,703 $ 12,046 $ 11,926 ____________ (1) Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

Assets and Liabilities with R23

Assets and Liabilities with Recurring Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Fair Value, Measurement Inputs, Disclosure	The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2017 and December 31, 2016 , by level within the fair value hierarchy: Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2017 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 166 $ — $ — $ 166 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,259 — — 1,259 Commodity forward contracts (2) — 359 402 761 Interest rate hedging instruments — 37 — 37 Total assets $ 1,425 $ 396 $ 402 $ 2,223 Liabilities: Commodity instruments: Commodity exchange traded futures and swaps contracts 1,298 — — 1,298 Commodity forward contracts (2) — 410 60 470 Interest rate hedging instruments — 55 — 55 Total liabilities $ 1,298 $ 465 $ 60 $ 1,823 Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2016 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 153 $ — $ — $ 153 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,542 — — 1,542 Commodity forward contracts (2) — 231 466 697 Interest rate hedging instruments — 29 — 29 Total assets $ 1,695 $ 260 $ 466 $ 2,421 Liabilities: Commodity instruments: Commodity exchange traded futures and swaps contracts 1,570 — — 1,570 Commodity forward contracts (2) — 411 67 478 Interest rate hedging instruments — 58 — 58 Total liabilities $ 1,570 $ 469 $ 67 $ 2,106 ___________ (1) As of March 31, 2017 and December 31, 2016 , we had cash equivalents of $36 million and $26 million included in cash and cash equivalents and $130 million and $127 million included in restricted cash, respectively. (2) Includes OTC swaps and options and retail contracts.
Fair Value Inputs, Assets, Quantitative Information	The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at March 31, 2017 and December 31, 2016 : Quantitative Information about Level 3 Fair Value Measurements March 31, 2017 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ 324 Discounted cash flow Market price (per MWh) $ 8.00 — $92.00 /MWh Power Congestion Products $ 11 Discounted cash flow Market price (per MWh) $ (7.52 ) — $4.54 /MWh Natural Gas Contracts $ 60 Discounted cash flow Market price (per MMBtu) $ 1.79 — $6.24 /MMBtu December 31, 2016 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ 360 Discounted cash flow Market price (per MWh) $ 9.60 — $86.34 /MWh Power Congestion Products $ 12 Discounted cash flow Market price (per MWh) $ (7.52 ) — $13.62 /MWh Natural Gas Contracts $ 17 Discounted cash flow Market price (per MMBtu) $ 1.95 — $5.66 /MMBtu
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions): Three Months Ended March 31, 2017 2016 Balance, beginning of period $ 399 $ (46 ) Realized and mark-to-market gains (losses): Included in net income: Included in operating revenues (1) 113 (22 ) Included in fuel and purchased energy expense (2) 13 (14 ) Purchases and settlements: Purchases — 2 Settlements (26 ) (4 ) Transfers in and/or out of level 3 (3) : Transfers into level 3 (4) (7 ) — Transfers out of level 3 (5) (150 ) 19 Balance, end of period $ 342 $ (65 ) Change in unrealized gains (losses) relating to instruments still held at end of period $ 126 $ (36 ) ___________ (1) For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations. (2) For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations. (3) We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three months ended March 31, 2017 and 2016 . (4) There were $7 million and nil in losses transferred out of level 2 into level 3 for the three months ended March 31, 2017 and 2016 , respectively, due to changes in market liquidity in various power markets. (5) We had $150 million in gains and $(19) million in losses transferred out of level 3 into level 2 for the three months ended March 31, 2017 and 2016 , respectively, due to changes in market liquidity in various power markets.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions	As of March 31, 2017 and December 31, 2016 , the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions): Derivative Instruments Notional Amounts March 31, 2017 December 31, 2016 Power (MWh) (78 ) (86 ) Natural gas (MMBtu) 779 613 Environmental credits (Tonnes) 16 16 Interest rate hedging instruments $ 4,600 (1) $ 3,721 ___________ (1) We entered into interest rate hedging instruments during the first quarter of 2017 to hedge approximately $1.0 billion of variable rate debt for 2018 through 2020 and approximately $500 million of variable rate debt for 2021 through 2022. We also extended the tenor of certain interest rate hedging instruments which effectively places a ceiling on LIBOR on $2.5 billion of variable rate corporate debt through 2020 and $1.25 billion of variable rate corporate debt in 2021.
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location [Table Text Block]	The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 Commodity Instruments Interest Rate Hedging Instruments Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 1,386 $ 1 $ 1,387 Long-term derivative assets 634 36 670 Total derivative assets $ 2,020 $ 37 $ 2,057 Current derivative liabilities $ 1,246 $ 27 $ 1,273 Long-term derivative liabilities 522 28 550 Total derivative liabilities $ 1,768 $ 55 $ 1,823 Net derivative assets (liabilities) $ 252 $ (18 ) $ 234 December 31, 2016 Commodity Interest Rate Hedging Instruments Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 1,724 $ 1 $ 1,725 Long-term derivative assets 515 28 543 Total derivative assets $ 2,239 $ 29 $ 2,268 Current derivative liabilities $ 1,602 $ 28 $ 1,630 Long-term derivative liabilities 446 30 476 Total derivative liabilities $ 2,048 $ 58 $ 2,106 Net derivative assets (liabilities) $ 191 $ (29 ) $ 162
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	March 31, 2017 December 31, 2016 Fair Value of Derivative Assets Fair Value of Derivative Liabilities Fair Value of Derivative Assets Fair Value of Derivative Liabilities Derivatives designated as cash flow hedging instruments: Interest rate hedging instruments $ 37 $ 55 $ 29 $ 58 Total derivatives designated as cash flow hedging instruments $ 37 $ 55 $ 29 $ 58 Derivatives not designated as hedging instruments: Commodity instruments $ 2,020 $ 1,768 $ 2,239 $ 2,048 Total derivatives not designated as hedging instruments $ 2,020 $ 1,768 $ 2,239 $ 2,048 Total derivatives $ 2,057 $ 1,823 $ 2,268 $ 2,106
Derivative Instruments Subject to Master Netting Arrangements [Table Text Block]	The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets Gross Amounts Presented on our Consolidated Condensed Balance Sheets Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets Margin/Cash (Received) Posted (1) Net Amount Derivative assets: Commodity exchange traded futures and swaps contracts $ 1,259 $ (1,253 ) $ (6 ) $ — Commodity forward contracts 761 (172 ) (11 ) 578 Interest rate hedging instruments 37 (5 ) — 32 Total derivative assets $ 2,057 $ (1,430 ) $ (17 ) $ 610 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,298 ) $ 1,253 $ 45 $ — Commodity forward contracts (470 ) 172 52 (246 ) Interest rate hedging instruments (55 ) 5 — (50 ) Total derivative (liabilities) $ (1,823 ) $ 1,430 $ 97 $ (296 ) Net derivative assets (liabilities) $ 234 $ — $ 80 $ 314 December 31, 2016 Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets Gross Amounts Presented on our Consolidated Condensed Balance Sheets Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets Margin/Cash (Received) Posted (1) Net Amount Derivative assets: Commodity exchange traded futures and swaps contracts $ 1,542 $ (1,521 ) $ (21 ) $ — Commodity forward contracts 697 (165 ) (11 ) 521 Interest rate hedging instruments 29 — — 29 Total derivative assets $ 2,268 $ (1,686 ) $ (32 ) $ 550 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,570 ) $ 1,521 $ 49 $ — Commodity forward contracts (478 ) 165 55 (258 ) Interest rate hedging instruments (58 ) — — (58 ) Total derivative (liabilities) $ (2,106 ) $ 1,686 $ 104 $ (316 ) Net derivative assets (liabilities) $ 162 $ — $ 72 $ 234 ____________ (1) Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 for a further discussion of our collateral.
Realized Unrealized Gain Loss by Instrument	The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions): Three Months Ended March 31, 2017 2016 Realized gain (loss) (1)(2) Commodity derivative instruments $ 29 $ 118 Total realized gain (loss) $ 29 $ 118 Mark-to-market gain (loss) (3) Commodity derivative instruments $ 55 $ (95 ) Interest rate hedging instruments — 1 Total mark-to-market gain (loss) $ 55 $ (94 ) Total activity, net $ 84 $ 24 ___________ (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. (2) Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power. (3) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location	Three Months Ended March 31, 2017 2016 Realized and mark-to-market gain (loss) (1) Derivatives contracts included in operating revenues (2)(3) $ 223 $ 204 Derivatives contracts included in fuel and purchased energy expense (2)(3) (139 ) (181 ) Interest rate hedging instruments included in interest expense (4) — 1 Total activity, net $ 84 $ 24 ___________ (1) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure. (2) Does not include the realized value associated with derivative instruments that settle through physical delivery. (3) Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power. (4) In addition to changes in market value on interest rate hedging instruments not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness.
Derivatives Designated as Hedges	The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions): Three Months Ended March 31, Three Months Ended March 31, Gain (Loss) Recognized in OCI (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) (3) 2017 2016 2017 2016 Affected Line Item on the Consolidated Condensed Statements of Operations Interest rate hedging instruments (1)(2) $ (4 ) $ (12 ) $ (11 ) $ (11 ) Interest expense ____________ (1) We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three months ended March 31, 2017 and 2016 . (2) We recorded an income tax expense of nil for each of the three months ended March 31, 2017 and 2016 , in AOCI related to our cash flow hedging activities. (3) Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $94 million and $90 million at March 31, 2017 and December 31, 2016 , respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $8 million and $8 million at March 31, 2017 and December 31, 2016 , respectively.

