EP Energy (EPEGQ) 10-K 22 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 10, 2016	Jun. 30, 2015
Entity Registrant Name	EP Energy Corp
Entity Central Index Key	1,584,952
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 450,746,921
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Class A Stock
Entity Common Stock, Shares Outstanding		247,961,372
Class B Stock
Entity Common Stock, Shares Outstanding		793,508

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating revenues
Oil	$ 981	$ 1,705	$ 1,254
Natural gas	200	284	300
NGLs	60	110	74
Financial derivatives	667	985	(52)
Total operating revenues	1,908	3,084	1,576
Operating expenses
Oil and natural gas purchases	31	23	25
Transportation costs	116	100	85
Lease operating expense	186	193	147
General and administrative	148	244	229
Depreciation, depletion and amortization	983	875	585
Impairment charges	4,299	2	2
Exploration and other expense	20	25	41
Taxes, other than income taxes	80	129	79
Total operating expenses	5,863	1,591	1,193
Operating (loss) income	(3,955)	1,493	383
Other income (expense)	0	1	(12)
Loss on extinguishment of debt	(41)	(17)	(9)
Interest expense	(330)	(318)	(354)
(Loss) income from continuing operations before income taxes	(4,326)	1,159	8
Income tax (benefit) expense	(578)	432	64
(Loss) income from continuing operations	(3,748)	727	(56)
Income from discontinued operations, net of tax	0	4	506
Net (loss) income	$ (3,748)	$ 731	$ 450
Basic and diluted net income (loss) per common share
Income (loss) from continuing operations (in dollars per share)	$ (15.37)	$ 3	$ (0.27)
Income from discontinued operations, net of tax (in dollars per share)	0	0.02	2.43
Net (loss) income (in dollars per share)	$ (15.37)	$ 3.02	$ 2.16
Basic and diluted weighted average common shares outstanding	244	242	209

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 26	$ 22
Accounts receivable
Customer, net of allowance of $1 in 2015 and less than $1 in 2014	202	234
Other, net of allowance of $1 for 2015 and 2014	15	38
Income tax receivable	3	24
Materials and supplies	24	25
Derivative instruments	694	752
Prepaid assets	5	7
Total current assets	969	1,102
Property, plant and equipment, at cost
Oil and natural gas properties	7,228	10,241
Other property, plant and equipment	82	76
Total property, plant and equipment, at cost	7,310	10,317
Less accumulated depreciation, depletion and amortization	2,555	1,589
Total property, plant and equipment, net	4,755	8,728
Other assets
Derivative instruments	85	297
Unamortized debt issue costs - revolving credit facility	23	25
Other	1	2
Total other assets	109	324
Total assets	5,833	10,154
Accounts payable
Trade	79	142
Other	171	403
Derivative instruments	0	1
Accrued interest	47	53
Asset retirement obligations	1	2
Other accrued liabilities	50	47
Total current liabilities	348	648
Long-term debt	4,812	4,533
Other long-term liabilities
Deferred income taxes	0	578
Derivative instruments	8	0
Asset retirement obligations	40	40
Other	6	7
Total non-current liabilities	$ 4,866	$ 5,158
Commitments and contingencies (Note 9)
Stockholders’ equity
Preferred stock, $0.01 par value; 50 million shares authorized; no shares issued or outstanding	$ 0	$ 0
Additional paid-in capital	3,529	3,510
(Accumulated deficit) Retained earnings	(2,912)	836
Total stockholders’ equity	619	4,348
Total liabilities and equity	5,833	10,154
Class A Stock
Stockholders’ equity
Common shares	2	2
Class B Stock
Stockholders’ equity
Common shares	$ 0	$ 0

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Millions, $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Maximum allowance for accounts receivable, customer (in dollars)	$ 1	$ 1
Other receivables, allowance (in dollars)	$ 1	$ 1
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	50	50
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Class A Stock
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, shares authorized	550	550
Common shares, shares issued	248	245
Common shares, shares outstanding	248	245
Class B Stock
Common shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common shares, shares authorized	0.8	0.8
Common shares, shares issued	0.8	0.8
Common shares, shares outstanding	0.8	0.8

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities
Net (loss) income	$ (3,748)	$ 731	$ 450
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	983	883	666
Gain on sale of assets	0	(2)	(468)
Deferred income tax (benefit) expense	(578)	435	67
Loss from unconsolidated affiliate, net of cash distributions	0	0	37
Impairment charges	4,299	20	46
Loss on extinguishment of debt	41	17	9
Share-based compensation expense	19	13	22
Non-cash portion of exploration expense	14	19	39
Amortization of debt issuance costs	18	21	22
Other	0	2	1
Asset and liability changes
Accounts receivable	55	7	(50)
Accounts payable	(70)	13	80
Derivative instruments	277	(939)	56
Accrued interest	(6)	0	(3)
Other asset changes	22	5	(13)
Other liability changes	1	(39)	(1)
Net cash provided by operating activities	1,327	1,186	960
Cash flows from investing activities
Cash paid for capital expenditures	(1,433)	(2,033)	(1,924)
Proceeds from the sale of assets and investments, net of cash transferred	1	154	1,451
Cash paid for acquisitions, net of cash acquired	(111)	(165)	(2)
Net cash used in investing activities	(1,543)	(2,044)	(475)
Cash flows from financing activities
Proceeds from issuance of long-term debt	2,067	2,455	1,880
Repayments of long-term debt	(1,826)	(2,293)	(2,190)
Proceeds from issuance of stock	0	669	0
Distributions to members	0	0	(205)
Contributions from members	0	0	17
Debt issuance costs	(20)	(1)	(5)
Other	(1)	(1)	0
Net cash provided by (used in) financing activities	220	829	(503)
Cash and cash equivalents
Change in cash and cash equivalents	4	(29)	(18)
Beginning of period	22	51	69
End of period	26	22	51
Supplemental cash flow information
Interest paid, net of amounts capitalized	312	289	305
Income tax (refunds) payments net of refunds	$ (22)	$ 26	$ 16

CONSOLIDATED STATEMENT OF CHANG

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - USD ($) shares in Millions, $ in Millions	Total	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)	Class A Stock	Class A StockCommon Stock	Class B Stock	Class B StockCommon Stock
Balance (Members’ Equity) at Dec. 31, 2012	$ 2,748
Increase (Decrease) in Partners' Capital
Share-based compensation | Members’ Equity	15
Member’s distribution | Members’ Equity	(205)
Net income | Members’ Equity	345
Corporate reorganization | Members’ Equity	(2,903)
Corporate reorganization		$ 2,903
Corporate reorganization (in shares)					209		0.9
Balance (Members’ Equity) at Aug. 31, 2013	0
Increase (Decrease) in Stockholders' Equity
Net income | Members’ Equity	345
Balance at Aug. 31, 2013	2,903	2,903
Balance (in shares) at Aug. 31, 2013					209		0.9
Balance (Members’ Equity) at Dec. 31, 2012	2,748
Increase (Decrease) in Partners' Capital
Net income	450
Increase (Decrease) in Stockholders' Equity
Net income	450
Balance at Dec. 31, 2013	2,937	2,832	$ 105
Balance (in shares) at Dec. 31, 2013					209		0.9
Balance (Members’ Equity) at Aug. 31, 2013	0
Increase (Decrease) in Partners' Capital
Net income	105		105
Balance at Aug. 31, 2013	2,903	2,903
Balance (in shares) at Aug. 31, 2013					209		0.9
Increase (Decrease) in Stockholders' Equity
Income taxes recorded upon corporate reorganization	(78)	(78)
Share-based compensation	7	7
Net income	105		105
Balance at Dec. 31, 2013	2,937	2,832	105
Balance (in shares) at Dec. 31, 2013					209		0.9
Increase (Decrease) in Partners' Capital
Net income	731		731
Increase (Decrease) in Stockholders' Equity
Share-based compensation	11	11
Share-based compensation (in shares)					(1)		(0.1)
Initial public offering of common stock	669	667			$ 2
Initial public offering of common stock (in shares)					35
Net income	731		731
Balance at Dec. 31, 2014	4,348	3,510	836		$ 2
Balance (in shares) at Dec. 31, 2014				245	245	0.8	0.8
Increase (Decrease) in Partners' Capital
Net income	(3,748)		(3,748)
Increase (Decrease) in Stockholders' Equity
Share-based compensation	19	19
Share-based compensation (in shares)					(3)		0
Net income	(3,748)		(3,748)
Balance at Dec. 31, 2015	$ 619	$ 3,529	$ (2,912)		$ 2
Balance (in shares) at Dec. 31, 2015				248	248	0.8	0.8

