EP Energy (EPEGQ) 10-K 2 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 16, 2018	Jun. 30, 2017
Entity Registrant Name	EP Energy Corp
Entity Central Index Key	1,584,952
Document Type	10-K
Document Period End Date	Dec. 31, 2017
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	Accelerated Filer
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Public Float			$ 146,818,078
Class A Common Stock
Entity Common Stock, Shares Outstanding		251,349,018
Class B Common Stock
Entity Common Stock, Shares Outstanding		296,431

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues
Oil	$ 812	$ 653	$ 981
Natural gas	110	122	200
NGLs	103	65	60
Financial derivatives	41	(73)	667
Total operating revenues	1,066	767	1,908
Operating expenses
Oil and natural gas purchases	2	10	31
Transportation costs	115	109	116
Lease operating expense	163	159	186
General and administrative	81	146	148
Depreciation, depletion and amortization	487	462	983
Gain on sale of assets	0	(78)	0
Impairment charges	2	2	4,299
Exploration and other expense	12	5	20
Taxes, other than income taxes	65	50	80
Total operating expenses	927	865	5,863
Operating income (loss)	139	(98)	(3,955)
(Loss) gain on extinguishment of debt	(16)	384	(41)
Interest expense	(326)	(312)	(330)
Loss before income taxes	(203)	(26)	(4,326)
Income tax benefit (expense)	9	(1)	578
Net loss	$ (194)	$ (27)	$ (3,748)
Basic and diluted net income (loss) per common share
Net loss (in dollars per share)	$ (0.79)	$ (0.11)	$ (15.37)
Basic and diluted weighted average common shares outstanding (in shares)	246	245	244

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 27	$ 20
Restricted cash	18	0
Accounts receivable
Customer, net of allowance of less than $1 in 2017 and 2016	158	133
Other, net of allowance of $1 in 2017 and 2016	13	16
Income tax receivable	9	0
Materials and supplies	16	16
Derivative instruments	18	58
Assets held for sale	172	0
Prepaid assets	35	5
Total current assets	466	248
Property, plant and equipment, at cost
Oil and natural gas properties	7,532	7,194
Other property, plant and equipment	69	85
Total property, plant and equipment, at cost	7,601	7,279
Less accumulated depreciation, depletion and amortization	3,179	2,781
Total property, plant and equipment, net	4,422	4,498
Other assets
Derivative instruments	4	4
Unamortized debt issue costs on revolving credit facility	6	10
Other	2	1
Total other assets	12	15
Total assets	4,900	4,761
Accounts payable
Trade	88	63
Other	158	113
Derivative instruments	17	4
Accrued interest	62	43
Liabilities related to assets held for sale	2	0
Short-term debt, net of debt issue costs	21	0
Other accrued liabilities	100	98
Total current liabilities	448	321
Long-term debt, net of debt issue costs	4,022	3,789
Other long-term liabilities
Derivative instruments	0	1
Asset retirement obligations	33	40
Other	5	4
Total non-current liabilities	4,060	3,834
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); 0.7 million shares at December 31, 2017 and 0.5 million shares at December 31, 2016	(3)	(3)
Additional paid-in capital	3,526	3,546
Accumulated deficit	(3,134)	(2,939)
Total stockholders’ equity	392	606
Total liabilities and equity	4,900	4,761
Class A Stock
Stockholders’ equity
Common stock	3	2
Class B Stock
Stockholders’ equity
Common stock	$ 0	$ 0

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Accounts receivable
Allowance for customer accounts receivable	$ 1	$ 1
Allowance for other accounts receivable	$ 1	$ 1
Preferred stock
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
Treasury stock
Treasury stock, shares held	700,000	500,000
Class A Stock
Common stock
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	550,000,000	550,000,000
Common stock, shares issued	252,000,000	251,000,000
Common stock, shares outstanding	252,000,000	251,000,000
Class B Stock
Common stock
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	300,000	800,000
Common stock, shares issued	300,000	800,000
Common stock, shares outstanding	300,000	800,000

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities
Net loss	$ (194)	$ (27)	$ (3,748)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	487	462	983
Gain on sale of assets	0	(78)	0
Deferred income tax benefit	0	0	(578)
Impairment charges	2	2	4,299
Loss (gain) on extinguishment of debt	16	(384)	41
Share-based compensation expense	(19)	17	19
Non-cash portion of exploration expense	5	2	14
Amortization of debt issuance costs	14	16	18
Other non-cash income items	0	1	0
Asset and liability changes
Accounts receivable	(22)	71	55
Accounts payable	55	(22)	(70)
Derivative instruments	52	714	277
Accrued interest	19	(4)	(6)
Other asset changes	(16)	8	22
Other liability changes	(24)	6	1
Net cash provided by operating activities	375	784	1,327
Cash flows from investing activities
Cash paid for capital expenditures	(541)	(533)	(1,433)
Proceeds from the sale of assets	0	389	1
Cash paid for acquisitions	(29)	0	(111)
Deposit paid in advance of acquisition	(25)	0	0
Deposit received in advance of divestiture	18	0	0
Net cash used in investing activities	(577)	(144)	(1,543)
Cash flows from financing activities
Proceeds from issuance of long-term debt	1,930	1,195	2,067
Repayments and repurchases of long-term debt	(1,679)	(1,804)	(1,826)
Debt issue costs	(21)	(34)	(20)
Other	(3)	(3)	(1)
Net cash provided by (used in) financing activities	227	(646)	220
Change in cash, cash equivalents and restricted cash	25	(6)	4
Cash, cash equivalents and restricted cash - beginning of period	20	26	22
Cash, cash equivalents and restricted cash - end of period	45	20	26
Supplemental cash flow information
Interest paid, net of amounts capitalized	291	293	312
Income tax payments (refunds)	$ 1	$ (2)	$ (22)

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - USD ($) shares in Millions, $ in Millions	Total	Class A Stock	Class B Stock	Common StockClass A Stock	Common StockClass B Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)
Balance at Dec. 31, 2014	$ 4,348			$ 2	$ 0	$ 0	$ 3,510	$ 836
Balance (in shares) at Dec. 31, 2014				245	0.8
Increase (Decrease) in Stockholders' Equity
Share-based compensation	19			$ 0	$ 0		19
Share-based compensation (in shares)				3	0
Net loss	(3,748)						0	(3,748)
Balance at Dec. 31, 2015	619			$ 2	$ 0	0	3,529	(2,912)
Balance (in shares) at Dec. 31, 2015				248	0.8
Increase (Decrease) in Stockholders' Equity
Share-based compensation	14			$ 0	$ 0	(3)	17
Share-based compensation (in shares)				3	0
Net loss	(27)						0
Balance at Dec. 31, 2016	606			$ 2	$ 0	(3)	3,546	(2,939)
Balance (in shares) at Dec. 31, 2016		251	0.8	251	0.8
Increase (Decrease) in Stockholders' Equity
Cumulative effect of accounting change	0						1	(1)
Balance at Dec. 31, 2016	606			$ 2	$ 0	(3)	3,547	(2,940)
Increase (Decrease) in Stockholders' Equity
Share-based compensation	(20)			$ 1	$ 0		(21)
Share-based compensation (in shares)				1	(0.5)
Net loss	(194)						0	(194)
Balance at Dec. 31, 2017	$ 392			$ 3	$ 0	$ (3)	$ 3,526	$ (3,134)
Balance (in shares) at Dec. 31, 2017		252	0.3	252	0.3

