EP Energy (EPEGQ) 10-K 3 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 17, 2017	Jun. 30, 2016
Entity Registrant Name	EP Energy Corp
Entity Central Index Key	1,584,952
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 195,471,382
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Class A Stock
Entity Common Stock, Shares Outstanding		250,746,362
Class B Stock
Entity Common Stock, Shares Outstanding		776,586

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating revenues
Oil	$ 653	$ 981	$ 1,705
Natural gas	122	200	284
NGLs	65	60	110
Financial derivatives	(73)	667	985
Total operating revenues	767	1,908	3,084
Operating expenses
Oil and natural gas purchases	10	31	23
Transportation costs	109	116	100
Lease operating expense	159	186	193
General and administrative	146	148	244
Depreciation, depletion and amortization	462	983	875
Gain on sale of assets	(78)	0	0
Impairment charges	2	4,299	2
Exploration and other expense	5	20	25
Taxes, other than income taxes	50	80	129
Total operating expenses	865	5,863	1,591
Operating (loss) income	(98)	(3,955)	1,493
Other income	0	0	1
Gain (loss) on extinguishment of debt	384	(41)	(17)
Interest expense	(312)	(330)	(318)
(Loss) income from continuing operations before income taxes	(26)	(4,326)	1,159
Income tax expense (benefit)	1	(578)	432
(Loss) income from continuing operations	(27)	(3,748)	727
Income from discontinued operations, net of tax	0	0	4
Net (loss) income	$ (27)	$ (3,748)	$ 731
Basic and diluted net income (loss) per common share
(Loss) income from continuing operations	$ (0.11)	$ (15.37)	$ 3
Income from discontinued operations, net of tax	0	0	0.02
Net (loss) income	$ (0.11)	$ (15.37)	$ 3.02
Basic and diluted weighted average common shares outstanding	245	244	242

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 20	$ 26
Accounts receivable
Customer, net of allowance of less than $1 in 2016 and $1 in 2015	133	189
Other, net of allowance of $1 in 2016 and 2015	16	12
Materials and supplies	16	24
Derivative instruments	58	694
Assets held for sale		344
Prepaid assets	5	8
Total current assets	248	1,297
Property, plant and equipment, at cost
Oil and natural gas properties	7,194	6,721
Other property, plant and equipment	85	80
Total property, plant and equipment, at cost	7,279	6,801
Less accumulated depreciation, depletion and amortization	2,781	2,374
Total property, plant and equipment, net	4,498	4,427
Other assets
Derivative instruments	4	85
Unamortized debt issue costs - revolving credit facility	10	23
Other	1	1
Total other assets	15	109
Total assets	4,761	5,833
Accounts payable
Trade	63	69
Other	113	164
Derivative instruments	4	0
Accrued interest	43	47
Liabilities related to assets held for sale		24
Other accrued liabilities	98	47
Total current liabilities	321	351
Long-term debt, net of debt issue costs	3,789	4,812
Other long-term liabilities
Derivative instruments	1	8
Asset retirement obligations	40	37
Other	4	6
Total non-current liabilities	3,834	4,863
Commitments and contingencies (Note 9)
Stockholders’ equity
Preferred stock, $0.01 par value; 50 million shares authorized; no shares issued or outstanding	0	0
Treasury stock (at cost); 0.5 million shares at December 31, 2016 and 0.1 million shares at December 31, 2015.	(3)	0
Additional paid-in capital	3,546	3,529
Accumulated deficit	(2,939)	(2,912)
Total stockholders’ equity	606	619
Total liabilities and equity	4,761	5,833
Class A Stock
Stockholders’ equity
Common Stock, Value, Issued	2	2
Class B Stock
Stockholders’ equity
Common Stock, Value, Issued	$ 0	$ 0

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Maximum allowance for accounts receivable, customer (in dollars)	$ 1	$ 1
Other receivables, allowance (in dollars)	$ 1	$ 1
Treasury Stock, Shares	500,000	100,000
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Class A Stock
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, shares authorized	550,000,000	550,000,000
Common shares, shares issued	251,000,000	248,000,000
Common shares, shares outstanding	251,000,000	248,000,000
Class B Stock
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, shares authorized	800,000	800,000
Common shares, shares issued	800,000	800,000
Common shares, shares outstanding	800,000	800,000

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities
Net (loss) income	$ (27)	$ (3,748)	$ 731
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	462	983	883
Gain on sale of assets	(78)	0	(2)
Deferred income tax (benefit) expense	0	(578)	435
Impairment charges	2	4,299	20
(Gain) loss on extinguishment of debt	(384)	41	17
Share-based compensation expense	17	19	13
Non-cash portion of exploration expense	2	14	19
Amortization of debt issuance costs	16	18	21
Other	1	0	2
Asset and liability changes
Accounts receivable	71	55	7
Accounts payable	(22)	(70)	13
Derivative instruments	714	277	(939)
Accrued interest	(4)	(6)	0
Other asset changes	8	22	5
Other liability changes	6	1	(39)
Net cash provided by operating activities	784	1,327	1,186
Cash flows from investing activities
Cash paid for capital expenditures	(533)	(1,433)	(2,033)
Proceeds from the sale of assets, net of cash transferred	389	1	154
Cash paid for acquisitions, net of cash acquired	0	(111)	(165)
Net cash used in investing activities	(144)	(1,543)	(2,044)
Cash flows from financing activities
Proceeds from issuance of long-term debt	1,195	2,067	2,455
Repayments and repurchases of long-term debt	(1,804)	(1,826)	(2,293)
Proceeds from issuance of stock	0	0	669
Debt issuance costs	(34)	(20)	(1)
Other	(3)	(1)	(1)
Net cash (used in) provided by financing activities	(646)	220	829
Cash and cash equivalents
Change in cash and cash equivalents	(6)	4	(29)
Beginning of period	26	22	51
End of period	20	26	22
Supplemental cash flow information
Interest paid, net of amounts capitalized	293	312	289
Income tax (refunds) payments net of refunds	$ (2)	$ (22)	$ 26

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - USD ($) shares in Millions, $ in Millions	Total	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)	Class A Stock	Class A StockCommon Stock	Class B Stock	Class B StockCommon Stock
Increase (Decrease) in Partners' Capital
Net income	$ 731		$ 731
Balance at Dec. 31, 2013	2,937	$ 2,832	105
Balance (in shares) at Dec. 31, 2013					209		0.9
Increase (Decrease) in Stockholders' Equity
Share-based compensation	11	11
Share-based compensation (in shares)					(1)		(0.1)
Initial public offering of common stock	669	667			$ 2
Initial public offering of common stock (in shares)					35
Net income	731		731
Balance at Dec. 31, 2014	4,348	3,510	836		$ 2
Balance (in shares) at Dec. 31, 2014					245		0.8
Increase (Decrease) in Partners' Capital
Net income	(3,748)		(3,748)
Increase (Decrease) in Stockholders' Equity
Share-based compensation	19	19
Share-based compensation (in shares)					(3)		0
Net income	(3,748)		(3,748)
Balance at Dec. 31, 2015	619	3,529	(2,912)		$ 2
Balance (in shares) at Dec. 31, 2015				248	248	0.8	0.8
Adjustments Related to Tax Withholding for Share-based Compensation	(3)
Increase (Decrease) in Partners' Capital
Net income	(27)
Increase (Decrease) in Stockholders' Equity
Share-based compensation	14	17
Share-based compensation (in shares)					(3)		0
Net income	(27)
Balance at Dec. 31, 2016	$ 606	$ 3,546	$ (2,939)		$ 2
Balance (in shares) at Dec. 31, 2016				251	251	0.8	0.8

Basis of Presentation and Signi

Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Significant Accounting Policies	Basis of Presentation and Significant Accounting Policies Basis of Presentation and Consolidation Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (U.S. GAAP) and include the accounts of all consolidated subsidiaries after the elimination of all significant intercompany accounts and transactions. We consolidate entities when we have the ability to control the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We are engaged in the exploration for and the acquisition, development, and production of oil, natural gas and NGLs in the United States. Our oil and natural gas properties are managed as a single operating segment rather than through discrete operating segments or business units. We track basic operational data by area and allocate capital resources on a project-by-project basis across our entire asset base without regard to individual areas. We assess financial performance as a single enterprise and not on a geographical area basis. New Accounting Pronouncements Issued But Not Yet Adopted The following accounting standards have been issued but not yet been adopted. Statement of Cash Flows. In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-15, Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows - Restricted Cash , which requires restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flow. Retrospective application of these standards is required for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and early adoption is allowed. We do not anticipate that the adoption of these standards will have a material impact on the presentation of our consolidated statement of cash flows. Stock Compensation. In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting , which updates several aspects of the accounting for and disclosure of share-based payment transactions. Adoption of this standard is required beginning in the first quarter of 2017. We do not anticipate that the adoption of this standard will have a material impact on our financial statements. Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases, which requires lessees to recognize lease assets and lease liabilities on the balance sheet and disclose key information about leasing arrangements. Adoption of this standard is required beginning in the first quarter of 2019 and early adoption is allowed. We continue to evaluate our contracts and other agreements to assess the impact this update will have on our financial statements. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which clarifies the principles for recognizing revenue and develops a common revenue standard for U.S. GAAP and International Financial Reporting Standards. Adoption of this standard is required beginning in the first quarter of 2018, with the option of early adoption in 2017. Modified or full retrospective application of this standard is required upon adoption. We presently intend to adopt this standard in 2018 and do not anticipate that the adoption of this standard will have a material impact on our financial statements. Significant Accounting Policies Use of Estimates The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates. Revenue Recognition Our revenues are generated primarily through the physical sale of oil, natural gas and NGLs to third party customers at spot or market prices under both short and long-term contracts. We recognize revenue upon delivery and transfer of control of the product to the customer which occurs at the point in time which delivery and passage of title and risk of loss have occurred. Delivery and transfer of control vary depending on the product and delivery method but typically occurs at a pipeline or gathering line delivery point interconnect when delivered via pipeline or at the wellhead or tank battery to purchasers who transport the oil via truck. Revenue is measured and based upon index prices (WTI, LLS, Henry Hub and Mt. Belvieu) or refiners posted prices at various delivery points across our producing basins. Realized prices received (not considering the effects of hedges) are generally less than the stated index price as a result of contractual deductions, differentials from the index to the delivery point and/or discounts for quality or grade. Revenue is recorded using the sales method, net of any royalty interests or other profit interests in the produced product. Revenues related to products delivered, but not yet billed, are estimated each month. These estimates are based on contract data, commodity prices and preliminary throughput and allocation measurements. When actual sales volumes exceed our entitled share of sales volumes, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, we record a liability. Costs associated with the transportation and delivery of production, generally between the wellhead and its intended sale location are included in transportation costs. We also purchase and sell oil and natural gas on a monthly basis to manage our overall oil and natural gas production and sales. These transactions are undertaken to optimize prices we receive for our oil and natural gas, to physically move oil and gas to its intended sales point, or to manage firm transportation agreements. Revenue related to these transactions are recorded in oil and natural gas sales in operating revenues and associated purchases reflected in oil and natural gas purchases in operating expenses in our consolidated income statements. For the years ended December 31, 2016 , 2015 and 2014 , we had two customers that individually accounted for 10 percent or more of our total revenues. The loss of any one customer would not have an adverse effect on our ability to sell our oil, natural gas and NGLs production. While most of our physical production is priced off of market indices, we actively manage the volatility of market pricing through our risk management program whereby we enter into financial derivatives contracts. All of our derivatives are marked-to-market each period. The change in the fair value of our commodity-based derivatives, as well as any realized amounts, are reflected in operating revenues as financial derivative revenues (see Derivatives below and Note 6). Cash and Cash Equivalents We consider short-term investments with an original maturity of less than three months to be cash equivalents. As of December 31, 2016 and 2015 , we had no restricted cash. Allowance for Doubtful Accounts We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method. Oil and Natural Gas Properties We account for oil and natural gas properties in accordance with the successful efforts method of accounting for oil and natural gas exploration and development activities. Under the successful efforts method, we capitalize (i) lease acquisition costs, all development costs and exploratory drilling costs until results are determined, (ii) certain internal costs directly identified with the acquisition, successful drilling of exploratory wells and development activities, and (iii) interest costs related to financing oil and natural gas projects actively being developed until the projects are evaluated or substantially complete and ready for their intended use if the projects were evaluated as successful. Non-drilling exploratory costs, including certain geological and geophysical costs such as seismic costs and delay rentals, are expensed as incurred. We provide for depreciation, depletion, and amortization on the basis of common geological structure or stratigraphic conditions applied to total capitalized costs, plus future abandonment costs, net of salvage value, using the unit of production method. Lease acquisition costs are amortized over total proved reserves, while other exploratory drilling and all developmental costs are amortized over total proved developed reserves. We evaluate capitalized costs related to proved properties upon a triggering event to determine if impairment of such properties is necessary. Our evaluation of recoverability is made on the basis of common geological structure or stratigraphic conditions and considers estimated future cash flows primarily from all proved developed (producing and non-producing) and proved undeveloped reserves in comparison to the carrying amount of the proved properties. Estimated future cash flows are determined based on estimates of future oil and gas production, estimated or published commodity prices as of the date of the estimate, adjusted for geographical location, contractual and quality price differentials, and estimates of future operating and development costs. If the carrying amount of a property exceeds these estimated undiscounted future cash flows, the carrying amount is reduced to its estimated fair value through a charge to income. Fair value is calculated by discounting the estimated future cash flows using a risk-adjusted discount rate. This discount rate is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas. Leasehold acquisitions costs associated with non-producing areas are also assessed for impairment based on our estimated drilling plans and anticipated capital expenditures related to potential lease expirations. Property, Plant and Equipment (Other than Oil and Natural Gas Properties) Our property, plant and equipment, other than our assets accounted for under the successful efforts method, are recorded at their original cost of construction or, upon acquisition, at the fair value of the assets acquired. We capitalize the major units of property replacements or improvements and expense minor items. We depreciate our non-oil and natural gas property, plant and equipment using the straight-line method over the useful lives of the assets which range from four to 15 years . Accounting for Asset Retirement Obligations We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred and is estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our consolidated income statement. Accounting for Long-Term Incentive Compensation We measure the cost of long-term incentive compensation based on the fair value of the award on the day it is granted. Awards issued under our incentive compensation programs are recognized as either equity awards or liability awards based on their characteristics. Expense is recognized in our consolidated financial statements as general and administrative expense over the period of service required by the award, net of estimated forfeitures. See Note 10 for further discussion of our long-term incentive compensation. Environmental Costs, Legal and Other Contingencies Environmental Costs. We record environmental liabilities at their undiscounted amounts on our consolidated balance sheet in other current and long-term liabilities when we assess that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on current available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and expense costs that do not in general and administrative expense. We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet. Legal and Other Contingencies. We recognize liabilities for legal and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other to occur, the low end of the range is accrued. Derivatives We enter into derivative contracts on our oil and natural gas products primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. We also use derivatives to reduce the risk of increases in variable interest rates. Derivative instruments are reflected on our consolidated balance sheet at their fair value as assets and liabilities. We classify our derivatives as either current or non-current based on their anticipated settlement date. We net derivative assets and liabilities with counterparties where we have a legal right of offset. All of our derivatives are marked-to-market each period and changes in the fair value of our commodity based derivatives, as well as any realized amounts, are reflected as operating revenues. Changes in the fair value of our interest rate derivatives are reflected as interest expense. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. In our consolidated balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables. See Note 6 for a further discussion of our derivatives. Income Taxes We record current income taxes based on our estimates of current taxable income and provide for deferred income taxes to reflect estimated future income tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We classify all deferred tax assets and liabilities, along with any related valuation allowance, as non-current on the consolidated balance sheet. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. The realization of our deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. We reduce deferred tax assets by a valuation allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating our valuation allowances, we consider cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of our taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to our valuation allowances could materially impact our results of operations.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures Divestitures. In May 2016, we completed the sale of our assets located in the Haynesville and Bossier shales for approximately $420 million (net cash proceeds of $388 million after customary adjustments) with the buyer also assuming a transportation commitment totaling $106 million . We recorded a gain on the sale of approximately $79 million . We classified the assets and liabilities associated with the assets sold as held for sale on our consolidated balance sheet as of December 31, 2015. Discontinued Operations. In 2014, we reflected as discontinued operations domestic natural gas assets in the Arklatex and South Louisiana Wilcox areas sold for approximately $111 million in May 2014 and our Brazilian operations sold in August 2014. We classified the results of operations of these assets prior to their sale as income from discontinued operations. Summarized operating results and financial position data of our assets held for sale and/or for our discontinued operations were as follows (in millions): Assets Held For Sale Discontinued Operations Year Ended December 31, Year Ended December 31, 2016 2015 2014 2014 Operating revenues $ 26 $ 78 $ 141 $ 82 Operating expenses Transportation costs 7 21 20 5 Lease operating expense 1 6 5 31 Depreciation, depletion and amortization 16 32 37 8 Impairment (1) — — — 18 Other expense 5 12 12 17 Total operating expenses 29 71 74 79 Gain on sale of assets 79 — — 2 Other income — — — 4 Income before income taxes $ 76 $ 7 $ 67 $ 9 Income tax expense 5 Income from discontinued operations, net of tax $ 4 (1) Related to the sale of our Brazilian operations. Assets Held for Sale December 31, 2015 Assets Current assets $ 16 Property, plant and equipment, net 328 Total assets held for sale $ 344 Liabilities Accounts payable $ 17 Other current liabilities 4 Asset retirement obligations 3 Total liabilities related to assets held for sale $ 24 Other Divestitures. In 2014, we also sold certain non-core acreage in Atascosa County in the Eagle Ford Shale for approximately $28 million . No gain or loss was recorded on the sale of these properties. Acquisitions. In 2015, we acquired approximately 12,000 net acres adjacent to our existing Eagle Ford Shale acreage for approximately $111 million . In 2014, we acquired producing properties and undeveloped acreage in the Southern Midland Basin, of which 37,000 net acres are adjacent to our existing Wolfcamp Shale position, for approximately $152 million . No goodwill or bargain purchase was recorded on these acquisitions.