Use of Collateral (Tables)

Use of Collateral (Tables)	3 Months Ended
	Mar. 31, 2017
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 March 31, 2017 and December 31, 2016 (in millions): March 31, 2017 December 31, 2016 Margin deposits (1) $ 284 $ 350 Natural gas and power prepayments 24 25 Total margin deposits and natural gas and power prepayments with our counterparties (2) $ 308 $ 375 Letters of credit issued $ 738 $ 798 First priority liens under power and natural gas agreements 217 206 First priority liens under interest rate hedging instruments 53 55 Total letters of credit and first priority liens with our counterparties $ 1,008 $ 1,059 Margin deposits posted with us by our counterparties (1)(3) $ 9 $ 16 Letters of credit posted with us by our counterparties 37 43 Total margin deposits and letters of credit posted with us by our counterparties $ 46 $ 59 ___________ (1) Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements. (2) At March 31, 2017 and December 31, 2016 , $298 million and $366 million , respectively, were included in margin deposits and other prepaid expense and $10 million and $9 million , respectively, were included in other assets on our Consolidated Condensed Balance Sheets. (3) Included in other current liabilities on our Consolidated Condensed Balance Sheets.

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions): Three Months Ended March 31, 2017 2016 Income tax expense (benefit) $ (61 ) $ 35 Effective tax rate 52 % (21 )%

Earnings (Loss) per Share (Tabl

Earnings (Loss) per Share (Tables)	3 Months Ended
	Mar. 31, 2017
Earnings Per Share [Abstract]
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	We excluded the following items from diluted earnings per common share for the three months ended March 31, 2017 and 2016 , because they were anti-dilutive (shares in thousands): Three Months Ended March 31, 2017 2016 Share-based awards 4,743 4,468