Basis of Presentation and Signi

Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
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. 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. Modified or full retrospective application of this standard is required upon adoption. We do not anticipate our adoption of this standard on January 1, 2018, utilizing the modified retrospective approach, will have a material impact on our financial statements, disclosure requirements, accounting policies, business processes and/or related controls. 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, adjustments for time, 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 between the wellhead and its intended sale location are generally 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, 2017 , 2016 and 2015 , 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 and Restricted Cash We consider short-term investments with an original maturity of less than three months to be cash equivalents. As of December 31, 2017 , we had $18 million in restricted cash reflecting a deposit received in advance of the divestiture of certain assets. As of December 31, 2016 , we had no restricted cash. As a result of early adopting ASU No. 2016-15, Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments and ASU No. 2016-18, Statement of Cash Flows - Restricted Cash as of December 31, 2017 our consolidated statement of cash flows for all historical periods reflect restricted cash combined with cash and cash equivalents. We did not have any other material impact of early adopting these ASUs. 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 acquisition 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 statements. 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. As a result of adopting ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, as of January 1, 2017, we recorded a cumulative adjustment of approximately $1 million to the opening balance of retained earnings related to our election to begin accounting for forfeitures in compensation cost when they occur rather than estimating them over the service period. 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. 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. 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. Changes in tax laws are recorded in the period they are enacted. 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, 2017
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures Acquisitions . In 2017, we acquired proved and unproved properties for approximately $29 million located in the Permian basin. In December 2017, we entered into an agreement to acquire certain producing properties and undeveloped acreage in Eagle Ford for approximately $245 million , subject to customary closing adjustments. As of December 31, 2017, we deposited $25 million related to the acquisition, which closed on January 31, 2018. In 2015, we acquired approximately 12,000 net acres adjacent to our existing Eagle Ford Shale acreage for approximately $111 million . Divestitures. In December 2017, we entered into an agreement to sell certain assets in the Altamont area for approximately $180 million , subject to customary closing adjustments. As of December 31, 2017, we received a deposit of $18 million related to the divestiture, which closed in February 2018. We classified the assets and liabilities associated with the assets to be sold, including $172 million in property, plant and equipment and $2 million in asset retirement obligations, as held for sale on our consolidated balance sheet as of December 31, 2017. In 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). We recorded a gain on the sale of the Haynesville/Bossier assets of approximately $79 million in 2016.

Impairment Charges

Impairment Charges	12 Months Ended
	Dec. 31, 2017
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 Permian basin based on reduced activity and not having a definitive agreement at that time to extend our Permian lease. In 2016, we amended our Consolidated Drilling and Development Unit Agreement with the University of Texas Land System in the Permian basin to provide flexibility to extend the time frame to hold our acreage by nearly four years to the end of 2021 (with a 10 -year option beyond 2021). The agreement also increased 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 2017. 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, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Pretax Income (Loss) and Income Tax (Expense) Benefit. The tables below show the pretax loss and the components of income tax benefit (expense) for the following periods: Year Ended December 31, 2017 2016 2015 (in millions) Pretax Loss $ (203 ) $ (26 ) $ (4,326 ) Components of Income Tax Benefit (Expense) Current Federal $ 9 $ — $ — State — (1 ) — 9 (1 ) — Deferred Federal $ — $ — $ 543 State — — 35 Total income tax benefit (expense) $ 9 $ (1 ) $ 578 Effective Tax Rate Reconciliation. Our income taxes included in net income differ from the amount computed by applying the statutory federal income tax rate of 35% for the following reasons: Year Ended December 31, 2017 2016 2015 (in millions) Income taxes at the statutory federal rate of 35% $ 71 $ 9 $ 1,514 Increase (decrease) State income taxes, net of federal income tax effect (1 ) 1 41 Change in enacted tax rate (409 ) — — Change in valuation allowance 341 (9 ) (975 ) Other 7 (2 ) (2 ) Income tax benefit (expense) $ 9 $ (1 ) $ 578 The effective tax rate for the year ended December 31, 2017 was 4.5% . Our effective tax rate differed from the statutory rate of 35% primarily due to recording a current income tax benefit and related receivable for the recovery of previously paid alternative minimum taxes based on a change in our tax depreciation elections, the change in our valuation allowance on our net deferred tax assets, and non-deductible compensation expenses. Changes in our deferred taxes from year to year are offset by changes to our related valuation allowance and thus have the effect of eliminating the impact of federal taxes on our income. In December 2017, Congress passed into law the Tax Cuts and Jobs Act (the Act) which lowered the federal corporate tax rate from 35% to 21% effective January 1, 2018. The passage of the Act had no effect on our financial statements since the $409 million provisional effect of adjusting the tax rate on all our deferred tax balances was offset by a corresponding adjustment to the valuation allowance on our net deferred assets. While there was no overall impact on our financial statements from the Act, we are still analyzing certain aspects of the Act which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. The effective tax rate for the year ended December 31, 2016 was (1.9)% . Our effective tax rate differed from 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 net deferred tax assets, which offset a deferred income tax benefit by $9 million . 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. 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 $ 50 $ 249 Net operating loss carryovers 554 692 U.S. tax credit carryovers — 10 Employee benefits 2 6 Financial derivatives 8 — Legal and other reserves 9 6 Asset retirement obligations 8 15 Transaction costs 13 19 Total deferred tax assets 644 997 Valuation allowance (644 ) (985 ) Net deferred tax assets — 12 Deferred tax liabilities Financial derivatives — 12 Total deferred tax liabilities — 12 Net deferred tax liabilities $ — $ — Unrecognized Tax Benefits. As of December 31, 2017 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 2017 , 2016 or 2015, nor do we have any accrued interest and penalties associated with income taxes in our consolidated balance sheets as of December 31, 2017 and December 31, 2016 . The Company's and certain subsidiaries' income tax years after 2013 remain open and subject to examination by both federal and state tax authorities. During the second quarter of 2017, the Internal Revenue Service concluded an examination of our subsidiary's 2013 U.S. tax return. 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, 2017 (in millions): Expiration Period 2031 - 2037 U.S. federal net operating loss carryover $ 2,522 2026 - 2037 State net operating loss carryover $ 411 Utilization of $87 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 capital loss carryovers of $23 million , which expire in 2018 unless we are unable to generate sufficient capital gains on the sale of assets by that time. There are no alternative minimum tax credits at December 31, 2017. Valuation Allowances. As of December 31, 2017 and 2016 , we have a valuation allowance on our deferred tax assets of $644 million and $985 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, 2017
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 net income per common share is antidilutive. Potentially dilutive securities consist of our stock options, restricted stock, performance share unit awards and performance unit awards. For the years ended December 31, 2017, 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.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
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 underlying 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, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value (in millions) Short-term debt $ 21 $ 19 $ — $ — Long-term debt $ 4,072 $ 3,248 $ 3,856 $ 3,637 Derivative instruments $ 5 $ 5 $ 57 $ 57 For the years ended December 31, 2017 and 2016 , 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, 2017 , we had derivatives contracts in the form of fixed price swaps and three-way collars on 14 MMBbls of oil in 2018. In addition to our oil derivatives, we had derivative contracts in the form of fixed price swaps and options on 33 TBtu of natural gas ( 26 TBtu in 2018 and 7 TBtu in 2019) and 92 MMGal of ethane and propane fixed price swaps in 2018. As of December 31, 2016 , we had derivative contracts for 16 MMBbls of oil, 36 TBtu on natural gas and 108 MMGal on ethane. In addition to the contracts above, we have derivative contracts related to locational basis differences on our oil and natural gas production. None of our derivative contracts are designated as accounting hedges. As of December 31, 2017 and 2016 , 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, 2017 and 2016 . 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, 2017 Derivative instruments $ 33 $ (11 ) $ 18 $ 4 $ (28 ) $ 11 $ (17 ) $ — December 31, 2016 Derivative instruments $ 79 $ (17 ) $ 58 $ 4 $ (22 ) $ 17 $ (4 ) $ (1 ) For the years ended December 31, 2017 , 2016 and 2015 , we recorded a derivative gain of $41 million , derivative loss of $73 million and derivative gain of $667 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. 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, 2017 represent financial instruments from seven counterparties, all of which are lenders associated with our $1.4 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 $1.4 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, 2017
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, 2017 and 2016 , we had approximately $4.4 billion and $4.5 billion , respectively, 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: 2017 2016 (in millions) Proved Eagle Ford $ 3,219 $ 3,001 Permian 2,705 2,415 Altamont 1,542 1,624 Total Proved 7,466 7,040 Unproved Permian 66 94 Altamont — 60 Total Unproved 66 154 Less accumulated depletion 3,137 2,731 Net capitalized costs for oil and natural gas properties $ 4,395 $ 4,463 During 2017 , we transferred approximately $63 million from unproved properties to proved properties. During 2017 , 2016 and 2015 , we recorded $5 million , $2 million and $9 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, 2017 or December 31, 2016 . 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 changing 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: 2017 2016 (in millions) Net asset retirement liability at January 1 $ 41 $ 38 Liabilities settled (2 ) (1 ) Accretion expense 3 3 Changes in estimate (5 ) 1 Liability reclassified as held for sale (2 ) — Net asset retirement liability at December 31 $ 35 $ 41 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 until production begins using a weighted average interest rate on our outstanding borrowings. Capitalized interest for the years ended December 31, 2017 , 2016 and 2015 , was approximately $4 million , $4 million and $14 million , respectively.