Impairment Charges

Impairment Charges	12 Months Ended
	Dec. 31, 2015
Impairment Charges [Abstract]
Impairment Charges	Impairment Charges We evaluate capitalized costs related to proved properties upon a triggering event (such as a significant continued decline in forward commodity prices) to determine if an impairment of such properties has occurred. Capitalized costs associated with unproved properties (e.g. leasehold acquisition costs associated with non-producing areas) are also assessed upon a triggering event for impairment based on estimated drilling plans and capital expenditures which may also change relative to forward commodity prices and/or potential lease expirations. See Notes 1 and 7 for a further discussion of our oil and natural gas properties and related significant accounting policies. Proved Properties. During the year ended December 31, 2015, we recorded a non-cash impairment charge of approximately $4.0 billion of our proved properties in the Eagle Ford Shale reflecting a reduction in the net book value of the proved property in this area to its estimated fair value due primarily to a significant decline in estimated forward commodity prices. Unproved Properties. Generally, economic recovery of unproved reserves in non-producing or unproved areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by continuing exploration and development activities. Our ability to retain our leases and thus recover our non-producing leasehold costs is dependent upon a number of factors including our levels of drilling activity, which may include drilling the acreage on our own behalf or jointly with partners, or our ability to modify or extend our leases. Should commodity prices not justify sufficient capital allocation to the continued development of properties where we have non-producing leasehold costs, we could incur impairment charges of our unproved property costs. During the year ended December 31, 2015, we recorded a non-cash impairment charge of $288 million of our unproved properties in the Wolfcamp Shale based on reduced activity and not having a definitive agreement at that time to extend our Wolfcamp lease. In May 2016, we amended our Wolfcamp development agreement with the University Lands to provide flexibility to extend the time frame to hold our acreage by nearly four years to the end of 2021, with an increase in annual well completion requirements from six wells per year to 34 , 55 and 55 wells per year in 2016, 2017 and 2018, respectively. We fulfilled this requirement in 2016 and have the intent and believe we have the ability to fulfill our 2017 and 2018 commitments prior to having to relinquish any associated acreage. Commodity price declines may cause changes to our capital spending levels, production rates, levels of proved reserves and development plans, which may result in an additional impairments of the carrying value of our proved and/or unproved properties in the future.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Pretax Income (Loss) and Income Tax Expense (Benefit). The tables below show the pretax income (loss) from continuing operations and the components of income tax expense (benefit) from continuing operations for the following periods: Year Ended December 31, 2016 2015 2014 (in millions) Pretax (Loss) Income U.S. $ (26 ) $ (4,326 ) $ 1,159 Components of Income Tax Expense Current State $ 1 $ — $ — 1 — — Deferred Federal $ — $ (543 ) $ 415 State — (35 ) 17 Total income tax expense (benefit) $ 1 $ (578 ) $ 432 Effective Tax Rate Reconciliation. Income taxes included in net income differs from the amount computed by applying the statutory federal income tax rate of 35% for the following reasons for the following periods: Year Ended December 31, 2016 2015 2014 (in millions) Income taxes at the statutory federal rate of 35% $ (9 ) $ (1,514 ) $ 406 Increase (decrease) State income taxes, net of federal income tax effect (1 ) (41 ) 12 Non-deductible reorganization costs — — 10 Valuation allowance 9 975 — Other 2 2 4 Income tax expense (benefit) $ 1 $ (578 ) $ 432 The effective tax rate for the year ended December 31, 2016 was (1.9)% , lower than the statutory rate of 35% as a result of the effects of state income taxes (net of federal income tax effects), non-deductible compensation, and adjustments to the valuation allowance on our deferred tax assets which offset a deferred income tax benefit by $9 million . For a further discussion of our valuation allowance, see below. The effective tax rate for the year ended December 31, 2015 was 13.4% , lower than the statutory rate of 35% as a result of recording a valuation allowance of $975 million against our deferred tax assets. The effective tax rate for the year ended December 31, 2014 differed from the statutory rate primarily due to the result of state income taxes, net of federal income tax effect and non-deductible reorganization costs recorded in conjunction with changing our organizational structure in 2014. Deferred Tax Assets and Liabilities. The following are the components of net deferred tax assets and liabilities: December 31, December 31, (in millions) Deferred tax assets Property, plant and equipment $ 249 $ 471 Net operating loss carryovers 692 720 U.S. tax credit carryovers 10 10 Employee benefits 6 4 Legal and other reserves 6 7 Asset retirement obligations 15 19 Transaction costs 19 22 Total deferred tax assets 997 1,253 Valuation allowance (985 ) (976 ) Net deferred tax assets 12 277 Deferred tax liabilities Financial derivatives 12 277 Total deferred tax liabilities 12 277 Net deferred tax liabilities $ — $ — Unrecognized Tax Benefits. As of December 31, 2016 there were no unrecognized tax benefits as income taxes in our financial statements. We did not recognize any interest and penalties related to unrecognized tax benefits (classified as income taxes in our consolidated income statements) in 2016 , 2015 or 2014, nor do we have any accrued interest and penalties associated with income taxes in our consolidated balance sheets as of December 31, 2016 and December 31, 2015 . The Company's and certain subsidiaries income tax years (2013-2016) remain open and subject to examination by both federal and state tax authorities. One of our subsidiary’s 2013 U.S. tax return is under examination by the IRS. Net Operating Loss and Tax Credit Carryovers. The table below presents the details of our federal and state net operating loss carryover periods as of December 31, 2016 (in millions): Expiration Period 2031 - 2036 U.S. federal net operating loss carryover $ 1,918 2026 - 2036 State net operating loss carryover $ 307 During 2016, we generated a federal net operating loss of $318 million , which does not include a gain we realized on debt repurchases of $405 million . As a result of excluding these amounts from taxable income, we were required to reduce our federal net operating loss carryovers at the end of December 31, 2016 by the amount of those gains. Utilization of $136 million of our federal net operating loss carryovers is subject to the limitations provided under Sections 382 of the Internal Revenue Code. While these limitations restrict the amount of carryovers we could potentially utilize in the next few years, it would not cause any carryovers to expire unused. In addition to our net operating loss carryovers, we also have (i) U.S. federal alternative minimum tax credit carryovers of $10 million and (ii) capital loss carryovers of $23 million . Our alternative minimum tax credits carry over indefinitely while our capital loss carryovers expire in 2018 if we are unable to generate sufficient capital gains on the sale of assets by that time. Valuation Allowances. As of December 31, 2016 and 2015 , we have a valuation allowance on our deferred tax assets of $985 million and $976 million , respectively. These amounts are recorded based on our evaluation of whether it was more likely than not that our deferred tax assets would be realized. Our evaluations considered cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in prior carryback years, tax planning strategies and future taxable income for each of our taxable jurisdictions.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share We exclude potentially dilutive securities from the determination of diluted earnings per share (as well as their related income statement impacts) when their impact on income from continuing operations per common share is antidilutive. Potentially dilutive securities consist of our stock options, restricted stock and performance unit awards. For both of the years ended December 31, 2016 and 2015, we incurred net losses and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive. Potentially dilutive securities did not have a material effect upon our diluted earnings per share for the year ended December 31, 2014.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair Value Measurements	Fair Value Measurements We use various methods to determine the fair values of our financial instruments. The fair value of a financial instrument depends on a number of factors, including the availability of observable market data over the contractual term of the instrument. We separate the fair value of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each of the levels are described below: • Level 1 instruments’ fair values are based on quoted prices in actively traded markets. • Level 2 instruments’ fair values are based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets). • Level 3 instruments’ fair values are partially calculated using pricing data that is similar to Level 2 instruments, but also reflect adjustments for being in less liquid markets or having longer contractual terms. The following table presents the carrying amounts and estimated fair values of our financial instruments: December 31, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value (in millions) Long-term debt $ 3,856 $ 3,637 $ 4,869 $ 3,379 Derivative instruments $ 57 $ 57 $ 771 $ 771 For the years ended December 31, 2016 and 2015 , the carrying amount of cash and cash equivalents, accounts receivable and accounts payable represent fair value because of the short-term nature of these instruments. Our long-term debt obligations (see Note 8) have various terms, and we estimated the fair value of debt (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances, considering our credit risk. Oil, Natural Gas and NGLs Derivative Instruments. We attempt to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of oil, natural gas and NGLs through the use of financial derivatives. As of December 31, 2016 , we had derivatives contracts in the form of fixed price swaps and three-way collars on 16 MMBbls of oil ( 13 MMBbls in 2017 and 3 MMBbls in 2018). In addition to our oil derivatives, we had derivative contracts in the form of fixed price swaps and options on 36 TBtu of natural gas ( 32 TBtu in 2017 and 4 TBtu in 2018) and 108 MMGal of ethane fixed price swaps ( 46 MMGal in 2017 and 62 MMGal in 2018). As of December 31, 2015 , we had fixed price derivative contracts for 23 MMBbls of oil, 7 TBtu on natural gas and 15 MMGal on propane. In addition to the contracts above, we have derivative contracts related to locational basis differences on our oil production. None of our derivative contracts are designated as accounting hedges. As of December 31, 2016 and 2015 , all derivative financial instruments were classified as Level 2. Our assessment of the level of an instrument can change over time based on the maturity or liquidity of the instrument, which can result in a change in the classification level of the financial instrument. The following table presents the fair value associated with our derivative financial instruments as of December 31, 2016 and 2015 . All of our derivative instruments are subject to master netting arrangements which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our consolidated balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements. On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform. Level 2 Derivative Assets Derivative Liabilities Gross Fair Value Balance Sheet Location Gross Fair Value Balance Sheet Location Impact of Netting Current Non-current Impact of Netting Current Non-current (in millions) (in millions) December 31, 2016 Derivative instruments $ 79 $ (17 ) $ 58 $ 4 $ (22 ) $ 17 $ (4 ) $ (1 ) December 31, 2015 Derivative instruments $ 795 $ (16 ) $ 694 $ 85 $ (24 ) $ 16 $ — $ (8 ) For the years ended December 31, 2016 , 2015 and 2014 , we recorded a derivative loss of $73 million and derivative gains of $667 million and $985 million , respectively. Derivative gains and losses on our oil, natural gas and NGLs financial derivative instruments are recorded in operating revenues in our consolidated income statements. Interest Rate Derivative Instruments . We have interest rate swaps with a notional amount of $600 million that extend through March 2017 and are intended to reduce variable interest rate risk. As of December 31, 2016 , we had a net asset of less than $1 million and of $1 million as of December 31, 2015, related to interest rate derivative instruments included in our consolidated balance sheets. For the years ended December 31, 2016 , 2015 and 2014, we recorded $2 million , $5 million and $5 million , respectively, of interest expense related to the change in fair market value and cash settlements on our interest rate derivative instruments. Credit Risk. We are subject to a risk of loss on our derivative instruments that could occur if our counterparties do not perform pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize our overall credit risk. These policies require that we (i) evaluate potential counterparties’ financial condition to determine their credit worthiness; (ii) monitor our oil, natural gas and NGLs counterparties’ credit exposures; (iii) review significant counterparties' credit from physical and financial transactions on an ongoing basis; (iv) use contractual language that affords us netting or set off opportunities to mitigate risk; and (v) when appropriate, require counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. Our assets related to derivatives as of December 31, 2016 represent financial instruments from eight counterparties, all of which are lenders associated with our $1.5 billion Reserve-based Loan facility (RBL Facility) with an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating. Subject to the terms of our $1.5 billion RBL Facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the RBL Facility. Other Fair Value Considerations. During the year ended December 31, 2015, we recorded a non-cash impairment charge on our proved properties in the Eagle Ford Shale. The estimate of fair value of our proved oil and natural gas properties used to determine the impairment represented a Level 3 fair value measurement. See Notes 1 and 3 for a further discussion of our impairment charges.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment Oil and Natural Gas Properties . As of December 31, 2016 and 2015 , we had approximately $4.5 billion and $4.4 billion of total property, plant, and equipment, net of accumulated depreciation, depletion, and amortization on our balance sheet, substantially all of which relates to proved and unproved oil and natural gas properties. Our capitalized costs related to proved and unproved oil and natural gas properties by area for the periods ended December 31 were as follows: 2016 2015 (in millions) Proved Eagle Ford $ 3,001 $ 2,833 Wolfcamp 2,415 2,174 Altamont 1,624 1,553 Total Proved 7,040 6,560 Unproved Wolfcamp 94 97 Altamont 60 64 Total Unproved 154 161 Less accumulated depletion 2,731 2,335 Net capitalized costs for oil and natural gas properties $ 4,463 $ 4,386 During 2016 , we transferred approximately $9 million from unproved properties to proved properties. During 2016 , 2015 and 2014 , we recorded $2 million , $9 million and $18 million , respectively, of amortization of unproved leasehold costs in exploration expense in our consolidated income statement. Suspended well costs were not material as of December 31, 2016 or December 31, 2015 . Asset Retirement Obligations. We have legal asset retirement obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We settle these obligations when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue these obligations when we can estimate the timing and amount of their settlement. In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted risk-free rate between 7 and 9 percent on a significant portion of our obligations and a projected inflation rate of 2.5 percent . Changes in estimates in the table below represent changes to the expected amount and timing of payments to settle our asset retirement obligations. Typically, these changes primarily result from obtaining new information about the timing of our obligations to plug and abandon oil and natural gas wells and the costs to do so, or reassessing our assumptions in light of market conditions. The net asset retirement liability as of December 31 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability for the periods ended December 31 were as follows: 2016 2015 (in millions) Net asset retirement liability at January 1 $ 38 $ 39 Liabilities incurred — 4 Liabilities settled (1 ) (2 ) Accretion expense 3 3 Changes in estimate 1 (6 ) Net asset retirement liability at December 31 $ 41 $ 38 Capitalized Interest. Interest expense is reflected in our financial statements net of capitalized interest. We capitalize interest primarily on the costs associated with drilling and completing wells generally until production begins. The interest rate used is the weighted average interest rate of our outstanding borrowings. Capitalized interest for the years ended December 31, 2016 , 2015 and 2014 , was approximately $4 million , $14 million and $21 million , respectively.

