EP Energy (EPEGQ) 10-K 23 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Jun. 30, 2014	Feb. 10, 2015
Entity Registrant Name	EP Energy Corp
Entity Central Index Key	1584952
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float		$729,098,077
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Class A Stock
Entity Common Stock, Shares Outstanding			244,781,024
Class B Stock
Entity Common Stock, Shares Outstanding			817,560

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (USD $)	11 Months Ended	12 Months Ended		5 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	24-May-12
Operating revenues
Oil	$499	$1,705	$1,254
Natural gas	216	284	300
NGLs	28	110	74
Financial derivatives	-62	985	-52
Total operating revenues	681	3,084	1,576
Operating expenses
Natural gas purchases	19	23	25
Transportation costs	48	100	85
Lease operating expense	63	193	147
General and administrative	358	244	229
Depreciation, depletion and amortization	188	875	585
Impairment and ceiling test charges	1	2	2
Exploration and other expense	40	25	41
Taxes, other than income taxes	36	129	79
Total operating expenses	753	1,591	1,193
Operating income (loss)	-72	1,493	383
Other income (expense)	-1	1	-12
Loss on extinguishment of debt	-14	-17	-9
Interest expense	-219	-318	-354
Income (Loss) from Continuing Operations before Income Taxes	-306	1,159	8
Income tax expense (benefit)		432	64
Income (loss) from continuing operations	-306	727	-56
Income (loss) from discontinued operations, net of tax	50	4	506
Net income (loss)	-256	731	450
Basic and diluted net income (loss) per common share
Income (loss) from continuing operations (in dollars per share)	($1.46)	$3	($0.27)
Income from discontinued operations, net of tax (in dollars per share)	$0.23	$0.02	$2.43
Net income (loss) (in dollars per share)	($1.23)	$3.02	$2.16
Basic and diluted weighted average common shares outstanding (in shares)	209	242	209
Member's Equity Predecessor
Operating revenues
Oil				310
Natural gas				228
NGLs				29
Financial derivatives				365
Total operating revenues				932
Operating expenses
Transportation costs				45
Lease operating expense				80
General and administrative				69
Depreciation, depletion and amortization				307
Impairment and ceiling test charges				62
Taxes, other than income taxes				31
Total operating expenses				594
Operating income (loss)				338
Other income (expense)				-3
Interest expense				-14
Income (Loss) from Continuing Operations before Income Taxes				321
Income tax expense (benefit)				134
Income (loss) from continuing operations				187
Income (loss) from discontinued operations, net of tax				-9
Net income (loss)				$178

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	11 Months Ended	12 Months Ended		5 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	24-May-12
Net income (loss)	($256)	$731	$450
Cash flow hedging activities:
Comprehensive income (loss)	-256	731	450
Member's Equity Predecessor
Net income (loss)				178
Cash flow hedging activities:
Reclassification adjustment				3
Comprehensive income (loss)				$181

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (Member's Equity Predecessor, USD $)	5 Months Ended
In Millions, unless otherwise specified	24-May-12
Member's Equity Predecessor
Maximum taxes recognized for reclassification adjustment	$2

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Current assets
Cash and cash equivalents	$22	$51
Accounts receivable
Customer, net of allowance of less than $1 in 2014 and 2013	234	231
Other, net of allowance of $1 for 2014 and 2013	38	40
Income tax receivable	24	3
Materials and supplies	25	20
Derivative instruments	752	47
Assets of discontinued operations		293
Deferred income taxes		28
Prepaid assets	7	10
Total current assets	1,102	723
Property, plant and equipment, at cost
Oil and natural gas properties	10,241	8,136
Other property, plant and equipment	76	56
Total property, plant and equipment, at cost	10,317	8,192
Less accumulated depreciation, depletion and amortization	1,589	770
Total property, plant and equipment, net	8,728	7,422
Other assets
Derivative instruments	297	97
Unamortized debt issue costs	90	116
Other	2	8
Total other assets	389	221
Total assets	10,219	8,366
Accounts payable
Trade	142	135
Other	403	386
Income tax payable		2
Deferred income taxes	251
Derivative instruments	1	35
Accrued interest	53	54
Asset retirement obligations	2	2
Liabilities of discontinued operations		125
Other accrued liabilities	47	63
Total current liabilities	899	802
Long-term debt	4,598	4,421
Other long-term liabilities
Deferred income taxes	327	171
Asset retirement obligations	40	28
Other	7	7
Total non-current liabilities	4,972	4,627
Commitments and contingencies (Note 8)
Stockholders' equity
Preferred stock, $0.01 par value; 50 million shares authorized; no shares issued or outstanding
Additional paid-in capital	3,510	2,832
Retained earnings.	836	105
Total stockholders' equity	4,348	2,937
Total liabilities and equity	10,219	8,366
Class A Stock
Stockholders' equity
Common shares	2
Total stockholders' equity	$2

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, except Per Share data, unless otherwise specified
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	245	209
Common shares, shares outstanding	245	209
Class B Stock
Common shares, par value (in dollars per share)	$0.01	$0.01
Common shares, shares authorized	0.8	0.9
Common shares, shares issued	0.8	0.9
Common shares, shares outstanding	0.8	0.9

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	11 Months Ended	12 Months Ended		5 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	24-May-12
Cash flows from operating activities
Net income (loss)	($256)	$731	$450
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	268	883	666
Gain on sale of assets		-2	-468
Deferred income tax expense	1	435	67
Loss from unconsolidated affiliate, net of cash distributions	15		37
Impairment and ceiling test charges	1	20	46
Loss on extinguishment of debt	14	17	9
Share-based compensation expense	17	13	22
Non-cash portion of exploration expense	23	19	39
Amortization of debt issuance costs	12	21	22
Other	1	2	1
Asset and liability changes
Accounts receivable	-73	7	-50
Accounts payable	66	13	80
Derivative instruments	281	-939	56
Accrued interest	57		-3
Other asset changes	-18	5	-13
Other liability changes	40	-39	-1
Net cash provided by operating activities	449	1,186	960
Cash flows from investing activities
Capital expenditures	-877	-2,033	-1,924
Proceeds from the sale of assets and investments, net of cash transferred	110	154	1,451
Cash paid for acquisitions, net of cash acquired	-7,126	-165	-2
Net cash used in investing activities	-7,893	-2,044	-475
Cash flows from financing activities
Proceeds from issuance of long-term debt	5,825	2,455	1,880
Repayment of long-term debt	-1,139	-2,293	-2,190
Proceeds from issuance of stock		669
Distributions to members	-337		-205
Contributed member equity			17
Contributions from members	3,323
Debt issuance costs	-159	-1	-5
Other		-1
Net cash provided by (used in) financing activities	7,513	829	-503
Cash and cash equivalents
Change in cash and cash equivalents	69	-29	-18
Beginning of period		51	69
End of period	69	22	51
Supplemental cash flow information
Interest paid, net of amounts capitalized	145	289	305
Income tax payments, net of refunds	2	26	16
Member's Equity Predecessor
Cash flows from operating activities
Net income (loss)				178
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization				319
Deferred income tax expense				199
Loss from unconsolidated affiliate, net of cash distributions				12
Impairment and ceiling test charges				62
Amortization of debt issuance costs				7
Asset and liability changes
Accounts receivable				132
Accounts payable				-56
Derivative instruments				-201
Accrued interest				-1
Other asset changes				-7
Other liability changes				-64
Net cash provided by operating activities				580
Cash flows from investing activities
Capital expenditures				-636
Proceeds from the sale of assets and investments, net of cash transferred				9
Cash paid for acquisitions, net of cash acquired				-1
Net cash used in investing activities				-628
Cash flows from financing activities
Proceeds from issuance of long-term debt				215
Repayment of long-term debt				-1,065
Contributed member equity				960
Net cash provided by (used in) financing activities				110
Cash and cash equivalents
Change in cash and cash equivalents				62
Beginning of period				25
End of period				87
Supplemental cash flow information
Interest paid, net of amounts capitalized				7
Income tax payments, net of refunds				$2