Long Term Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long Term Debt	Long Term Debt Listed below are our debt obligations as of the periods presented: Interest Rate December 31, 2017 December 31, 2016 (in millions) RBL credit facility - due May 24, 2019 (1) Variable $ 595 $ 370 Senior secured term loans: Due May 24, 2018 (2) Variable 21 21 Due April 30, 2019 (3) Variable 8 8 Due June 30, 2021 (4) Variable — 580 Senior secured notes: Due November 29, 2024 8.00 % 500 500 Due February 15, 2025 8.00 % 1,000 — Senior unsecured notes: Due May 1, 2020 9.375 % 1,200 1,576 Due September 1, 2022 7.75 % 250 250 Due June 15, 2023 6.375 % 519 551 Total debt 4,093 3,856 Less short-term debt, net of debt issue costs of less than $1 million (21 ) — Total long-term debt 4,072 3,856 Less non-current portion of unamortized debt issue costs (50 ) (67 ) Total long-term debt, net $ 4,022 $ 3,789 (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, 2017 and 2016 , the effective interest rate of the term loan was 4.23% and 3.50% , respectively. (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, 2017 and 2016 , the effective interest rate for the term loan was 4.98% and 4.50% , respectively. (4) As of December 31, 2016, the effective interest rate for the term loan was 9.75% . 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 (i) repay in full our senior secured term loans due 2021, (ii) repurchase $250 million in aggregate principal amount of our 9.375% senior unsecured notes due 2020 and (iii) repay $111 million of the amounts outstanding under our RBL Facility. As a result of the issuance, our RBL Facility borrowing base was also reduced from $1.5 billion to $1.44 billion . In conjunction with these transactions, we recorded a loss on extinguishment of debt of approximately $53 million (including $30 million in non-cash expense related to eliminating associated unamortized debt issue costs and debt discounts). In 2017 and 2016, we also repurchased additional debt as follows: Year ended December 31, 2017 2016 (in millions) Debt repurchased - face value (1) 157 812 Cash paid 118 407 Gain on extinguishment of debt (2)(3) 37 393 (1) In 2017, repurchases were associated with 2020 and 2023 senior unsecured notes. In 2016, repurchases were associated with certain senior unsecured notes and term loans. (2) Includes $2 million and $12 million for the years ended December 31, 2017 and 2016, respectively, of non-cash expense related to eliminating associated unamortized debt issue costs. (3) For the years ended December 31, 2017 and 2016, we also recorded a loss on the extinguishment of debt of approximately $1 million and $9 million , respectively, primarily related to eliminating a portion of the unamortized debt issue costs due to the reduction of our RBL Facility borrowing base in May 2016. In January 2018, we completed an exchange of $954 million , $54 million and $139 million of the outstanding amount of our senior unsecured notes maturing in May 2020, September 2022 and June 2023, respectively, for new 9.375% senior secured notes maturing in 2024 with an aggregate principal amount of approximately $1,092 million . Unamortized Debt Issue Costs. As of December 31, 2017 and 2016 , we had total unamortized debt issue costs of $56 million and $77 million . Of these amounts $6 million and $10 million , respectively, are associated with our RBL Facility and $50 million and $67 million , respectively, are associated with our senior secured term loans and senior notes and reflected net in our debt balances. During 2017 , 2016 and 2015 , we amortized $14 million , $16 million and $18 million , respectively, of deferred financing costs into interest expense. Reserve-based Loan Facility. We have a $1.4 billion RBL 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, 2017 , we had $786 million of capacity remaining with approximately $19 million of LC's issued and approximately $595 million outstanding under the facility. Listed below is a further description of our credit facility as of December 31, 2017 : Credit Facility Maturity Interest Commitment fees $1.4 billion RBL May 24, 2019 LIBOR + 2.75% (1) 2.5% for LCs 0.375% commitment fee on unused capacity (1) Based on our December 31, 2017 borrowing level. Amounts outstanding under the $1.4 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 October 2017, our RBL Facility borrowing base was affirmed at $1.4 billion . In January 2018, as a result of the debt exchange, the borrowing base was reduced from $1.4 billion to $1.36 billion . Our next redetermination date is in April 2018. Downward revisions of our oil and natural gas reserve volume and value due to declines in commodity prices, the impact of lower estimated capital spending in response to lower prices, performance revisions, or sales of assets or the incurrence of certain types of additional debt, among other items, could cause a reduction of our borrowing base in the future, and these reductions could be significant. Restrictive Provisions/Covenants. The availability of borrowings under our credit agreement and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions. In conjunction with the redetermination of our RBL Facility in April 2017, we extended our first lien debt to EBITDAX covenant through March 31, 2019 and the ratio was reduced to 3.0 to 1.0 . As of December 31, 2017 , we were in compliance with our debt covenants, with a ratio of first lien debt to EBITDAX of 0.86 x. In April 2019, this financial covenant will revert to a requirement that our total net debt to EBITDAX ratio not exceed 4.5 to 1.0 . As of December 31, 2017, our ratio of total net debt to EBITDAX was 5.88 x. We are currently working to renew and extend the maturity of the facility as well as the required covenants thereunder. Under our debt agreements, we are limited in non-RBL Facility debt repurchases. As of December 31, 2017, the non-RBL Facility debt repurchases limit was approximately $885 million . On January 3, 2018 we entered into a new debt agreement with the new 2024 senior secured note holders that reduced the non-RBL Facility debt repurchases limit to $225 million subject to certain customary adjustments. This limitation does not apply to debt repurchases completed using proceeds from dispositions. Certain other covenants and restrictions, among other things, also limit or place certain conditions on our ability to incur or guarantee additional indebtedness; make any restricted payments or pay any dividends on equity interests or redeem, repurchase or retire 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, 2017
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, 2017 , we had approximately $5 million accrued for all outstanding legal matters. FairfieldNodal v. EP Energy E&P Company , L.P. On March 3, 2014, Fairfield filed suit against one of our subsidiaries in the 157th District Court of Harris County, Texas, claiming we were contractually obligated to pay a transfer fee of approximately $21 million for seismic licensing, triggered by a change in control with the Sponsors' acquisition of our predecessor entity in 2012. Prior to the change in control, we had unilaterally terminated the seismic licensing agreements, and we returned the applicable seismic data. Fairfield also claimed EP Energy did not properly maintain the confidentiality of the seismic data and interpretations made from it. In April 2015, the district court granted summary judgment to EP Energy, and Fairfield then appealed. On July 6, 2017, an intermediate court of appeals in Texas reversed the judgment related to the transfer fee and denied rehearing on October 5, 2017. We filed a petition for review in the Texas Supreme Court in December 2017. At this time, we are unable to estimate the amount or range of possible loss, if any, on this matter. 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, 2017 , we had approximately $5 million accrued related to these indemnifications and other matters. Non-Income Tax Matters. We are under a number of examinations by taxing authorities related to non-income tax matters. As of December 31, 2017, we had approximately $42 million accrued (in other accrued liabilities in our consolidated balance sheet) in connection with ongoing examinations related to certain prior period non-income tax matters. 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 Environmental Protection Agency (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. 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. For additional details on certain environmental matters related to climate change, air quality and other emissions, hydraulic fracturing regulations and waste handling, refer to Part I, Item 1A, "Risk Factors". While our reserves for environmental matters are currently not material, there are still uncertainties related to the ultimate costs we may incur in the future in order to comply with 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. Based upon our evaluation and experience to date, however, we believe our accruals for these matters are adequate. It is possible that new information or future developments could result in substantial additional costs and liabilities which could require us to reassess our potential exposure related to these matters and to adjust our accruals accordingly, and these adjustments could be material. 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, 2017 , were as follows: Year Ending December 31, Operating Leases (in millions) 2018 $ 5 2019 5 2020 5 2021 5 Thereafter 22 Total $ 42 Rental expense for the years ended December 31, 2017 , 2016 and 2015 was $6 million , $13 million and $12 million , respectively. Other Commercial Commitments At December 31, 2017 , we have various commercial commitments totaling $336 million primarily related to commitments and contracts associated with volume and transportation, completion activities and seismic activities. Our annual obligations under these arrangements are $103 million in 2018 , $76 million in 2019 , $58 million in 2020 , $52 million in 2021 , and $47 million thereafter.