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]	A summary of all of our non-qualified stock option activity for the Equity Plan for the three months ended March 31, 2017 , is as follows: Number of Shares Weighted Average Exercise Price Weighted Average Remaining Term (in years) Aggregate Intrinsic Value (in millions) Outstanding — December 31, 2016 2,697,136 $ 13.59 3.0 $ 2 Granted 1,460,909 $ 11.69 Forfeited 15,721 $ 11.69 Expired 6,200 $ 17.50 Outstanding — March 31, 2017 4,136,124 $ 12.92 5.2 $ 1 Exercisable — March 31, 2017 2,690,936 $ 13.58 2.7 $ 1 Vested and expected to vest – March 31, 2017 3,930,873 $ 12.98 5.0 $ 1
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]	Certain assumptions were used in order to estimate fair value for options as noted in the following table: 2017 Expected term (in years) (1) 7.32 Risk-free interest rate (2) 2.25 % Expected volatility (3) 40 % Dividend yield (4) — Weighted average grant-date fair value (per option) $ 5.38 ___________ (1) Expected term calculated using historical exercise data. (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 Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]	A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the three months ended March 31, 2017 , is as follows: Number of Restricted Stock Awards Weighted Average Grant-Date Fair Value Nonvested — December 31, 2016 4,869,648 $ 15.83 Granted 2,546,223 $ 11.70 Forfeited 340,080 $ 14.28 Vested 1,465,907 $ 17.13 Nonvested — March 31, 2017 5,609,884 (1 ) $ 13.71 ___________ (1) Includes 49,897 shares of restricted stock and restricted stock units outstanding under the Director Plan and 5,559,987 shares of restricted stock and restricted stock units outstanding under the Equity Plan.
Schedule of Share-based Compensation, Activity	A summary of our performance share unit activity for the three months ended March 31, 2017 , is as follows: Number of Performance Share Units Weighted Average Grant-Date Fair Value Nonvested — December 31, 2016 890,587 $ 17.90 Granted 472,278 $ 10.69 Forfeited 54,638 $ 18.38 Vested (1) 5,810 $ 14.81 Nonvested — March 31, 2017 1,302,417 $ 15.28 ___________ (1) In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date.

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2017
Segment Reporting [Abstract]
Schedule of Financial Data for Segments	The tables below show our financial data for our segments for the periods indicated (in millions): Three Months Ended March 31, 2017 West Texas East Consolidation and Elimination Total Revenues from external customers $ 712 $ 799 $ 770 $ — $ 2,281 Intersegment revenues 2 3 2 (7 ) — Total operating revenues $ 714 $ 802 $ 772 $ (7 ) $ 2,281 Commodity Margin $ 221 $ 148 $ 189 $ — $ 558 Add: Mark-to-market commodity activity, net and other (1) 77 (30 ) (8 ) (8 ) 31 Less: Plant operating expense 97 96 96 (7 ) 282 Depreciation and amortization expense 91 62 53 — 206 Sales, general and other administrative expense 13 17 10 — 40 Other operating expenses 9 3 9 (1 ) 20 (Gain) on sale of assets, net — — (27 ) — (27 ) (Income) from unconsolidated subsidiaries — — (4 ) — (4 ) Income (loss) from operations 88 (60 ) 44 — 72 Interest expense 159 Debt extinguishment costs and other (income) expense, net 26 Loss before income taxes $ (113 ) Three Months Ended March 31, 2016 West Texas East Consolidation and Elimination Total Revenues from external customers $ 424 $ 532 $ 659 $ — $ 1,615 Intersegment revenues 2 3 3 (8 ) — Total operating revenues $ 426 $ 535 $ 662 $ (8 ) $ 1,615 Commodity Margin $ 197 $ 153 $ 230 $ — $ 580 Add: Mark-to-market commodity activity, net and other (1) 46 (110 ) (21 ) (6 ) (91 ) Less: Plant operating expense 91 86 84 (6 ) 255 Depreciation and amortization expense 69 53 58 — 180 Sales, general and other administrative expense 10 16 12 — 38 Other operating expenses 8 2 10 — 20 (Income) from unconsolidated subsidiaries — — (7 ) — (7 ) Income (loss) from operations 65 (114 ) 52 — 3 Interest expense 157 Other (income) expense, net 5 Loss before income taxes $ (159 ) _________ (1) Includes $(22) million and $ (22) million of lease levelization and $60 million and $ 27 million of amortization expense for the three months ended March 31, 2017 and 2016 , respectively.

Basis of Presentation and Sum30

Basis of Presentation and Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Accounting Policies [Line Items]
Goodwill, Beginning Balance	$ 187
Goodwill, Ending Balance	233
Current	162		$ 173
Non-current	15		15
Total	177		188
Interest costs capitalized	7	$ 4
Transfer of Financial Assets Accounted for as Sales, Fair Value of Derecognized Assets	179		211
Continuing Involvement with Continued to be Recognized Transferred Financial Assets, Amount Outstanding	40		32
Trade Receivables Sold	542
Cash Flows Between Transferor and Transferee, Proceeds from New Transfers	546
Debt service
Accounting Policies [Line Items]
Current	12		11
Non-current	7		8
Total	19		19
Construction major maintenance
Accounting Policies [Line Items]
Current	48		45
Non-current	6		6
Total	54		51
Security project insurance
Accounting Policies [Line Items]
Current	99		114
Non-current	0		0
Total	99		114
Other
Accounting Policies [Line Items]
Current	3		3
Non-current	2		1
Total	$ 5		$ 4
Geothermal Properties, Gross [Member] | Minimum [Member]
Accounting Policies [Line Items]
Property, plant and equipment, estimated useful lives	13 years
Geothermal Properties, Gross [Member] | Maximum [Member]
Accounting Policies [Line Items]
Property, plant and equipment, estimated useful lives	58 years
Property, Plant and Equipment, Other Types [Member] | Minimum [Member]
Accounting Policies [Line Items]
Property, plant and equipment, estimated useful lives	3 years
Property, Plant and Equipment, Other Types [Member] | Maximum [Member]
Accounting Policies [Line Items]
Property, plant and equipment, estimated useful lives	46 years
Building, Machinery and Equipment, Gross [Member] | Minimum [Member]
Accounting Policies [Line Items]
Property, plant and equipment, estimated useful lives	3 years
Building, Machinery and Equipment, Gross [Member] | Maximum [Member]
Accounting Policies [Line Items]
Property, plant and equipment, estimated useful lives	46 years
Texas [Member]
Accounting Policies [Line Items]
Goodwill, Beginning Balance	$ 31
Goodwill, Ending Balance	31
East [Member]
Accounting Policies [Line Items]
Goodwill, Beginning Balance	88
Goodwill, Ending Balance	135
West [Member]
Accounting Policies [Line Items]
Goodwill, Beginning Balance	68
Goodwill, Ending Balance	67
Calpine Solutions [Member]
Accounting Policies [Line Items]
Goodwill, Purchase Accounting Adjustments	(3)
Calpine Solutions [Member] | Texas [Member]
Accounting Policies [Line Items]
Goodwill, Purchase Accounting Adjustments	0
Calpine Solutions [Member] | East [Member]
Accounting Policies [Line Items]
Goodwill, Purchase Accounting Adjustments	(2)
Calpine Solutions [Member] | West [Member]
Accounting Policies [Line Items]
Goodwill, Purchase Accounting Adjustments	(1)
North American Power [Member]
Accounting Policies [Line Items]
Goodwill, Acquired During Period	49
North American Power [Member] | Texas [Member]
Accounting Policies [Line Items]
Goodwill, Acquired During Period	0
North American Power [Member] | East [Member]
Accounting Policies [Line Items]
Goodwill, Acquired During Period	49
North American Power [Member] | West [Member]
Accounting Policies [Line Items]
Goodwill, Acquired During Period	$ 0