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (USD $)	Class A Stock	Class B Stock	Member's Equity Predecessor	Member's Equity Predecessor	Member's Equity Predecessor	Member's Equity Predecessor	Member's Equity Predecessor	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit).	Total
In Millions, unless otherwise specified	USD ($)		Common Stock	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit).	Accumulated Other Comprehensive Income (Loss)	USD ($)	USD ($)	USD ($)	USD ($)
			USD ($)	USD ($)	USD ($)	USD ($)
Balance at Dec. 31, 2011							$3,100
Balance at Dec. 31, 2011				4,580	-1,476	-4
Balance (in shares) at Dec. 31, 2011			1,000
Increase (Decrease) in Stockholders' Equity
Contribution from parent				1,481			1,481
Other				12		3	15
Net income (loss)					178		178
Elimination of predecessor parent stockholder's equity			-1,000	-6,073	1,298	1	-4,774
Balance at May. 24, 2012
Balance at Dec. 31, 2012										2,748
Increase (Decrease) in Stockholders' Equity
Net income (loss)										345
Corporate reorganization								2,903		-2,903
Corporate reorganization (in shares)	209	0.9
Increase (Decrease) in Partners' Capital
Member distributions										-205
Share-based compensation expense										15
Balance at Aug. 31, 2013								2,903		2,903
Balance (in shares) at Aug. 31, 2013	209	0.9
Increase (Decrease) in Stockholders' Equity
Net income (loss)									105	105
Income taxes recorded upon corporate reorganization								-78		-78
Share-based compensation								7		7
Balance at Dec. 31, 2013								2,832	105	2,937
Balance (in shares) at Dec. 31, 2013	209	0.9
Increase (Decrease) in Stockholders' Equity
Net income (loss)									731	731
Share-based compensation								11		11
Share-based compensation (in shares)	1	-0.1
Initial public offering of common stock	2							667		669
Initial public offering of common stock (in shares)	35
Balance at Dec. 31, 2014	$2							$3,510	$836	$4,348
Balance (in shares) at Dec. 31, 2014	245	0.8