Long-Term Incentive Compensatio

Long-Term Incentive Compensation / 401(k) Retirement Plan	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Long-Term Incentive Compensation / Retirement 401(k) Plan	Long-Term Incentive Compensation / 401(k) Retirement Plan Overview. Under our current stock-based compensation plans (the EP Energy Corporation 2014 Omnibus Incentive Plan and 2017 EP Energy Corporation Employment Inducement 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 36,832,525 shares of our common stock for awards under these plans, with 28,695,370 shares remaining available for issuance as of December 31, 2017 . In addition, in conjunction with the acquisition of certain of our subsidiaries by Apollo and other private equity investors in 2012 (the Acquisition), we issued Class B shares (formerly management incentive units intended to constitute profits interests) which become payable should certain liquidity events occur. No additional Class B shares are available for issuance. We record stock-based compensation expense as general and administrative expense over the requisite service period. For the years ended December 31, 2017 , 2016 and 2015 , we recognized pre-tax compensation expense related to our LTI programs, net of the impact of forfeitures of approximately $(19) million , $22 million and $21 million , respectively, and recorded an associated income tax benefit of $5 million , $9 million and $6 million for the years 2017 , 2016 and 2015 , respectively. As a result of a change in our management and certain other staff reductions and departures during 2017, we recorded a reduction of compensation expense of approximately $33 million related to the reversal of previously recognized compensation expense to reflect the forfeitures of these individual's LTI awards. 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, 2017 is presented below: Number of Shares Weighted Average Grant Date Fair Value per Share Non-vested at December 31, 2016 6,326,788 $ 7.69 Granted 5,895,639 $ 3.92 Vested (2,355,507 ) $ 8.42 Forfeited (4,582,934 ) $ 5.86 Non-vested at December 31, 2017 5,283,986 $ 4.63 The total unrecognized compensation cost related to these arrangements at December 31, 2017 was approximately $17 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 subsequent to 2014. Stock options granted have contractual terms of 10 years and 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. As of December 31, 2017 we had approximately 101,844 outstanding options with a weighted average exercise price of $19.82 per share and a weighted average remaining contractual term of 6.25 years . There were no options exercised during the year, and options outstanding had no intrinsic value as of December 31, 2017. Total compensation cost related to non-vested option awards not yet recognized at December 31, 2017 was less than $1 million , which is expected to be recognized over a weighted average period of 1 year . Class B Shares . At the time of the Acquisition in 2012, certain employees were awarded management incentive units (MIPs) intended to constitute profits interests. In 2013, these MIPs converted into Class B shares on a one-for-one basis. Any payout on Class B shares occurs 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. As of December 31, 2017 , we had unrecognized compensation expense of $3 million , which will only be recognized should the certain liquidity events described above occur and the right to such amounts become nonforfeitable. Performance Share Units. In November 2017, we granted 912,000 performance share units (PSUs) to certain members of EP Energy's management team. The PSUs represent a contractual right to receive one share of EP Energy’s common stock if certain conditions are met, and the number of PSUs actually earned, if any, will be based upon achievement of specified stock price goals over a four -year performance period (grant date thru October 2021). The PSUs vest over a six -year period; 80% ratably over the first four years and the final 20% on the sixth year with settlement dates over three years ; 20% in the fourth year, 20% in the fifth year and 60% in the sixth year. The PSUs will settle in shares of common stock if certain stock price hurdles are met, but such shares will remain subject to transfer restrictions through October 2024 unless certain conditions are satisfied. For accounting purposes, the PSUs are treated as an equity award with the expense recognized on an accelerated basis over the life of the award. The grant date fair value of these awards was approximately $12 million as determined by a Monte Carlo simulation utilizing multiple input variables that determine the probability of satisfying the market condition stipulated in the award. We estimated an expected volatility of approximately 86.77% based on life-to-date volatility of EP Energy’s common stock, which has been publicly traded for an amount of time less than the contractual term of the award. We estimated a risk free rate of 2.10% based on the yield, as of the valuation date, on zero coupon U.S. Treasury STRIPS (Separate Trading of Registered Interest and Principal of Securities) that have a term equal to the length of the period from the valuation date to the final vest date. The expected term of the award is 6 years . Total compensation cost related to our non-vested performance share units not yet recognized at December 31, 2017 was $11 million , which is expected to be recognized over a weighted average period of 3 years. Performance Unit Awards. We granted 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. Performance units awarded in 2016 are subject to three separate performance periods starting on January 1, 2016 and ending on December 31, 2016, 2017 and 2018 and vest in three separate tranches over the requisite service period beginning on the grant date. Performance units awarded in 2017 are subject to one performance period starting on January 1, 2017 and ending on December 31, 2019 and "cliff" vest three years from 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, 2017 and been settled in stock, no shares would have been issued. For accounting purposes, the performance unit awards are treated as a liability award with the expense recognized on an accelerated basis over the life of the award and fair value remeasured at each reporting period. As of December 31, 2017 and 2016, we had approximately 18,317 and 78,900 awards outstanding, respectively. The fair value of these awards measured as of December 31, 2017 was less than $1 million for both the 2017 and 2016 awards determined using a Monte Carlo simulation. The following table summarizes the significant assumptions used to calculate the fair value of the performance unit awards as of December 31, 2017, which were granted in 2016 and 2017: 2016 Awards 2017 Awards Expected Term in Years 3.0 3.0 Expected Volatility (1) 64.93 % 100.03 % Expected Dividends — — Risk-Free Interest Rate (2) 1.76 % 1.89 % (1) Expected volatility assumption for performance unit awards is based on the historical stock price volatility equal to the remaining length of the performance period as of the valuation date. (2) The risk-free rate is based upon the yield on U.S. Treasury STRIPS over the expected term as of the grant date. Total compensation cost related to our non-vested performance unit awards not yet recognized at December 31, 2017 was less than $1 million , which is expected to be recognized over a weighted average period of 2 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 2017 , 2016 and 2015 , we contributed $7 million , $9 million and $10 million , respectively, of matching and non-elective employer contributions.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Affiliate Payments. In November 2017, in connection with the release of members of the leadership team of a portfolio company of funds managed by Apollo Management, LLC (Apollo) affiliates to join the Company, the Company reimbursed that portfolio company approximately $4 million for money contributed to it by fund investors (other than Apollo). Joint Venture. In January 2017, we entered into a drilling joint venture with Wolfcamp Drillco Operating L.P. (the Investor), which is managed and controlled by an affiliate of Apollo Global Management LLC, to fund future oil and natural gas development in the Permian basin. Subsequently, Access Industries acquired an indirect minority ownership interest in the Investor, and therefore is also indirectly responsible for funding a portion of the Investor’s capital commitment. The Investor may fund approximately $450 million over the entire program ( 150 wells in two separate 75 well tranches), or approximately 60 percent of the estimated drilling, completion and equipping costs of the wells, 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 are the operator of the joint venture assets. The first wells under the joint venture began producing in January 2017, and for the year ended December 31, 2017 , we recovered approximately $214 million related to the capital costs of the joint venture wells from the Investor and have drilled and completed 58 wells. Affiliate Supply Agreement. For the years ended December 31, 2017 , 2016 and 2015 , we recorded approximately $1 million , $6 million and $67 million , respectively, in capital expenditures for amounts expended under supply agreements entered into with an affiliate of Apollo to provide certain fracturing materials used in our Eagle Ford drilling operations.