Basis of Presentation and Sum31

Basis of Presentation and Summary of Significant Accounting Policies Property, Plant and Equipment, Net (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Buildings, machinery and equipment	$ 16,481	$ 16,468
Geothermal properties	1,460	1,377
Other	237	259
Property, plant and equipment, gross	18,178	18,104
Less: Accumulated depreciation	5,975	5,865
Property, plant and equipment, gross, less accumulated depreciation, depletion and amortization	12,203	12,239
Land	116	116
Construction in progress	690	658
Property, plant and equipment, net	$ 13,009	$ 13,013
Minimum [Member] | Building, Machinery and Equipment, Gross [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, estimated useful lives	3 years
Minimum [Member] | Geothermal Properties, Gross [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, estimated useful lives	13 years
Minimum [Member] | Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, estimated useful lives	3 years
Maximum [Member] | Building, Machinery and Equipment, Gross [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, estimated useful lives	46 years
Maximum [Member] | Geothermal Properties, Gross [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, estimated useful lives	58 years
Maximum [Member] | Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, estimated useful lives	46 years

Acquisition (Details)

Acquisition (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)	Jan. 17, 2017USD ($)	Feb. 05, 2016USD ($)MW
North American Power [Member]
Business Acquisition [Line Items]
Ownership percentage of acquiree		100.00%
Business combination, recognized identifiable assets acquired and liabilities assumed, net		$ 105
Granite Ridge Energy Center [Member]
Business Acquisition [Line Items]
Business combination, recognized identifiable assets acquired and liabilities assumed, net			$ 500
Power generation capacity | MW			745
Summer Peaking Capacity | MW			695
Osprey Energy Center [Member]
Business Acquisition [Line Items]
Proceeds from Sale of Productive Assets	$ 166
Gain (Loss) on Sale of Assets and Asset Impairment Charges	$ 27

Variable Interest Entities an33

Variable Interest Entities and Unconsolidated Investments in Power Plants (Unconsolidated VIEs) (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 92	$ 99
Greenfield [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 78	73
Equity method investment, ownership percentage	50.00%
Whitby [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 4	16
Equity method investment, ownership percentage	50.00%
Calpine Receivables [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 10	$ 10
Equity method investment, ownership percentage	100.00%

Variable Interest Entities an34

Variable Interest Entities and Unconsolidated Investments in Power Plants (Income from Unconsolidated Investments 10-Q) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
(Income) from unconsolidated subsidiaries	$ (4)	$ (7)
Greenfield [Member]
(Income) from unconsolidated subsidiaries	(2)	(4)
Whitby [Member]
(Income) from unconsolidated subsidiaries	$ (2)	$ (3)

Variable Interest Entities an35

Variable Interest Entities and Unconsolidated Investments in Power Plants (VIE Texuals) (Details) $ in Millions	3 Months Ended
	Mar. 31, 2017USD ($)MW	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)MW
Variable Interest Entity [Line Items]
Variable interest entity, financial or other support, amount	$ 0	$ 0
Equity method investment, summarized financial information, debt	256		$ 259
Prorata share of equity method investment, summarized financial information, debt	$ 128		$ 130
Greenfield [Member]
Variable Interest Entity [Line Items]
Power generation capacity | MW	1,038
Equity method investment, ownership percentage	50.00%
Distribution from equity method investee	$ 0	0
Whitby [Member]
Variable Interest Entity [Line Items]
Power generation capacity | MW	50
Equity method investment, ownership percentage	50.00%
Distribution from equity method investee	$ 13	$ 0
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Power generation capacity | MW	8,988		9,491

Debt (Debt) (Details)

Debt (Debt) (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	$ 11,952	$ 12,179
Debt, Current	608	748
Long-term Debt, Excluding Current Maturities	11,344	11,431
Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	3,413	3,412
Loans Payable [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	3,405	3,165
Corporate Debt Securities [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	1,841	2,290
Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	1,561	1,597
Secured Debt [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	1,550	1,553
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Debt and Capital Lease Obligations	$ 157	$ 162

Debt Senior Unsecured Notes (De

Debt Senior Unsecured Notes (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt	$ 11,943	$ 12,046
Senior Unsecured Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	1,237	1,237
Senior Unsecured Notes 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt	643	643
Senior Unsecured Notes 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt	1,533	1,532
Unsecured Debt [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 3,413	$ 3,412

Debt (First Lien Term Loans) (D

Debt (First Lien Term Loans) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt		$ 11,943		$ 12,046
Gain (Loss) on Extinguishment of Debt		(24)	$ 0
2017 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	393		537
Gain (Loss) on Extinguishment of Debt		(3)
New 2019 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		400
Long-term Debt		389		0
Debt Issuance Costs, Net		$ 8
Gain (Loss) on Extinguishment of Debt		0.25%
Debt Instrument Unamortized Discount Percent		1.00%
2023 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 1,070		1,071
2024 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Long-term Debt		1,553		1,557
First Lien Term Loans [Member]
Debt Instrument [Line Items]
Long-term Debt		3,405		3,165
First Lien Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	[2]	0		$ 450
Gain (Loss) on Extinguishment of Debt		$ (21)
Federal Funds Effective Rate [Member] | New 2019 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.50%
Eurodollar Rate For A One-Month Interest Period [Member] | New 2019 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.00%
Prime Rate or The Eurodollar Rate For A One-Month Interest Period [Member] | New 2019 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		0.75%
London Interbank Offered Rate (LIBOR) [Member] | New 2019 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | New 2019 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		0.00%
Early Redemption Amount [Member] | 2017 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 150
Early Redemption Amount [Member] | First Lien Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 453
[1]	On March 16, 2017, we used cash on hand to repay $150 million of our outstanding 2017 First Lien Term Loan. During the first quarter of 2017, we recorded approximately $3 million in debt extinguishment costs related to the partial repayment of our 2017 First Lien Term Loan.
[2]	On March 6, 2017, we used cash on hand along with the proceeds from our 2019 First Lien Term Loan to redeem the remaining $453 million of our 2023 First Lien Notes, plus accrued and unpaid interest. During the first quarter of 2017, we recorded approximately $21 million in debt extinguishment costs related to the redemption of our 2023 First Lien Notes.