Basis of Presentation and Signi

Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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 EP Energy Corporation through its wholly-owned subsidiaries engages in the exploration for and the acquisition, development, and production of oil, natural gas and NGLs in the United States. On August 30, 2013, EP Energy Corporation was reorganized (Corporate Reorganization) as a corporate holding company with a 100% equity interest in EPE Acquisition, LLC. EP Energy Corporation has Class A and Class B common stock. Class A common stock represents the full value of our capital interests and Class B common stock represents profits interests (for further information see Note 10). 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. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation, including the adoption of accounting standards updates related to the balance sheet classification of deferred taxes and debt issuance costs. None of these reclassifications impacted our reported net income (loss) or stockholders’ equity. 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. Our oil and natural gas properties are managed as a whole in one 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. Revenue Recognition. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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. In July 2015, the FASB approved the deferral of the new revenue standard by one year, with the option of early adoption in 2017 or, if not adopted early, beginning in the first quarter of 2018. Retrospective application of this standard is required upon adoption. We are currently evaluating the impact, if any, that this update will have on our financial statements. Significant Accounting Policies Use of Estimates The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates. Revenue Recognition Our revenues are generated primarily through the physical sale of oil, natural gas and NGLs. Revenues from sales of these products are recorded upon delivery and the passage of title 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 are included in transportation costs. We also purchase and sell oil and natural gas on a monthly basis to manage our overall oil and natural gas production and sales. These transactions are undertaken to optimize prices we receive for our oil and natural gas, to physically move oil and gas to its intended sales point, or to manage firm transportation agreements. Revenue related to these transactions are recorded in oil and natural gas sales in operating revenues and associated purchases reflected in oil and natural gas purchases in operating expenses on our consolidated income statement. For the years ended December 31, 2015 , 2014 and 2013 , 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. Cash and Cash Equivalents We consider short-term investments with an original maturity of less than three months to be cash equivalents. As of December 31, 2015 and 2014 , we had no restricted cash and less than $1 million of restricted cash, respectively, in other current assets to cover escrow amounts required for leasehold agreements in our operations. 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, (i) lease acquisition costs and all development costs are capitalized and exploratory drilling costs are capitalized until results are determined, (ii) other non-drilling exploratory costs, including certain geological and geophysical costs such as seismic costs and delay rentals, are expensed as incurred, (iii) certain internal costs directly identified with the acquisition, successful drilling of exploratory wells and development activities are capitalized, and (iv) interest costs related to financing oil and natural gas projects actively being developed are capitalized until the projects are evaluated or substantially complete and ready for their intended use if the projects were evaluated as successful. The provision for depreciation, depletion, and amortization is determined on a basis identified by 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, and other exploratory drilling and all developmental costs are amortized over total proved developed reserves. We evaluate capitalized costs related to proved properties at least annually or upon a triggering event to determine if impairment of such properties is necessary. Our evaluation of recoverability is made based on common geological structure or stratigraphic conditions and considers estimated future cash flows for all proved developed (producing and non-producing) and proved undeveloped reserves in comparison to the carrying amount of the proved properties. If the carrying amount of a property exceeds the estimated undiscounted future cash flows, the carrying amount is reduced to estimated fair value through a charge to income. Fair value is calculated by discounting the future cash flows 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 differentials, estimates of future operating and development costs, and a risk-adjusted discount rate. The discount rate is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas. Leasehold acquisitions costs associated with non-producing areas are assessed for impairment based on our estimated drilling plans and anticipated capital expenditures related to potential lease expirations. Property, Plant and Equipment (Other than Oil and Natural Gas Properties) Our property, plant and equipment, other than our assets accounted for under the successful efforts method, are recorded at their original cost of construction or, upon acquisition, at the fair value of the assets acquired. We capitalize the major units of property replacements or improvements and expense minor items. We depreciate our non-oil and natural gas property, plant and equipment using the straight-line method over the useful lives of the assets which range from four to 15 years . Accounting for Asset Retirement Obligations We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred and is estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our consolidated income statement. Accounting for Long-Term Incentive Compensation We measure the cost of long-term incentive compensation based on the grant date fair value of the award. Awards issued under these 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 requisite service period, net of estimated forfeitures. See Note 10 for further discussion of our long-term incentive compensation. Environmental Costs, Legal and Other Contingencies Environmental Costs. We record environmental liabilities at their undiscounted amounts on our consolidated balance sheet in other current and long-term liabilities when our environmental assessments indicate 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 we recognize a current period charge in general and administrative expense when clean-up efforts do not benefit future periods. We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet. Legal and Other Contingencies. We recognize liabilities for legal and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other to occur, the low end of the range is accrued. Derivatives We enter into derivative contracts on our oil and natural gas products primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. We also use derivatives to reduce the risk of variable interest rates. Derivative instruments are reflected on our balance sheet at their fair value as assets and liabilities. We classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities with counterparties where we have a legal right of offset. All of our derivatives are marked-to-market each period and changes in the fair value of our commodity based derivatives, as well as any realized amounts, are reflected as operating revenues. Changes in the fair value of our interest rate derivatives are reflected as interest expense. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. In our consolidated balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables. See Note 6 for a further discussion of our derivatives. Income Taxes We record current income taxes based on our estimates of current taxable income and provide for deferred income taxes to reflect estimated future income tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. As a result of adopting ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, as of December 31, 2015, we are required to classify all deferred tax assets and liabilities, along with any related valuation allowance, as non-current on the balance sheet. Pursuant to adopting this accounting standard update, we reclassified $251 million of current deferred income tax liabilities as of December 31, 2014 as non-current deferred income tax liabilities. 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 eligible carryback years, various tax-planning strategies and future taxable income, 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, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures Acquisitions. On September 4, 2015, we acquired approximately 12,000 net acres adjacent to our existing Eagle Ford Shale acreage for an adjusted cash purchase price of approximately $111 million . Our consolidated balance sheet presented as of December 31, 2015 , reflects our allocation of the purchase price to the underlying acquired properties. In 2014, we acquired producing properties and undeveloped acreage in the Southern Midland Basin, of which 37,000 net acres are adjacent to our existing Wolfcamp Shale position, for an aggregate cash purchase price of approximately $152 million . The acquisition represented an approximate 25% expansion of our Wolfcamp acreage. No goodwill or bargain purchase was recorded on these acquisitions. Discontinued Operations. In 2014 and 2013, we reflected as discontinued operations certain assets sold for approximately $111 million and $1.3 billion , respectively, including (i) certain domestic natural gas assets in the Arklatex area and South Louisiana Wilcox areas sold in May 2014, (ii) domestic natural gas assets which closed in June 2013 (including CBM properties located in the Raton, Black Warrior and Arkoma basins; Arklatex conventional natural gas assets located in East Texas and North Louisiana, and legacy South Texas conventional natural gas assets) and (iii) our Brazilian operations which closed in August 2014. We classified the results of operations of these assets prior to their sale as income (loss) from discontinued operations. Summarized operating results of our discontinued operations were as follows: Year Ended December 31, 2014 2013 (in millions) Operating revenues $ 82 $ 361 Operating expenses Natural gas purchases — 19 Transportation costs 5 25 Lease operating expense 31 92 Depreciation, depletion and amortization 8 81 Impairment and ceiling test charges (1) 18 44 Other expense 17 53 Total operating expenses 79 314 Gain on sale of assets 2 468 Other income (expense) 4 (2 ) Income from discontinued operations before income taxes 9 513 Income tax expense 5 7 Income from discontinued operations, net of tax $ 4 $ 506 (1) During the years ended December 31, 2014 and 2013, we recorded $18 million and $44 million , respectively, in impairment charges related to the sale of our Brazilian operations. Other Divestitures. In 2014, we also sold certain non-core acreage in Atascosa County in the Eagle Ford Shale for approximately $28 million . During 2013, we (i) received approximately $10 million from the sale of certain domestic oil and natural gas properties and (ii) sold our approximate 49% equity interest in Four Star Oil & Gas Company (Four Star) for proceeds of approximately $183 million . We did not record a gain or loss on the sale of any of these other domestic properties; however, in connection with entering into the sale of Four Star, we recorded a $20 million impairment reflected in other income (expense) on our income statement.