Long Term Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long Term Debt	Long Term Debt Listed below are our debt obligations as of the periods presented: Interest Rate December 31, 2016 December 31, 2015 (in millions) RBL credit facility - due May 24, 2019 (1) Variable $ 370 $ 1,072 Senior secured term loan - due May 24, 2018 (2)(4) Variable 21 497 Senior secured term loan - due April 30, 2019 (3)(4) Variable 8 150 Senior secured term loan - due June 30, 2021 (5)(6) Variable 580 — Senior secured notes - due November 29, 2024 8.00 % 500 — Senior unsecured notes - due May 1, 2020 9.375 % 1,576 2,000 Senior unsecured notes - due September 1, 2022 7.75 % 250 350 Senior unsecured notes - due June 15, 2023 6.375 % 551 800 Total long-term debt 3,856 4,869 Less unamortized debt issue costs (67 ) (57 ) Total long-term debt, net $ 3,789 $ 4,812 (1) Carries interest at a specified margin over LIBOR of 2.50% to 3.50% , based on borrowing utilization. (2) Issued at 99% of par and carries interest at a specified margin over the LIBOR of 2.75% , with a minimum LIBOR floor of 0.75% . As of December 31, 2016 and 2015 , the effective interest rate of the term loan was 3.50% . (3) Carries interest at a specified margin over the LIBOR of 3.50% , with a minimum LIBOR floor of 1.00% . As of December 31, 2016 and 2015 , the effective interest rate for the term loan was 4.50% . (4) Secured by a second priority lien on all of the collateral securing the RBL Facility, and effectively ranks junior to any existing and future priority lien secured indebtedness of the Company. (5) Carries an interest rate of LIBOR plus 8.75% , with a minimum LIBOR floor of 1.00% . As of December 31, 2016 , the effective interest rate for the term loan was 9.75% . (6) Secured by a priority lien on all of the collateral securing the RBL Facility, and effectively ranks junior to RBL indebtedness and senior priority lien indebtedness. In 2016, we (i) issued $500 million of 8.00% senior secured notes due in November 2024 using the net proceeds from the offering to repay a portion of our outstanding balance on our RBL Facility and (ii) exchanged approximately 95% of the outstanding amount of our term loans maturing in May 2018 and April 2019 for new term loans maturing in 2021 with an aggregate principal amount of approximately $580 million . In February 2017, we issued $1 billion of 8.00% senior secured notes which mature in 2025 and used the proceeds (less fees and expenses) to repay in full our $580 million senior secured term loans due 2021, repurchase $250 million of our 9.375% senior notes due 2020 in the open market, and repay $111 million of the amounts outstanding under our RBL facility. (Gain) Loss on Extinguishment of Debt. During 2016, we paid approximately $407 million in cash to repurchase a total of approximately $812 million in aggregate principal amount of our senior unsecured notes and term loans which resulted in a gain on extinguishment of debt of approximately $393 million for the year ended December 31, 2016 (including $12 million of non-cash expense related to eliminating associated unamortized debt issue costs). For the year ended December 31, 2016 , we also recorded losses on the extinguishment of debt of $9 million , primarily related to eliminating a portion of the unamortized debt issue costs upon the reduction of our RBL borrowing base in May 2016 and November 2016 as further noted in Liquidity and Capital Resources . In 2015, we issued $800 million of 6.375% senior unsecured notes due in June 2023. We used a substantial portion of the proceeds from the offering to purchase for cash our $750 million senior secured notes due in 2019. In conjunction with repurchasing these notes, we recorded a $41 million loss on extinguishment of debt, of which $12 million was a non-cash expense related to eliminating associated unamortized debt issuance costs. In 2014, we repaid and retired our senior PIK toggle note with a portion of the proceeds from our initial public offering recording a $17 million loss on extinguishment of debt. Unamortized Debt Issue Costs. As of December 31, 2016 and 2015 , we had total unamortized debt issue costs of $77 million and $80 million . Of these amounts $10 million and $23 million , respectively, are associated with our RBL Facility and $67 million and $57 million , respectively, are associated with our senior secured term loans and senior notes. During 2016, we (i) recorded an additional $10 million in conjunction with the issuance of our $500 million of 8.00% senior secured notes, (ii) recorded an additional $22 million in conjunction with the exchange of $580 million in new term loans for approximately 95% of the outstanding amount of our 2018 and 2019 term loans and (iii) expensed approximately $21 million in conjunction with the repurchase of a portion of our senior unsecured notes and term loans and the reduction of our RBL borrowing base. During 2016 , 2015 and 2014 , we amortized $16 million , $18 million and $21 million , respectively, of deferred financing costs into interest expense. Reserve-based Loan Facility. We have a $1.5 billion credit facility in place which allows us to borrow funds or issue letters of credit (LC's). The facility matures in May 2019. As of December 31, 2016 , we had $1,111 million of capacity remaining with approximately $19 million of LC's issued and approximately $370 million outstanding under the facility. Listed below is a further description of our credit facility as of December 31, 2016 : Credit Facility Maturity Date Interest Rate Commitment fees $1.5 billion RBL May 24, 2019 LIBOR + 2.5% (1) 2.5% for LCs 0.375% commitment fee on unused capacity (1) Based on our December 31, 2016 borrowing level. Amounts outstanding under the $1.5 billion RBL Facility bear interest at specified margins over the LIBOR of between 2.50% and 3.50% for Eurodollar loans or at specified margins over the Alternative Base Rate ( ABR ) of between 1.50% and 2.50% for ABR loans. Such margins will fluctuate based on the utilization of the facility. The RBL Facility is collateralized by certain of our oil and natural gas properties and has a borrowing base subject to semi-annual redetermination. In May 2016, we completed our semi-annual redetermination of our RBL Facility and the borrowing base was reduced to $1.65 billion , reflecting significantly lower bank commodity price forecasts, the sale of our Haynesville assets and the roll-off of certain hedge positions. The borrowing base was reaffirmed in our semi-annual redetermination in early November 2016. Following such redetermination in early November 2016, we issued $500 million of 8.00% senior secured notes which triggered an additional automatic reduction to the RBL Facility's borrowing base to $1.5 billion . In February 2017, as a result of the issuance of our $1 billion senior secured notes due 2025, our RBL borrowing base was automatically reduced to $1.44 billion . Our next redetermination date is in April 2017. Downward revisions of our oil and natural gas reserves due to declines in commodity prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a reduction of our borrowing base which could negatively impact our borrowing capacity under the RBL Facility in the future. Restrictive Provisions/Covenants. The availability of borrowings under our credit agreements and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions. In conjunction with our RBL Facility redetermination in May 2016, we amended certain covenants, the most significant of which suspended the requirement that our debt to EBITDAX ratio, as defined in the credit agreement, not exceed 4.5 to 1.0 and replaced it with a requirement that our ratio of first lien debt to EBITDAX not exceed 3.5 to 1.0 . As of December 31, 2016 , we were in compliance with our debt covenants, and our ratio of first lien debt to EBITDAX was 0.36 x. The 4.5 to 1.0 debt to EBITDAX requirement will be reinstated beginning in April 2018, and while we are not currently subject to this covenant as of December 31, 2016 our ratio of debt to EBITDAX is 3.69 x, below the required levels. As part of the amendment, we also agreed to limit debt repurchases occurring after the redetermination to $350 million subject to certain adjustments. Certain other covenants and restrictions, among other things, also limit our ability to incur or guarantee additional indebtedness; make any restricted payments or pay any dividends on equity interests or redeem, repurchase or retire parent entities’ equity interests or subordinated indebtedness; sell assets; make investments; create certain liens; prepay debt obligations; engage in transactions with affiliates; and enter into certain hedge agreements.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Legal Matters We and our subsidiaries and affiliates are parties to various legal actions and claims that arise in the ordinary course of our business. For each matter, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of our current matters cannot be predicted with certainty and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure and adjust our accruals accordingly, and these adjustments could be material. As of December 31, 2016 , we had approximately $3 million accrued for all outstanding legal matters. Indemnifications and Other Matters. We periodically enter into indemnification arrangements as part of the divestiture of assets or businesses. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes, environmental and other contingent matters. In addition, under various laws or regulations, we could be subject to the imposition of certain liabilities. For example, the decline in commodity prices has created an environment where there is an increased risk that owners and/or operators of assets previously purchased from us may no longer be able to satisfy plugging and abandonment obligations that attach to such assets. In that event, under various laws or regulations, we could be required to assume all, or a portion of the plugging or abandonment obligations on assets we no longer own or operate. As of December 31, 2016 , we had approximately $8 million accrued related to these indemnifications and other matters. Sales Tax Audits. We are under a number of other examinations by taxing authorities related to non-income tax matters. During the third and fourth quarters of 2016 , we accrued a total of approximately $40 million (included in other accrued liabilities in our consolidated balance sheet) in connection with ongoing examinations related to certain prior period non-income tax matters. In conjunction with recording the accrual, we recorded approximately $29 million in additional depreciation, depletion and amortization expense as certain prior year costs would have been historically capitalized and amortized or impaired in prior periods, $2 million as lease operating expense, $5 million as property, plant and equipment and $4 million as interest expense. Environmental Matters We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and greenhouse gas (GHG) emissions. Numerous governmental agencies, such as the EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may, among other things, (i) require the acquisition of a permit before drilling commences, (ii) restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, (iii) limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive areas, seismically active areas and other protected areas, (iv) require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, (v) result in the suspension or revocation of necessary permits, licenses and authorizations and (vi) require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. The environmental laws and regulations to which we are subject also require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of December 31, 2016 , we had accrued and had exposure of approximately $1 million for related environmental remediation costs associated with onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts that we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities. Climate Change and Other Emissions. In recent years, federal, state and local governments have taken steps to reduce GHG emissions. The EPA has finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. In December 2015, the United States participated in the 21st Conference of the Parties (COP-21) of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake ambitious efforts to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. Any regulations regarding GHG emissions would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner . As part of an effort to reduce methane emissions, the EPA, the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the Bureau of Land Management (BLM) have recently proposed or finalized new regulations affecting the oil and gas industry. On January 10, 2017, the PHMSA approved final rules for oil pipelines, in part requiring inspections in areas affected by natural disasters, expanding use of leak detection systems, and requiring increased use of inline inspection tools. The final rule will become effective six months after publication in the Federal Register. However, because the current Presidential Administration has prohibited such publication until it has had time to review the pending regulations, it is not clear when, or if, the final rules will become effective. In November 2016, the BLM published final rules for oil and gas facilities on onshore federal and Indian leases to prohibit venting, limit flaring, require leak detection to allow adjustment of royalty rates for new leases, and to establish requirements for the measurement of oil and gas. The rules went into effect in January 2017 and will require installation of tank vapor controls at over 70 existing well sites in the Altamont area at an estimated cost of approximately $5 million . On February 2, 2017, the U.S. House of Representatives passed a resolution under the Congressional Review Act to reverse this rule, and a similar resolution has been introduced in the U.S. Senate. Although we are following these legal developments, it is uncertain at this time whether the rule will be reversed. On June 3, 2016, the EPA published several proposed regulations under the Clean Air Act to reduce methane and volatile organic compounds emissions, in part through green completions at oil wells, fugitive emission surveys, limits on pneumatic pumps and controllers, and draft guidelines for controls on equipment in ozone nonattainment areas. These rules went into effect on August 2, 2016, but we do not expect any material capital expenditure for initial and ongoing compliance with these rules. Air Quality Regulations . The EPA has promulgated various performance and emission standards that mandate air pollutant emission limits and operating requirements for stationary reciprocating internal combustion engines and process equipment. We do not anticipate material capital expenditures to meet these requirements. In August 2012, the EPA promulgated additional standards to reduce various air pollutants associated with hydraulic fracturing of natural gas wells and equipment including compressors, storage vessels, and pneumatic valves. Additional amendments to the new standard were finalized in 2013 through 2016. We do not anticipate material capital expenditures to meet these requirements. The EPA has promulgated regulations to require pre-construction permits for minor sources of air emissions in tribal lands. In September 2015, the EPA proposed a federal implementation plan (FIP), rather than a general permit, to effect these regulations. The FIP was finalized in June 2016. The FIP requires registration of new and modified minor sources beginning October 2015 and incorporates emission limits and other requirements from six standards under the Clean Air Act for the oil and gas industry. Additionally, the FIP requires an operator to document compliance with the Endangered Species Act and National Historic Preservation Act. This rule may delay pad construction and commencement of drilling in the future if the EPA does not timely provide written confirmation that requisites of the FIP have been met. Hydraulic Fracturing Regulations . We use hydraulic fracturing extensively in our operations. Various regulations have been adopted and proposed at the federal, state and local levels to regulate hydraulic fracturing operations. These regulations range from banning or substantially limiting hydraulic fracturing operations, requiring disclosure of the hydraulic fracturing fluids and requiring additional permits for the use, recycling and disposal of water used in such operations. In addition, various agencies, including the EPA and Department of Energy, have been reviewing changes in their regulations to address the environmental impacts of hydraulic fracturing operations. Until such regulations are implemented, it is uncertain what impact they might have on our operations. In March 2015, the BLM published final rules for hydraulic fracturing on federal and certain tribal lands, including use of tanks for recovered water, updated cementing and testing requirements, and disclosure of chemicals used in hydraulic fracturing. Several states and the Ute Indian Tribe have filed suit to challenge these rules. In September 2015, a federal court issued a preliminary injunction suspending the rules and, in June 2016, ordered the rules set aside as exceeding the BLM's authority. The BLM has filed an appeal in the Tenth Circuit Court of Appeals. No material cost is expected for the Company’s 2017 program. Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. As part of our environmental remediation projects, we are or have received notice that we could be designated as a Potentially Responsible Party (PRP) with respect to one active site under the CERCLA or state equivalents. As of December 31, 2016 , we have estimated our share of the remediation costs at this site to be less than $1 million . Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro-rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the reserve for environmental matters discussed above. Waste Handling. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements imposed under the Resource Conservation and Recovery Act, as amended, and comparable state laws. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations, and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrued amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate. Lease Obligations We maintain operating leases in the ordinary course of our business activities. These leases include those for office space and various equipment. The terms of the agreements, the largest of which relates to our building lease, vary through 2025. Future minimum annual rental commitments under non-cancelable future operating lease commitments at December 31, 2016 , were as follows: Year Ending December 31, Operating Leases (in millions) 2017 $ 7 2018 5 2019 5 2020 5 2021 5 Thereafter 22 Total $ 49 Rental expense for the years ended December 31, 2016 , 2015 and 2014 was $13 million , $12 million and $13 million , respectively. Other Commercial Commitments At December 31, 2016 , we have various commercial commitments totaling $395 million primarily related to commitments and contracts associated with volume and transportation, completion activities and seismic activities. Our annual obligations under these arrangements are $112 million in 2017 , $65 million in 2018 , $62 million in 2019 , $57 million in 2020 , and $99 million thereafter.