Debt (First Lien Notes) (Detail

Debt (First Lien Notes) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt		$ 11,943	$ 12,046
2022 First Lien Notes [Member]
Debt Instrument [Line Items]
Long-term Debt		739	739
First Lien Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	[1]	0	450
New 2019 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		400
Long-term Debt		389	0
Debt Issuance Costs, Net		8
2024 First Lien Notes [Member]
Debt Instrument [Line Items]
Long-term Debt		485	485
2026 First Lien Notes [Member]
Debt Instrument [Line Items]
Long-term Debt		617	616
Corporate Debt Securities [Member]
Debt Instrument [Line Items]
Long-term Debt		1,841	$ 2,290
Early Redemption Amount [Member] | First Lien Notes 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 453
London Interbank Offered Rate (LIBOR) [Member] | New 2019 First Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		1.75%
[1]	On March 6, 2017, we used cash on hand along with the proceeds from our 2019 First Lien Term Loan to redeem the remaining $453 million of our 2023 First Lien Notes, plus accrued and unpaid interest. During the first quarter of 2017, we recorded approximately $21 million in debt extinguishment costs related to the redemption of our 2023 First Lien Notes.

Debt (Letter of Credit) (Detail

Debt (Letter of Credit) (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount		$ 891	$ 991
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount	[1]	471	535
CDH [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount		237	250
Various Project Financing Facilities [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount		$ 183	$ 206
[1]	The Corporate Revolving Facility represents our primary revolving facility

Debt (Fair Value of Debt) (Deta

Debt (Fair Value of Debt) (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		$ 11,943	$ 12,046
Unsecured Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		3,413	3,412
Loans Payable [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		3,405	3,165
Corporate Debt Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		1,841	2,290
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		11,703	11,926
Reported Value Measurement [Member] | Unsecured Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		3,413	3,412
Reported Value Measurement [Member] | Loans Payable [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		3,405	3,165
Reported Value Measurement [Member] | Corporate Debt Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		1,841	2,290
Reported Value Measurement [Member] | Notes Payable, Other Payable excluding Capital Leases [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	[1]	1,469	1,506
Reported Value Measurement [Member] | Secured Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		1,550	1,553
Reported Value Measurement [Member] | Revolving Credit Facility [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		25	0
Fair Value, Inputs, Level 2 [Member] | Unsecured Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		3,435	3,343
Fair Value, Inputs, Level 2 [Member] | Loans Payable [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		3,480	3,244
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		1,931	2,349
Fair Value, Inputs, Level 2 [Member] | Secured Debt [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		1,567	1,567
Fair Value, Inputs, Level 2 [Member] | Revolving Credit Facility [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt		25	0
Fair Value, Inputs, Level 3 [Member] | Notes Payable, Other Payable excluding Capital Leases [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	[1]	$ 1,505	$ 1,543
[1]	Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP

Debt (Debt Textuals) (Details)

Debt (Debt Textuals) (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2015
Line of Credit Facility [Line Items]
Debt and Capital Lease Obligations	$ 11,952	$ 12,179
Debt Instruments [Abstract]
Debt Instrument, Interest Rate, Effective Percentage	5.40%		5.50%
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Debt and Capital Lease Obligations	$ 25	0
Notes Payable, Other Payables [Member]
Line of Credit Facility [Line Items]
Debt and Capital Lease Obligations	$ 1,561	$ 1,597

Assets and Liabilities with R43

Assets and Liabilities with Recurring Fair Value Measurements Fair Value Hierarchy (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	$ 166	$ 153
Commodity futures contracts		1,259	1,542
Commodity forward contracts	[2]	761	697
Interest Rate Derivative Assets, Fair Value		37	29
Total assets		2,223	2,421
Commodity futures contracts		1,298	1,570
Commodity forward contracts	[2]	470	478
Interest Rate Derivative Liabilities At Fair Value		55	58
Liabilities, Fair Value Disclosure		1,823	2,106
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	166	153
Commodity futures contracts		1,259	1,542
Commodity forward contracts	[2]	0	0
Interest Rate Derivative Assets, Fair Value		0	0
Total assets		1,425	1,695
Commodity futures contracts		1,298	1,570
Commodity forward contracts	[2]	0	0
Interest Rate Derivative Liabilities At Fair Value		0	0
Liabilities, Fair Value Disclosure		1,298	1,570
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	0	0
Commodity futures contracts		0	0
Commodity forward contracts	[2]	359	231
Interest Rate Derivative Assets, Fair Value		37	29
Total assets		396	260
Commodity futures contracts		0	0
Commodity forward contracts	[2]	410	411
Interest Rate Derivative Liabilities At Fair Value		55	58
Liabilities, Fair Value Disclosure		465	469
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[1]	0	0
Commodity futures contracts		0	0
Commodity forward contracts	[2]	402	466
Interest Rate Derivative Assets, Fair Value		0	0
Total assets		402	466
Commodity futures contracts		0	0
Commodity forward contracts	[2]	60	67
Interest Rate Derivative Liabilities At Fair Value		0	0
Liabilities, Fair Value Disclosure		$ 60	$ 67
[1]	As of March 31, 2017 and December 31, 2016, we had cash equivalents of $36 million and $26 million included in cash and cash equivalents and $130 million and $127 million included in restricted cash, respectively.
[2]	Includes OTC swaps and options and retail contracts.