Impairment Charges

Impairment Charges	12 Months Ended
	Dec. 31, 2015
Impairment Charges [Abstract]
Impairment Charges	Impairment Charges We evaluate capitalized costs related to proved properties at least annually or upon a triggering event (such as a significant continued forward commodity price decline) to determine if 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 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. Eagle Ford. During the fourth quarter of 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. Wolfcamp. In the Wolfcamp Shale, we have drilling commitments that obligate us to drill a specific number of wells by March 2018 in order to hold all of our acreage. Because of the current oil price environment, we reduced our estimated future capital spending in Wolfcamp. Due to this estimated decline in activity and the absence of a definitive agreement to extend our Wolfcamp lease, we recorded a non-cash impairment charge of $288 million of our unproved properties in the Wolfcamp Shale. Commodity prices have remained volatile subsequent to December 31, 2015 and have further declined. Further price declines from these levels and/or changes to our future capital, production rates, levels of proved reserves and development plans as a consequence of the lower price environment, may result in an additional impairment of the carrying value of our proved and/or unproved properties in the future. Other . During the years ended December 31, 2015, 2014 and 2013, we recorded $2 million in impairments on oil inventory and on certain materials and supplies to reflect a market value lower than the underlying cost of those items.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes General. On August 30, 2013, we became a corporation subject to federal and state income taxes. As a result, we began recording the effects of income taxes in our financial statements on that date and recorded $78 million as a reduction to additional paid-in capital on our statement of changes in equity which represented the initial net current and deferred tax liabilities. From May 25, 2012 until August 30, 2013, we were a limited liability company treated as a partnership for federal and state income tax purposes. Pretax Income (Loss) and Income Tax Expense (Benefit). The tables below show the pretax income (loss) from continuing operations and the components of income tax expense (benefit) from continuing operations for the following periods: Year Ended December 31, 2015 2014 2013 (in millions) Pretax Income (Loss) U.S. $ (4,326 ) $ 1,159 $ 8 Components of Income Tax Expense (Benefit) Current Federal $ — $ — $ (2 ) Deferred Federal (543 ) 415 59 State (35 ) 17 7 (578 ) 432 66 Total income tax (benefit) expense $ (578 ) $ 432 $ 64 Effective Tax Rate Reconciliation. Income taxes included in net income differs from the amount computed by applying the statutory federal income tax rate of 35% for the following reasons for the following periods: Year Ended December 31, 2015 2014 2013 (in millions) Income taxes at the statutory federal rate of 35% $ (1,514 ) $ 406 $ 3 Increase (decrease) State income taxes, net of federal income tax effect (41 ) 12 4 Partnership earnings not subject to tax — — 57 Non-deductible reorganization costs — 10 — Valuation allowance 975 — — Other 2 4 — Income tax (benefit) expense $ (578 ) $ 432 $ 64 The effective tax rate for the year ended December 31, 2015 was 13.4% , lower than the statutory rate of 35% as a result of recording a valuation allowance of $975 million against our deferred tax assets. The effective tax rate for the year ended December 31, 2014 differed from the statutory rate primarily due to the result of state income taxes, net of federal income tax effect and non-deductible reorganization costs recorded in conjunction with changing our organizational structure in 2014. The effective tax rate for the year ended December 31, 2013 differed from the statutory rate primarily due to recording income tax expense subsequent to the Corporate Reorganization on August 30, 2013 and the level of pretax income not subject to tax during those periods. If we had recorded income taxes effective January 1, 2013, through December 31, 2013 , pro forma income from continuing operations would have been approximately $5 million based on applying a federal statutory tax rate of 35% . 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 $ 471 $ — Net operating loss carryovers 720 532 U.S. tax credit carryovers 10 10 Employee benefits 4 1 Legal and other reserves 7 5 Asset retirement obligations 19 15 Transaction costs 22 21 Total deferred tax assets 1,253 584 Valuation allowance (976 ) (1 ) Net deferred tax assets 277 583 Deferred tax liabilities Property, plant and equipment — 794 Financial derivatives 277 367 Total deferred tax liabilities 277 1,161 Net deferred tax liabilities $ — $ 578 Unrecognized Tax Benefits. As of December 31, 2015 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 2015 or 2014, nor do we have any accrued interest and penalties in our consolidated balance sheet as of December 31, 2015 and December 31, 2014 . The Company's and certain subsidiaries income tax years remain open and subject to examination by both federal and state tax authorities. In the third quarter of 2015, we were notified of an IRS examination of one 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, 2015 (in millions): Expiration Period 2031 - 2035 U.S. federal net operating loss $ 1,997 2016 - 2035 State net operating loss $ 315 In addition to our net operating loss carryovers, we also have (i) U.S. federal alternative minimum tax credit carryovers of $10 million and (ii) capital loss carryovers of $23 million . Our U.S. federal alternative minimum tax credits carry over indefinitely while our capital loss carryovers expire in 2018 if we are unable to generate sufficient capital gains on the sale of assets by that time. Utilization of $320 million of our federal net operating loss carryovers and $10 million of our alternative minimum tax credit 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. Valuation Allowances. As of December 31, 2015 and 2014, we have $976 million and $1 million , respectively, in valuation allowances which we 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. For further information on our assessment of our deferred tax assets and valuation allowances, see Income taxes in Note 1.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share On January 2, 2014, we completed a 62.553 -for-1 stock split of our common stock. We have retrospectively reflected earnings per common share/earnings per member unit (each member unit was converted into an equivalent common share in connection with the August 2013 Corporate Reorganization), giving effect to the stock split. Additionally, as of and for periods subsequent to our Corporate Reorganization on August 30, 2013, common share disclosures on our statement of changes in equity reflect the effects of the stock split. On January 23, 2014, we completed a public offering of 35.2 million shares of Class A Common Stock, $0.01 par value per share. We exclude potentially dilutive securities from the determination of diluted earnings per share (as well as their related income statement impacts) when their impact on income from continuing operations per common share is antidilutive. For the year ended December 31, 2015 , we incurred losses from continuing operations and accordingly excluded all potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive. Potentially dilutive securities consist of our employee stock options and restricted stock which did not have a material effect upon our diluted earnings per share for the year ended December 31, 2014.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
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, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value (in millions) Long-term debt $ 4,869 $ 3,379 $ 4,598 $ 4,582 Derivative instruments $ 771 $ 771 $ 1,048 $ 1,048 For the years ended December 31, 2015 and 2014 , 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. We hold long-term debt obligations (see Note 8) with various terms. 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, including consideration of 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 and natural gas through the use of financial derivatives. As of December 31, 2015 and 2014 , we had fixed price derivative contracts for 23 MMBbls and 37 MMBbls of oil and 7 TBtu and 69 TBtu of natural gas, respectively. In addition, we have derivative contracts related to locational basis differences and/or timing of physical settlement prices. As of December 31, 2015 , we also had derivative contracts on 15 MMGal of propane. None of these contracts are designated as accounting hedges. As of December 31, 2015 and 2014 , 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 could result in a change in the classification of our financial instruments between other levels. The following table presents the fair value associated with our derivative financial instruments as of December 31, 2015 and 2014 . 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 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, 2015 Derivative instruments $ 795 $ (16 ) $ 694 $ 85 $ (24 ) $ 16 $ — $ (8 ) December 31, 2014 Derivative instruments $ 1,093 $ (44 ) $ 752 $ 297 $ (45 ) $ 44 $ (1 ) $ — For the years ended December 31, 2015, 2014 and 2013, we recorded derivative gains of $667 million and $985 million and a derivative loss of $52 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 statement. Interest Rate Derivative Instruments . We have interest rate swaps with a notional amount of $600 million that extend through March 2017 and are intended to reduce variable interest rate risk. As of December 31, 2015 and 2014 , we had a net asset of $1 million and $3 million , respectively, related to interest rate derivative instruments included in our consolidated balance sheets. For both of the years ended December 31, 2015 and 2014 , we recorded $5 million of interest expense and for the year ended December 31, 2013 , we recorded $3 million of interest income related to the change in fair market value and cash settlements of our interest rate derivative instruments. Credit Risk. We are subject to the risk of loss on our derivative instruments that we would incur as a result of non-performance by counterparties 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 (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the daily monitoring of our oil, natural gas and NGLs counterparties’ credit exposures; (iii) comprehensive credit reviews on significant counterparties from physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords us netting or set off opportunities to mitigate exposure risk; and (v) when appropriate requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. Our assets related to derivatives as of December 31, 2015 represent financial instruments from ten counterparties; all of which are financial institutions that have an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating and are lenders associated with our $2.75 billion Reserve-based Loan facility (RBL Facility). Subject to the terms of our $2.75 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 non-cash impairment charges on our proved properties in the Eagle Ford Shale. The estimation of the fair value of our proved oil and natural gas properties related to 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, 2015
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, 2015 and 2014 , we had approximately $4.8 billion and $8.7 billion of total property, plant, and equipment, net of accumulated depreciation, depletion, and amortization on our balance sheet, substantially all of which related to both proved and unproved oil and natural gas properties. During the fourth quarter of 2015, we recorded a non-cash impairment charge of approximately $4.0 billion of our proved properties in the Eagle Ford Shale and a non-cash impairment charge of $288 million of our unproved properties in the Wolfcamp Shale. See Note 3 for details of the impairment charges. Our capitalized costs related to proved and unproved oil and natural gas properties by area for the periods ended December 31 were as follows: 2015 2014 (in millions) Proved Eagle Ford $ 2,833 $ 5,862 Wolfcamp 2,174 1,933 Altamont 1,553 1,275 Haynesville 500 442 Total Proved 7,060 9,512 Unproved Eagle Ford — 131 Wolfcamp 97 383 Altamont 64 201 Haynesville 7 14 Total Unproved 168 729 Less accumulated depletion 2,516 1,560 Net capitalized costs for oil and natural gas properties $ 4,712 $ 8,681 During 2015 , we transferred approximately $0.3 billion from unproved properties to proved properties. During 2015 , 2014 and 2013, we recorded $9 million , $18 million and $36 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, 2015 or December 31, 2014 . 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 - 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. 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: 2015 2014 (in millions) Net asset retirement liability at January 1 $ 42 $ 30 Liabilities incurred 4 10 Liabilities settled (2 ) (2 ) Accretion expense 3 3 Changes in estimate (6 ) 2 Other — (1 ) Net asset retirement liability at December 31 $ 41 $ 42 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. The interest rate used is the weighted average interest rate of our outstanding borrowings. Capitalized interest for the years ended December 31, 2015 , 2014 and 2013, was approximately $14 million , $21 million and $19 million , respectively.

Long Term Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long Term Debt	Long Term Debt Listed below are our debt obligations as of the periods presented: Interest Rate December 31, 2015 December 31, 2014 (in millions) $2.75 billion RBL credit facility - due May 24, 2019 Variable $ 1,072 $ 852 Senior secured term loan - due May 24, 2018 (1)(3) Variable 497 496 Senior secured term loan - due April 30, 2019 (2)(3) Variable 150 150 Senior secured notes - due May 1, 2019 6.875 % — 750 Senior unsecured notes - due May 1, 2020 9.375 % 2,000 2,000 Senior unsecured notes - due September 1, 2022 7.75 % 350 350 Senior unsecured notes - due June 15, 2023 6.375 % 800 — 4,869 4,598 Less unamortized debt issue costs (57 ) (65 ) Total long-term debt $ 4,812 $ 4,533 (1) The term loan was 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, 2015 and 2014, the effective interest rate of the term loan was 3.50% . (2) The term loan carries interest at a specified margin over the LIBOR of 3.50% , with a minimum LIBOR floor of 1.00% . As of December 31, 2015 and 2014, the effective interest rate for the term loan was 4.50% . (3) The term loans are secured by a second priority lien on all of the collateral securing the RBL credit facility, and effectively rank junior to any existing and future first lien secured indebtedness of the Company. Unamortized Debt Issue Costs. As of December 31, 2015 and 2014, we had total unamortized debt issue costs of $80 million and $90 million . Of these amounts $23 million and $25 million , respectively, are associated with our RBL Facility and $57 million and $65 million , respectively, are associated with our senior secured term loans and senior notes. During 2015, we (i) recorded an additional $19 million in deferred financing costs in conjunction with the issuance of our $800 million of 6.375% senior unsecured notes and with the extension of our RBL Facility and (ii) expensed approximately $12 million related to repurchasing our $750 million 6.875% senior secured notes. During 2015, 2014 and 2013, we amortized $18 million , $21 million and $22 million , respectively, of deferred financing costs into interest expense. As a result of adopting ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs, we reclassified unamortized debt issue costs associated with our senior secured term loans and senior notes from unamortized debt issue costs in other assets to a reduction of long-term debt on our consolidated balance sheets. Unamortized debt issue costs associated with our RBL Facility continue to be reflected as unamortized debt issue costs on our consolidated balance sheets. Pursuant to adopting this accounting standard update, we retrospectively reclassified $65 million of unamortized debt issue costs as a reduction of long-term debt as of December 31, 2014. Loss on Extinguishment of Debt. In 2015, we issued $800 million of 6.375% senior unsecured notes due in June 2023. We used a substantial portion of the proceeds from the offering to purchase for cash our $750 million senior secured notes due in 2019. In conjunction with repurchasing these notes, we recorded a $41 million loss on extinguishment of debt, of which $12 million was a non-cash expense related to eliminating associated unamortized debt issuance costs. In 2014, we repaid and retired our senior PIK toggle note with a portion of the proceeds from our initial public offering recording a $17 million loss on extinguishment of debt. In 2013, we recorded $9 million in losses on the extinguishment of debt associated with the pro-rata portion of deferred financing costs written off in conjunction with the repayment of a portion of our senior secured term loans, our term loan re-pricing and the semi-annual redetermination of our RBL Facility. $2.75 Billion Reserve-based Loan Facility. We have a $2.75 billion credit facility in place which allows us to borrow funds or issue letters of credit (LCs). As of December 31, 2015 , we had approximately $82 million of LC's issued under the facility, in addition to amounts borrowed, with $1.6 billion of available capacity. Listed below is a further description of our credit facility as of December 31, 2015 : Credit Facility Maturity Date Interest Rate Commitment fees $2.75 billion RBL May 24, 2019 LIBOR + 1.75% (1) 1.75% for LCs 0.375% commitment fee on unused capacity (1) Based on our December 31, 2015 borrowing level. Amounts outstanding under the $2.75 billion RBL Facility bear interest at specified margins over the LIBOR of between 1.50% and 2.50% for Eurodollar loans or at specified margins over the Alternative Base Rate ( ABR ) of between 0.50% and 1.50% for ABR loans. Such margins will fluctuate based on the utilization of the facility. In April 2015, we extended the maturity to May 2019, provided that we retire or refinance our 2018 and 2019 secured notes and term loans at least six months prior to their maturity. As noted above, we refinanced our $750 million secured notes in mid-2015. We will be required to retire or refinance our remaining $500 million senior secured term loans due 2018 by November 2017 and $150 million senior secured term loans due 2019 by November 2018. 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 November 2015, we completed our semi-annual redetermination, affirming the borrowing base at $2.75 billion . Our next redetermination date for the RBL Facility is in April 2016. Downward revisions of our oil and natural gas reserves due to declines in commodity prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a reduction of our borrowing base which could negatively impact our borrowing capacity under the RBL Facility in the future. Restrictive Provisions/Covenants. The availability of borrowings under our credit agreements and our ability to incur additional indebtedness is subject to various financial and non-financial covenants and restrictions. Our most restrictive financial covenant requires that our debt to EBITDAX ratio, as defined in the credit agreement, must not exceed 4.50 to 1.0 during the current period. Certain other covenants and restrictions, among other things, also limit our ability to incur or guarantee additional indebtedness; make any restricted payments or pay any dividends on equity interests or redeem, repurchase or retire parent entities’ equity interests or subordinated indebtedness; sell assets; make investments; create certain liens; prepay debt obligations; engage in transactions with affiliates; and enter into certain hedge agreements. As of December 31, 2015 , we were in compliance with our debt covenants.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
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, 2015 , we had approximately $5 million accrued for all outstanding legal matters. Indemnifications and Other Matters. We periodically enter into indemnification arrangements as part of the divestitures 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 recent decline in commodity prices may create an environment where there is an increased risk that owners and/or operators of assets 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 may be required to assume these plugging or abandonment obligations on assets no longer owned and operated by us. As of December 31, 2015 , we had approximately $8 million accrued related to these indemnifications and other 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 EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. The environmental laws and regulations to which we are subject also require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of December 31, 2015 , we had accrued and had exposure of approximately $1 million for related environmental remediation costs associated with onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts that we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities. Climate Change and Other Emissions. The EPA and several state environmental agencies have adopted regulations to regulate GHG emissions. Although the EPA has adopted a “tailoring” rule to regulate GHG emissions, the U.S. Supreme Court partially invalidated it in an opinion decided June 2014. The tailoring rule remains applicable for those facilities considered major sources of six other “criteria” pollutants and at this time we do not expect a material impact to our existing operations from the rule. Any regulations regarding GHG emissions would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner . As part of the White House’s Climate Action Plan Strategy to Reduce Methane Emissions, the EPA, the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the Bureau of Land Management (BLM) have recently proposed new regulations affecting the oil and gas industry. On September 18, 2015, the EPA published several proposed regulations under the Clean Air Act to reduce methane and volatile organic compounds emissions, in part through green completions at oil wells, fugitive emission surveys, limits on pneumatic pumps and controllers, and draft guidelines for controls on equipment in ozone nonattainment areas. On October 13, 2015, the PHMSA published a proposed rule for oil pipelines, in part requiring inspections in areas affected by natural disasters, expanding use of leak detection systems, and increased use of inline inspection tools. On January 22, 2016, the BLM released a proposed rule for oil and gas facilities on onshore federal and Indian leases to prohibit venting, limit flaring, require leak detection, and allow adjustment of royalty rates for new leases. Although we are examining these proposed regulations, it is uncertain what impact they might have on our operations until they are implemented. Air Quality Regulations . The EPA has promulgated various performance and emission standards that mandate air pollutant emission limits and operating requirements for stationary reciprocating internal combustion engines and process equipment. We do not anticipate material capital expenditures to meet these requirements. In August 2012, the EPA promulgated additional standards to reduce various air pollutants associated with hydraulic fracturing of natural gas wells and equipment including compressors, storage vessels, and pneumatic valves. Parts of the new standard were amended August 2013. We do not anticipate material capital expenditures to meet these requirements. Effective December 31, 2014, additional amendments to the new standard were finalized, for which we do not anticipate material capital expenditure. The EPA has promulgated regulations to require pre-construction permits for minor sources of air emissions in tribal lands as of September 2, 2014. The EPA has twice extended this deadline, to March 2, 2016 and then to October 3, 2016. Meanwhile, the EPA has proposed a federal implementation plan (FIP), rather than a general permit, that incorporates emission limits and other requirements from six standards under the Clean Air Act for the oil and gas industry. Additionally, the proposed FIP would require an operator to document compliance with the Endangered Species Act and National Historic Preservation Act. Until such regulations are adopted, it is uncertain what impact they might have on our operations in tribal lands. Hydraulic Fracturing Regulations . We use hydraulic fracturing extensively in our operations. Various regulations have been adopted and proposed at the federal, state and local levels to regulate hydraulic fracturing operations. These regulations range from banning or substantially limiting hydraulic fracturing operations, requiring disclosure of the hydraulic fracturing fluids and requiring additional permits for the use, recycling and disposal of water used in such operations. In addition, various agencies, including the EPA and Department of Energy are reviewing changes in their regulations to address the environmental impacts of hydraulic fracturing operations. Until such regulations are implemented, it is uncertain what impact they might have on our operations. In March 2015, the BLM published final rules for hydraulic fracturing on federal and certain tribal lands, including use of tanks for recovered water, updated cementing and testing requirements, and disclosure of chemicals used in hydraulic fracturing. Several states and the Ute Indian Tribe have filed suit to challenge these rules, and on September 30, 2015, a federal court issued a preliminary injunction suspending the rules. No material cost is expected for the Company’s 2016 program. Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. As part of our environmental remediation projects, we are or have received notice that we could be designated as a Potentially Responsible Party (PRP) with respect to one active site under the CERCLA or state equivalents. As of December 31, 2015 , we have estimated our share of the remediation costs at this site to be less than $1 million . Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro-rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the reserve for environmental matters discussed above. Waste Handling. Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements imposed under the Resource Conservation and Recovery Act, as amended, and comparable state laws. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations, and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate. Lease Obligations We maintain operating leases in the ordinary course of our business activities. These leases include those for office space and various equipment. The terms of the agreements vary through 2018. Future minimum annual rental commitments under non-cancelable future operating lease commitments at December 31, 2015 , were as follows: Year Ending December 31, Operating Leases (in millions) 2016 $ 12 2017 13 2018 9 Total $ 34 Rental expense for the years ended December 31, 2015 , 2014 and 2013 was $12 million , $13 million and $13 million , respectively. Other Commercial Commitments At December 31, 2015 , we have various commercial commitments totaling $525 million primarily related to commitments and contracts associated with volume and transportation, completion activities and seismic activities. Our annual obligations under these arrangements are $160 million in 2016 , $129 million in 2017 , $85 million in 2018 , $81 million in 2019 , and $70 million thereafter.