Basis_of_Presentation_and_Sign

Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Basis of Presentation and Significant Accounting Policies
Basis of Presentation and Significant Accounting Policies	1.  Basis of Presentation and Significant Accounting Policies
	Basis of Presentation and Consolidation
	EP Energy Corporation was reorganized on August 30, 2013 as a corporate holding company with a 100% equity interest in EPE Acquisition, LLC. Prior to this corporate reorganization, activities were conducted through EPE Acquisition, LLC, a holding company formed on February 14, 2012. EPE Acquisition, LLC had two classes of membership interests: Class A membership units and Class B membership units. The Class A membership units represented the full value of our capital interests, and the Class B membership units represented profits interests (for further information see Note 9). As part of the corporate reorganization, (i) all of the Class A and Class B membership units in EPE Acquisition, LLC were directly or indirectly exchanged for shares of Class A and Class B common stock, respectively of EP Energy Corporation, which have the same interests, rights and obligations of the Class A and B membership units.
	EPE Acquisition, LLC had no independent operations and through its wholly-owned subsidiaries, owned the units of EP Energy LLC (which owned 100 percent of EP Energy Global LLC). On May 24, 2012, Apollo Global Management LLC (together with its subsidiaries, Apollo) and other private equity investors (collectively, the Sponsors) acquired EP Energy Global LLC and subsidiaries for approximately $7.2 billion in cash (the Acquisition) as contemplated by the merger agreement among El Paso Corporation (El Paso) and Kinder Morgan, Inc. (KMI) which is further described in Note 2. The acquired entities engage in the exploration for and the acquisition, development, and production of oil, natural gas and NGLs in the United States. Hereinafter, for periods prior to the Acquisition in 2012, the acquired entities are referred to as the predecessor for financial accounting and reporting purposes.
	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. Predecessor periods reflect reclassifications to conform to EP Energy Corporation’s financial statement presentation.
	We consolidate entities when we have the ability to control the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions and activities of an entity.
	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 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.  Retrospective application of this standard is required beginning in the first quarter of 2017.  We are currently evaluating the impact, if any, that this update will have on our financial statements.
	Discontinued Operations.  In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which alters the criteria under which assets to be disposed of are evaluated for reporting as a discontinued operation.  While early adoption of this update is permitted, prospective application is required in the first quarter of 2015.  Accordingly, the update will not impact our historical presentation of assets as discontinued operations. The revised standard will (i) raise the threshold for divestitures to qualify as discontinued operations and (ii) require new disclosures for both discontinued operations and material divestitures which do not qualify as discontinued operations.
	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 natural gas on a monthly basis to manage our overall natural gas production and sales. These transactions are undertaken to optimize prices we receive for our natural gas, to physically move gas to its intended sales point, or to manage firm transportation agreements. Revenue related to these transactions are recorded in natural gas sales in operating revenues and associated purchases reflected in natural gas purchases in operating expenses on our consolidated income statement.
	For the years ended December 31, 2014 and 2013 and the successor period in 2012, we had two customers that individually accounted for 10 percent or more of our total revenues.  The predecessor period in 2012 had three customers that individually accounted for 10 percent or more of 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, 2014 and 2013, we had less than $1 million, of restricted cash 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
	Successful Efforts (Successor). In conjunction with the Acquisition, we began applying 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 by major prospect area based on our estimates or current drilling plans.
	Full Cost (Predecessor). Prior to the Acquisition, the predecessor used the full cost method to account for their oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves were capitalized on a country-by-country basis. These capitalized amounts included the costs of unproved properties that were transferred into the full cost pool when the properties were determined to have proved reserves, internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs were capitalized into the full cost pool, which was subject to amortization and was periodically assessed for impairment through a ceiling test calculation discussed below.
	Under full cost accounting, capitalized costs associated with proved reserves were amortized over the life of the proved reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties were excluded from the amortizable base until these properties were evaluated or determined that the costs were impaired. On a quarterly basis, unproved property costs were transferred into the amortizable base when properties were determined to have proved reserves. If costs were determined to be impaired, the amount of any impairment was transferred to the full cost pool if an oil or natural gas reserve base exists, or was expensed if a reserve base has not yet been created. The amortizable base included future development costs; dismantlement, restoration and abandonment costs, net of estimated salvage values; and geological and geophysical costs incurred that could not be associated with specific unevaluated properties or prospects in which we owned a direct interest.
	Under full cost accounting, capitalized costs in each country, net of related deferred income taxes, were limited to a ceiling based on the present value of future net revenues from proved reserves less estimated future capital expenditures, discounted at 10 percent, plus the cost of unproved oil and natural gas properties not being amortized, less related income tax effects.  Prior to the Acquisition, this ceiling test calculation was performed each quarter.  The prices used when performing the ceiling test were based on the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period. These prices were required to be held constant over the life of the reserves, even though actual prices of oil and natural gas changed from period to period.  If total capitalized costs exceeded the ceiling, a write down of capitalized costs to the ceiling was required. Any required write-down was included as a ceiling test charge in the consolidated income statement and as an increase to accumulated depreciation, depletion and amortization on the consolidated balance sheet. The present value of future net revenues used for these ceiling test calculations excluded the impact of derivatives and the estimated future cash outflows associated with asset retirement liabilities related to proved developed reserves.
	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 three 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 9 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 5 for a further discussion of our derivatives.
	Income Taxes
	We record current income taxes based on our estimates of current taxable income and provide for deferred income taxes to reflect estimated future income tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We 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 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.
	Prior to the Acquisition, the predecessor’s taxable income or loss was included in El Paso’s U.S. federal and certain state returns and we recorded income taxes on a separate return basis in our financial statements as if we had filed separate income tax returns under our then existing structure for the periods presented in accordance with a tax sharing agreement between us and El Paso. Under that agreement El Paso paid all consolidated U.S. federal and state income tax directly to the appropriate taxing jurisdictions and, under a separate tax billing agreement, El Paso billed or was refunded for their portion of these income taxes. In certain states, the predecessor filed and paid taxes directly to the state taxing authorities.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2014
Acquisitions and Divestitures
Acquisitions and Divestitures	2.  Acquisitions and Divestitures
	Acquisitions. On April 30, 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 current Wolfcamp acreage.  The fair value of the business acquired was allocated to the underlying properties and no goodwill or bargain purchase was recorded.
	On May 24, 2012, investment funds managed by Apollo (collectively, “the Apollo Funds”) and other investors acquired all of the equity of EP Energy Global LLC for approximately $7.2 billion. The Acquisition was funded with approximately $3.3 billion in equity contributions and the issuance of approximately $4.25 billion of debt. In conjunction with the Acquisition, a portion of the proceeds were also used to repay approximately $960 million outstanding under the predecessor’s revolving credit facility at that time. See Note 7 for additional discussion of debt.
	The unaudited pro forma information below for the year ended December 31, 2012 has been derived from the historical consolidated financial statements and has been prepared as though the Acquisition occurred as of the beginning of January 1, 2012. The unaudited pro forma information does not purport to represent what our results of operations would have been if such transactions had occurred on such date.
			Year ended
			December 31,
			2012
			(in millions)
	Operating Revenues		$	1,659
	Net Income		143
	In conjunction with the Acquisition, approximately $330 million in transaction, advisory, and other fees were incurred, of which $142 million were capitalized as debt issue costs and $15 million were capitalized as prepaid costs in other assets on our balance sheet. The remaining $173 million in fees were reflected in general and administrative expense in our consolidated income statement.  Additionally, during the successor period in 2012 we recorded approximately $48 million related to transition and restructuring costs, including severance charges totaling approximately $17 million ($4 million related to divested assets).  These amounts were included as general and administrative expenses in our consolidated income statement.