Assets and Liabilities with R44

Assets and Liabilities with Recurring Fair Value Measurements Quantitative Info on Level 3 (Details) - USD ($)	Mar. 31, 2017	Dec. 31, 2016
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Fair Value, Net	$ 234,000,000	$ 162,000,000
Power Contracts [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Fair Value, Net	324,000,000	360,000,000
Power Contracts [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information	8	9.60
Power Contracts [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information	92	86.34
Natural Gas [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Fair Value, Net	60,000,000	17,000,000
Natural Gas [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information	1.79	1.95
Natural Gas [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information	6.24	5.66
Power Congestion Products [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Derivative, Fair Value, Net	11,000,000	12,000,000
Power Congestion Products [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information	(7.52)	(7.52)
Power Congestion Products [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Fair Value Inputs Quantitative Information	$ 4.54	$ 13.62

Assets and Liabilities with R45

Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2015
Fair Value Measurement [Domain]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash and Cash Equivalents, at Carrying Value		$ 36		$ 26
Restricted Cash and Cash Equivalents		130		127
Balance, beginning of period		399	$ (46)
Included in operating revenues	[1]	113	(22)
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Gain (Loss) Included In Fuel And Purchased Energy Expense	[2]	13	(14)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases		0	2
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements		(26)	(4)
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount		0				$ 0
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount		0				$ 0
Transfers into level 3	[3],[4]	7	0
Transfers out of Level 3	[4],[5]	(150)	19
Balance, end of period		342	(65)
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)		126	(36)
Cash and Cash Equivalents, at Carrying Value		243	$ 244	418	$ 906
Restricted Cash and Cash Equivalents		$ 177		$ 188
[1]	For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations.
[2]	For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.
[3]	There were $7 million and nil in losses transferred out of level 2 into level 3 for the three months ended March 31, 2017 and 2016, respectively, due to changes in market liquidity in various power markets.
[4]	We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three months ended March 31, 2017 and 2016.
[5]	We had $150 million in gains and $(19) million in losses transferred out of level 3 into level 2 for the three months ended March 31, 2017 and 2016, respectively, due to changes in market liquidity in various power markets.

Derivative Instruments (Details

Derivative Instruments (Details) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017USD ($)MWhMMBTUt		Dec. 31, 2014MWhMMBTUt	Dec. 31, 2016USD ($)
Power [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh	(78)		(86)
Natural Gas [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	779		613
Environmental Credits [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Mass | t	16		16
Interest Rate Hedging Instruments
Derivative [Line Items]
Derivative, Notional Amount | $	$ 4,600	[1]		$ 3,721
[1]	We entered into interest rate hedging instruments during the first quarter of 2017 to hedge approximately $1.0 billion of variable rate debt for 2018 through 2020 and approximately $500 million of variable rate debt for 2021 through 2022. We also extended the tenor of certain interest rate hedging instruments which effectively places a ceiling on LIBOR on $2.5 billion of variable rate corporate debt through 2020 and $1.25 billion of variable rate corporate debt in 2021.

Derivative Instruments (Detai47

Derivative Instruments (Details 2) (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative assets, current	$ 1,387	$ 1,725
Long-term derivative assets	670	543
Total derivative assets	2,057	2,268
Derivative liabilities, current	1,273	1,630
Long-term derivative liabilities	550	476
Total derivative liabilities	1,823	2,106
Derivative, Fair Value, Net	234	162
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	37	29
Total derivative liabilities	55	58
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	2,020	2,239
Total derivative liabilities	1,768	2,048
Interest Rate Hedging Instruments
Derivatives, Fair Value [Line Items]
Derivative assets, current	1	1
Derivative Assets, Noncurrent	36	28
Total derivative assets	37	29
Current derivative liabilities	27	28
Derivative Liabilities, Noncurrent	28	30
Total derivative liabilities	55	58
Derivative, Fair Value, Net	(18)	(29)
Interest Rate Hedging Instruments | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	37	29
Total derivative liabilities	55	58
Energy Related Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, current	1,386	1,724
Derivative Assets, Noncurrent	634	515
Total derivative assets	2,020	2,239
Current derivative liabilities	1,246	1,602
Derivative Liabilities, Noncurrent	522	446
Total derivative liabilities	1,768	2,048
Derivative, Fair Value, Net	252	191
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	2,020	2,239
Total derivative liabilities	$ 1,768	$ 2,048

Derivative Instruments (Detail

Derivative Instruments (Detail 3) (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 2,057	$ 2,268
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		(1,430)	(1,686)
Derivative, Collateral, Obligation to Return Cash	[1]	(17)	(32)
Derivative Liability, Fair Value, Gross Liability		(1,823)	(2,106)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		1,430	1,686
Derivative, Collateral, Right to Reclaim Cash	[1]	97	104
Derivative, Fair Value, Net		234	162
Derivative Fair Value, Amount Not Offset Against Collateral, Net		0	0
Margin/Cash (Received) Posted Subject to Master Netting Arrangement	[1]	80	72
Derivative Asset, Fair Value, Amount Offset Against Collateral		610	550
Derivative Liability, Fair Value, Amount Offset Against Collateral		(296)	(316)
Derivative, Fair Value, Amount Offset Against Collateral, Net		314	234
Commodity Exchange Traded Futures and Swaps Contracts [Member]
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
Derivative Asset, Fair Value, Gross Asset		1,259	1,542
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		(1,253)	(1,521)
Derivative, Collateral, Obligation to Return Cash	[1]	(6)	(21)
Derivative Liability, Fair Value, Gross Liability		(1,298)	(1,570)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		1,253	1,521
Derivative, Collateral, Right to Reclaim Cash	[1]	45	49
Derivative Asset, Fair Value, Amount Offset Against Collateral		0	0
Derivative Liability, Fair Value, Amount Offset Against Collateral		0	0
Commodity Forward Contract [Member]
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
Derivative Asset, Fair Value, Gross Asset		761	697
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		(172)	(165)
Derivative, Collateral, Obligation to Return Cash	[1]	(11)	(11)
Derivative Liability, Fair Value, Gross Liability		(470)	(478)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		172	165
Derivative, Collateral, Right to Reclaim Cash	[1]	52	55
Derivative Asset, Fair Value, Amount Offset Against Collateral		578	521
Derivative Liability, Fair Value, Amount Offset Against Collateral		(246)	(258)
Interest Rate Hedging Instruments
Derivative Instruments Subject to Master Netting Arrangement [Line Items]
Derivative Asset, Fair Value, Gross Asset		37	29
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		(5)	0
Derivative, Collateral, Obligation to Return Cash	[1]	0	0
Derivative Liability, Fair Value, Gross Liability		(55)	(58)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		5	0
Derivative, Collateral, Right to Reclaim Cash	[1]	0	0
Derivative, Fair Value, Net		(18)	(29)
Derivative Asset, Fair Value, Amount Offset Against Collateral		32	29
Derivative Liability, Fair Value, Amount Offset Against Collateral		$ (50)	$ (58)
[1]	Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 for a further discussion of our collateral.