Long-Term Incentive Compensatio

Long-Term Incentive Compensation / 401(k) Retirement Plan	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Long-Term Incentive Compensation / Retirement 401(k) Plan	Long-Term Incentive Compensation / 401(k) Retirement Plan Overview. Under our current stock-based compensation plan (the EP Energy Corporation 2014 Omnibus Incentive Plan, or omnibus plan ), we may issue to our employees and non-employee directors various forms of long-term incentive (LTI) compensation including stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares/units, incentive awards, cash awards, and other stock-based awards. We are authorized to grant awards of up to 12,433,749 shares of our common stock for awards under the omnibus plan, with 7,987,514 shares remaining available for issuance as of December 31, 2015 . In addition, in conjunction with the acquisition of certain of our subsidiaries by Apollo and other private equity investors in 2012 (the Acquisition), certain employees received other LTI awards based on their purchased equity interests including, but not limited to (i) Class A “matching” units (subsequently converted into common shares upon our Corporate Reorganization) and (ii) Management Incentive Units (subsequently converted into Class B shares upon our Corporate Reorganization) which become payable upon certain liquidity events. At the time of our 2013 Corporate Reorganization, we also issued additional Class B shares to a subsidiary for grants to current and future employees that likewise become payable upon certain liquidity events. No additional Class B shares are available for issuance. We record stock-based compensation expense as general and administrative expense over the requisite service period, net of estimates of forfeitures. If actual forfeitures differ from our estimates, additional adjustments to compensation expense will be required in future periods. All of these LTI programs are discussed further below. 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, 2015 is presented below: Number of Shares Weighted Average Grant Date Fair Value per Share Non-vested at December 31, 2014 1,033,394 $ 19.80 Granted 3,678,997 $ 9.40 Vested (336,268 ) $ 19.59 Forfeited (388,469 ) $ 12.03 Non-vested at December 31, 2015 3,987,654 $ 10.98 During 2015 and 2014, we recognized approximately $13 million and $5 million of pre-tax compensation expense, respectively, and recorded deferred income tax benefits of $2 million for both of the years 2015 and 2014 on our restricted share awards. In 2015, we also recorded current income tax expense of $1 million for the vesting of our restricted share awards. The total unrecognized compensation cost related to these arrangements at December 31, 2015 was approximately $30 million , which is expected to be recognized over a weighted average period of 3 years . Stock Options. We grant stock options as compensation for future service at an exercise price equal to the closing share price of our stock on the grant date. 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), but commence vesting earlier in the event of a complete sell-down by certain of our private equity investors of their shares of our common stock. We do not pay dividends on unexercised options. A summary of our stock option transactions for the year ended December 31, 2015 is presented below. Number of Shares Underlying Options Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (in years) (in millions) Outstanding at December 31, 2014 219,352 $ 19.82 Granted — $ — Vested (638 ) $ 19.82 Forfeited or canceled (4,377 ) $ 19.82 Outstanding at December 31, 2015 214,337 $ 19.82 8.25 — For both of the years ended December 31, 2015 and 2014, we recognized less than $1 million of pre-tax compensation expense related to stock options awards granted. Total compensation cost related to non-vested option awards not yet recognized at December 31, 2015 was approximately $1 million , which is expected to be recognized over a weighted average period of 3 years . There were no options exercised during the year. Fair Value Assumptions . For the year ended December 31, 2015 , we did not issue stock options. In 2014, the fair value of each stock option granted was estimated on the date of grant using a Black-Scholes option-pricing model based on several assumptions utilizing management’s best estimate at the time of grant. For the year ended December 31, 2014, the weighted average grant date fair value per share of options granted was $9.03 . Listed below is the weighted average of each assumption based on the grant in 2014: 2014 Expected Term in Years 7.0 Expected Volatility 40 % Expected Dividends — Risk-Free Interest Rate 2.3 % We estimated expected volatility based on an analysis of historical stock price volatility of a group of similar publicly traded peer companies which share similar characteristics with us over the expected term because our stock has been publicly traded for a very short period of time. We estimate the expected term of our option awards based on the vesting period and average remaining contractual term, referred to as the “simplified method.” We used this method to provide a reasonable basis for estimating our expected term based on insufficient historical data prior to 2014. Cash-Based Long Term Incentive . In 2013 , we provided long term cash-based incentives to certain of our employees linking annual performance-based cash incentive payments to the financial performance of the company as approved by the Compensation Committee of our board of directors, and the employee’s individual performance for the year. Beginning in 2014, no further cash-based awards were granted. Our cash-based LTI awards vested over three -years ( 50% vesting at the end of the first year, and 25% vesting at the end of each of the succeeding two years), and were treated as liability awards. Cash-based LTI awards granted during 2013 and 2012 had a fair value of $22 million and $24 million on each respective grant date which are amortized primarily on an accelerated basis over the three -year vesting period. For the years ended December 31, 2015 , 2014 and 2013, we recorded approximately $2 million , $8 million and $16 million , respectively, in expense related to these awards. As of December 31, 2015 , we had unrecognized compensation expense of less than $1 million related to these awards which we will recognize in 2016 . Class A “Matching” Grants . In conjunction with the Acquisition, certain of our employees purchased Class A units. In connection with their purchase of these units, these employees were awarded compensatory awards for accounting purposes including (i) “matching” Class A unit grants with a fair value of $12 million equal to 50% of the Class A units purchased subject to repurchase by the Company in the event of certain termination scenarios and (ii) a “guaranteed cash bonus” with a fair value of $12 million which was treated as a liability award and was paid in March 2013 equivalent to the amount of the “matching” Class A unit grant. In connection with the Corporate Reorganization in August 2013, each “matching” unit was converted into common stock. For the “guaranteed cash bonus”, we recognized the fair value as compensation cost ratably over the period from the date of grant (May 24, 2012) through the cash payout date in March 2013. For the “matching” Class A unit grant, we recognize the fair value as compensation cost ratably over the three year period from the date of grant through the period over which the requisite service is provided and the time period at which certain transferability restrictions are removed. For the years ended December 31, 2015 , 2014 and 2013, we recognized approximately $2 million , $2 million and $3 million , respectively, as compensation expense related to "matching" Class A unit grants. In 2013, we also recognized $3 million as compensation expense related to other awards granted in conjunction with the Acquisition. As of December 31, 2015 , we had unrecognized compensation expense of $1 million related to the “matching” Class A unit grants, which we will recognize in 2016. Management Incentive Units (MIPs) . In addition to the Class A “matching” awards described above, certain employees were awarded MIPs at the time of the Acquisition. These MIPs are intended to constitute profits interests. Each award of MIPs represents a share in any future appreciation of the Company after the date of grant, subject to certain limitations, and once certain shareholder returns have been achieved. The MIPs vest ratably over 5 years subject to certain forfeiture provisions based on continued employment with the Company, although 25% of any vested awards are forfeitable in the event of certain termination events. The MIPs become payable based on the achievement of certain predetermined performance measures (e.g. certain liquidity events in which our private equity investors receive a return of at least one times their invested capital plus a stated return). The MIPs were issued at no cost to the employees and have value only to the extent the value of the Company increases. For accounting purposes, these awards were treated as compensatory equity awards. The MIPs were subsequently converted into Class B common shares on a one -for-one basis in August 2013 in connection with the Corporate Reorganization. On May 24, 2012, the grant date fair value of this award was determined using a non-controlling, non-marketable option pricing model which valued these MIPs assuming a 0.77% risk free rate, a 5 year time to expiration, and a 73% volatility rate. Based on these factors, we determined a grant date fair value of $74 million . For the years ended December 31, 2015 , 2014 and 2013, we recognized approximately $4 million , $6 million and $19 million , respectively, as compensation expense related to these awards. As of December 31, 2015 , we had unrecognized compensation expense of $4 million . Of this amount, we will recognize $3 million in 2016 and the remainder on an accelerated basis for each tranche of the award, over the remainder of the five year requisite service period. The remaining $16 million of compensation will be recognized upon a specified capital transaction when the right to such amounts become nonforfeitable. Other . On September 18, 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 will be granted. Holders of the awards will 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 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 2015 , 2014 and 2013, we had contributed $10 million , $11 million and $12 million , respectively, of matching and non-elective employer contributions.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Affiliate Supply Agreement. For the years ended December 31, 2015 , 2014 and 2013, we recorded approximately $67 million , $112 million and $120 million , respectively, in capital expenditures for amounts expended under supply agreements entered into with an affiliate of Apollo Management LLC (Apollo) to provide certain fracturing materials to our Eagle Ford drilling operations. Management Fee Agreement. In January 2014, we paid a quarterly management fee of $6.25 million to our private equity investors (affiliates of Apollo, Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively the Sponsors). Additionally, upon the closing of our initial public offering in January 2014, we paid the Sponsors an additional transaction fee equal to approximately $83 million . We recorded both of these fees in general and administrative expense. Our Management Fee Agreement with the Sponsors, including the obligation to pay the quarterly management fee, terminated automatically in accordance with its terms upon the closing of our initial public offering in January 2014. For the year ended December 31, 2013, we recognized approximately $26 million in general and administrative expense related to the management fee and other sponsor related fees. Member Distribution. In 2013, we made $205 million in distributions to our members including a leveraged distribution of approximately $200 million .