	Discontinued Operations.  We have reflected as discontinued operations certain non-core assets sold including (i) certain domestic natural gas assets in our Arklatex area and those in our 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 have reflected the domestic natural gas assets sold as discontinued operations in all successor periods and reflected our Brazilian operations as discontinued operations in all periods presented in these consolidated financial statements. For periods prior to the Acquisition, the predecessor applied the full cost method of accounting for oil and natural gas properties where capitalized costs were aggregated by country (e.g. U.S.); accordingly, these domestic assets sold did not qualify for and have not been reflected as discontinued operations in the predecessor financial statement periods.
	Summarized operating results and financial position data of our discontinued operations were as follows:
			Successor							Predecessor
			Year ended		Year ended			February 14		January 1
			December 31,		December 31,			to		to
			2014		2013			December 31,		May 24,
								2012		2012
								(in millions)
	Operating revenues		$	82	$	361		$	309	$	46
	Operating expenses
	Natural gas purchases		—		19			23		—
	Transportation costs		5		25			25		—
	Lease operating expense		31		92			74		16
	Depreciation, depletion and amortization		8		81			80		12
	Impairment and ceiling test charges(1)		18		44			—		—
	Other expense		17		53			58		20
	Total operating expenses		79		314			260		48
	Gain on sale of assets		2		468			—		—
	Other income (expense)		4		(2		)	3		(5		)
	Income (loss) from discontinued operations before income taxes		9		513			52		(7		)
	Income tax expense		5		7			2		2
	Income (loss) from discontinued operations		$	4	$	506		$	50	$	(9	)
		-1		During the year ended December 31, 2014, we recorded $18 million in impairment charges to impair earnings subsequent to entering into a Quota Purchase Agreement to sell our Brazil operations.  During the year ended December 31, 2013, we recorded $44 million in impairment charges ($34 million to impair earnings subsequent to entering into the Quota Purchase Agreement and $10 million based on a comparison of the fair value of our Brazil operations to its underlying carrying value).
			December 31,
			2013
			(in millions)
	Assets of discontinued operations
	Current assets		$	37
	Property, plant and equipment, net		246
	Other non-current assets		10
	Total assets of discontinued operations		$	293
	Liabilities of discontinued operations
	Accounts payable		$	50
	Other current liabilities		10
	Asset retirement obligations		60
	Other non-current liabilities		5
	Total liabilities of discontinued operations		$	125
	Other Divestitures.  In 2014, we closed the sale of certain non-core acreage in Eagle Ford in Atascosa County for approximately $28 million. No gain or loss on the sale was recorded. 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 these other domestic properties; however, in connection with entering into the sale of Four Star, we recorded a $20 million impairment in earnings from unconsolidated affiliates. See Note 10 for further discussion.
	In 2012, we sold our interests in Egypt for approximately $22 million and sold oil and natural gas properties located in the Gulf of Mexico for a net purchase price of approximately $79 million. We did not record a gain or loss on any of these sales as the purchase price allocated to the assets sold was reflective of the estimated sales price of these properties and the relationship between capitalized costs and proved reserves was not altered.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Taxes
Income Taxes	3.  Income Taxes
	General. As a result of the Corporate Reorganization on August 30, 2013 described in Note 1, we became a corporation subject to federal and state income taxes. Accordingly, we began recording the effects of income taxes in our financial statements 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 the Corporate Reorganization, we were a limited liability company treated as a partnership for federal and state income tax purposes. During that time, our Brazil operations continued to be subject to foreign income taxes; however, amounts related to Brazil have been reclassified in all periods as discontinued operations (see Note 2). Prior to the Acquisition (May 25, 2012), the predecessor was party to a tax accrual policy with El Paso whereby El Paso filed U.S. and certain state returns on the predecessor’s behalf. Under its policy, the predecessor recorded federal and state income taxes on a separate return basis and reflected current and deferred income taxes in the financial statements through the acquisition date.
	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:
		Successor									Predecessor
		Year ended			Year ended			February 14			January 1 to
		December 31,			December 31,			to			May 24,
		2014			2013			December 31,			2012
								2012
					(in millions)
	Pretax Income (Loss)
	U.S.	$	1,159		$	8		$	(306	)	$	384
	Foreign	—			—			—			(63		)
		$	1,159		$	8		$	(306	)	$	321
	Components of Income Tax Expense (Benefit)
	Current
	Federal	$	—		$	(2	)	$	—		$	(62	)
	State	—			—			—			(3		)
		—			(2		)	—			(65		)
	Deferred
	Federal	415			59			—			188
	State	17			7			—			11
		432			66			—			199
	Total income tax expense	$	432		$	64		$	—		$	134
	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:
		Successor									Predecessor
		Year ended			Year ended			February 14			January 1 to
		December 31,			December 31,			to			May 24,
		2014			2013			December 31,			2012
								2012
								(in millions)
	Income taxes at the statutory federal rate of 35%	$	406		$	3		$	(107	)	$	112
	Increase (decrease)
	State income taxes, net of federal income tax effect	12			4			—			5
	Partnership earnings not subject to tax	—			57			107			—
	Earnings from unconsolidated affiliates where we received or will receive dividends	—			—			—			(2		)
	Foreign income taxed at different rates	—			—			—			22
	Non-deductible reorganization costs	10			—			—			—
	Other	4			—			—			(3		)
	Income tax expense	$	432		$	64		$	—		$	134
	The effective tax rate for the year ended December 31, 2014 was 37.3%, higher than the statutory rate of 35% primarily as a 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 December 2014.  The effective tax rates for both the year ended December 31, 2013 and the period from February 14 to December 31, 2012, 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. The effective tax rate for the predecessor period from January 1, 2012 to May 24, 2012 was significantly higher than the statutory rate primarily due to the impact of an Egyptian non-cash charge without a corresponding tax benefit.
	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,
		2014			2013
		(in millions)
	Deferred tax assets
	Net operating loss and tax credit carryovers	$	542		$	252
	Employee benefits	1			2
	Investment in partnership	—			11
	Financial derivatives	—			3
	Legal and other reserves	5			2
	Asset retirement obligations	15			19
	Transaction costs	21			21
	Total deferred tax assets	584			310
	Valuation allowance	(1		)	—
	Net deferred tax assets	583			310
	Deferred tax liabilities
	Property, plant and equipment	794			453
	Financial derivatives	367			—
	Total deferred tax liabilities	1,161			453
	Net deferred tax liabilities	$	578		$	143
	Unrecognized Tax Benefits. We are currently not under any U.S. or state income tax audits; however, the 2013 and 2014 tax years remain open to examination.  Furthermore, pursuant to the Acquisition agreement, KMI indemnified us for any U.S. or state liability due to most of our entities having been members of the El Paso federal and state returns for any adjustments through the Acquisition date.  As of December 31, 2014 there were no unrecognized tax benefits as income taxes in our financial statements in continuing operations. We did not recognize any interest and penalties related to unrecognized tax benefits (classified as income taxes in our consolidated income statements) in 2014 or 2013, nor do we have any accrued interest and penalties in our consolidated balance sheet as of December 31, 2014 and December 31, 2013.
	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, 2014 (in millions):
	Expiration Period
	2031 - 2033
U.S. federal net operating loss	$	1,466
	2016 - 2028
State net operating loss	$	226
Net Operating Loss and Tax Credit Carryovers. In addition to our federal and state 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 all 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.  The realization of our deferred tax assets depends on recognition of sufficient future taxable income in specific tax jurisdictions during periods in which those temporary differences are deductible. Valuation allowances are established when necessary to reduce deferred income tax assets to the amounts we believe are more likely than not to be recovered. In evaluating our valuation allowances, we consider 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, the latter two of which involve the exercise of significant judgment. Changes to our valuation allowances could materially impact our results of operations.
As of December 31, 2014 and 2013, we had recorded $1 million and less than $1 million in valuation allowances on certain state net operating losses expiring in five years and where it was more likely than not they would not be realized.  We continually monitor the realization of loss carryovers with the appropriate character of income.  We believe it is more likely than not that we will realize the benefit of our deferred tax assets, net of existing valuation allowances.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2014
Earnings Per Share
Earnings Per Share	4.  Earnings Per Share
	On January 2, 2014, we completed a 62.553-for-1 stock split of our common stock. For the successor financial statement periods, 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 balance sheet and statement of changes in equity reflect the effects of the stock split. Neither earnings per share nor the effects of the stock split were presented in predecessor periods prior to the Acquisition as the predecessor operated under a different capital structure than the successor.  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. These potentially dilutive securities consist of our employee stock options and restricted stock which did not affect diluted earnings per share for the year ended December 31, 2014.