Long-Term Incentive Compensatio

Long-Term Incentive Compensation / 401(k) Retirement Plan	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Long-Term Incentive Compensation / Retirement 401(k) Plan	Long-Term Incentive Compensation / 401(k) Retirement Plan Overview. Under our current stock-based compensation plan (the EP Energy Corporation 2014 Omnibus Incentive Plan, or omnibus plan ), we may issue to our employees and non-employee directors various forms of long-term incentive (LTI) compensation including stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares/units, incentive awards, cash awards, and other stock-based awards. We are authorized to grant awards of up to 24,832,525 shares of our common stock for awards under the omnibus plan, with 17,150,841 shares remaining available for issuance as of December 31, 2016 . In addition, in conjunction with the acquisition of certain of our subsidiaries by Apollo and other private equity investors in 2012 (the Acquisition), certain employees received other LTI awards based on their purchased equity interests including, but not limited to Class A “matching” units (subsequently converted into common shares) and Management Incentive Units (subsequently converted into Class B shares) which become payable upon certain liquidity events. We also issued additional Class B shares in 2013 to a subsidiary for grants to current and future employees that likewise become payable upon certain liquidity events. No additional Class B shares are available for issuance. All of these LTI programs are discussed further below. We record stock-based compensation expense as general and administrative expense over the requisite service period, net of estimates of forfeitures. If actual forfeitures differ from our estimates, additional adjustments to compensation expense will be required in future periods. For the years ended December 31, 2016, 2015 and 2014, we recognized approximately $22 million , $21 million and $22 million , respectively, of pre-tax compensation expense related to our LTI programs and recorded an associated income tax benefit of $9 million , $6 million and $6 million for the years 2016, 2015 and 2014, respectively. Restricted stock. We grant shares of restricted common stock which carry voting and dividend rights and may not be sold or transferred until they are vested. The fair value of our restricted stock is determined on the date of grant and these shares generally vest in equal amounts over 3 years from the date of the grant. A summary of the changes in our non-vested restricted shares for the year ended December 31, 2016 is presented below: Number of Shares Weighted Average Grant Date Fair Value per Share Non-vested at December 31, 2015 3,987,654 $ 10.98 Granted 4,676,322 $ 6.08 Vested (1,255,394 ) $ 11.76 Forfeited (1,081,794 ) $ 8.17 Non-vested at December 31, 2016 6,326,788 $ 7.69 The total unrecognized compensation cost related to these arrangements at December 31, 2016 was approximately $32 million , which is expected to be recognized over a weighted average period of 2 years . Stock Options. In 2014, we granted stock options as compensation for future service at an exercise price equal to the closing share price of our stock on the grant date. No stock options were granted in 2015 or 2016. Stock options granted have contractual terms of 10 years and generally vest in three tranches over a five -year period (with the first tranche vesting on the third anniversary of the grant date, the second tranche vesting on the fourth anniversary of the grant date and the third tranche vesting on the fifth anniversary thereof). We do not pay dividends on unexercised options. A summary of our stock options for the year ended December 31, 2016 is presented below. Number of Shares Underlying Options Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (in years) (in millions) Outstanding at December 31, 2015 214,337 $ 19.82 Granted — $ 19.82 Vested (1,514 ) $ 19.82 Forfeited or canceled (4,933 ) $ 19.82 Outstanding at December 31, 2016 207,890 $ 19.82 7.25 — Total compensation cost related to non-vested option awards not yet recognized at December 31, 2016 was approximately $1 million , which is expected to be recognized over a weighted average period of 2 years . There were no options exercised during the year. Fair Value Assumptions . The fair value of each stock option granted in 2014 was estimated on the date of grant using a Black-Scholes option-pricing model based on several assumptions utilizing management’s best estimate at the time of grant. For the year ended December 31, 2014, the weighted average grant date fair value per share of options granted was $9.03 . Listed below is the weighted average of each assumption based on the grant in 2014: 2014 Expected Term in Years 7.0 Expected Volatility 40 % Expected Dividends — Risk-Free Interest Rate 2.3 % We estimated expected volatility based on an analysis of historical stock price volatility of a group of similar publicly traded peer companies which share similar characteristics with us over the expected term because our stock at that time had been publicly traded for a very short period of time. We estimated the expected term of our option awards based on the vesting period and average remaining contractual term, referred to as the “simplified method.” We used this method to provide a reasonable basis for estimating our expected term based on insufficient historical data prior to 2014. Cash-Based Long Term Incentive . In 2013, we provided long term cash-based incentives to certain of our employees linking annual performance-based cash incentive payments to the financial performance of the company as approved by the Compensation Committee of our board of directors, and the employee’s individual performance for the year. Beginning in 2014, no further cash-based awards were granted. Cash-based LTI awards granted were amortized primarily on an accelerated basis over the three -year vesting period. Class A “Matching” Grants . In conjunction with the Acquisition, certain of our employees purchased Class A units. In connection with their purchase of these units, these employees were awarded compensatory awards for accounting purposes including “matching” Class A unit grants with a fair value of $12 million equal to 50% of the Class A units purchased subject to repurchase by the Company in the event of certain termination scenarios. In 2013, each “matching” unit was converted into common stock. For the “matching” Class A unit grant, we recognized the fair value as compensation cost ratably over the period from the date of grant through the period over which the requisite service were provided and the time period at which certain transferability restrictions are removed which occurred in May 2016. Management Incentive Units (MIPs) . In addition to the Class A “matching” awards described above, certain employees were awarded MIPs at the time of the Acquisition. These MIPs are intended to constitute profits interests. Each award of MIPs represents a share in any future appreciation of the Company after the date of grant, subject to certain limitations, and once certain shareholder returns have been achieved. The MIPs vest ratably over 5 years subject to certain forfeiture provisions based on continued employment with the Company, although 25% of any vested awards are forfeitable in the event of certain termination events. The MIPs become payable based on the achievement of certain predetermined performance measures (e.g. certain liquidity events in which our private equity investors receive a return of at least one times their invested capital plus a stated return). The MIPs were issued at no cost to the employees and have value only to the extent the value of the Company increases. For accounting purposes, these awards were treated as compensatory equity awards at the date of grant. The MIPs were subsequently converted into Class B common shares on a one -for-one basis in 2013. On May 24, 2012, the grant date fair value of this award was determined using a non-controlling, non-marketable option pricing model which valued these MIPs assuming a 0.77% risk free rate, a 5 year time to expiration, and a 73% volatility rate. Based on these factors, we determined a grant date fair value of $74 million . As of December 31, 2016 , we had unrecognized compensation expense of $14 million . Of this amount, we will recognize $1 million during the remaining requisite service period in 2017. The remaining $13 million of compensation will be recognized should a specified capital transaction occur and the right to such amounts become nonforfeitable. Performance Units. We grant performance unit awards to certain members of EP Energy's management team. Performance units have a target value of $100 per unit; however, the ultimate value of each performance unit will range from zero to $200 depending on the level of total shareholder return (TSR) relative to that of EP Energy’s peer group of companies for the performance period. The performance units are subject to three separate performance periods starting on January 1, 2016 and ending on December 31, 2016, 2017 and 2018. The performance units vest in three separate tranches over the requisite service period beginning on the grant date. The awards may be settled in either stock or cash at the election of the Board of Directors. Had all performance unit awards vested on December 31, 2016 and been settled in stock, 1.9 million shares would have been issued. A summary of our performance unit award transactions for the year ended December 31, 2016 is presented below: Number of Awards Weighted Average Fair Value Non-vested at December 31, 2015 — $ — Granted 83,150 $ 102.41 Cancelled/Forfeited (4,250 ) $ 68.32 Non-vested at December 31, 2016 78,900 $ 97.77 For accounting purposes, the performance unit awards are treated as a liability award with the expense recognized on an accelerated basis and fair value remeasured at each reporting period. The fair value of these awards measured at the grant date and as of December 31, 2016 was approximately $8 million determined using a Monte Carlo simulation based on numerous iterations of random projections of stock price paths. The following table summarizes the significant assumptions used to calculate the grant date fair value of the performance unit awards granted in 2016: 2016 Expected Term in Years 3.0 Expected Volatility (1) 85.9 % Expected Dividends — Risk-Free Interest Rate (2) 1.01 % (1) Expected volatility assumption is based on the historical stock price volatility over approximately the last 3 years. (2) The risk-free rate is based upon the yield on U.S. Treasury STRIPS (Separate Trading of Registered Interest and Principal of Securities) over the expected term as of the grant date. U.S. Treasury STRIPS are fixed-income securities sold at a significant discount to face value and offer no interest payments because they mature at par. Total compensation cost related to non-vested performance unit awards not yet recognized at December 31, 2016 was approximately $3 million , which is expected to be recognized over a weighted average period of 1.3 years. Other . In September 2013, we issued an additional 70,000 shares of Class B common stock to EPE Employee Holdings II, LLC (EPE Holdings II), a subsidiary. EPE Holdings II was formed to hold such shares and serve as an entity through which current and future employee incentive awards would be granted. Holders of the awards do not hold actual Class B common stock or equity in EPE Holdings II, but rather will have a right to receive proceeds paid to EPE Holdings II in respect of such shares which is conditional upon certain events (e.g. certain liquidity events in which our private equity investors receive a return of at least one times their invested capital plus a stated return) that are not yet probable of occurring. As a result, no compensation expense was recognized upon the issuance of the Class B shares to EPE Holdings II, and none will occur until those events that give rise to a payout on such shares becomes probable of occurring. At that time, the full value of the awards issued to EPE Holdings II will be recognized based on actual amounts paid, if any, on the Class B common stock. 401(k) Retirement Plan. We sponsor a tax-qualified defined contribution retirement plan for a broad-based group of employees. We make matching contributions (dollar for dollar up to 6% of eligible compensation) and non-elective employer contributions ( 5% of eligible compensation) to the plan, and individual employees are also eligible to contribute to the defined contribution plan. During 2016 , 2015 and 2014 , we contributed $9 million , $10 million and $11 million , respectively, of matching and non-elective employer contributions.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Joint Venture. In January 2017, we entered into a drilling joint venture with Wolfcamp Drillco Operating L.P. (the Investor), managed and owned by affiliates of Apollo Global Management LLC, to fund future oil and natural gas development in our Wolfcamp program. The Investor will fund approximately $450 million over the entire program, or approximately 60 percent of the drilling, completion and equipping costs in exchange for a 50 percent working interest in the joint venture wells. Once the Investor achieves a 12 percent internal rate of return on its invested capital in each tranche, its working interest will revert to 15 percent . We will retain operational control of the joint venture assets and the transaction is expected to increase well-level returns on the jointly developed wells. The first wells under the joint venture began production in January 2017. Affiliate Supply Agreement. For the years ended December 31, 2016 , 2015 and 2014 , we recorded approximately $6 million , $67 million and $112 million , respectively, in capital expenditures for amounts expended under supply agreements entered into with an affiliate of Apollo Management, LLC (Apollo) to provide certain fracturing materials to our Eagle Ford drilling operations. This agreement was terminated effective May 2016. Management Fee Agreement. In January 2014, we paid a quarterly management fee of $6.25 million to our private equity investors (affiliates of Apollo, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively the Sponsors). Additionally, upon the closing of our initial public offering in January 2014, we paid the Sponsors a transaction fee equal to approximately $83 million . We recorded both of these fees in general and administrative expense. Our Management Fee Agreement with the Sponsors, including the obligation to pay the quarterly management fee, terminated automatically in accordance with its terms upon the closing of our initial public offering in January 2014.