Basis of Presentation and Sig18

Basis of Presentation and Significant Accounting Policies (Polices)	12 Months Ended
	Dec. 31, 2017
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	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	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. Modified or full retrospective application of this standard is required upon adoption. We do not anticipate our adoption of this standard on January 1, 2018, utilizing the modified retrospective approach, will have a material impact on our financial statements, disclosure requirements, accounting policies, business processes and/or related controls.
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, adjustments for time, 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 between the wellhead and its intended sale location are generally 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, 2017 , 2016 and 2015 , 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.
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 acquisition 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 statements.
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. As a result of adopting ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, as of January 1, 2017, we recorded a cumulative adjustment of approximately $1 million to the opening balance of retained earnings related to our election to begin accounting for forfeitures in compensation cost when they occur rather than estimating them over the service period. 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. 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. 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.
Income Tax	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. Changes in tax laws are recorded in the period they are enacted. 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.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Pretax loss and the components of income tax benefit (expense)	The tables below show the pretax loss and the components of income tax benefit (expense) for the following periods: Year Ended December 31, 2017 2016 2015 (in millions) Pretax Loss $ (203 ) $ (26 ) $ (4,326 ) Components of Income Tax Benefit (Expense) Current Federal $ 9 $ — $ — State — (1 ) — 9 (1 ) — Deferred Federal $ — $ — $ 543 State — — 35 Total income tax benefit (expense) $ 9 $ (1 ) $ 578
Effective tax rate reconciliation	Our income taxes included in net income differ from the amount computed by applying the statutory federal income tax rate of 35% for the following reasons: Year Ended December 31, 2017 2016 2015 (in millions) Income taxes at the statutory federal rate of 35% $ 71 $ 9 $ 1,514 Increase (decrease) State income taxes, net of federal income tax effect (1 ) 1 41 Change in enacted tax rate (409 ) — — Change in valuation allowance 341 (9 ) (975 ) Other 7 (2 ) (2 ) Income tax benefit (expense) $ 9 $ (1 ) $ 578
Components 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 $ 50 $ 249 Net operating loss carryovers 554 692 U.S. tax credit carryovers — 10 Employee benefits 2 6 Financial derivatives 8 — Legal and other reserves 9 6 Asset retirement obligations 8 15 Transaction costs 13 19 Total deferred tax assets 644 997 Valuation allowance (644 ) (985 ) Net deferred tax assets — 12 Deferred tax liabilities Financial derivatives — 12 Total deferred tax liabilities — 12 Net deferred tax liabilities $ — $ —
Federal and state net operating loss carryover periods	The table below presents the details of our federal and state net operating loss carryover periods as of December 31, 2017 (in millions): Expiration Period 2031 - 2037 U.S. federal net operating loss carryover $ 2,522 2026 - 2037 State net operating loss carryover $ 411

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Carrying amounts and estimated fair values of financial instruments	The following table presents the carrying amounts and estimated fair values of our financial instruments: December 31, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value (in millions) Short-term debt $ 21 $ 19 $ — $ — Long-term debt $ 4,072 $ 3,248 $ 3,856 $ 3,637 Derivative instruments $ 5 $ 5 $ 57 $ 57
Fair value associated with derivative financial instruments	The following table presents the fair value associated with our derivative financial instruments as of December 31, 2017 and 2016 . 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, 2017 Derivative instruments $ 33 $ (11 ) $ 18 $ 4 $ (28 ) $ 11 $ (17 ) $ — December 31, 2016 Derivative instruments $ 79 $ (17 ) $ 58 $ 4 $ (22 ) $ 17 $ (4 ) $ (1 )

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized costs related to proved and unproved oil and natural gas properties by area	Our capitalized costs related to proved and unproved oil and natural gas properties by area for the periods ended December 31 were as follows: 2017 2016 (in millions) Proved Eagle Ford $ 3,219 $ 3,001 Permian 2,705 2,415 Altamont 1,542 1,624 Total Proved 7,466 7,040 Unproved Permian 66 94 Altamont — 60 Total Unproved 66 154 Less accumulated depletion 3,137 2,731 Net capitalized costs for oil and natural gas properties $ 4,395 $ 4,463
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: 2017 2016 (in millions) Net asset retirement liability at January 1 $ 41 $ 38 Liabilities settled (2 ) (1 ) Accretion expense 3 3 Changes in estimate (5 ) 1 Liability reclassified as held for sale (2 ) — Net asset retirement liability at December 31 $ 35 $ 41

Long Term Debt (Tables)

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt obligations	Listed below are our debt obligations as of the periods presented: Interest Rate December 31, 2017 December 31, 2016 (in millions) RBL credit facility - due May 24, 2019 (1) Variable $ 595 $ 370 Senior secured term loans: Due May 24, 2018 (2) Variable 21 21 Due April 30, 2019 (3) Variable 8 8 Due June 30, 2021 (4) Variable — 580 Senior secured notes: Due November 29, 2024 8.00 % 500 500 Due February 15, 2025 8.00 % 1,000 — Senior unsecured notes: Due May 1, 2020 9.375 % 1,200 1,576 Due September 1, 2022 7.75 % 250 250 Due June 15, 2023 6.375 % 519 551 Total debt 4,093 3,856 Less short-term debt, net of debt issue costs of less than $1 million (21 ) — Total long-term debt 4,072 3,856 Less non-current portion of unamortized debt issue costs (50 ) (67 ) Total long-term debt, net $ 4,022 $ 3,789 (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, 2017 and 2016 , the effective interest rate of the term loan was 4.23% and 3.50% , respectively. (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, 2017 and 2016 , the effective interest rate for the term loan was 4.98% and 4.50% , respectively. (4) As of December 31, 2016, the effective interest rate for the term loan was 9.75% .
Repurchases of debt	In 2017 and 2016, we also repurchased additional debt as follows: Year ended December 31, 2017 2016 (in millions) Debt repurchased - face value (1) 157 812 Cash paid 118 407 Gain on extinguishment of debt (2)(3) 37 393 (1) In 2017, repurchases were associated with 2020 and 2023 senior unsecured notes. In 2016, repurchases were associated with certain senior unsecured notes and term loans. (2) Includes $2 million and $12 million for the years ended December 31, 2017 and 2016, respectively, of non-cash expense related to eliminating associated unamortized debt issue costs. (3) For the years ended December 31, 2017 and 2016, we also recorded a loss on the extinguishment of debt of approximately $1 million and $9 million , respectively, primarily related to eliminating a portion of the unamortized debt issue costs due to the reduction of our RBL Facility borrowing base in May 2016.
Credit facility	Listed below is a further description of our credit facility as of December 31, 2017 : Credit Facility Maturity Interest Commitment fees $1.4 billion RBL May 24, 2019 LIBOR + 2.75% (1) 2.5% for LCs 0.375% commitment fee on unused capacity (1) Based on our December 31, 2017 borrowing level. Amounts outstanding under the $1.4 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, 2017
Commitments and Contingencies Disclosure [Abstract]
Future minimum annual rental commitments under non-cancelable future operating lease commitments	Future minimum annual rental commitments under non-cancelable future operating lease commitments at December 31, 2017 , were as follows: Year Ending December 31, Operating Leases (in millions) 2018 $ 5 2019 5 2020 5 2021 5 Thereafter 22 Total $ 42

Long-Term Incentive Compensat24

Long-Term Incentive Compensation / 401(k) Retirement Plan (Tables)	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Summary of changes in non-vested restricted shares	A summary of the changes in our non-vested restricted shares for the year ended December 31, 2017 is presented below: Number of Shares Weighted Average Grant Date Fair Value per Share Non-vested at December 31, 2016 6,326,788 $ 7.69 Granted 5,895,639 $ 3.92 Vested (2,355,507 ) $ 8.42 Forfeited (4,582,934 ) $ 5.86 Non-vested at December 31, 2017 5,283,986 $ 4.63
Summary of significant assumptions used to calculate fair value	The following table summarizes the significant assumptions used to calculate the fair value of the performance unit awards as of December 31, 2017, which were granted in 2016 and 2017: 2016 Awards 2017 Awards Expected Term in Years 3.0 3.0 Expected Volatility (1) 64.93 % 100.03 % Expected Dividends — — Risk-Free Interest Rate (2) 1.76 % 1.89 % (1) Expected volatility assumption for performance unit awards is based on the historical stock price volatility equal to the remaining length of the performance period as of the valuation date. (2) The risk-free rate is based upon the yield on U.S. Treasury STRIPS over the expected term as of the grant date.