Financial_Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2014
Financial Instruments
Financial Instruments	5.  Financial Instruments
	The following table presents the carrying amounts and estimated fair values of the financial instruments:
			December 31, 2014						December 31, 2013
			Carrying			Fair Value			Carrying			Fair Value
			Amount						Amount
			(in millions)
	Long-term debt		$	4,598		$	4,582		$	4,421		$	4,841
	Derivative instruments		$	1,048		$	1,048		$	109		$	109
	For the years ended December 31, 2014 and 2013, 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 7) 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 related to these instruments.
	Oil and Natural Gas 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, 2014 and 2013, we had total derivative contracts of 37 MMBbls and 47 MMBbls of oil and 69 TBtu and 135 TBtu of natural gas, respectively. None of these contracts are designated as accounting hedges.
	The following table reflects the volumes associated with derivative contracts entered into between January 1, 2015 and February 16, 2015.
			2016		2017
			Volumes		Volumes
	Oil (MBbls)
	Fixed Price Swaps
	WTI(1)		3,294		4,015
	Basis Swaps
	LLS vs. WTI(2)		1,830		—
		-1		In February 2015, we unwound 3,294 MBbls of 2016 LLS three way collars in exchange for 3,294 MBbls of 2016 WTI fixed price swaps. No cash or other consideration was included as part of this exchange.
		-2		In February 2015, we unwound 1,830 MBbls of 2016 LLS vs. Brent basis swaps in exchange for 1,830 MBbls of 2016 LLS vs. WTI basis swaps. No cash or other consideration was included as part of this exchange.
	Interest Rate Derivative Instruments. We have interest rate swaps with a notional amount of $600 million that extend through April 2017 and are intended to reduce variable interest rate risk. As of December 31, 2014 and 2013, we had a net asset of $3 million and $4 million, respectively, related to interest rate derivative instruments included in our consolidated balance sheets. For the years ended December 31, 2014 and 2013 and the period from February 14 to December 31, 2012, we recorded $5 million of interest expense, $3 million of interest income and $3 million of interest expense, respectively, related to the change in fair market value and cash settlements of our interest rate derivative instruments.
	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.
	As of December 31, 2014 and 2013, all derivative financial instruments were classified as Level 2. Our assessment of an instrument within a level 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.
	Financial Statement Presentation.  The following table presents the fair value associated with derivative financial instruments as of December 31, 2014 and 2013.  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(1)						Balance Sheet Location						Gross(1)						Balance Sheet Location
			Fair			Impact of			Current			Non-			Fair			Impact of			Current			Non-
			Value			Netting						current			Value			Netting						current
						(in millions)												(in millions)
	December 31, 2014
	Derivative instruments		$	1,093		$	(44	)	$	752		$	297		$	(45	)	$	44	$		(1	)	$	—
	December 31, 2013
	Derivative instruments		$	164		$	(20	)	$	47		$	97		$	(55	)	$	20	$		(35	)	$	—
		-1		Gross derivative assets are comprised primarily of $1,088 million of oil and natural gas derivatives as of December 31, 2014, $157 million of oil and natural gas derivatives as of December 31, 2013, and $5 million and $7 million of interest rate derivatives as of December 31, 2014 and December 31, 2013, respectively.  Gross derivative liabilities are comprised primarily of $43 million of oil and natural gas derivatives as of December 31, 2014, $52 million of oil and natural gas derivatives as of December 31, 2013 and $2 million and $3 million of interest rate derivatives as of December 31, 2014 and December 31, 2013, respectively.
	The following table presents gains and losses on financial oil and natural gas derivative instruments presented in operating revenues and dedesignated cash flow hedges of the predecessor included in accumulated other comprehensive income (in millions):
			Successor										Predecessor
			Year ended			Year ended			February 14				January 1
			December 31,			December 31,			to				to
									December 31,				May 24,
			2014			2013			2012				2012
	Gains (losses) on financial derivative instruments		$	985		$	(52	)	$	(62	)		$	365
	Accumulated other comprehensive income		—			—			—				5
	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, 2014 represent financial instruments from twelve counterparties; all of which are financial institutions that have an “investment grade” (minimum Standard & Poor’s rating of A- or better) credit rating and are lenders associated with our $2.75 billion RBL credit facility. Subject to the terms of our $2.75 billion RBL credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the RBL Facility.