Basis of Presentation and Sig18

Basis of Presentation and Significant Accounting Policies (Polices)	12 Months Ended
	Dec. 31, 2015
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. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation, including the adoption of accounting standards updates related to the balance sheet classification of deferred taxes and debt issuance costs. None of these reclassifications impacted our reported net income (loss) or stockholders’ equity.
Consolidation	We consolidate entities when we have the ability to control the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment.
Segment Reporting	Our oil and natural gas properties are managed as a whole in one operating segment rather than through discrete operating segments or business units. We track basic operational data by area and allocate capital resources on a project-by-project basis across our entire asset base without regard to individual areas. We assess financial performance as a single enterprise and not on a geographical area basis.
New Accounting Pronouncements Issued But not Yet Adopted	New Accounting Pronouncements Issued But Not Yet Adopted The following accounting standards have been issued but not yet been adopted. Revenue Recognition. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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. In July 2015, the FASB approved the deferral of the new revenue standard by one year, with the option of early adoption in 2017 or, if not adopted early, beginning in the first quarter of 2018. Retrospective application of this standard is required upon adoption. We are currently evaluating the impact, if any, that this update will have on our financial statements.
Use of Estimates	Use of Estimates The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.
Revenue Recognition	Revenue Recognition Our revenues are generated primarily through the physical sale of oil, natural gas and NGLs. Revenues from sales of these products are recorded upon delivery and the passage of title 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 are included in transportation costs. We also purchase and sell oil and natural gas on a monthly basis to manage our overall oil and natural gas production and sales. These transactions are undertaken to optimize prices we receive for our oil and natural gas, to physically move oil and gas to its intended sales point, or to manage firm transportation agreements. Revenue related to these transactions are recorded in oil and natural gas sales in operating revenues and associated purchases reflected in oil and natural gas purchases in operating expenses on our consolidated income statement.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider short-term investments with an original maturity of less than three months to be cash equivalents.
Allowance for Doubtful Accounts	Allowance for Doubtful Accounts We establish provisions for losses on accounts receivable and for natural gas imbalances with other parties if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.
Oil and Natural Gas Properties	Oil and Natural Gas Properties We account for oil and natural gas properties in accordance with the successful efforts method of accounting for oil and natural gas exploration and development activities. Under the successful efforts method, (i) lease acquisition costs and all development costs are capitalized and exploratory drilling costs are capitalized until results are determined, (ii) other non-drilling exploratory costs, including certain geological and geophysical costs such as seismic costs and delay rentals, are expensed as incurred, (iii) certain internal costs directly identified with the acquisition, successful drilling of exploratory wells and development activities are capitalized, and (iv) interest costs related to financing oil and natural gas projects actively being developed are capitalized until the projects are evaluated or substantially complete and ready for their intended use if the projects were evaluated as successful. The provision for depreciation, depletion, and amortization is determined on a basis identified by 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, and other exploratory drilling and all developmental costs are amortized over total proved developed reserves. We evaluate capitalized costs related to proved properties at least annually or upon a triggering event to determine if impairment of such properties is necessary. Our evaluation of recoverability is made based on common geological structure or stratigraphic conditions and considers estimated future cash flows for all proved developed (producing and non-producing) and proved undeveloped reserves in comparison to the carrying amount of the proved properties. If the carrying amount of a property exceeds the estimated undiscounted future cash flows, the carrying amount is reduced to estimated fair value through a charge to income. Fair value is calculated by discounting the future cash flows 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 differentials, estimates of future operating and development costs, and a risk-adjusted discount rate. The discount rate is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas. Leasehold acquisitions costs associated with non-producing areas are assessed for impairment based on our estimated drilling plans and anticipated capital expenditures related to potential lease expirations.
Property, Plant and Equipment (Other than Oil and Natural Gas Properties)	Property, Plant and Equipment (Other than Oil and Natural Gas Properties) Our property, plant and equipment, other than our assets accounted for under the successful efforts method, are recorded at their original cost of construction or, upon acquisition, at the fair value of the assets acquired. We capitalize the major units of property replacements or improvements and expense minor items. We depreciate our non-oil and natural gas property, plant and equipment using the straight-line method over the useful lives of the assets which range from four to 15 years .
Accounting for Asset Retirement Obligations	Accounting for Asset Retirement Obligations We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred and is estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our consolidated income statement.
Accounting for Long-Term Incentive Compensation	Accounting for Long-Term Incentive Compensation We measure the cost of long-term incentive compensation based on the grant date fair value of the award. Awards issued under these 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 requisite service period, net of estimated forfeitures. See Note 10 for further discussion of our long-term incentive compensation.
Environmental Costs, Legal and Other Contingencies	Environmental Costs, Legal and Other Contingencies Environmental Costs. We record environmental liabilities at their undiscounted amounts on our consolidated balance sheet in other current and long-term liabilities when our environmental assessments indicate 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 we recognize a current period charge in general and administrative expense when clean-up efforts do not benefit future periods. We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet. Legal and Other Contingencies. We recognize liabilities for legal and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other to occur, the low end of the range is accrued.
Derivatives	Derivatives We enter into derivative contracts on our oil and natural gas products primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. We also use derivatives to reduce the risk of variable interest rates. Derivative instruments are reflected on our balance sheet at their fair value as assets and liabilities. We classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date. We net derivative assets and liabilities with counterparties where we have a legal right of offset. All of our derivatives are marked-to-market each period and changes in the fair value of our commodity based derivatives, as well as any realized amounts, are reflected as operating revenues. Changes in the fair value of our interest rate derivatives are reflected as interest expense. We classify cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of our oil and natural gas operations, they are classified as cash flows from operating activities. In our consolidated balance sheet, receivables and payables resulting from the settlement of our derivative instruments are reported as trade receivables and payables. See Note 6 for a further discussion of our derivatives.
Income Tax	Income Taxes We record current income taxes based on our estimates of current taxable income and provide for deferred income taxes to reflect estimated future income tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. As a result of adopting ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, as of December 31, 2015, we are required to classify all deferred tax assets and liabilities, along with any related valuation allowance, as non-current on the balance sheet. Pursuant to adopting this accounting standard update, we reclassified $251 million of current deferred income tax liabilities as of December 31, 2014 as non-current deferred income tax liabilities. 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 eligible carryback years, various tax-planning strategies and future taxable income, the latter two of which involve the exercise of significant judgment. Changes to our valuation allowances could materially impact our results of operations.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Summary of operating results and financial position data of discontinued operations	ummarized operating results of our discontinued operations were as follows: Year Ended December 31, 2014 2013 (in millions) Operating revenues $ 82 $ 361 Operating expenses Natural gas purchases — 19 Transportation costs 5 25 Lease operating expense 31 92 Depreciation, depletion and amortization 8 81 Impairment and ceiling test charges (1) 18 44 Other expense 17 53 Total operating expenses 79 314 Gain on sale of assets 2 468 Other income (expense) 4 (2 ) Income from discontinued operations before income taxes 9 513 Income tax expense 5 7 Income from discontinued operations, net of tax $ 4 $ 506 (1) During the years ended December 31, 2014 and 2013, we recorded $18 million and $44 million , respectively, in impairment charges related to the sale of our Brazilian operations.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of pretax income (loss) from continuing operations and the components of income tax expense (benefit) from continuing operations	Year Ended December 31, 2015 2014 2013 (in millions) Pretax Income (Loss) U.S. $ (4,326 ) $ 1,159 $ 8 Components of Income Tax Expense (Benefit) Current Federal $ — $ — $ (2 ) Deferred Federal (543 ) 415 59 State (35 ) 17 7 (578 ) 432 66 Total income tax (benefit) expense $ (578 ) $ 432 $ 64
Schedule of pretax income (loss), components of income tax expense (benefit) and effective tax rates	Income taxes included in net income differs from the amount computed by applying the statutory federal income tax rate of 35% for the following reasons for the following periods: Year Ended December 31, 2015 2014 2013 (in millions) Income taxes at the statutory federal rate of 35% $ (1,514 ) $ 406 $ 3 Increase (decrease) State income taxes, net of federal income tax effect (41 ) 12 4 Partnership earnings not subject to tax — — 57 Non-deductible reorganization costs — 10 — Valuation allowance 975 — — Other 2 4 — Income tax (benefit) expense $ (578 ) $ 432 $ 64
Schedule of 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 $ 471 $ — Net operating loss carryovers 720 532 U.S. tax credit carryovers 10 10 Employee benefits 4 1 Legal and other reserves 7 5 Asset retirement obligations 19 15 Transaction costs 22 21 Total deferred tax assets 1,253 584 Valuation allowance (976 ) (1 ) Net deferred tax assets 277 583 Deferred tax liabilities Property, plant and equipment — 794 Financial derivatives 277 367 Total deferred tax liabilities 277 1,161 Net deferred tax liabilities $ — $ 578
Schedule of 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, 2015 (in millions): Expiration Period 2031 - 2035 U.S. federal net operating loss $ 1,997 2016 - 2035 State net operating loss $ 315