Basis of Presentation and Sig25

Basis of Presentation and Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2017USD ($)segment	Dec. 31, 2016USD ($)
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Number of operating segments | segment	1
Restricted cash	$ 18,000,000	$ 0
Cumulative effect of accounting change		0
Retained Earnings
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Cumulative effect of accounting change		1,000,000
Retained Earnings | ASU 2016-09
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Cumulative effect of accounting change		$ 1,000,000
Minimum
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of the assets	4 years
Maximum
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of the assets	15 years

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisitions (Details) $ in Millions	Jan. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)a
Other Acquisitions and Divestitures [Line Items]
Payments to acquire producing properties and undeveloped acreage			$ 29	$ 0	$ 111
Deposit paid in advance of acquisition			25	$ 0	0
Permian
Other Acquisitions and Divestitures [Line Items]
Payments to acquire producing properties and undeveloped acreage			$ 29
Eagle Ford
Other Acquisitions and Divestitures [Line Items]
Deposit paid in advance of acquisition		$ 25
Properties adjacent to Eagle Ford Shale
Other Acquisitions and Divestitures [Line Items]
Payments to acquire producing properties and undeveloped acreage					$ 111
Net acres acquired | a					12,000
Subsequent Event | Eagle Ford
Other Acquisitions and Divestitures [Line Items]
Payments to acquire producing properties and undeveloped acreage	$ 245

Acquisitions and Divestitures27

Acquisitions and Divestitures - Divestitures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Divestitures
Proceeds from sale of assets	$ 18	$ 0	$ 0
Altamont
Divestitures
Sale price of assets	180
Deposit received related to divestiture	18
Altamont | Held-for-Sale
Divestitures
Property, plant, and equipment to be sold	172
Asset retirement obligations to be disposed of in sale	$ 2
Haynesville and Bossier Shales | Disposed of by Sale
Divestitures
Proceeds from sale of assets		420
Net cash proceeds from sale of assets		388
Gain on sale of assets		$ 79

Impairment Charges (Details)

Impairment Charges (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018Well	Dec. 31, 2017USD ($)Well	Dec. 31, 2016USD ($)Well	Dec. 31, 2015USD ($)Well
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Non-cash impairment charges		$ 2	$ 2	$ 4,299
Number of annual required well completions | Well		55	34	6
Forecast
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Number of annual required well completions | Well	55
Eagle Ford
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Non-cash impairment charges				$ 4,000
Permian
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Non-cash impairment charges				$ 288
Length of extension to development agreement			4 years
Length of additional extension option			10 years

Income Taxes - Pretax Loss and

Income Taxes - Pretax Loss and the Components of Income Tax Benefit (Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Pretax Loss	$ (203)	$ (26)	$ (4,326)
Current
Federal	9	0	0
State	0	(1)	0
Current income tax benefit (expense)	9	(1)	0
Deferred
Federal	0	0	543
State	0	0	35
Total income tax benefit (expense)	$ 9	$ (1)	$ 578

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Statutory federal income tax rate	35.00%	35.00%	35.00%
Effective tax rate	4.50%	(1.90%)	13.40%
Provisional effect of the Tax Cuts and Jobs Act on deferred tax balances	$ 409,000,000
Adjustment to the valuation allowance on net deferred assets	(341,000,000)	$ 9,000,000	$ 975,000,000
Unrecognized tax benefits	0
Federal net operating loss carryover subject to limitations	87,000,000
Capital loss carryovers	23,000,000
Alternative minimum tax credits	0
Valuation allowance on deferred tax assets	$ 644,000,000	$ 985,000,000

Income Taxes - Effective Income

Income Taxes - Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Statutory federal income tax rate	35.00%	35.00%	35.00%
Effective tax rate reconciliation
Income taxes at the statutory federal rate of 35%	$ 71	$ 9	$ 1,514
Increase (decrease)
State income taxes, net of federal income tax effect	(1)	1	41
Change in enacted tax rate	(409)	0	0
Change in valuation allowance	341	(9)	(975)
Other	7	(2)	(2)
Total income tax benefit (expense)	$ 9	$ (1)	$ 578

- Components of Deferred Tax As

- Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Deferred tax assets
Property, plant and equipment	$ 50	$ 249
Net operating loss carryovers	554	692
U.S. tax credit carryovers	0	10
Employee benefits	2	6
Financial derivatives	8	0
Legal and other reserves	9	6
Asset retirement obligations	8	15
Transaction costs	13	19
Total deferred tax assets	644	997
Valuation allowance	(644)	(985)
Net deferred tax assets	0	12
Deferred tax liabilities
Financial derivatives	0	12
Total deferred tax liabilities	0	12
Net deferred tax liabilities	$ 0	$ 0

- Federal and State Net Operati

- Federal and State Net Operating Loss Carryover Periods (Details) $ in Millions	Dec. 31, 2017USD ($)
U.S. | 2031 - 2037
Income Taxes
Net operating loss carryforwards	$ 2,522
State | 2026 - 2037
Income Taxes
Net operating loss carryforwards	$ 411

Fair Value Measurements - Carry

Fair Value Measurements - Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Carrying amounts and estimated fair values of financial instruments
Short-term debt	$ 21	$ 0
Long-term debt	4,072	3,856
Carrying Amount
Carrying amounts and estimated fair values of financial instruments
Short-term debt	21	0
Long-term debt	4,072	3,856
Derivative instruments	5	57
Fair Value
Carrying amounts and estimated fair values of financial instruments
Short-term debt	19	0
Long-term debt	3,248	3,637
Derivative instruments	$ 5	$ 57

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) BTU in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)BTUContractcounterpartygalMMBbls	Dec. 31, 2016USD ($)BTUgalMMBbls	Dec. 31, 2015USD ($)	Oct. 31, 2017USD ($)	Feb. 28, 2017USD ($)	Jan. 31, 2017USD ($)
Derivative [Line Items]
Number of derivative contracts designated as accounting hedges | Contract	0
Gain (loss) on derivative instruments | $	$ 41,000,000	$ (73,000,000)	$ 667,000,000
Number of counterparties | counterparty	7
RBL Facility
Derivative [Line Items]
Borrowing capacity | $	$ 1,400,000,000			$ 1,400,000,000	$ 1,440,000,000	$ 1,500,000,000
Derivatives not designated as accounting hedges | Oil derivatives
Derivative [Line Items]
Volume notional amount | MMBbls		16
Derivatives not designated as accounting hedges | Natural gas derivatives
Derivative [Line Items]
Energy notional amount	33	36
Derivatives not designated as accounting hedges | Propane derivatives
Derivative [Line Items]
Volume notional amount | gal		108,000,000
2018 | Derivatives not designated as accounting hedges | Oil derivatives
Derivative [Line Items]
Volume notional amount | MMBbls	14
2018 | Derivatives not designated as accounting hedges | Natural gas derivatives
Derivative [Line Items]
Energy notional amount	26
2018 | Derivatives not designated as accounting hedges | Propane derivatives
Derivative [Line Items]
Volume notional amount | gal	92,000,000
2019 | Derivatives not designated as accounting hedges | Natural gas derivatives
Derivative [Line Items]
Energy notional amount	7

Fair Value Measurements - Fair

Fair Value Measurements - Fair Value Associated With Derivative Financial Instruments (Details) - Level 2 - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative Assets
Gross Fair Value	$ 33	$ 79
Impact of Netting	(11)	(17)
Derivative Liabilities
Gross Fair Value	(28)	(22)
Impact of Netting	11	17
Current Assets
Derivative Assets
Derivatives instruments	18	58
Non-current Assets
Derivative Assets
Derivatives instruments	4	4
Current Liabilities
Derivative Liabilities
Derivatives instruments	(17)	(4)
Non-current Liabilities
Derivative Liabilities
Derivatives instruments	$ 0	$ (1)

Property, Plant and Equipment -

Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and Natural Gas Properties
Property, plant and equipment, net of accumulated depreciation, depletion, and amortization	$ 4,422	$ 4,498
Transfer to (from) unproved properties to proved properties	(63)
Amortization of unproved leasehold costs	$ 5	2	$ 9
Asset Retirement Obligations
Projected inflation rate	2.50%
Capitalized Interest
Capitalized interest	$ 4	$ 4	$ 14
Minimum
Asset Retirement Obligations
Credit-adjusted risk-free rate	7.00%
Maximum
Asset Retirement Obligations
Credit-adjusted risk-free rate	9.00%