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment
Property, Plant and Equipment	6.  Property, Plant and Equipment
	Oil and Natural Gas Properties.  As of December 31, 2014 and 2013, we had approximately $8.7 billion and $7.4 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. At December 31, 2014 and 2013, the cost associated with unproved oil and natural gas properties totaled approximately $0.7 billion and $1.4 billion, respectively.  During 2014, we transferred approximately $0.7 billion from unproved properties to proved properties. During 2014, 2013 and the period from February 14 to December 31, 2012, we recorded $18 million, $36 million and $23 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, 2014 or December 31, 2013.
	Impairment Assessment / Ceiling Test Charges. Forward commodity prices can play a significant role in determining future impairments of our proved or unproved property. Due to the significant decline in oil prices in the fourth quarter of 2014, we reviewed our proved and unproved property for impairment.  In 2014, 2013 and from the Acquisition (May 25, 2012) to December 31, 2012, all periods under which we applied the successful efforts method, we did not record any impairments of our oil and gas properties included in continuing operations. Under the full cost method of accounting, the predecessor recorded a non-cash charge of approximately $62 million in the period from January 1 to May 24, 2012, as a result of the decision to exit exploration and development activities in Egypt.  The charge related to unevaluated costs in that country and included approximately $2 million related to equipment.  Considering the significant amount of fair value allocated to our natural gas and oil properties in conjunction with the Acquisition, sustained lower oil and natural gas prices, further price reductions or changes to our future capital and development plans due to the lower price environment could result in an impairment of the carrying value of our proved and/or unproved properties in the future, and such charges could be significant.
	Leasehold acquisition costs associated with non-producing areas are assessed for impairment based on our estimated drilling plans and capital expenditures relative to potential lease expirations. Our unproved property costs were approximately $0.7 billion at December 31, 2014, of which approximately $0.4 billion was associated with Wolfcamp, $0.2 billion with Altamont and $0.1 billion with Eagle Ford. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing exploration and development activities.  Our allocation of capital to the development of unproved properties may be influenced by changes in commodity prices (e.g. the rapid decline in oil prices in the fourth quarter of 2014), the availability of drilling rigs and associated costs, and/or the relative returns of our unproved property development in comparison to the use of capital for other strategic objectives.  Due to the significant decline in oil prices, we have reduced our expected capital expenditures in certain of our operating areas for 2015; however, we currently have the intent and ability to fulfill our drilling commitments prior to the expiration of the associated leases.  Among other factors, should oil prices not justify sufficient capital allocation to the continued development of these unproved properties, we could incur impairment charges of our unproved property, and such charges could be significant.
	Asset Retirement Obligations.  We have legal asset retirement obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We incur 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 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:
		2014			2013
		(in millions)
	Net asset retirement liability at January 1	$	30		$	24
	Liabilities incurred	10			6
	Liabilities settled	(2		)	(2		)
	Accretion expense	3			2
	Changes in estimate	2			1
	Property sales	—			(1		)
	Other	(1		)	—
	Net asset retirement liability at December 31	$	42		$	30
	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 year ended December 31, 2014 and 2013 was approximately $21 million and $19 million, respectively.  For the period from February 14 to December 31, 2012, capitalized interest was $12 million, and for the predecessor period from January 1, 2012 to May 24, 2012, it was $4 million.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Long-Term Debt
Long-Term Debt	7.  Long Term Debt
	Listed below are our debt obligations as of the periods presented:
			Interest Rate		December 31, 2014			December 31, 2013
					(in millions)
	EP Energy LLC
	$2.75 billion RBL credit facility - due May 24, 2017		Variable		$	852		$	295
	$750 million senior secured term loan - due May 24, 2018(1)(3)		Variable		496			495
	$400 million senior secured term loan - due April 30, 2019(2)(3)		Variable		150			149
	$750 million senior secured notes - due May 1, 2019(3)		6.875	%	750			750
	$2.0 billion senior unsecured notes - due May 1, 2020		9.375	%	2,000			2,000
	$350 million senior unsecured notes - due September 1, 2022		7.75	%	350			350
	EPE Holdings LLC
	$350 million senior PIK toggle note - due December 15, 2017(4)		8.125%/8.875	%	—			382
	Total				$	4,598		$	4,421
		-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, 2014 and 2013, 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, 2014 and 2013, the effective interest rate for the term loan was 4.50%.
		-3		The term loans and secured notes 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.
		-4		In 2014, we repaid our senior PIK toggle note with proceeds from our initial public offering.
	As of December 31, 2014 and 2013, we had $90 million and $116 million, respectively, in deferred financing costs on our consolidated balance sheets. During 2014, 2013, the period from February 14 to December 31, 2012, and the predecessor period from January 1 to May 24, 2012, we amortized $21 million, $22 million, $12 million, and $7 million, respectively, of deferred financing costs in interest expense.
	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. During 2013 and the period from February 14 to December 31, 2012, we recorded $9 million and $14 million in losses on the extinguishment of debt. The 2013 losses were associated with the pro-rata portion of deferred financing costs written off in conjunction with (i) the repayment of approximately $250 million under each of our $750 million and $400 million term loans, (ii) our $750 million term loan re-pricing in May 2013 and (iii) the semi-annual redetermination of our RBL Facility in March 2013.  The 2012 losses were associated with the pro-rata portion of deferred financing costs written off, debt discount and call premiums paid related to lenders who exited or reduced their loan commitments in conjunction with our $750 million term loan repricing.
	$2.75 Billion Reserve-based Loan (RBL). 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, 2014, we had $852 million of outstanding borrowings and approximately $83 million of letters of credit issued under the facility, leaving $1.8 billion of remaining capacity available.  Listed below is a further description of our credit facility as of December 31, 2014:
	Credit Facility		Maturity		Interest		Commitment fees
			Date		Rate
	$2.75 billion RBL		May 24, 2017		LIBOR + 1.75%(1)		0.375% commitment fee on unused capacity
					1.75% for LCs
		-1		Based on our December 31, 2014 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.
	The RBL Facility is collateralized by certain of our oil and natural gas properties and has a borrowing base subject to semi-annual redetermination. In October 2014, we completed our semi-annual redetermination, increasing the borrowing base of our RBL Facility to $2.75 billion. Our next redetermination date is in April 2015.  Downward revisions of our oil and natural gas reserves due to future declines in commodity prices, performance revisions, sales of assets or the incurrence of certain types of additional debt, among other items, could cause a redetermination of the borrowing base and could negatively impact our ability to borrow funds 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, 2014, we were in compliance with our debt covenants.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies
Commitments and Contingencies	8.  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 of these matters, 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 related to these matters and adjust our accruals accordingly, and these adjustments could be material. As of December 31, 2014, we had approximately $2 million accrued for all outstanding legal matters.
	Southeast Louisiana Flood Protection Authority v. EP Energy Management, L.L.C.  On July 24, 2013, the levee authority for New Orleans and surrounds (the Authority) filed suit against 97 oil, gas and pipeline companies, seeking (among other relief) restoration of wetlands allegedly lost due to historic industry operations in those areas. The suit, which does not specify an amount of damages, was filed in Louisiana state court in New Orleans but then removed to the U.S. District Court for the Eastern District of Louisiana (the District Court). The Louisiana State Legislature has passed legislation that could result in dismissal of the lawsuit. Our subsidiary, EP Energy Management, L.L.C., is named as successor to Colorado Oil Company, Inc. and Gas Producing Enterprises as operators of five wells from the mid-1970s to 1980. On February 13, 2015, the District Court dismissed the case for failure to state a claim finding that the defendants had no duty to the Authority. The Authority will have 30 days from a final judgment to appeal to the U.S. Court of Appeals for the Fifth Circuit.
	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, 2014, we had approximately $8 million accrued related to these indemnifications and other matters.
	Sales Tax Audits. As a result of sales and use tax audits during 2010, the state of Texas asserted additional taxes plus penalties and interest for the audit period 2001-2008 for two of our operating entities. During 2013, we settled the last of these audits for approximately $3 million, including penalties and fees. As a result of the settlement, we recorded a reduction in taxes, other than income taxes in our consolidated income statement of approximately $13 million.
	Environmental Matters
	We are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and greenhouse gas (GHG) emissions. 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, 2014, we had accrued 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 exposure could be as high as $1 million.  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. There have also been various legislative and regulatory proposals and final rules at the federal and state levels to address emissions from power plants and industrial boilers, which will generally favor the use of natural gas over other fossil fuels such as coal.  It remains uncertain what regulations or amended final rules will ultimately be adopted and when they will be adopted. As part of the White House’s Climate Action Plan Strategy to Reduce Methane Emissions, the EPA has announced it will propose additional regulations in 2015 for the oil and gas industry addressing methane and other emissions.  Further, the Bureau of Land Management is expected to propose additional regulations for public lands in 2015, and the Pipeline and Hazardous Materials Safety Administration is expected to propose new standards in 2015 for natural gas pipelines.  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.
	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.  On May 22, 2014, the EPA extended this deadline to March 2, 2016, during which time the EPA anticipates separate rulemaking to create general permits for true minor sources in the oil and gas production industry.  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, the Department of the Interior 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.
	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, 2014, 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.
	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, 2014, were as follows:
	Year Ending December 31,	Operating Leases
		(in millions)
	2015	$	11
	2016	12
	2017	7
	Total	$	30
	Subsequent to December 31, 2014, we extended certain office leases and will pay an additional $5 million and $9 million in 2017 and 2018, respectively.  These amounts are not included in the table above.
	Rental expense for the successor periods for the years ended December 31, 2014 and 2013, and for the period from February 14 to December 31, 2012 was $13 million, $13 million and $10 million, respectively. Rental expense for the predecessor period from January 1, 2012 to May 24, 2012 was $1 million.
	Other Commercial Commitments
	At December 31, 2014, we have various commercial commitments totaling $809 million primarily related to commitments and contracts associated with volume and transportation, drilling rigs, completion activities and seismic activities. Our annual obligations under these arrangements are $184 million in 2015, $185 million in 2016, $83 million in 2017, $83 million in 2018, and $274 million thereafter.