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of carrying amounts and estimated fair values of the financial instruments	The following table presents the carrying amounts and estimated fair values of our financial instruments: December 31, 2015 December 31, 2014 Carrying Amount Fair Value Carrying Amount Fair Value (in millions) Long-term debt $ 4,869 $ 3,379 $ 4,598 $ 4,582 Derivative instruments $ 771 $ 771 $ 1,048 $ 1,048
Schedule of fair value associated with derivative financial instruments	The following table presents the fair value associated with our derivative financial instruments as of December 31, 2015 and 2014 . 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 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, 2015 Derivative instruments $ 795 $ (16 ) $ 694 $ 85 $ (24 ) $ 16 $ — $ (8 ) December 31, 2014 Derivative instruments $ 1,093 $ (44 ) $ 752 $ 297 $ (45 ) $ 44 $ (1 ) $ —

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of capitalized costs of proved and unproven properties	Our capitalized costs related to proved and unproved oil and natural gas properties by area for the periods ended December 31 were as follows: 2015 2014 (in millions) Proved Eagle Ford $ 2,833 $ 5,862 Wolfcamp 2,174 1,933 Altamont 1,553 1,275 Haynesville 500 442 Total Proved 7,060 9,512 Unproved Eagle Ford — 131 Wolfcamp 97 383 Altamont 64 201 Haynesville 7 14 Total Unproved 168 729 Less accumulated depletion 2,516 1,560 Net capitalized costs for oil and natural gas properties $ 4,712 $ 8,681
Schedule of changes in net asset retirement liability	The net asset retirement liability as of December 31 on our consolidated balance sheet in other current and non-current liabilities and the changes in the net liability for the periods ended December 31 were as follows: 2015 2014 (in millions) Net asset retirement liability at January 1 $ 42 $ 30 Liabilities incurred 4 10 Liabilities settled (2 ) (2 ) Accretion expense 3 3 Changes in estimate (6 ) 2 Other — (1 ) Net asset retirement liability at December 31 $ 41 $ 42

Long Term Debt (Tables)

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of debt obligations	Listed below are our debt obligations as of the periods presented: Interest Rate December 31, 2015 December 31, 2014 (in millions) $2.75 billion RBL credit facility - due May 24, 2019 Variable $ 1,072 $ 852 Senior secured term loan - due May 24, 2018 (1)(3) Variable 497 496 Senior secured term loan - due April 30, 2019 (2)(3) Variable 150 150 Senior secured notes - due May 1, 2019 6.875 % — 750 Senior unsecured notes - due May 1, 2020 9.375 % 2,000 2,000 Senior unsecured notes - due September 1, 2022 7.75 % 350 350 Senior unsecured notes - due June 15, 2023 6.375 % 800 — 4,869 4,598 Less unamortized debt issue costs (57 ) (65 ) Total long-term debt $ 4,812 $ 4,533 (1) The term loan was 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, 2015 and 2014, the effective interest rate of the term loan was 3.50% . (2) The term loan carries interest at a specified margin over the LIBOR of 3.50% , with a minimum LIBOR floor of 1.00% . As of December 31, 2015 and 2014, the effective interest rate for the term loan was 4.50% . (3) The term loans are secured by a second priority lien on all of the collateral securing the RBL credit facility, and effectively rank junior to any existing and future first lien secured indebtedness of the Company.
Schedule of description of credit facility	Listed below is a further description of our credit facility as of December 31, 2015 : Credit Facility Maturity Date Interest Rate Commitment fees $2.75 billion RBL May 24, 2019 LIBOR + 1.75% (1) 1.75% for LCs 0.375% commitment fee on unused capacity (1) Based on our December 31, 2015 borrowing level. Amounts outstanding under the $2.75 billion RBL Facility bear interest at specified margins over the LIBOR of between 1.50% and 2.50% for Eurodollar loans or at specified margins over the Alternative Base Rate ( ABR ) of between 0.50% and 1.50% 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, 2015
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	Future minimum annual rental commitments under non-cancelable future operating lease commitments at December 31, 2015 , were as follows: Year Ending December 31, Operating Leases (in millions) 2016 $ 12 2017 13 2018 9 Total $ 34

LLong-Term Incentive Compensati

LLong-Term Incentive Compensation / 401(k) Retirement Plan (Tables)	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Schedule of the changes in non-vested restricted shares	A summary of the changes in our non-vested restricted shares for the year ended December 31, 2015 is presented below: Number of Shares Weighted Average Grant Date Fair Value per Share Non-vested at December 31, 2014 1,033,394 $ 19.80 Granted 3,678,997 $ 9.40 Vested (336,268 ) $ 19.59 Forfeited (388,469 ) $ 12.03 Non-vested at December 31, 2015 3,987,654 $ 10.98
Schedule of stock option	A summary of our stock option transactions for the year ended December 31, 2015 is presented below. Number of Shares Underlying Options Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term Aggregate Intrinsic Value (in years) (in millions) Outstanding at December 31, 2014 219,352 $ 19.82 Granted — $ — Vested (638 ) $ 19.82 Forfeited or canceled (4,377 ) $ 19.82 Outstanding at December 31, 2015 214,337 $ 19.82 8.25 —
Schedule weighted average of each assumption	Listed below is the weighted average of each assumption based on the grant in 2014: 2014 Expected Term in Years 7.0 Expected Volatility 40 % Expected Dividends — Risk-Free Interest Rate 2.3 %

Basis of Presentation and Sig26

Basis of Presentation and Significant Accounting Policies (Details) - segment	Aug. 30, 2013	Dec. 31, 2015
Acquisitions
Number of operating segments		1
EPE Acquisition LLC
Acquisitions
Ownership interest held in EPE Acquisition LLC	100.00%

Basis of Presentation and Sig27

Basis of Presentation and Significant Accounting Policies (Details 2) - Total revenues - customer	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenue Recognition
Number of major customers	2	2	2
Customer concentration risk
Revenue Recognition
Number of major customers	1

Basis of Presentation and Sig28

Basis of Presentation and Significant Accounting Policies (Details 3) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Cash and Cash Equivalents [Line Items]
Restricted cash (less than in 2014)	$ 0
Maximum
Cash and Cash Equivalents [Line Items]
Restricted cash (less than in 2014)		$ 1,000,000

Basis of Presentation and Sig29

Basis of Presentation and Significant Accounting Policies (Details 4)	12 Months Ended
	Dec. 31, 2015
Minimum
Property, plant and equipment (other than oil and natural gas properties)
Estimated useful lives of the assets	4 years
Maximum
Property, plant and equipment (other than oil and natural gas properties)
Estimated useful lives of the assets	15 years

Basis of Presentation and Sig30

Basis of Presentation and Significant Accounting Policies (Details 5) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
New Accounting Pronouncement, Early Adoption [Line Items]
Deferred tax liabilities, noncurrent	$ 0	$ 578
New Accounting Pronouncement, Early Adoption, Effect
New Accounting Pronouncement, Early Adoption [Line Items]
Deferred tax liabilities, current	251
Deferred tax liabilities, noncurrent	$ 251

Acquisitions and Divestitures31

Acquisitions and Divestitures (Details)	Sep. 04, 2015USD ($)a	Apr. 30, 2014USD ($)	Dec. 31, 2014USD ($)a
Other Acquisitions and Divestitures
Expansion of current Wolfcamp acreage (as a percent)			25.00%
Property Adjacent To Eagle Ford Shale
Other Acquisitions and Divestitures
Area (in acres) | a	12,000
Aggregate cash purchase price	$ 111,000,000
Goodwill recorded	0
Bargain purchase recorded	$ 0
Producing properties and undeveloped acreage in the Southern Midland Basin adjacent to the entity's existing Wolfcamp Shale position
Other Acquisitions and Divestitures
Area (in acres) | a			37,000
Aggregate cash purchase price			$ 152,000,000
Bargain purchase recorded		$ 0

Acquisitions and Divestitures32

Acquisitions and Divestitures (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Divestitures
Proceeds from the sale of assets and investments, net of cash transferred	$ 1	$ 154	$ 1,451
Operating expenses
Income from discontinued operations, net of tax	$ 0	4	506
Proceeds from sale of certain non-core acreage eagle ford properties		28
CBM properties, natural gas properties in South Texas, Arklatex and South Louisiana Wilcox along with Brazil operations natural gas properties
Summary of operating results and financial position data of discontinued operations
Operating revenues		82	361
Operating expenses
Natural gas purchases		0	19
Transportation costs		5	25
Lease operating expense		31	92
Depreciation, depletion and amortization		8	81
Impairment and ceiling test charges		18	44
Other expense		17	53
Total operating expenses		79	314
Gain on sale of assets		2	468
Other income (expense)		4	(2)
Income from discontinued operations before income taxes		9	513
Income tax expense		5	7
Income from discontinued operations, net of tax		4	506
Domestic oil and natural gas properties
Divestitures
Proceeds from the sale of assets and investments, net of cash transferred			10
Various disposal asset groups
Divestitures
Proceeds from the sale of assets and investments, net of cash transferred		111	1,300
Brazil operations
Operating expenses
Impairment and ceiling test charges		$ 18	$ 44
Four Star
Operating expenses
Equity interest			49.00%
Net proceeds from sale of equity investment			$ 183
Impairment charges			$ 20

Impairment Charges (Details)