Basis of Presentation and Sig18

Basis of Presentation and Significant Accounting Policies (Polices)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Accounting	Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (U.S. GAAP) and include the accounts of all consolidated subsidiaries after the elimination of all significant intercompany accounts and transactions.
Consolidation	We consolidate entities when we have the ability to control the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment.
Segment Reporting	Our oil and natural gas properties are managed as a single operating segment rather than through discrete operating segments or business units. We track basic operational data by area and allocate capital resources on a project-by-project basis across our entire asset base without regard to individual areas. We assess financial performance as a single enterprise and not on a geographical area basis.
New Accounting Pronouncements Issued But not Yet Adopted	New Accounting Pronouncements Issued But Not Yet Adopted The following accounting standards have been issued but not yet been adopted. Statement of Cash Flows. In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-15, Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows - Restricted Cash , which requires restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flow. Retrospective application of these standards is required for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and early adoption is allowed. We do not anticipate that the adoption of these standards will have a material impact on the presentation of our consolidated statement of cash flows. Stock Compensation. In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting , which updates several aspects of the accounting for and disclosure of share-based payment transactions. Adoption of this standard is required beginning in the first quarter of 2017. We do not anticipate that the adoption of this standard will have a material impact on our financial statements. Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases, which requires lessees to recognize lease assets and lease liabilities on the balance sheet and disclose key information about leasing arrangements. Adoption of this standard is required beginning in the first quarter of 2019 and early adoption is allowed. We continue to evaluate our contracts and other agreements to assess the impact this update will have on our financial statements. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which clarifies the principles for recognizing revenue and develops a common revenue standard for U.S. GAAP and International Financial Reporting Standards. Adoption of this standard is required beginning in the first quarter of 2018, with the option of early adoption in 2017. Modified or full retrospective application of this standard is required upon adoption. We presently intend to adopt this standard in 2018 and do not anticipate that the adoption of this standard will have a material impact on our financial statements.
Use of Estimates	Use of Estimates The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.
Revenue Recognition	Revenue Recognition Our revenues are generated primarily through the physical sale of oil, natural gas and NGLs to third party customers at spot or market prices under both short and long-term contracts. We recognize revenue upon delivery and transfer of control of the product to the customer which occurs at the point in time which delivery and passage of title and risk of loss have occurred. Delivery and transfer of control vary depending on the product and delivery method but typically occurs at a pipeline or gathering line delivery point interconnect when delivered via pipeline or at the wellhead or tank battery to purchasers who transport the oil via truck. Revenue is measured and based upon index prices (WTI, LLS, Henry Hub and Mt. Belvieu) or refiners posted prices at various delivery points across our producing basins. Realized prices received (not considering the effects of hedges) are generally less than the stated index price as a result of contractual deductions, differentials from the index to the delivery point and/or discounts for quality or grade. Revenue is recorded using the sales method, net of any royalty interests or other profit interests in the produced product. Revenues related to products delivered, but not yet billed, are estimated each month. These estimates are based on contract data, commodity prices and preliminary throughput and allocation measurements. When actual sales volumes exceed our entitled share of sales volumes, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, we record a liability. Costs associated with the transportation and delivery of production, generally between the wellhead and its intended sale location are included in transportation costs. We also purchase and sell oil and natural gas on a monthly basis to manage our overall oil and natural gas production and sales. These transactions are undertaken to optimize prices we receive for our oil and natural gas, to physically move oil and gas to its intended sales point, or to manage firm transportation agreements. Revenue related to these transactions are recorded in oil and natural gas sales in operating revenues and associated purchases reflected in oil and natural gas purchases in operating expenses in our consolidated income statements. For the years ended December 31, 2016 , 2015 and 2014 , we had two customers that individually accounted for 10 percent or more of our total revenues. The loss of any one customer would not have an adverse effect on our ability to sell our oil, natural gas and NGLs production. While most of our physical production is priced off of market indices, we actively manage the volatility of market pricing through our risk management program whereby we enter into financial derivatives contracts. All of our derivatives are marked-to-market each period. The change in the fair value of our commodity-based derivatives, as well as any realized amounts, are reflected in operating revenues as financial derivative revenues (see Derivatives below and Note 6).
Cash and Cash Equivalents	Cash and Cash Equivalents We consider short-term investments with an original maturity of less than three months to be cash equivalents. As of December 31, 2016 and 2015 , we had no restricted cash.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.
Oil and Natural Gas Properties	Oil and Natural Gas Properties We account for oil and natural gas properties in accordance with the successful efforts method of accounting for oil and natural gas exploration and development activities. Under the successful efforts method, we capitalize (i) lease acquisition costs, all development costs and exploratory drilling costs until results are determined, (ii) certain internal costs directly identified with the acquisition, successful drilling of exploratory wells and development activities, and (iii) interest costs related to financing oil and natural gas projects actively being developed until the projects are evaluated or substantially complete and ready for their intended use if the projects were evaluated as successful. Non-drilling exploratory costs, including certain geological and geophysical costs such as seismic costs and delay rentals, are expensed as incurred. We provide for depreciation, depletion, and amortization on the basis of common geological structure or stratigraphic conditions applied to total capitalized costs, plus future abandonment costs, net of salvage value, using the unit of production method. Lease acquisition costs are amortized over total proved reserves, while other exploratory drilling and all developmental costs are amortized over total proved developed reserves. We evaluate capitalized costs related to proved properties upon a triggering event to determine if impairment of such properties is necessary. Our evaluation of recoverability is made on the basis of common geological structure or stratigraphic conditions and considers estimated future cash flows primarily from all proved developed (producing and non-producing) and proved undeveloped reserves in comparison to the carrying amount of the proved properties. Estimated future cash flows are determined based on estimates of future oil and gas production, estimated or published commodity prices as of the date of the estimate, adjusted for geographical location, contractual and quality price differentials, and estimates of future operating and development costs. If the carrying amount of a property exceeds these estimated undiscounted future cash flows, the carrying amount is reduced to its estimated fair value through a charge to income. Fair value is calculated by discounting the estimated future cash flows using a risk-adjusted discount rate. This discount rate is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas. Leasehold acquisitions costs associated with non-producing areas are also assessed for impairment based on our estimated drilling plans and anticipated capital expenditures related to potential lease expirations.
Property, Plant and Equipment (Other than Oil and Natural Gas Properties)	Property, Plant and Equipment (Other than Oil and Natural Gas Properties) Our property, plant and equipment, other than our assets accounted for under the successful efforts method, are recorded at their original cost of construction or, upon acquisition, at the fair value of the assets acquired. We capitalize the major units of property replacements or improvements and expense minor items. We depreciate our non-oil and natural gas property, plant and equipment using the straight-line method over the useful lives of the assets which range from four to 15 years .
Accounting for Asset Retirement Obligations	Accounting for Asset Retirement Obligations We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred and is estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our consolidated income statement.
Accounting for Long-Term Incentive Compensation	Accounting for Long-Term Incentive Compensation We measure the cost of long-term incentive compensation based on the fair value of the award on the day it is granted. Awards issued under our incentive compensation programs are recognized as either equity awards or liability awards based on their characteristics. Expense is recognized in our consolidated financial statements as general and administrative expense over the period of service required by the award, net of estimated forfeitures. See Note 10 for further discussion of our long-term incentive compensation.
Environmental Costs, Legal and Other Contingencies	Environmental Costs, Legal and Other Contingencies Environmental Costs. We record environmental liabilities at their undiscounted amounts on our consolidated balance sheet in other current and long-term liabilities when we assess that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on current available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and expense costs that do not in general and administrative expense. We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet. Legal and Other Contingencies. We recognize liabilities for legal and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other to occur, the low end of the range is accrued.
Derivatives	Derivatives We enter into derivative contracts on our oil and natural gas products primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. We also use derivatives to reduce the risk of increases in variable interest rates. Derivative instruments are reflected on our consolidated balance sheet at their fair value as assets and liabilities. We classify our derivatives as either current or non-current based on their anticipated settlement date. We net derivative assets and liabilities with counterparties where we have a legal right of offset. All of our derivatives are marked-to-market each period and changes in the fair value of our commodity based derivatives, as well as any realized amounts, are reflected as operating revenues. Changes in the fair value of our interest rate derivatives are reflected as interest expense. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. In our consolidated balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables. See Note 6 for a further discussion of our derivatives.
Income Tax	Income Taxes We record current income taxes based on our estimates of current taxable income and provide for deferred income taxes to reflect estimated future income tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We classify all deferred tax assets and liabilities, along with any related valuation allowance, as non-current on the consolidated balance sheet. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. The realization of our deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. We reduce deferred tax assets by a valuation allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating our valuation allowances, we consider cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of our taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to our valuation allowances could materially impact our results of operations.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Summary of operating results and financial position data of discontinued operations	Summarized operating results and financial position data of our assets held for sale and/or for our discontinued operations were as follows (in millions): Assets Held For Sale Discontinued Operations Year Ended December 31, Year Ended December 31, 2016 2015 2014 2014 Operating revenues $ 26 $ 78 $ 141 $ 82 Operating expenses Transportation costs 7 21 20 5 Lease operating expense 1 6 5 31 Depreciation, depletion and amortization 16 32 37 8 Impairment (1) — — — 18 Other expense 5 12 12 17 Total operating expenses 29 71 74 79 Gain on sale of assets 79 — — 2 Other income — — — 4 Income before income taxes $ 76 $ 7 $ 67 $ 9 Income tax expense 5 Income from discontinued operations, net of tax $ 4 (1) Related to the sale of our Brazilian operations. Assets Held for Sale December 31, 2015 Assets Current assets $ 16 Property, plant and equipment, net 328 Total assets held for sale $ 344 Liabilities Accounts payable $ 17 Other current liabilities 4 Asset retirement obligations 3 Total liabilities related to assets held for sale $ 24