LongTerm_Incentive_Compensatio

Long-Term Incentive Compensation / Retirement 401(k) Plan	12 Months Ended
	Dec. 31, 2014
Long-Term Incentive Compensation / Retirement 401(k) Plan
Long-Term Incentive Compensation	9.  Long-Term Incentive Compensation / Retirement 401(k) 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 11,179,603 shares remaining available for issuance as of December 31, 2014.  In addition, in conjunction with the Acquisition in 2012, certain employees received other LTI awards based on their purchased equity interests including (i) Class A “matching” units (subsequently converted into common shares upon our Corporate Reorganization) and (ii) a “guaranteed bonus” as well as (iii) 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, 2014 is presented below:
		Number of Shares		Weighted Average
				Grant Date Fair Value
				per Share
	Non-vested at December 31, 2013	—		$	—
	Granted	1,131,154		19.8
	Vested	(1,929	)	19.82
	Forfeited	(95,831	)	19.82
	Non-vested at December 31, 2014	1,033,394		$	19.8
	During 2014 we recognized approximately $5 million of pre-tax compensation expense and recorded income tax benefits of $2 million on our restricted share awards. The total unrecognized compensation cost related to these arrangements at December 31, 2014 was approximately $14 million, which is expected to be recognized over a weighted average period of 2 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, 2014 is presented below.
		Number of Shares		Weighted		Weighted	Aggregate
		Underlying		Average		Average	Intrinsic Value
		Options		Exercise Price		Remaining
				per Share		Contractual
						Term
						(in years)	(in millions)
	Outstanding at December 31, 2013	—		—
	Granted	253,740		$	19.82
	Forfeited or canceled	(34,388	)	19.82
	Outstanding at December 31, 2014	219,352		$	19.82	9.25	—
	During 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, 2014 was approximately $2 million, which is expected to be recognized over a weighted average period of 4 years. There were no options exercised during the year.
	Fair Value Assumptions.  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 years 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 grants in 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 use 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 2012 and 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. These cash-based LTI awards have a three-year vesting schedule (50% vesting at the end of the first year, and 25% vesting at the end of each of the succeeding two years). These performance based cash incentive awards 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 that will be amortized primarily on an accelerated basis over a three-year vesting period. For the years ended December 31, 2014 and 2013 and the period from February 14 to December 31, 2012, we recorded approximately $8 million, $16 million and $8 million, respectively, in expense related to these awards.  As of December 31, 2014, we had unrecognized compensation expense of $3 million related to these awards which we will recognize in 2015.
	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 four 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, 2014 and 2013 and the period from February 14 to December 31, 2012, we recognized approximately $2 million, $6 million and $11 million, respectively, as compensation expense related to both of these awards.  As of December 31, 2014, we had unrecognized compensation expense of $4 million related to the “matching” Class A unit grants, of which we will recognize $3 million in 2015 and the remainder 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, 2014 and 2013 and the period from February 14 to December 31, 2012, we recognized approximately $6 million, $19 million and $15 million, respectively, as compensation expense related to these awards.  As of December 31, 2014, we had unrecognized compensation expense of $9 million. Of this amount, we will recognize $6 million in 2015 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.
	Retirement 401(k) 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 2014 and 2013 and the period from February 14 to December 31, 2012, we had contributed $11 million, $12 million and $7 million, respectively, of matching and non-elective employer contributions.

Investment_in_Unconsolidated_A

Investment in Unconsolidated Affiliate	12 Months Ended
	Dec. 31, 2014
Investment in Unconsolidated Affiliate
Investment in Unconsolidated Affiliate	10.  Investments in Unconsolidated Affiliate
	As discussed in Note 2, in September 2013, we sold our equity investment in Four Star, for net proceeds of $183 million and recorded an impairment of $20 million based on comparison of net proceeds received to the underlying carrying value of our investment. Our consolidated income statement in 2012 and 2013 reflects (i) our share of net earnings directly attributable to Four Star, (ii) impairments of our investment and (iii) prior to its sale, the amortization of the excess of the carrying value of our investment relative to the underlying equity in the net assets of the entity.
	Below is summarized financial information of the operating results of Four Star.
		Successor				Predecessor
		Year Ended		February 14		January 1
		December 31,		to		to
		2013		December 31, 2012		May 24, 2012
				(in millions)
	Operating revenues	$	142	$	105	$	75
	Operating expenses	94		87		58
	Net income	30		11		11
	In addition to recording our share of Four Star operating results, we amortized the excess of our investment in Four Star prior to its sale over the underlying equity in its net assets using the unit-of-production method over the life of our estimate of Four Star’s oil and natural gas reserves. Amortization of our investment for the year ended December 31, 2013 and for the period of February 14 to December 31, 2012, was $8 million and $7 million, respectively. Amortization of our investment for the predecessor period from January 1 to May 24, 2012 was $12 million. Our financial results related to our equity investment in Four Star were included as other income (expense) on our consolidated income statements.
	For the year ended December 31, 2013 and the period from February 14 to December 31, 2012, we received dividends from Four Star of approximately $24 million and $13 million, respectively. Dividends received from Four Star for the predecessor period from January 1 to May 24, 2012 was $8 million.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions
Related Party Transactions	11.  Related Party Transactions
	Member Distribution.  In 2013, we made $205 million in distributions to our members including a leveraged distribution of approximately $200 million.
	Transaction Fee Agreement. Following the Acquisition, we were subject to a transaction fee agreement with certain of our Sponsors (the Service Providers) for the provision of certain structuring, financial, investment banking and other similar advisory services. At the time of the Acquisition, we paid one-time transaction fees of $71.5 million (recorded as general and administrative expense in our consolidated income statement) to the Service Providers in the aggregate in exchange for services rendered in connection with structuring, arranging the financing and performing other services. On December 20, 2013, the Transaction Fee Agreement was amended and restated in its entirety pursuant to which the requirement to pay an additional transaction fee to the Service Providers under the agreement was eliminated (and, as described below, an additional fee became payable under the amended and restated Management Fee Agreement). The amended and restated Transaction Fee Agreement terminated automatically in accordance with its terms upon the closing of our initial public offering.
	Management Fee Agreement. In January 2014, we paid a quarterly management fee of $6.25 million to our private equity investors (affiliates of Apollo Management LLC (Apollo), Riverstone Holdings LLC, Access Industries and Korea National Oil Corporation, collectively the Sponsors). Additionally, subject to the terms and conditions of the amended and restated Management Fee Agreement, 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. The amended and restated Management Fee Agreement, including the obligation to pay the quarterly management fee, terminated automatically in accordance with its terms upon the closing of our initial public offering.
	Affiliate Supply Agreement.  For the year ended December 31, 2014, we have recorded approximately $112 million in capital expenditures for amounts provided under two supply agreements entered into with an Apollo affiliate to provide certain fracturing materials for our Eagle Ford drilling operations.
	Related Party Transactions Prior to the Acquisition. At the time of the Acquisition, El Paso made total contributions of approximately $1.5 billion to the predecessor including a non-cash contribution of approximately $0.5 billion to satisfy its then current and deferred income tax balances and a cash contribution to facilitate repayment of approximately $960 million of then outstanding debt of the predecessor under its revolving credit facility. Additionally, prior to the completion of the Acquisition, the predecessor entered into transactions during the ordinary course of conducting its business with affiliates of El Paso, primarily related to the sale, transportation and hedging of its oil, natural gas and NGLs production.
	The agreements noted below ceased on the date of Acquisition and included the following services:
	General. El Paso billed the predecessor directly for certain general and administrative costs and allocated a portion of its general and administrative costs. The allocation was based on the estimated level of resources devoted to its operations and the relative size of its earnings before interest and taxes, gross property and payroll. These expenses were primarily related to management, legal, financial, tax, consultative, administrative and other services, including employee benefits, pension benefits, annual incentive bonuses, rent, insurance, and information technology. El Paso also billed the predecessor directly for compensation expense related to certain stock-based compensation awards granted directly to the predecessor’s employees, and allocated to the predecessor a proportionate share of El Paso’s corporate compensation expense.  Compensation cost associated with the acceleration of vesting as a result of the merger between El Paso and KMI was assumed by El Paso and KMI and is not reflected in the predecessor financial statements.
		·		Pension and Retirement Benefits.  El Paso maintained a primary pension plan, the El Paso Corporation Pension Plan, a defined benefit plan covering substantially all of our employees prior to the Acquisition and providing benefits under a cash balance formula. El Paso also maintained a defined contribution plan covering all of our employees prior to the Acquisition. El Paso matched 75% of participant basic contributions up to 6 percent of eligible compensation and made additional discretionary matching contributions. El Paso was responsible for benefits accrued under these plans and allocated related costs.
		·		Other Post-Retirement Benefits.  El Paso provided limited post-retirement life insurance benefits for current and retired employees prior to the Acquisition. El Paso was responsible for benefits accrued under its plan and allocated the related costs to its affiliates.
		·		Marketing. Prior to the completion of the Acquisition, the predecessor sold natural gas primarily to El Paso Marketing at spot market prices. The predecessor was also a party to a hedging contract with El Paso Marketing. Realized gains and losses on these hedges were included in operating revenues.
		·		Transportation and Related Services. Prior to the completion of the Acquisition, the predecessor contracted for services with El Paso’s regulated interstate pipelines that provided transportation and related services for natural gas production.
	The following table shows revenues and charges to/from affiliates for the following predecessor period (in millions):
			January 1
			to May 24,
			2012
	Operating revenues		$	143
	Operating expenses		44
	Reimbursements of operating expenses		—
		·		Income Taxes.  Prior to the Acquisition, El Paso filed consolidated U.S. federal and certain state tax returns which included the predecessor’s taxable income. See Note 3 for additional information on income tax related matters.
		·		Cash Management Program. Prior to the Acquisition, our predecessor participated in El Paso’s cash management program which matched short-term cash surpluses and needs of its participating affiliates, thus minimizing total borrowings from outside sources.