Impairment Charges (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Impairment charges		$ 4,299	$ 2	$ 2
Impairment charges, other		2	$ 2	$ 2
Eagle Ford
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Impairment charges	$ 4,000
Wolfcamp
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Impairment charges		$ 288

Income Taxes (Details)

Income Taxes (Details) $ in Millions	4 Months Ended
	Dec. 31, 2013USD ($)
Income Tax Disclosure [Abstract]
Income Taxes Recorded Upon C Corp Conversion	$ 78

Income Taxes (Details 1)

Income Taxes (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pretax Income (Loss)
U.S.	$ (4,326)	$ 1,159	$ 8
Current
Federal	0	0	(2)
Deferred
Federal	(543)	415	59
State	(35)	17	7
Deferred	(578)	432	66
Total income tax (benefit) expense	(578)	432	64
Effective tax rate reconciliation
Income taxes at the statutory federal rate of 35%	(1,514)	406	3
Increase (decrease)
State income taxes, net of federal income tax effect	(41)	12	4
Partnership earnings not subject to tax	0	0	(57)
Non-deductible reorganization costs	0	10	0
Valuation allowance	975	0	0
Other	2	4	0
Total income tax (benefit) expense	$ (578)	$ 432	$ 64
Effective tax rates (as a percent)	13.40%
Statutory federal income tax rate (as a percent)	35.00%	35.00%	35.00%
Valuation allowance	$ 976	$ 1
(Loss) income from continuing operations	$ (3,748)	$ 727	$ (56)
Pro forma
Increase (decrease)
(Loss) income from continuing operations			$ 5

Income Taxes (Details 2)

Income Taxes (Details 2) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Property, plant and equipment	$ 471	$ 0
Net operating loss carryovers	720	532
U.S. tax credit carryovers	10	10
Employee benefits	4	1
Legal and other reserves	7	5
Asset retirement obligations	19	15
Transaction costs	22	21
Total deferred tax assets	1,253	584
Valuation allowance	(976)	(1)
Net deferred tax assets	277	583
Property, plant and equipment	0	794
Financial derivatives	277	367
Total deferred tax liabilities	277	1,161
Net deferred tax liabilities	0	$ 578
Uncertain tax benefits	$ 0

Income Taxes (Details 3)

Income Taxes (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Income Taxes
U.S. federal alternative minimum tax credits	$ 10
Capital loss carryovers	23
Utilization federal carryover	320
Valuation allowance	976	$ 1
Maximum
Income Taxes
U.S. federal alternative minimum tax credits	10
2031 - 2035 | U.S. federal net operating loss
Income Taxes
Net operating loss carryforwards	1,997
2016 - 2035 | State net operating loss
Income Taxes
Net operating loss carryforwards	$ 315

Earnings Per Share (Details)

Earnings Per Share (Details) shares in Millions	Jan. 23, 2014$ / sharesshares	Jan. 02, 2014	Dec. 31, 2015$ / shares	Dec. 31, 2014$ / shares
Earnings Per Share [Abstract]
Stock split ratio		62.553
Class A Stock
Earnings per share
Number of shares issued | shares	35.2
Par value per share (in dollars per share) | $ / shares	$ 0.01		$ 0.01	$ 0.01

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Carrying amounts and estimated fair values of financial instruments
Long-term debt	$ 4,812	$ 4,533
Carrying Amount
Carrying amounts and estimated fair values of financial instruments
Long-term debt	4,869	4,598
Derivative instruments	771	1,048
Fair Value
Carrying amounts and estimated fair values of financial instruments
Long-term debt	3,379	4,582
Derivative instruments	$ 771	$ 1,048

Fair Value Measurements (Deta40

Fair Value Measurements (Details 2) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Liabilities
Gain (loss) on derivative instruments	$ 667	$ 985	$ (52)
Level 2
Derivative Assets
Gross Fair Value	795	1,093
Impact of Netting	(16)	(44)
Derivative Liabilities
Gross Fair Value	(24)	(45)
Impact of Netting	16	44
Level 2 | Current Assets
Derivative Assets
Derivatives instruments	694	752
Level 2 | Non Current Assets
Derivative Assets
Derivatives instruments	85	297
Level 2 | Current Liabilities
Derivative Liabilities
Derivatives instruments	0	(1)
Level 2 | Non-current liabilities
Derivative Liabilities
Derivatives instruments	$ (8)	$ 0

Fair Value Measurements (Deta41

Fair Value Measurements (Details 3) BTU in Thousands, gal in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)BTUContractgalMMBbls	Dec. 31, 2014USD ($)BTUMMBbls	Dec. 31, 2013USD ($)
Derivative [Line Items]
Number of contracts that are designated as accounting hedges | Contract	0
Derivatives not designated as accounting hedges | Interest rate derivative instruments
Derivative [Line Items]
Monetary notional amount	$ 600
Net asset related to interest rate derivatives	1	$ 3
Interest expense related to the change in fair market value and cash settlements of interest rate derivative instruments	$ 5	$ 5
Interest income related to the change in fair market value and cash settlements of interest rate derivative instruments			$ 3
Derivatives not designated as accounting hedges | Oil derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume (in barrels and gallons) | MMBbls	23	37
Derivatives not designated as accounting hedges | Natural gas derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, energy measure (in btus) | BTU	7	69
Derivatives not designated as accounting hedges | Propane derivatives
Derivative [Line Items]
Derivative, nonmonetary notional amount, volume (in barrels and gallons) | gal	15

Fair Value Measurements (Deta42

Fair Value Measurements (Details 4)	Dec. 31, 2015USD ($)counterparty
Credit Risk
Number of counterparties | counterparty	10
$2.75 billion RBL credit facility - due May 24, 2019
Debt Instrument [Line Items]
Borrowing capacity | $	$ 2,750,000,000

Property, Plant and Equipment43

Property, Plant and Equipment (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, plant and equipment (other than oil and natural gas properties)
Property, Plant and Equipment, Net	$ 4,755	$ 4,755	$ 8,728
Impairment charges		4,299	2	$ 2
Oil and Natural Gas Properties
Capitalized costs, proved properties	7,060	7,060	9,512
Capitalized costs, unproved properties	168	168	729
Less accumulated depletion	2,516	2,516	1,560
Net capitalized costs for oil and natural gas properties	4,712	4,712	8,681
Transfer to (from) unproved properties to proved properties		(300)
Amortization of unproved leasehold costs		$ 9	18	36
Asset Retirement Obligations
Projected inflation rate (as a percent)		2.50%
Changes in net asset retirement liability
Net asset retirement liability at January 1		$ 42	30
Liabilities incurred		4	10
Liabilities settled		(2)	(2)
Accretion expense		3	3
Changes in estimate		(6)	2
Other		0	(1)
Net asset retirement liability at December 31	41	41	42	30
Capitalized Interest
Capitalized Interest (approximately)		$ 14	21	$ 19
Minimum
Asset Retirement Obligations
Credit-adjusted risk-free rate (as a percent)		7.00%
Maximum
Asset Retirement Obligations
Credit-adjusted risk-free rate (as a percent)		9.00%
Eagle Ford
Property, plant and equipment (other than oil and natural gas properties)
Fair value of asset	2,833	$ 2,833
Impairment charges	4,000
Oil and Natural Gas Properties
Capitalized costs, proved properties			5,862
Capitalized costs, unproved properties	0	0	131
Wolfcamp
Property, plant and equipment (other than oil and natural gas properties)
Impairment charges		288
Oil and Natural Gas Properties
Capitalized costs, proved properties	2,174	2,174	1,933
Capitalized costs, unproved properties	97	97	383
Altamont
Oil and Natural Gas Properties
Capitalized costs, proved properties	1,553	1,553	1,275
Capitalized costs, unproved properties	64	64	201
Haynesville
Oil and Natural Gas Properties
Capitalized costs, proved properties	500	500	442
Capitalized costs, unproved properties	$ 7	$ 7	$ 14

Long Term Debt - Schedule of Lo

Long Term Debt - Schedule of Long Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt	$ 4,812	$ 4,533
Less unamortized debt issue costs	(57)	$ (65)
Senior secured term loan - due May 24, 2018 | London Interbank Offered Rate LIBOR
Debt Instrument [Line Items]
Effective interest rate (as a percent)		3.50%
Senior secured term loan - due April 30, 2019
Debt Instrument [Line Items]
Effective interest rate (as a percent)		4.50%
EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt	4,869	$ 4,598
EP Energy Global LLC | $2.75 billion RBL credit facility - due May 24, 2019
Debt Instrument [Line Items]
Long-term debt	1,072	852
EP Energy Global LLC | Senior secured term loan - due May 24, 2018
Debt Instrument [Line Items]
Long-term debt	$ 497	496
Debt instrument issuance as a percentage of the par value	99.00%
EP Energy Global LLC | Senior secured term loan - due May 24, 2018 | London Interbank Offered Rate LIBOR
Debt Instrument [Line Items]
Reference rate for variable interest rate	LIBOR
Reference rate floor for variable interest rate (as a percent)	2.75%
Effective interest rate (as a percent)	3.50%
EP Energy Global LLC | Senior secured term loan - due April 30, 2019
Debt Instrument [Line Items]
Long-term debt	$ 150	150
Effective interest rate (as a percent)	4.50%
EP Energy Global LLC | Senior secured term loan - due April 30, 2019 | London Interbank Offered Rate LIBOR
Debt Instrument [Line Items]
Reference rate for variable interest rate	LIBOR
Specified margin on reference rate (as a percent)	3.50%
EP Energy Global LLC | Senior secured notes - due May 1, 2019
Debt Instrument [Line Items]
Interest rate (as a percent)	6.875%
Long-term debt	$ 0	750
EP Energy Global LLC | Senior unsecured notes - due May 1, 2020
Debt Instrument [Line Items]
Interest rate (as a percent)	9.375%
Long-term debt	$ 2,000	2,000
EP Energy Global LLC | Senior unsecured notes - due September 1, 2022
Debt Instrument [Line Items]
Interest rate (as a percent)	7.75%
Long-term debt	$ 350	350
EP Energy Global LLC | Senior unsecured notes - due June 15, 2023
Debt Instrument [Line Items]
Interest rate (as a percent)	6.375%
Long-term debt	$ 800	$ 0
Minimum | EP Energy Global LLC | $2.75 billion RBL credit facility - due May 24, 2019 | London Interbank Offered Rate LIBOR
Debt Instrument [Line Items]
Reference rate for variable interest rate	LIBOR
Specified margin on reference rate (as a percent)	1.50%
Minimum | EP Energy Global LLC | Senior secured term loan - due May 24, 2018 | London Interbank Offered Rate LIBOR
Debt Instrument [Line Items]
Reference rate for variable interest rate	LIBOR
Reference rate floor for variable interest rate (as a percent)	0.75%
Minimum | EP Energy Global LLC | Senior secured term loan - due April 30, 2019 | London Interbank Offered Rate LIBOR
Debt Instrument [Line Items]
Reference rate for variable interest rate	LIBOR
Reference rate floor for variable interest rate (as a percent)	1.00%