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of pretax income (loss) from continuing operations and the components of income tax expense (benefit) from continuing operations	Year Ended December 31, 2016 2015 2014 (in millions) Pretax (Loss) Income U.S. $ (26 ) $ (4,326 ) $ 1,159 Components of Income Tax Expense Current State $ 1 $ — $ — 1 — — Deferred Federal $ — $ (543 ) $ 415 State — (35 ) 17 Total income tax expense (benefit) $ 1 $ (578 ) $ 432
Schedule of pretax income (loss), components of income tax expense (benefit) and effective tax rates	Effective Tax Rate Reconciliation. Income taxes included in net income differs from the amount computed by applying the statutory federal income tax rate of 35% for the following reasons for the following periods: Year Ended December 31, 2016 2015 2014 (in millions) Income taxes at the statutory federal rate of 35% $ (9 ) $ (1,514 ) $ 406 Increase (decrease) State income taxes, net of federal income tax effect (1 ) (41 ) 12 Non-deductible reorganization costs — — 10 Valuation allowance 9 975 — Other 2 2 4 Income tax expense (benefit) $ 1 $ (578 ) $ 432
Schedule of deferred tax assets and liabilities	Deferred Tax Assets and Liabilities. The following are the components of net deferred tax assets and liabilities: December 31, December 31, (in millions) Deferred tax assets Property, plant and equipment $ 249 $ 471 Net operating loss carryovers 692 720 U.S. tax credit carryovers 10 10 Employee benefits 6 4 Legal and other reserves 6 7 Asset retirement obligations 15 19 Transaction costs 19 22 Total deferred tax assets 997 1,253 Valuation allowance (985 ) (976 ) Net deferred tax assets 12 277 Deferred tax liabilities Financial derivatives 12 277 Total deferred tax liabilities 12 277 Net deferred tax liabilities $ — $ —
Schedule of net operating loss and tax credit carryovers	Net Operating Loss and Tax Credit Carryovers. The table below presents the details of our federal and state net operating loss carryover periods as of December 31, 2016 (in millions): Expiration Period 2031 - 2036 U.S. federal net operating loss carryover $ 1,918 2026 - 2036 State net operating loss carryover $ 307

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of carrying amounts and estimated fair values of the financial instruments	The following table presents the carrying amounts and estimated fair values of our financial instruments: December 31, 2016 December 31, 2015 Carrying Amount Fair Value Carrying Amount Fair Value (in millions) Long-term debt $ 3,856 $ 3,637 $ 4,869 $ 3,379 Derivative instruments $ 57 $ 57 $ 771 $ 771
Schedule of fair value associated with derivative financial instruments	The following table presents the fair value associated with our derivative financial instruments as of December 31, 2016 and 2015 . All of our derivative instruments are subject to master netting arrangements which provide for the unconditional right of offset for all derivative assets and liabilities with a given counterparty in the event of default. We present assets and liabilities related to these instruments in our consolidated balance sheets as either current or non-current assets or liabilities based on their anticipated settlement date, net of the impact of master netting agreements. On derivative contracts recorded as assets in the table below, we are exposed to the risk that our counterparties may not perform. Level 2 Derivative Assets Derivative Liabilities Gross Fair Value Balance Sheet Location Gross Fair Value Balance Sheet Location Impact of Netting Current Non-current Impact of Netting Current Non-current (in millions) (in millions) December 31, 2016 Derivative instruments $ 79 $ (17 ) $ 58 $ 4 $ (22 ) $ 17 $ (4 ) $ (1 ) December 31, 2015 Derivative instruments $ 795 $ (16 ) $ 694 $ 85 $ (24 ) $ 16 $ — $ (8 )

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of capitalized costs of proved and unproven properties	Our capitalized costs related to proved and unproved oil and natural gas properties by area for the periods ended December 31 were as follows: 2016 2015 (in millions) Proved Eagle Ford $ 3,001 $ 2,833 Wolfcamp 2,415 2,174 Altamont 1,624 1,553 Total Proved 7,040 6,560 Unproved Wolfcamp 94 97 Altamont 60 64 Total Unproved 154 161 Less accumulated depletion 2,731 2,335 Net capitalized costs for oil and natural gas properties $ 4,463 $ 4,386
Schedule of changes in net asset retirement liability	The net asset retirement liability as of December 31 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability for the periods ended December 31 were as follows: 2016 2015 (in millions) Net asset retirement liability at January 1 $ 38 $ 39 Liabilities incurred — 4 Liabilities settled (1 ) (2 ) Accretion expense 3 3 Changes in estimate 1 (6 ) Net asset retirement liability at December 31 $ 41 $ 38

Long Term Debt (Tables)

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of debt obligations	Listed below are our debt obligations as of the periods presented: Interest Rate December 31, 2016 December 31, 2015 (in millions) RBL credit facility - due May 24, 2019 (1) Variable $ 370 $ 1,072 Senior secured term loan - due May 24, 2018 (2)(4) Variable 21 497 Senior secured term loan - due April 30, 2019 (3)(4) Variable 8 150 Senior secured term loan - due June 30, 2021 (5)(6) Variable 580 — Senior secured notes - due November 29, 2024 8.00 % 500 — Senior unsecured notes - due May 1, 2020 9.375 % 1,576 2,000 Senior unsecured notes - due September 1, 2022 7.75 % 250 350 Senior unsecured notes - due June 15, 2023 6.375 % 551 800 Total long-term debt 3,856 4,869 Less unamortized debt issue costs (67 ) (57 ) Total long-term debt, net $ 3,789 $ 4,812 (1) Carries interest at a specified margin over LIBOR of 2.50% to 3.50% , based on borrowing utilization. (2) Issued at 99% of par and carries interest at a specified margin over the LIBOR of 2.75% , with a minimum LIBOR floor of 0.75% . As of December 31, 2016 and 2015 , the effective interest rate of the term loan was 3.50% . (3) Carries interest at a specified margin over the LIBOR of 3.50% , with a minimum LIBOR floor of 1.00% . As of December 31, 2016 and 2015 , the effective interest rate for the term loan was 4.50% . (4) Secured by a second priority lien on all of the collateral securing the RBL Facility, and effectively ranks junior to any existing and future priority lien secured indebtedness of the Company. (5) Carries an interest rate of LIBOR plus 8.75% , with a minimum LIBOR floor of 1.00% . As of December 31, 2016 , the effective interest rate for the term loan was 9.75% . (6) Secured by a priority lien on all of the collateral securing the RBL Facility, and effectively ranks junior to RBL indebtedness and senior priority lien indebtedness.
Schedule of description of credit facility	Listed below is a further description of our credit facility as of December 31, 2016 : Credit Facility Maturity Date Interest Rate Commitment fees $1.5 billion RBL May 24, 2019 LIBOR + 2.5% (1) 2.5% for LCs 0.375% commitment fee on unused capacity (1) Based on our December 31, 2016 borrowing level. Amounts outstanding under the $1.5 billion RBL Facility bear interest at specified margins over the LIBOR of between 2.50% and 3.50% for Eurodollar loans or at specified margins over the Alternative Base Rate ( ABR ) of between 1.50% and 2.50% for ABR loans. Such margins will fluctuate based on the utilization of the facility.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	Future minimum annual rental commitments under non-cancelable future operating lease commitments at December 31, 2016 , were as follows: Year Ending December 31, Operating Leases (in millions) 2017 $ 7 2018 5 2019 5 2020 5 2021 5 Thereafter 22 Total $ 49

LLong-Term Incentive Compensati

LLong-Term Incentive Compensation / 401(k) Retirement Plan (Tables)	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Share-based Compensation, Performance Shares Award Outstanding Activity [Table Text Block]	A summary of our performance unit award transactions for the year ended December 31, 2016 is presented below: Number of Awards Weighted Average Fair Value Non-vested at December 31, 2015 — $ — Granted 83,150 $ 102.41 Cancelled/Forfeited (4,250 ) $ 68.32 Non-vested at December 31, 2016 78,900 $ 97.77
Schedule of the changes in non-vested restricted shares	A summary of the changes in our non-vested restricted shares for the year ended December 31, 2016 is presented below: Number of Shares Weighted Average Grant Date Fair Value per Share Non-vested at December 31, 2015 3,987,654 $ 10.98 Granted 4,676,322 $ 6.08 Vested (1,255,394 ) $ 11.76 Forfeited (1,081,794 ) $ 8.17 Non-vested at December 31, 2016 6,326,788 $ 7.69
Schedule of stock option	A summary of our stock options for the year ended December 31, 2016 is presented below. Number of Shares Underlying Options Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (in years) (in millions) Outstanding at December 31, 2015 214,337 $ 19.82 Granted — $ 19.82 Vested (1,514 ) $ 19.82 Forfeited or canceled (4,933 ) $ 19.82 Outstanding at December 31, 2016 207,890 $ 19.82 7.25 — The following table summarizes the significant assumptions used to calculate the grant date fair value of the performance unit awards granted in 2016: 2016 Expected Term in Years 3.0 Expected Volatility (1) 85.9 % Expected Dividends — Risk-Free Interest Rate (2) 1.01 % (1) Expected volatility assumption is based on the historical stock price volatility over approximately the last 3 years. (2) The risk-free rate is based upon the yield on U.S. Treasury STRIPS (Separate Trading of Registered Interest and Principal of Securities) over the expected term as of the grant date. U.S. Treasury STRIPS are fixed-income securities sold at a significant discount to face value and offer no interest payments because they mature at par.
Schedule weighted average of each assumption	Listed below is the weighted average of each assumption based on the grant in 2014: 2014 Expected Term in Years 7.0 Expected Volatility 40 % Expected Dividends — Risk-Free Interest Rate 2.3 %