Derivative Instruments (Detai49

Derivative Instruments (Details 4) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Summary of Derivative Instruments by Risk Exposure [Abstract]
Power contracts included in operating revenues		$ 2,281	$ 1,615
Natural gas contracts included in fuel and purchased energy expense		1,692	1,126
Interest expense		159	157
Gain (Loss) on Derivative Instruments, Net, Pretax	[1]	84	24
Gain (Loss) on Sale of Derivatives	[2],[3]	29	118
Mark-to-market gain (loss)	[4]	55	(94)
Power [Member]
Summary of Derivative Instruments by Risk Exposure [Abstract]
Power contracts included in operating revenues	[1],[5],[6]	223	204
Interest Rate Contract [Member]
Summary of Derivative Instruments by Risk Exposure [Abstract]
Interest expense	[1],[7]	0	1
Mark-to-market gain (loss)	[4]	0	1
Energy Related Derivative [Member]
Summary of Derivative Instruments by Risk Exposure [Abstract]
Gain (Loss) on Sale of Derivatives	[2],[3]	29	118
Mark-to-market gain (loss)	[4]	55	(95)
Natural Gas [Member]
Summary of Derivative Instruments by Risk Exposure [Abstract]
Natural gas contracts included in fuel and purchased energy expense	[1],[5],[6]	$ (139)	$ (181)
[1]	In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure.
[2]	Does not include the realized value associated with derivative instruments that settle through physical delivery.
[3]	Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power.
[4]	In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
[5]	Does not include the realized value associated with derivative instruments that settle through physical delivery.
[6]	Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power.
[7]	In addition to changes in market value on interest rate hedging instruments not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness.

Derivative Instruments (Detai50

Derivative Instruments (Details 5) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Interest expense		$ 159	$ 157
Interest Rate Hedging Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	[1],[2]	(4)	(12)
Interest expense	[3],[4]	0	1
Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Hedging Instruments
Derivative Instruments, Gain (Loss) [Line Items]
Interest expense	[1],[2],[5]	$ (11)	$ (11)
[1]	We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three months ended March 31, 2017 and 2016.
[2]	We recorded an income tax expense of nil for each of the three months ended March 31, 2017 and 2016, in AOCI related to our cash flow hedging activities.
[3]	In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure.
[4]	In addition to changes in market value on interest rate hedging instruments not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness.
[5]	Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $94 million and $90 million at March 31, 2017 and December 31, 2016, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $8 million and $8 million at March 31, 2017 and December 31, 2016, respectively.

Derivative Instruments (Textual

Derivative Instruments (Textuals) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	$ 0	$ 0
Summary of Derivative Instruments [Abstract]
Maximum length of time hedging using interest rate derivative instruments	9 years
Derivative, Net Liability Position, Aggregate Fair Value	$ 24
Collateral Already Posted, Aggregate Fair Value	2
Additional Collateral, Aggregate Fair Value	0
Cash Flow Hedge (Gain) Loss to be Reclassified within Twelve Months	38
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	94		$ 90
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	8		$ 8
2021 through 2022 [Member] | Interest Rate Hedging Instruments
Derivatives, Fair Value [Line Items]
Derivative, Amount of Hedged Item	500
2020 [Member] | Interest Rate Hedging Instruments
Derivatives, Fair Value [Line Items]
Derivative, Amount of Hedged Item	2,500
2018 through 2020 [Member] | Interest Rate Hedging Instruments
Derivatives, Fair Value [Line Items]
Derivative, Amount of Hedged Item	1,000
2021 [Member] | Interest Rate Hedging Instruments
Derivatives, Fair Value [Line Items]
Derivative, Amount of Hedged Item	$ 1,250

Use of Collateral (Details)

Use of Collateral (Details) - USD ($) $ in Millions		Mar. 31, 2017	Dec. 31, 2016
Financial Instruments Owned and Pledged as Collateral [Line Items]
Margin deposits	[1]	$ 284	$ 350
Natural gas and power prepayments		24	25
Total margin deposits and natural gas and power prepayments with our counterparties	[2]	308	375
Letters of credit issued		738	798
First priority liens under power and natural gas agreements		217	206
First priority liens under interest rate hedging instruments		53	55
Total letters of credit and first priority liens with our counterparties		1,008	1,059
Margin deposits held by us posted by our counterparties	[1],[3]	9	16
Letters of credit posted with us by our counterparties		37	43
Total margin deposits and letters of credit posted with us by our counterparties		46	59
Use of Collateral (Textuals) [Abstract]
Margin And Prepayment Amounts Included In Other Assets		10	9
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses		$ 298	$ 366
[1]	Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements.
[2]	At March 31, 2017 and December 31, 2016, $298 million and $366 million, respectively, were included in margin deposits and other prepaid expense and $10 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
[3]	Included in other current liabilities on our Consolidated Condensed Balance Sheets.