Long Term Debt - Long Term Debt

Long Term Debt - Long Term Debt (Details)	1 Months Ended	12 Months Ended
	Apr. 30, 2015USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Nov. 30, 2015USD ($)
Debt Instrument [Line Items]
Unamortized debt issue costs		$ 80,000,000	$ 90,000,000
Long-term debt		4,812,000,000	4,533,000,000
Write off of deferred debt issuance cost		12,000,000
Amortization of deferred financing costs		18,000,000	21,000,000	$ 22,000,000
Loss on extinguishment of debt		41,000,000	17,000,000	$ 9,000,000
EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt		$ 4,869,000,000	4,598,000,000
EP Energy Global LLC | Debt Related to Extension of RBL Facility
Debt Instrument [Line Items]
Period to refinance existing debt, months	6 months
Minimum
Debt Instrument [Line Items]
Debt to EBITDAX multiple		1
Maximum
Debt Instrument [Line Items]
Debt to EBITDAX multiple		4.50
$2.75 billion RBL credit facility - due May 24, 2019
Debt Instrument [Line Items]
Unamortized debt issue costs		$ 23,000,000	25,000,000
Borrowing capacity		$ 2,750,000,000
Interest rate (as a percent)		1.75%
Commitment fees (as a percent)		0.375%
$2.75 billion RBL credit facility - due May 24, 2019 | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt		$ 1,072,000,000	852,000,000
Borrowing capacity		2,750,000,000
Letters of credit outstanding		82,000,000
Remaining capacity		$ 1,600,000,000
$2.75 billion RBL credit facility - due May 24, 2019 | Minimum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Reference rate for variable interest rate		LIBOR
Specified margin on reference rate (as a percent)		1.50%
$2.75 billion RBL credit facility - due May 24, 2019 | Minimum | Alternate base rate | EP Energy Global LLC
Debt Instrument [Line Items]
Reference rate for variable interest rate		ABR
Specified margin on reference rate (as a percent)		0.50%
$2.75 billion RBL credit facility - due May 24, 2019 | Maximum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Specified margin on reference rate (as a percent)		2.50%
$2.75 billion RBL credit facility - due May 24, 2019 | Maximum | Alternate base rate | EP Energy Global LLC
Debt Instrument [Line Items]
Reference rate for variable interest rate		ABR
Specified margin on reference rate (as a percent)		1.50%
Senior Secured Term Loans and Senior Notes
Debt Instrument [Line Items]
Unamortized debt issue costs		$ 57,000,000	65,000,000
Senior secured term loan - due May 24, 2018 | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt		$ 497,000,000	496,000,000
Senior secured term loan - due May 24, 2018 | EP Energy Global LLC | Debt Related to Extension of RBL Facility
Debt Instrument [Line Items]
Long-term debt	$ 500,000,000
Senior secured term loan - due May 24, 2018 | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Reference rate for variable interest rate		LIBOR
Senior secured term loan - due May 24, 2018 | Minimum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Reference rate for variable interest rate		LIBOR
Senior secured term loan - due April 30, 2019 | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt		$ 150,000,000	150,000,000
Senior secured term loan - due April 30, 2019 | EP Energy Global LLC | Debt Related to Extension of RBL Facility
Debt Instrument [Line Items]
Long-term debt	150,000,000
Senior secured term loan - due April 30, 2019 | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Reference rate for variable interest rate		LIBOR
Specified margin on reference rate (as a percent)		3.50%
Senior secured term loan - due April 30, 2019 | Minimum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt Instrument [Line Items]
Reference rate for variable interest rate		LIBOR
Senior secured notes - due May 1, 2019 | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt		$ 0	750,000,000
Interest rate (as a percent)		6.875%
Write off of deferred debt issuance cost		$ 12,000,000
Senior secured notes - due May 1, 2019 | EP Energy Global LLC | Debt Related to Extension of RBL Facility
Debt Instrument [Line Items]
Long-term debt	$ 750,000,000
Senior unsecured notes - due June 15, 2023
Debt Instrument [Line Items]
Deferred finance costs		19,000,000
Senior unsecured notes - due June 15, 2023 | EP Energy Global LLC
Debt Instrument [Line Items]
Long-term debt		$ 800,000,000	0
Interest rate (as a percent)		6.375%
Redetermination Credit Facility | EP Energy Global LLC
Debt Instrument [Line Items]
Borrowing capacity					$ 2,750,000,000
New Accounting Pronouncement, Early Adoption, Effect | Unamortized Debt Issue Costs
Debt Instrument [Line Items]
Unamortized debt issue costs			65,000,000
New Accounting Pronouncement, Early Adoption, Effect | Long-term Debt
Debt Instrument [Line Items]
Unamortized debt issue costs			$ 65,000,000

Commitments and Contingencies46

Commitments and Contingencies (Details) $ in Millions	Dec. 31, 2015USD ($)
Legal Matters
Legal Matters
Amount accrued	$ 5
Indemnification and Other Matters
Legal Matters
Amount accrued	$ 8

Commitments and Contingencies47

Commitments and Contingencies (Details 2) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Method	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Environmental Matters
Accrued environmental remediation costs	$ 1
Number of estimation methodologies | Method	2
Rental expense	$ 12	$ 13	$ 13
Annual minimum lease payments under non-cancelable future operating lease commitments
2,016	12
2,017	13
2,018	9
Total	34
Various commercial commitments due
Other commercial commitments, 2016	160
Other commercial commitments, 2017	129
Other commercial commitments, 2018	85
Other commercial commitments, 2019	81
Other commercial commitments, thereafter	70
Total, Other commercial commitments	525
Maximum | Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters
Environmental Matters
Estimated environmental remediation costs (less than)	$ 1

Long-Term Incentive Compensat48

Long-Term Incentive Compensation / 401(k) Retirement Plan (Details)	Sep. 18, 2013USD ($)shares	May. 24, 2012USD ($)	Dec. 31, 2015USD ($)trancheshares	Dec. 31, 2014USD ($)$ / shares	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares remaining for issuance | shares			7,987,514
Vesting period (in years)			3 years
Income tax (benefit) expense			$ (578,000,000)	$ 432,000,000	$ 64,000,000
Unrecognized compensation cost			$ 1,000,000
Recognition period of fair value as compensation cost			2 years
Awards vesting in the first year (as a percent)			50.00%
Awards vesting in each of the succeeding two years (as a percent)			25.00%
Fair value of cash-based awards on the grant date					$ 22,000,000	$ 24,000,000
Vesting period for cash based incentive					3 years
Compensation cost recorded			$ 2,000,000	8,000,000	$ 16,000,000
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			$ 10,000,000	11,000,000	12,000,000
Class B Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional shares to authorize (in shares) | shares			0
EP Energy Corporation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Authorized amount of shares to grant (in shares) | shares			12,433,749
EPE Holdings II
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recorded (less than for 2014)	$ 0
Additional stock issued (in shares) | shares	70,000
Compensation expense that will occur until those events that give rise to payout become probable			$ 0
Class A Matching Grants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recorded (less than for 2014)			$ 2,000,000	2,000,000	3,000,000
Recognition period of fair value as compensation cost			3 years
Unrecognized compensation cost			$ 1,000,000
Grants as a percentage of the Class A units purchased			50.00%
Guaranteed cash bonus			$ 12,000,000
Fair value			12,000,000
MIPs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recorded (less than for 2014)			4,000,000	6,000,000	19,000,000
Unrecognized compensation cost			$ 4,000,000
Vesting period for cash based incentive			5 years
Percentage of vested awards forfeitable in the event of certain termination events			25.00%
Issuance cost			$ 0
Risk-free interest rate		0.77%
Term in years		5 years
Expected volatility rate		73.00%
Fair value on the grant date		$ 74,000,000
Unrecognized compensation cost to be recognized on an accelerated basis for each tranche of the award			$ 3,000,000
Requisite service period			5 years
Unrecognized compensation cost to be recognized upon a specified capital transaction			$ 16,000,000
MIPs | Class B Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Conversion basis			1
Restricted stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recorded (less than for 2014)			$ 13,000,000	5,000,000
Income tax (benefit) expense			(2,000,000)	$ (2,000,000)
Unrecognized compensation cost			$ 30,000,000
Recognition period of fair value as compensation cost			3 years
Restricted stock | EP Energy Corporation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)			3 years
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)			5 years
Recognition period of fair value as compensation cost			3 years
Contratual term, in years			10 years
Number of tranches | tranche			3
Unrecognized compensation cost			$ 1,000,000
Weighted average of each assumption based on grants (in dollars per share) | $ / shares				$ 9.03
Risk-free interest rate				2.30%
Term in years				7 years
Expected volatility rate				40.00%
Stock options | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recorded (less than for 2014)				$ 1,000,000
Vested Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Income tax (benefit) expense				$ 1,000,000
Acquisition-related Costs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recorded (less than for 2014)					$ 3,000,000

Long-Term Incentive Compensat49

Long-Term Incentive Compensation / 401(k) Retirement Plan - Restricted Stock (Details) - Restricted stock	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Number of Shares
Nonvested at beginning of period (shares) | shares	1,033,394
Granted (shares) | shares	3,678,997
Vested (shares) | shares	(336,268)
Forfeited (shares) | shares	(388,469)
Nonvested at end of period (shares) | shares	3,987,654
Weighted Average Grant Date Fair Value per Share
Non-vested at beginning of period (dollars per share) | $ / shares	$ 19.80
Granted (dollars per share) | $ / shares	9.40
Vested (dollars per share) | $ / shares	19.59
Forfeited (dollars per share) | $ / shares	12.03
Non-vested at end of period (dollars per share) | $ / shares	$ 10.98

Long-Term Incentive Compensat50

Long-Term Incentive Compensation / 401(k) Retirement Plan - Stock Options (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares
Weighted-Average Exercise Price
Vested (in dollars per share) | $ / shares	$ 19.82
Stock options
Number of Options
Outstanding at the beginning of the period (in shares) | shares	219,352
Granted (in shares) | shares	0
Vested (in shares) | shares	(638)
Forfeited or canceled (in shares) | shares	(4,377)
Outstanding at the end of the period (in shares) | shares	214,337
Weighted-Average Exercise Price
Outstanding at the beginning of the period (in dollars per share) | $ / shares	$ 19.82
Granted (in dollars per share) | $ / shares	0
Forfeited or canceled (in dollars per share) | $ / shares	19.82
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 19.82
Weighted Average Remaining Contractual Term	8 years 3 months
Aggregate intrinsic value of options | $	$ 0

Long-Term Incentive Compensat51

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

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related party transactions
Capital expenditures	$ 83,000	$ 1,433,000	$ 2,033,000	$ 1,924,000
Transaction fee paid	$ 6,250
Payments of Capital Distribution		0	0	205,000
General and administrative expense				26,000
Member Distribution
Related party transactions
Payments of Capital Distribution				205,000
Leveraged distribution				200,000
Affiliate Supply Agreement
Related party transactions
Capital expenditures		$ 67,000	$ 112,000	$ 120,000