Basis of Presentation and Sig26

Basis of Presentation and Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2016segment
Acquisitions
Number of operating segments	1

Basis of Presentation and Sig27

Basis of Presentation and Significant Accounting Policies (Details 2) - Total revenues - customer	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenue Recognition
Number of major customers	2	2	2
Customer concentration risk
Revenue Recognition
Number of major customers	1

Basis of Presentation and Sig28

Basis of Presentation and Significant Accounting Policies (Details 3) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Cash and Cash Equivalents [Line Items]
Restricted cash	$ 0	$ 0

Basis of Presentation and Sig29

Basis of Presentation and Significant Accounting Policies (Details 4)	12 Months Ended
	Dec. 31, 2016
Minimum
Property, plant and equipment (other than oil and natural gas properties)
Estimated useful lives of the assets	4 years
Maximum
Property, plant and equipment (other than oil and natural gas properties)
Estimated useful lives of the assets	15 years

Acquisitions and Divestitures30

Acquisitions and Divestitures (Details)	Sep. 04, 2015USD ($)a	Dec. 31, 2014USD ($)a
Property Adjacent To Eagle Ford Shale
Other Acquisitions and Divestitures [Line Items]
Area (in acres) | a	12,000
Aggregate cash purchase price	$ 111,000,000
Goodwill recorded	0
Bargain purchase recorded	$ 0
Producing properties and undeveloped acreage in the Southern Midland Basin adjacent to the entity's existing Wolfcamp Shale position
Other Acquisitions and Divestitures [Line Items]
Area (in acres) | a		37,000
Aggregate cash purchase price		$ 152,000,000
Bargain purchase recorded		$ 0

Acquisitions and Divestitures31

Acquisitions and Divestitures (Details 2) - USD ($)	3 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Divestitures
Proceeds from Sale of Property, Plant, and Equipment	$ 420,000,000
Net Proceeds from Sale of Property Plant and Equipment	$ 388,000,000
Sale Of Oil And Gas Property And Equipment Transportation Liability Assumed By Buyer		$ 106,000,000
Proceeds from the sale of assets, net of cash transferred		389,000,000	$ 1,000,000	$ 154,000,000
Proceeds from sale of certain non-core acreage eagle ford properties				28,000,000
Summary of operating results and financial position data of assets held for sale
Operating revenues		26,000,000	78,000,000	141,000,000
Operating expenses
Transportation costs		7,000,000	21,000,000	20,000,000
Lease operating expense		1,000,000	6,000,000	5,000,000
Depreciation, depletion and amortization		16,000,000	32,000,000	37,000,000
Gain on sale of assets		79,000,000	0	0
Other expense		5,000,000	12,000,000	12,000,000
Total operating expenses		29,000,000	71,000,000	74,000,000
Income from discontinued operations before income taxes		76,000,000	7,000,000	67,000,000
Income from discontinued operations, net of tax		$ 0	0	4,000,000
Current assets			16,000,000
Property, plant and equipment, net			328,000,000
Total assets held for sale			344,000,000
Accounts payable			17,000,000
Other current liabilities			4,000,000
Asset retirement obligations			3,000,000
Total liabilities related to assets held for sale			$ 24,000,000
Arklatex and South Louisiana Wilcox along with Brazil operations natural gas properties
Summary of operating results and financial position data of assets held for sale
Operating revenues				82,000,000
Operating expenses
Transportation costs				5,000,000
Lease operating expense				31,000,000
Disposal Group, Including Discontinued Operation, Depreciation and Amortization				8,000,000
Impairment charges				18,000,000
Other expense				17,000,000
Total operating expenses				79,000,000
Gain on sale of assets				2,000,000
Other income				4,000,000
Income from discontinued operations before income taxes				9,000,000
Income tax expense				5,000,000
Income from discontinued operations, net of tax				4,000,000
Various disposal asset groups
Divestitures
Proceeds from the sale of assets, net of cash transferred				$ 111,000,000

Impairment Charges (Details)

Impairment Charges (Details) $ in Millions	5 Months Ended	7 Months Ended	12 Months Ended
	May 19, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Impairment charges					$ 2	$ 4,299	$ 2
LeaseholdNumberofWells	6	34	55	55
Impairment charges, other							$ 2
Eagle Ford
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Impairment charges						4,000
Wolfcamp
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Impairment charges						$ 288

Income Taxes (Details 1)

Income Taxes (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Current Income Tax Expense (Benefit)	$ 1	$ 0	$ 0
Pretax (Loss) Income
U.S.	(26)	(4,326)	1,159
Deferred
Federal	0	(543)	415
State	0	(35)	17
Total income tax expense (benefit)	1	(578)	432
Current State and Local Tax Expense (Benefit)	1	0	0
Effective tax rate reconciliation
Income taxes at the statutory federal rate of 35%	(9)	(1,514)	406
Increase (decrease)
State income taxes, net of federal income tax effect	(1)	(41)	12
Non-deductible reorganization costs	0	0	10
Valuation allowance	9	975	0
Other	2	2	4
Total income tax expense (benefit)	$ 1	$ (578)	432
Effective tax rates (as a percent)	(1.90%)	13.40%
Statutory federal income tax rate (as a percent)	35.00%	35.00%
(Loss) income from continuing operations	$ (27)	$ (3,748)	$ 727

Income Taxes (Details 2)

Income Taxes (Details 2) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Property, plant and equipment	$ 249	$ 471
Net operating loss carryovers	692	720
U.S. tax credit carryovers	10	10
Employee benefits	6	4
Legal and other reserves	6	7
Asset retirement obligations	15	19
Transaction costs	19	22
Total deferred tax assets	997	1,253
Valuation allowance	(985)	(976)
Net deferred tax assets	12	277
Financial derivatives	12	277
Total deferred tax liabilities	12	277
Net deferred tax liabilities	0	$ 0
Uncertain tax benefits	$ 0

Income Taxes (Details 3)

Income Taxes (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	$ 9	$ 975	$ 0
Net operating loss carryforwards	318
OperatingLossCarryforwardFromGainLossOnExtinguishmentOfDebt	405
U.S. federal alternative minimum tax credits	10
Capital loss carryovers	23
Utilization federal carryover	136
Valuation allowance	985	$ 976
2031 - 2036 | U.S. federal net operating loss
Income Taxes
Net operating loss carryforwards	1,918
2026 - 2036 | State net operating loss
Income Taxes
Net operating loss carryforwards	$ 307

Earnings Per Share (Details)

Earnings Per Share (Details) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Class A Stock
Earnings per share
Par value per share (in dollars per share)	$ 0.01	$ 0.01

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Carrying amounts and estimated fair values of financial instruments
Long-term debt, net of debt issue costs	$ 3,789	$ 4,812
Carrying Amount
Carrying amounts and estimated fair values of financial instruments
Long-term debt, net of debt issue costs	3,856	4,869
Derivative instruments	57	771
Fair Value
Carrying amounts and estimated fair values of financial instruments
Long-term debt	3,637	3,379
Derivative instruments	$ 57	$ 771

Fair Value Measurements (Deta38

Fair Value Measurements (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Liabilities
Gain (loss) on derivative instruments	$ (73)	$ 667	$ 985
Level 2
Derivative Assets
Gross Fair Value	79	795
Impact of Netting	(17)	(16)
Derivative Liabilities
Gross Fair Value	(22)	(24)
Impact of Netting	17	16
Level 2 | Current Assets
Derivative Assets
Derivatives instruments	58	694
Level 2 | Non Current Assets
Derivative Assets
Derivatives instruments	4	85
Level 2 | Current Liabilities
Derivative Liabilities
Derivatives instruments	(4)	0
Level 2 | Non-current liabilities
Derivative Liabilities
Derivatives instruments	$ (1)	$ (8)

Fair Value Measurements (Deta39

Fair Value Measurements (Details 3) BTU in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)BTUContractgalMMBbls	Dec. 31, 2015USD ($)BTUgalMMBbls	Dec. 31, 2014USD ($)
Derivative [Line Items]
Number of contracts that are designated as accounting hedges | Contract	0
Derivatives not designated as accounting hedges | Oil derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume (in barrels and gallons) | MMBbls	16	23
Derivatives not designated as accounting hedges | Natural gas derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure (in btus) | BTU	36	7
Derivatives not designated as accounting hedges | Propane derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume (in barrels and gallons) | gal	108	15
Derivatives not designated as accounting hedges | Interest rate derivative instruments
Derivative [Line Items]
Monetary notional amount | $	$ 600
Net asset related to interest rate derivatives | $	1	$ 1
Interest expense related to the change in fair market value and cash settlements of interest rate derivative instruments | $	$ 2	$ 5	$ 5
2017 Fixed Price Swaps [Member] | Derivatives not designated as accounting hedges | Oil derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume (in barrels and gallons) | MMBbls	13
2017 Fixed Price Swaps [Member] | Derivatives not designated as accounting hedges | Natural gas derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure (in btus) | BTU	32
2017 Fixed Price Swaps [Member] | Derivatives not designated as accounting hedges | Propane derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume (in barrels and gallons) | gal	46,000,000
2018 Fixed Price Swaps [Member] | Derivatives not designated as accounting hedges | Oil derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume (in barrels and gallons) | MMBbls	3
2018 Fixed Price Swaps [Member] | Derivatives not designated as accounting hedges | Natural gas derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure (in btus) | BTU	4
2018 Fixed Price Swaps [Member] | Derivatives not designated as accounting hedges | Propane derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume (in barrels and gallons) | gal	62,000,000

Fair Value Measurements (Deta40

Fair Value Measurements (Details 4)	Dec. 31, 2016USD ($)counterparty
Credit Risk
Number of counterparties | counterparty	8
RBL credit facility - due May 24, 2019(1)
Debt Instrument [Line Items]
Borrowing capacity | $	$ 1,500,000,000

Property, Plant and Equipment41

Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property, plant and equipment (other than oil and natural gas properties)
Property, Plant and Equipment, Net	$ 4,498	$ 4,427
Oil and Natural Gas Properties
Capitalized costs, proved properties	7,040	6,560
Capitalized costs, unproved properties	154	161
Less accumulated depletion	2,731	2,335
Net capitalized costs for oil and natural gas properties	4,463	4,386
Transfer to (from) unproved properties to proved properties	(9)
Amortization of unproved leasehold costs	$ 2	9	$ 18
Asset Retirement Obligations
Projected inflation rate (as a percent)	2.50%
Changes in net asset retirement liability
Net asset retirement liability at January 1	$ 38	39
Liabilities incurred	0	4
Liabilities settled	(1)	(2)
Accretion expense	3	3
Changes in estimate	1	(6)
Net asset retirement liability at December 31	41	38	39
Capitalized Interest
Capitalized Interest (approximately)	$ 4	14	$ 21
Minimum
Asset Retirement Obligations
Credit-adjusted risk-free rate (as a percent)	7.00%
Maximum
Asset Retirement Obligations
Credit-adjusted risk-free rate (as a percent)	9.00%
Eagle Ford
Oil and Natural Gas Properties
Capitalized costs, proved properties	$ 3,001	2,833
Wolfcamp
Oil and Natural Gas Properties
Capitalized costs, proved properties	2,415	2,174
Capitalized costs, unproved properties	94	97
Altamont
Oil and Natural Gas Properties
Capitalized costs, proved properties	1,624	1,553
Capitalized costs, unproved properties	$ 60	$ 64