Income Taxes (Income Tax Expens

Income Taxes (Income Tax Expense (Benefit)) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Tax Contingency [Line Items]
Income tax (expense) benefit	$ 61	$ (35)
Effective Income Tax Rate, Continuing Operations	52.00%	(21.00%)
Income Tax Uncertainties [Abstract]
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	$ 17
Unrecognized Tax Benefits	48
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	10
Unrecognized Tax Benefit Related to Deferred Tax Asset	38
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	3
Minimum [Member]
Income Tax Contingency [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	0
Maximum [Member]
Income Tax Contingency [Line Items]
Decrease in Unrecognized Tax Benefits is Reasonably Possible	$ 7

Earnings (Loss) per Share (Deta

Earnings (Loss) per Share (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Share-based awards	4,743	4,468

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($)		3 Months Ended			12 Months Ended
		Mar. 31, 2017		Mar. 31, 2016	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	[1]	7 years 3 months 25 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number		4,136,124			2,697,136
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price		$ 12.92			$ 13.59
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period		6,200
Share-based Compensation Arrangements by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price		$ 17.50
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term		5 years 2 months 12 days			3 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value		$ 1,000,000			$ 2,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross		1,460,909
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price		$ 11.69
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period		15,721
Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price		$ 11.69
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number		2,690,936
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price		$ 13.58
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term		2 years 8 months 12 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value		$ 1,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number		3,930,873
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price		$ 12.98
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term		5 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value		$ 1,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	[2]	2.25%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	[3]	40.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	[4]	0.00%
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 5.38
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		5,609,884	[5]		4,869,648
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 13.71			$ 15.83
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		2,546,223
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 11.70
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period		340,080
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 14.28
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period		1,465,907
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		$ 17.13
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options		$ 6,000,000
Employee service share-based compensation, Nonvested awards, Stock Options		2 years 7 months 6 days
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards		$ 0		$ 2,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		1,302,417			890,587
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 15.28			$ 17.90
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		472,278
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 10.69
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period		54,638
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 18.38
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	[6]	5,810
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		$ 14.81
[1]	Expected term calculated using historical exercise data.
[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]	Includes 49,897 shares of restricted stock and restricted stock units outstanding under the Director Plan and 5,559,987 shares of restricted stock and restricted stock units outstanding under the Equity Plan.
[6]	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.

Stock-Based Compensation Equity

Stock-Based Compensation Equity Classified Share Based Awards (Details) - USD ($)	3 Months Ended
	Mar. 31, 2017		Mar. 31, 2016	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period for graded and cliff vesting options - minimum	1 year
Vesting period for graded and cliff vesting options - maximum	5 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Minimum Range	5 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Expiration Maximum Range	10 years
Allocated Share-based Compensation Expense	$ 8,000,000		$ 7,000,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	5,609,884	[1]		4,869,648
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 40,000,000
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	$ 17,000,000		15,000,000
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	1,302,417			890,587
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards	$ 0		$ 2,000,000
Director Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	49,897
Common Stock, Capital Shares Reserved for Future Issuance	84,221
Equity Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	5,559,987
Common Stock, Capital Shares Reserved for Future Issuance	878,194
[1]	Includes 49,897 shares of restricted stock and restricted stock units outstanding under the Director Plan and 5,559,987 shares of restricted stock and restricted stock units outstanding under the Equity Plan.

Stock-Based Compensation Liabil

Stock-Based Compensation Liability Classified Share Based Awards (Details) - Performance Shares [Member] - $ / shares		3 Months Ended
		Mar. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number		1,302,417	890,587
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value		$ 15.28	$ 17.90
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period		472,278
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 10.69
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period		54,638
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value		$ 18.38
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	[1]	5,810
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value		$ 14.81
[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.

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Details)	3 Months Ended
	Mar. 31, 2017
Other Commitments [Line Items]
Outstanding claims related to guarantees	0

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		$ 2,281	$ 1,615
Commodity Margin		558	580
Add: Mark-to-market commodity activity, net and other	[1]	31	(91)
Plant operating expense		282	255
Depreciation and amortization expense		206	180
Sales, general and other administrative expense		40	38
Other operating expenses		20	20
Gain on sale of assets, net		(27)	0
(Income) loss from unconsolidated investments in power plants		(4)	(7)
Income from operations		72	3
Interest expense, net of interest income		159	157
Debt Extinguishment Costs and Other (Income) Expense, Net		26	5
Loss before income taxes		(113)	(159)
Lease levelization		(22)	(22)
West [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		714	426
Commodity Margin		221	197
Add: Mark-to-market commodity activity, net and other	[1]	77	46
Plant operating expense		97	91
Depreciation and amortization expense		91	69
Sales, general and other administrative expense		13	10
Other operating expenses		9	8
Gain on sale of assets, net		0
(Income) loss from unconsolidated investments in power plants		0	0
Income from operations		88	65
Texas [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		802	535
Commodity Margin		148	153
Add: Mark-to-market commodity activity, net and other	[1]	(30)	(110)
Plant operating expense		96	86
Depreciation and amortization expense		62	53
Sales, general and other administrative expense		17	16
Other operating expenses		3	2
Gain on sale of assets, net		0
(Income) loss from unconsolidated investments in power plants		0	0
Income from operations		(60)	(114)
East [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		772	662
Commodity Margin		189	230
Add: Mark-to-market commodity activity, net and other	[1]	(8)	(21)
Plant operating expense		96	84
Depreciation and amortization expense		53	58
Sales, general and other administrative expense		10	12
Other operating expenses		9	10
Gain on sale of assets, net		(27)
(Income) loss from unconsolidated investments in power plants		(4)	(7)
Income from operations		44	52
Consolidation, Eliminations [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		(7)	(8)
Commodity Margin		0	0
Add: Mark-to-market commodity activity, net and other	[1]	(8)	(6)
Plant operating expense		(7)	(6)
Depreciation and amortization expense		0	0
Sales, general and other administrative expense		0	0
Other operating expenses		(1)	0
Gain on sale of assets, net		0
(Income) loss from unconsolidated investments in power plants		0	0
Income from operations		0	0
Operating Segments [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		2,281	1,615
Operating Segments [Member] | West [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		712	424
Operating Segments [Member] | Texas [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		799	532
Operating Segments [Member] | East [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		770	659
Operating Segments [Member] | Consolidation, Eliminations [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		0	0
Intersegment Eliminations [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		0	0
Intersegment Eliminations [Member] | West [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		2	2
Intersegment Eliminations [Member] | Texas [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		3	3
Intersegment Eliminations [Member] | East [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		2	3
Intersegment Eliminations [Member] | Consolidation, Eliminations [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Operating revenues		(7)	(8)
Other Assets [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Amortization of Intangible Assets		$ 60	$ 27
[1]	Includes $(22) million and $(22) million of lease levelization and $60 million and $27 million of amortization expense for the three months ended March 31, 2017 and 2016, respectively.