Property, Plant and Equipment38

Property, Plant and Equipment - Capitalized Costs Related to Proved and Unproved Oil and Natural Gas Properties by Area (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Proved	$ 7,466	$ 7,040
Unproved	66	154
Less accumulated depletion	3,137	2,731
Net capitalized costs for oil and natural gas properties	4,395	4,463
Eagle Ford
Property, Plant and Equipment [Line Items]
Proved	3,219	3,001
Permian
Property, Plant and Equipment [Line Items]
Proved	2,705	2,415
Unproved	66	94
Altamont
Property, Plant and Equipment [Line Items]
Proved	1,542	1,624
Unproved	$ 0	$ 60

Property, Plant and Equipment39

Property, Plant and Equipment - Changes in Net Asset Retirement Liability (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Changes in net asset retirement liability
Net asset retirement liability at January 1	$ 41	$ 38
Liabilities settled	(2)	(1)
Accretion expense	3	3
Changes in estimate	(5)	1
Liability reclassified as held for sale	(2)	0
Net asset retirement liability at December 31	$ 35	$ 41

Long Term Debt - Debt Obligatio

Long Term Debt - Debt Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Feb. 28, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Debt	$ 4,093		$ 3,856
Less short-term debt, net of debt issue costs of less than $1 million	(21)		0
Debt issue costs, short term debt	1		1
Total long-term debt	4,072		3,856
Less non-current portion of unamortized debt issue costs	(50)		(67)
Total long-term debt, net	4,022		3,789
RBL Credit Facility due May 24, 2019
Debt Instrument [Line Items]
Debt	$ 595		370
RBL Credit Facility due May 24, 2019 | LIBOR
Debt Instrument [Line Items]
Reference rate for variable interest rate	LIBOR
Specified margin on reference rate	2.75%
RBL Credit Facility due May 24, 2019 | LIBOR | Minimum
Debt Instrument [Line Items]
Reference rate for variable interest rate	LIBOR
Specified margin on reference rate	2.50%
RBL Credit Facility due May 24, 2019 | LIBOR | Maximum
Debt Instrument [Line Items]
Specified margin on reference rate	3.50%
Senior Secured Term Loans due May 24, 2018
Debt Instrument [Line Items]
Debt	$ 21		$ 21
Debt instrument issuance as a percentage of par value	99.00%
Effective interest rate	4.23%		3.50%
Senior Secured Term Loans due May 24, 2018 | LIBOR
Debt Instrument [Line Items]
Reference rate for variable interest rate	LIBOR
Floor on variable rate	2.75%
Senior Secured Term Loans due May 24, 2018 | LIBOR | Minimum
Debt Instrument [Line Items]
Reference rate for variable interest rate	LIBOR
Floor on variable rate	0.75%
Senior Secured Term Loans due April 30, 2019
Debt Instrument [Line Items]
Debt	$ 8		$ 8
Effective interest rate	4.98%		4.50%
Senior Secured Term Loans due April 30, 2019 | LIBOR
Debt Instrument [Line Items]
Reference rate for variable interest rate	LIBOR
Specified margin on reference rate	3.50%
Senior Secured Term Loans due April 30, 2019 | LIBOR | Minimum
Debt Instrument [Line Items]
Reference rate for variable interest rate	LIBOR
Floor on variable rate	1.00%
Senior Secured Term Loans due June 30, 2021
Debt Instrument [Line Items]
Debt	$ 0		$ 580
Effective interest rate			9.75%
Senior Secured Notes due November 29, 2024
Debt Instrument [Line Items]
Interest Rate	8.00%
Debt	$ 500		$ 500
Senior Secured Notes due February 15, 2025
Debt Instrument [Line Items]
Interest Rate	8.00%	8.00%
Debt	$ 1,000		0
Senior Unsecured Notes due May 1, 2020
Debt Instrument [Line Items]
Interest Rate	9.375%
Debt	$ 1,200		1,576
Senior Unsecured Notes due September 1, 2022
Debt Instrument [Line Items]
Interest Rate	7.75%
Debt	$ 250		250
Senior Unsecured Notes due June 15, 2023
Debt Instrument [Line Items]
Interest Rate	6.375%
Debt	$ 519		$ 551

Long Term Debt - Narrative (Det

Long Term Debt - Narrative (Details)	1 Months Ended		12 Months Ended
	Apr. 30, 2017	Feb. 28, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Jan. 31, 2018USD ($)	Jan. 03, 2018USD ($)	Oct. 31, 2017USD ($)	Jan. 31, 2017USD ($)
Debt Instrument [Line Items]
Debt outstanding			$ 4,093,000,000	$ 3,856,000,000
Gain (loss) on extinguishment of debt			(16,000,000)	384,000,000	$ (41,000,000)
Non-cash expense related to amortization of debt issue costs			2,000,000	12,000,000
Long-term debt, net of debt issue costs			4,022,000,000	3,789,000,000
Unamortized debt issue costs			56,000,000	77,000,000
Amortization of deferred financing costs			14,000,000	16,000,000	$ 18,000,000
Long-term debt			$ 4,072,000,000	3,856,000,000
First lien debt to EBITDAX ratio	3		0.86
Net debt to EBITDAX			5.88
Debt repurchase limit			$ 885,000,000
Subsequent Event
Debt Instrument [Line Items]
Debt repurchase limit							$ 225,000,000
Maximum
Debt Instrument [Line Items]
Net debt to EBITDAX			4.50
Senior Secured Notes due 2025
Debt Instrument [Line Items]
Debt outstanding			$ 1,000,000,000	0
Principal amount issued		$ 1,000,000,000
Stated interest rate		8.00%	8.00%
Gain (loss) on extinguishment of debt		$ (53,000,000)
Non-cash expense related to amortization of debt issue costs		30,000,000
Senior Unsecured Notes due 2020
Debt Instrument [Line Items]
Debt outstanding			$ 1,200,000,000	1,576,000,000
Stated interest rate			9.375%
Repurchase of aggregate principal amount		250,000,000
Senior Unsecured Notes due 2020 | Subsequent Event
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs						$ 954,000,000
Senior Unsecured Notes due 2022
Debt Instrument [Line Items]
Debt outstanding			$ 250,000,000	250,000,000
Stated interest rate			7.75%
Senior Unsecured Notes due 2022 | Subsequent Event
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs						54,000,000
Senior Unsecured Notes due 2023
Debt Instrument [Line Items]
Debt outstanding			$ 519,000,000	551,000,000
Stated interest rate			6.375%
Senior Unsecured Notes due 2023 | Subsequent Event
Debt Instrument [Line Items]
Long-term debt, net of debt issue costs						139,000,000
Senior Secured Notes due 2024 | Subsequent Event
Debt Instrument [Line Items]
Principal amount issued						$ 1,092,000,000
Stated interest rate						9.375%
RBL Facility
Debt Instrument [Line Items]
Debt outstanding			$ 595,000,000	370,000,000
Repayments of amounts outstanding under lines of credit		111,000,000
Borrowing capacity		$ 1,440,000,000	1,400,000,000					$ 1,400,000,000	$ 1,500,000,000
Gain (loss) on extinguishment of debt			(1,000,000)	(9,000,000)
Unamortized debt issue costs			6,000,000	10,000,000
Remaining capacity			786,000,000
Letters of credit outstanding			19,000,000
RBL Facility | Subsequent Event
Debt Instrument [Line Items]
Borrowing capacity						$ 1,360,000,000
Senior Secured Term Loans and Senior Notes
Debt Instrument [Line Items]
Unamortized debt issue costs			$ 50,000,000	$ 67,000,000

Long Term Debt - Repurchases of

Long Term Debt - Repurchases of Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt	$ (16)	$ 384	$ (41)
Non-cash expense related to amortization of debt issue costs	2	12
2020 and 2023 Senior Unsecured Notes
Debt Instrument [Line Items]
Debt repurchased - face value	157
Cash paid	118
Gain (loss) on extinguishment of debt	37
Senior Unsecured Notes and Term Loans
Debt Instrument [Line Items]
Debt repurchased - face value		812
Cash paid		407
Gain (loss) on extinguishment of debt		393
RBL Facility
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt	$ (1)	$ (9)