Long Term Debt - Long Term Debt

Long Term Debt - Long Term Debt (Details)	1 Months Ended	12 Months Ended
	May 05, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Feb. 06, 2017USD ($)	Nov. 01, 2016USD ($)	Sep. 30, 2016USD ($)	Apr. 30, 2015USD ($)
Debt Instrument [Line Items]
Unamortized debt issue costs			$ 77,000,000	$ 80,000,000
Long-term debt, net of debt issue costs			3,789,000,000	4,812,000,000
Unamortized Debt Issuance Expense Senior Notes			67,000,000	57,000,000
Write off of deferred debt issuance cost			21,000,000
Amortization of deferred financing costs			16,000,000	18,000,000	$ 21,000,000
(Gain) loss on extinguishment of debt			$ (384,000,000)	41,000,000	$ 17,000,000
RatioOfDebtToEBITDAX			3.69
Ratio of Indebtedness to Net Capital			0.36
Repayments of Debt			$ 407,000,000
Debt Instrument, Repurchase Amount			812,000,000
Debt Covenant Debt Repurchase Limit	$ 350,000,000
EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs			$ 3,856,000,000	4,869,000,000
Minimum
Debt Instrument [Line Items]
Debt to EBITDAX multiple	1		1
Maximum
Debt Instrument [Line Items]
Debt to EBITDAX multiple	3.5		4.5
RBL credit facility - due May 24, 2019(1)
Debt Instrument [Line Items]
Unamortized debt issue costs			$ 10,000,000	23,000,000
(Gain) loss on extinguishment of debt			9,000,000
Borrowing capacity			$ 1,500,000,000
Interest rate (as a percent)			2.50%
Commitment fees (as a percent)			0.375%
RBL credit facility - due May 24, 2019(1) | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs			$ 370,000,000	1,072,000,000
Borrowing capacity	$ 1,650,000,000						$ 1,500,000,000
Letters of credit outstanding			19,000,000
Remaining capacity			$ 1,111,000,000
RBL credit facility - due May 24, 2019(1) | London Interbank Offered Rate LIBOR
Debt Instrument [Line Items]
Reference rate for variable interest rate			LIBOR
RBL credit facility - due May 24, 2019(1) | Minimum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Reference rate for variable interest rate			LIBOR
Specified margin on reference rate (as a percent)			2.50%
RBL credit facility - due May 24, 2019(1) | Minimum | Alternate base rate | EP Energy Global LLC
Debt Instrument [Line Items]
Reference rate for variable interest rate			ABR
Specified margin on reference rate (as a percent)			1.50%
RBL credit facility - due May 24, 2019(1) | Maximum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Specified margin on reference rate (as a percent)			3.50%
RBL credit facility - due May 24, 2019(1) | Maximum | Alternate base rate | EP Energy Global LLC
Debt Instrument [Line Items]
Reference rate for variable interest rate			ABR
Specified margin on reference rate (as a percent)			2.50%
Senior Secured Term Loans and Senior Notes
Debt Instrument [Line Items]
Unamortized debt issue costs			$ 67,000,000	57,000,000
Senior Secured Note Due 29 November 2024 [Member] | EP Energy Global LLC
Debt Instrument [Line Items]
Unamortized debt issue costs			10,000,000
Long-term debt, net of debt issue costs			$ 500,000,000
Interest rate (as a percent)			8.00%
Senior secured term loan - due May 24, 2018 | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs			$ 21,000,000	$ 497,000,000
Debt Instrument Issuance as Percentage of Face Amount			99.00%
Senior secured term loan - due May 24, 2018 | London Interbank Offered Rate LIBOR
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Effective Percentage				3.50%
Senior secured term loan - due May 24, 2018 | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Debt Instrument Variable Rate Basis Floor			2.75%
Debt Instrument, Interest Rate, Effective Percentage			3.50%
Reference rate for variable interest rate			LIBOR
Senior secured term loan - due May 24, 2018 | Minimum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Debt Instrument Variable Rate Basis Floor			0.75%
Reference rate for variable interest rate			LIBOR
Senior secured term loan - due April 30, 2019
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Effective Percentage				4.50%
Senior secured term loan - due April 30, 2019 | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs			$ 8,000,000	$ 150,000,000
Debt Instrument, Interest Rate, Effective Percentage			4.50%
Senior secured term loan - due April 30, 2019 | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Reference rate for variable interest rate			LIBOR
Specified margin on reference rate (as a percent)			3.50%
Senior secured term loan - due April 30, 2019 | Minimum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Debt Instrument Variable Rate Basis Floor			1.00%
Reference rate for variable interest rate			LIBOR
Senior Unsecured Note Due1 May2020 [Member] | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs			$ 1,576,000,000	2,000,000,000
Interest rate (as a percent)			9.375%
Debt Instrument, Repurchase Amount			$ 250,000,000
Senior Unsecured Note Due1 September2022 [Member] | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs			$ 250,000,000	350,000,000
Interest rate (as a percent)			7.75%
Senior Secured Term Loan Due30 June2021 [Member] [Domain]
Debt Instrument [Line Items]
Unamortized debt issue costs			$ 22,000,000
Long-term debt, net of debt issue costs			$ 580,000,000					$ 580,000,000
Senior Secured Term Loan Due30 June2021 [Member] [Domain] | London Interbank Offered Rate LIBOR
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Effective Percentage			9.75%
Reference rate for variable interest rate			LIBOR
Specified margin on reference rate (as a percent)			8.75%
Senior Secured Term Loan Due30 June2021 [Member] [Domain] | Minimum | London Interbank Offered Rate LIBOR
Debt Instrument [Line Items]
Debt Instrument Variable Rate Basis Floor			1.00%
Senior secured notes - due May 1, 2019
Debt Instrument [Line Items]
Write off of deferred debt issuance cost				12,000,000
Senior secured notes - due May 1, 2019 | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs									$ 750,000,000
Senior Unsecured Notes and Term Loans [Member]
Debt Instrument [Line Items]
Write off of deferred debt issuance cost			$ 12,000,000
(Gain) loss on extinguishment of debt			(393,000,000)
Senior unsecured notes - due June 15, 2023 | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs			$ 551,000,000	$ 800,000,000
Interest rate (as a percent)			6.375%	6.375%
Subsequent Event [Member] | RBL credit facility - due May 24, 2019(1) | EP Energy Global LLC
Debt Instrument [Line Items]
Repayments of Lines of Credit		$ 111,000,000
Borrowing capacity						$ 1,440,000,000
Subsequent Event [Member] | Senior Secured Note Due 2025 [Member] | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs						$ 1,000,000,000
Interest rate (as a percent)						8.00%

Commitments and Contingencies43

Commitments and Contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Legal Matters
Lease operating expense	$ 159	$ 186	$ 193
Property, Plant and Equipment, Gross	7,279	6,801
Interest Expense	312	$ 330	$ 318
Legal Matters
Legal Matters
Amount accrued	3
Indemnification and Other Matters
Legal Matters
Amount accrued	8
Sales and Use Tax Adjustment [Member]
Legal Matters
Accrual for Taxes Other than Income Taxes	40
Other Depreciation and Amortization	29
Lease operating expense	2
Property, Plant and Equipment, Gross	5
Interest Expense	$ 4

Commitments and Contingencies44

Commitments and Contingencies (Details 2) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)Method	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Environmental Matters
Accrued environmental remediation costs	$ 1
Number of estimation methodologies | Method	2
EstimatedEnvironmentalRemeditationCostsforAltamont	$ 5
Rental expense	13	$ 12	$ 13
Annual minimum lease payments under non-cancelable future operating lease commitments
2,017	7
2,018	5
2,019	5
2,020	5
2,021	5
Operating Leases, Future Minimum Payments, Due Thereafter	22
Total	49
Various commercial commitments due
Other commercial commitments, 2017	112
Other commercial commitments, 2018	65
Other commercial commitments, 2019	62
Other commercial commitments, 2020	57
Other commercial commitments, thereafter	99
Total, Other commercial commitments	395
Maximum | Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters
Environmental Matters
Estimated environmental remediation costs (less than)	$ 1

Long-Term Incentive Compensat45

Long-Term Incentive Compensation / 401(k) Retirement Plan (Details)	Sep. 18, 2013USD ($)shares	May 24, 2012USD ($)	Dec. 31, 2016USD ($)trancheshares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)$ / shares	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit expense			$ (1,000,000)	$ 578,000,000	$ (432,000,000)
Vesting period for cash based incentive						3 years
Maximum matching contributions as a percentage of eligible compensation			6.00%
Non-elective employer contributions as a percentage of eligible compensation			5.00%
Matching and non-elective employer contributions by employer			$ 9,000,000	10,000,000	11,000,000
Class B Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional shares to authorize (in shares) | shares			0
EP Energy Corporation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Authorized amount of shares to grant (in shares) | shares			24,832,525
Shares remaining for issuance | shares			17,150,841
Compensation expense recorded			$ 22,000,000	21,000,000	22,000,000
Income tax benefit expense			9,000,000	$ 6,000,000	6,000,000
EPE Holdings II
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recorded	$ 0
Additional stock issued (in shares) | shares	70,000
Compensation expense that will occur until those events that give rise to payout become probable			$ 0
Class A Matching Grants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants as a percentage of the Class A units purchased			50.00%
Fair value			$ 12,000,000
MIPs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected Term in Years		5 years
Expected Volatility		73.00%
Unrecognized compensation cost			$ 14,000,000
Vesting period for cash based incentive			5 years
Percentage of vested awards forfeitable in the event of certain termination events			25.00%
Issuance cost			$ 0
Risk-Free Interest Rate		0.77%
Fair value on the grant date		$ 74,000,000
Unrecognized compensation cost to be recognized on an accelerated basis for each tranche of the award			$ 1,000,000
Requisite service period			5 years
Unrecognized compensation cost to be recognized upon a specified capital transaction			$ 13,000,000
MIPs | Class B Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Conversion basis			1
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit expense					$ 2,000,000
Unrecognized compensation cost			$ 32,000,000
Recognition period of fair value as compensation cost			2 years
Restricted Stock | EP Energy Corporation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)			3 years
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected Term in Years					7 years
Expected Volatility					40.00%
Vesting period (in years)			5 years
Recognition period of fair value as compensation cost			2 years
Contratual term, in years			10 years
Number of tranches | tranche			3
Unrecognized compensation cost			$ 1,000,000
Weighted average of each assumption based on grants (in dollars per share) | $ / shares					$ 9.03
Risk-Free Interest Rate					2.30%
Stock options | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recorded					$ 1,000,000

Long-Term Incentive Compensat46

Long-Term Incentive Compensation / 401(k) Retirement Plan - Restricted Stock (Details) - Restricted Stock	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Number of Shares
Nonvested at beginning of period (shares) | shares	3,987,654
Granted (shares) | shares	4,676,322
Vested (shares) | shares	(1,255,394)
Forfeited (shares) | shares	(1,081,794)
Nonvested at end of period (shares) | shares	6,326,788
Weighted Average Grant Date Fair Value per Share
Non-vested at beginning of period (dollars per share) | $ / shares	$ 10.98
Granted (dollars per share) | $ / shares	6.08
Vested (dollars per share) | $ / shares	11.76
Forfeited (dollars per share) | $ / shares	8.17
Non-vested at end of period (dollars per share) | $ / shares	$ 7.69

Long-Term Incentive Compensat47

Long-Term Incentive Compensation / 401(k) Retirement Plan - Stock Options (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Weighted-Average Exercise Price
Vested (in dollars per share) | $ / shares	$ 19.82
Stock options
Number of Options
Outstanding at the beginning of the period (in shares) | shares	214,337
Granted (in shares) | shares	0
Vested (in shares) | shares	(1,514)
Forfeited or canceled (in shares) | shares	(4,933)
Outstanding at the end of the period (in shares) | shares	207,890
Weighted-Average Exercise Price
Outstanding at the beginning of the period (in dollars per share) | $ / shares	$ 19.82
Granted (in dollars per share) | $ / shares	19.82
Forfeited or canceled (in dollars per share) | $ / shares	19.82
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 19.82
Weighted Average Remaining Contractual Term	7 years 3 months
Aggregate intrinsic value of options | $	$ 0

Long-Term Incentive Compensat48

Long-Term Incentive Compensation / 401(k) Retirement Plan - Fair Value Assumptions (Details) - Stock options	12 Months Ended
	Dec. 31, 2014
Assumptions used for estimating weighted-average grant-date fair value of stock options
Expected Term in Years	7 years
Expected Volatility	40.00%
Expected Dividends	0.00%
Risk-Free Interest Rate	2.30%

Long-Term Incentive Compensat49

Long-Term Incentive Compensation / 401(k) Retirement Plan Performance Unit Awards (Details)	12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Weighted Average Grant Date Fair Value per Share
Target Performance Dollar Of Actual Payout | $	$ 100
Performance Dollar Actual Payout Minimum | $	0
Performance Dollar Of Actual Payout Maximum | $	$ 200
Performance Shares [Member]
Number of Shares
Nonvested at beginning of period (shares) | shares	0
Granted | shares	83,150
Cancelled/Forfeited | shares	(4,250)
Nonvested at end of period (shares) | shares	78,900
Weighted Average Grant Date Fair Value per Share
Non-vested at beginning of period (dollars per share) | $ / shares	$ 0
Granted | $ / shares	102.41
Forfeited (dollars per share) | $ / shares	68.32
Non-vested at end of period (dollars per share) | $ / shares	$ 97.77
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost | $	$ 3,000,000
Recognition period of fair value as compensation cost	1 year 3 months 18 days
Grant day Fair Value | $	$ 8,000,000
Expected Term in Years	3 years
Expected Volatility	85.90%
Expected Dividend	0.00%
Risk-Free Interest Rate	1.01%
Weighted Average Number Diluted Shares Outstanding Adjustment | shares	1,900,000

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jan. 24, 2017
Related party transactions
Capital expenditures	$ 83,000		$ 533,000	$ 1,433,000	$ 2,033,000
Transaction fee paid	$ 6,250
Affiliate Supply Agreement
Related party transactions
Capital expenditures			$ 6,000	$ 67,000	$ 112,000
Subsequent Event [Member]
Related party transactions
CapitalFromInvestor		$ 450,000
PercentOfCapitalFromInvestor		60.00%
Noncontrolling Interest in Joint Ventures		50.00%
Return on Invested Capital						12.00%
PercentOfWorkingInterest		15.00%