Long Term Debt - Credit Facilit

Long Term Debt - Credit Facility (Details) - RBL Credit Facility due May 24, 2019 - USD ($)	12 Months Ended
	Dec. 31, 2017	Oct. 31, 2017	Feb. 28, 2017	Jan. 31, 2017
Line of Credit Facility [Line Items]
Credit facility	$ 1,400,000,000	$ 1,400,000,000	$ 1,440,000,000	$ 1,500,000,000
Interest rate	2.50%
Commitment fee percentage	0.375%
LIBOR
Line of Credit Facility [Line Items]
Reference rate for variable interest rate	LIBOR
Specified margin on reference rate	2.75%
LIBOR | Minimum
Line of Credit Facility [Line Items]
Reference rate for variable interest rate	LIBOR
Specified margin on reference rate	2.50%
LIBOR | Maximum
Line of Credit Facility [Line Items]
Specified margin on reference rate	3.50%
ABR | Minimum
Line of Credit Facility [Line Items]
Reference rate for variable interest rate	ABR
Specified margin on reference rate	1.50%
ABR | Maximum
Line of Credit Facility [Line Items]
Reference rate for variable interest rate	ABR
Specified margin on reference rate	2.50%

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) - USD ($) $ in Millions	Mar. 03, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Legal Matters
Transfer fee sought by plaintiff	$ 21
Rental expense		$ 6	$ 13	$ 12
Total other commercial commitments		336
Other commercial commitments, 2018		103
Other commercial commitments, 2019		76
Other commercial commitments, 2020		58
Other commercial commitments, 2020		52
Other commercial commitments, thereafter		47
Legal Matters
Legal Matters
Amount accrued		5
Indemnification and Other Matters
Legal Matters
Amount accrued		5
Sales and Use Tax Adjustment [Member]
Legal Matters
Accrual for taxes other than income taxes		$ 42

Commitments and Contingencies45

Commitments and Contingencies - Future Minimum Annual Rental Commitments Under Non-Cancelable Future Operating Lease Commitments (Details) $ in Millions	Dec. 31, 2017USD ($)
Annual minimum lease payments under non-cancelable future operating lease commitments
2,018	$ 5
2,019	5
2,020	5
2,021	5
Thereafter	22
Total	$ 42

Long-Term Incentive Compensat46

Long-Term Incentive Compensation / 401(k) Retirement Plan - Overview (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Authorized number of awards to grant (in shares)	36,832,525
Shares remaining for issuance	28,695,370
Compensation expense recorded	$ (19)	$ 22	$ 21
Income tax benefit	9	(1)	578
Reduction of compensation expense due to forfeitures	$ 33
Class B Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional shares of common stock available for issuance	0
EP Energy Corporation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax benefit	$ 5	$ 9	$ 6

Long-Term Incentive Compensat47

Long-Term Incentive Compensation / 401(k) Retirement Plan - Restricted Stock (Details) - Restricted Stock $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Unrecognized compensation cost	$ 17
Recognition period of fair value as compensation cost	2 years

Long-Term Incentive Compensat48

Long-Term Incentive Compensation / 401(k) Retirement Plan - Summary of Changes in Non-Vested Restricted Shares (Details) - Restricted Stock	12 Months Ended
	Dec. 31, 2017$ / sharesshares
Number of Shares
Non-vested at beginning of period (in shares) | shares	6,326,788
Granted (in shares) | shares	5,895,639
Vested (in shares) | shares	(2,355,507)
Forfeited (in shares) | shares	(4,582,934)
Non-vested at end of period (in shares) | shares	5,283,986
Weighted Average Grant Date Fair Value per Share
Non-vested at beginning of period (in dollars per share) | $ / shares	$ 7.69
Granted (in dollars per share) | $ / shares	3.92
Vested (in dollars per share) | $ / shares	8.42
Forfeited (in dollars per share) | $ / shares	5.86
Non-vested at end of period (in dollars per share) | $ / shares	$ 4.63

Long-Term Incentive Compensat49

Long-Term Incentive Compensation / 401(k) Retirement Plan - Stock Options (Details) - Stock Options	12 Months Ended
	Dec. 31, 2017USD ($)tranche$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Contractual term	10 years
Number of tranches | tranche	3
Vesting period	5 years
Options outstanding (in shares) | shares	101,844
Weighted average exercise price of options outstanding (in dollars per share) | $ / shares	$ 19.82
Weighted average remaining contractual term	6 years 3 months
Options exercised (in shares) | shares	0
Intrinsic value of options outstanding | $	$ 0
Unrecognized compensation cost | $	$ 1,000,000
Recognition period of fair value as compensation cost	1 year

Long-Term Incentive Compensat50

Long-Term Incentive Compensation / 401(k) Retirement Plan - Class B Shares (Details) - MIPs	12 Months Ended
	Dec. 31, 2017USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Issuance cost	$ 0
Unrecognized compensation cost	$ 3,000,000

Long-Term Incentive Compensat51

Long-Term Incentive Compensation / 401(k) Retirement Plan - Performance Share Units (Details) - Performance Share Units $ in Millions	1 Months Ended
	Nov. 30, 2017USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted (in shares) | shares	912,000
Performance period	4 years
Vesting period	6 years
Grant date fair value of awards | $	$ 12
Expected volatility rate	86.77%
Risk-free interest rate	2.10%
Expected term	6 years
Vested over first four years
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate	80.00%
Vested in the sixth year
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate	20.00%
Settled in fourth year
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Settlement rate	0.2
Settled in fifth year
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Settlement rate	0.2
Settled in sixth year
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Settlement rate	0.6

Long-Term Incentive Compensat52

Long-Term Incentive Compensation / 401(k) Retirement Plan - Performance Unit Awards (Details) - Performance Unit Awards - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target value per unit	$ 100
Minimum ultimate value of performance units	0
Maximum ultimate value of performance units	$ 200
Adjustment to weighted average diluted shares outstanding	0
Awards outstanding (in shares)	18,317	78,900
Fair value of awards	$ 1,000,000
2017 Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation cost	$ 11,000,000
Recognition period of fair value as compensation cost	3 years
2016 Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation cost	$ 1,000,000
Recognition period of fair value as compensation cost	2 years

Long-Term Incentive Compensat53

Long-Term Incentive Compensation / 401(k) Retirement Plan - Summary of Significant Assumptions Used to Calculate Fair Value (Details) - Performance Unit Awards	12 Months Ended
	Dec. 31, 2017
2016 Awards
Assumptions used for estimating weighted-average grant-date fair value of stock options
Expected Term in Years	3 years
Expected Volatility	64.93%
Expected Dividends	0.00%
Risk-Free Interest Rate	1.76%
2017 Awards
Assumptions used for estimating weighted-average grant-date fair value of stock options
Expected Term in Years	3 years
Expected Volatility	100.03%
Expected Dividends	0.00%
Risk-Free Interest Rate	1.89%

Long-Term Incentive Compensat54

Long-Term Incentive Compensation / 401(k) Retirement Plan - Other (Details) - USD ($)	1 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recorded		$ (19,000,000)	$ 22,000,000	$ 21,000,000
EPE Holdings II
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional stock issued (in shares)	70,000
Compensation expense recorded	$ 0
Compensation expense that will occur until those events that give rise to payout become probable		$ 0

Long-Term Incentive Compensat55

Long-Term Incentive Compensation / 401(k) Retirement Plan - 401(k) Retirement Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Retirement Benefits [Abstract]
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	$ 7	$ 9	$ 10

Related Party Transactions (Det

Related Party Transactions (Details) $ in Millions	1 Months Ended		12 Months Ended
	Nov. 30, 2017USD ($)	Jan. 31, 2017Well	Dec. 31, 2017USD ($)Well	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Jan. 24, 2017
Related party transactions
Reimbursement to affiliate entity	$ 4
Capital funding from investor			$ 450
Number of wells required to be drilled | Well		150
Number of well tranches | Well		2
Number of wells in each tranche | Well		75
Percent of estimated drilling, completion, and equipping costs of wells contributed by investor			60.00%
Working interest in joint venture wells			50.00%
Internal rate of return on invested capital in each tranche						12.00%
Working interest			15.00%
Recovery of capital costs			$ 214
Number of wells drilled and completed | Well			58
Capital expenditures			$ 541	$ 533	$ 1,433
Affiliate Supply Agreement
Related party transactions
Capital expenditures			$ 1	$ 6	$ 67