Basis_of_Presentation_and_Sign1

Basis of Presentation and Significant Accounting Policies (Polices)	12 Months Ended
	Dec. 31, 2014
Basis of Presentation and Significant Accounting Policies
Basis of Presentation	Basis of Presentation and Consolidation
	EP Energy Corporation was reorganized on August 30, 2013 as a corporate holding company with a 100% equity interest in EPE Acquisition, LLC. Prior to this corporate reorganization, activities were conducted through EPE Acquisition, LLC, a holding company formed on February 14, 2012. EPE Acquisition, LLC had two classes of membership interests: Class A membership units and Class B membership units. The Class A membership units represented the full value of our capital interests, and the Class B membership units represented profits interests (for further information see Note 9). As part of the corporate reorganization, (i) all of the Class A and Class B membership units in EPE Acquisition, LLC were directly or indirectly exchanged for shares of Class A and Class B common stock, respectively of EP Energy Corporation, which have the same interests, rights and obligations of the Class A and B membership units.
	EPE Acquisition, LLC had no independent operations and through its wholly-owned subsidiaries, owned the units of EP Energy LLC (which owned 100 percent of EP Energy Global LLC). On May 24, 2012, Apollo Global Management LLC (together with its subsidiaries, Apollo) and other private equity investors (collectively, the Sponsors) acquired EP Energy Global LLC and subsidiaries for approximately $7.2 billion in cash (the Acquisition) as contemplated by the merger agreement among El Paso Corporation (El Paso) and Kinder Morgan, Inc. (KMI) which is further described in Note 2. The acquired entities engage in the exploration for and the acquisition, development, and production of oil, natural gas and NGLs in the United States. Hereinafter, for periods prior to the Acquisition in 2012, the acquired entities are referred to as the predecessor for financial accounting and reporting purposes.
	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. Predecessor periods reflect reclassifications to conform to EP Energy Corporation’s financial statement presentation.
	We consolidate entities when we have the ability to control the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions and activities of an entity.
	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 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.  Retrospective application of this standard is required beginning in the first quarter of 2017.  We are currently evaluating the impact, if any, that this update will have on our financial statements.
	Discontinued Operations.  In April 2014, the FASB issued Accounting Standards Update No. 2014-08, Presentation of Financial Statements and Property, Plant, and Equipment: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which alters the criteria under which assets to be disposed of are evaluated for reporting as a discontinued operation.  While early adoption of this update is permitted, prospective application is required in the first quarter of 2015.  Accordingly, the update will not impact our historical presentation of assets as discontinued operations. The revised standard will (i) raise the threshold for divestitures to qualify as discontinued operations and (ii) require new disclosures for both discontinued operations and material divestitures which do not qualify as discontinued operations.
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 natural gas on a monthly basis to manage our overall natural gas production and sales. These transactions are undertaken to optimize prices we receive for our natural gas, to physically move gas to its intended sales point, or to manage firm transportation agreements. Revenue related to these transactions are recorded in natural gas sales in operating revenues and associated purchases reflected in natural gas purchases in operating expenses on our consolidated income statement.
	For the years ended December 31, 2014 and 2013 and the successor period in 2012, we had two customers that individually accounted for 10 percent or more of our total revenues.  The predecessor period in 2012 had three customers that individually accounted for 10 percent or more of 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	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, 2014 and 2013, we had less than $1 million, of restricted cash in other current assets to cover escrow amounts required for leasehold agreements in our operations.
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
	Successful Efforts (Successor). In conjunction with the Acquisition, we began applying 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 by major prospect area based on our estimates or current drilling plans.
	Full Cost (Predecessor). Prior to the Acquisition, the predecessor used the full cost method to account for their oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves were capitalized on a country-by-country basis. These capitalized amounts included the costs of unproved properties that were transferred into the full cost pool when the properties were determined to have proved reserves, internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs were capitalized into the full cost pool, which was subject to amortization and was periodically assessed for impairment through a ceiling test calculation discussed below.
	Under full cost accounting, capitalized costs associated with proved reserves were amortized over the life of the proved reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties were excluded from the amortizable base until these properties were evaluated or determined that the costs were impaired. On a quarterly basis, unproved property costs were transferred into the amortizable base when properties were determined to have proved reserves. If costs were determined to be impaired, the amount of any impairment was transferred to the full cost pool if an oil or natural gas reserve base exists, or was expensed if a reserve base has not yet been created. The amortizable base included future development costs; dismantlement, restoration and abandonment costs, net of estimated salvage values; and geological and geophysical costs incurred that could not be associated with specific unevaluated properties or prospects in which we owned a direct interest.
	Under full cost accounting, capitalized costs in each country, net of related deferred income taxes, were limited to a ceiling based on the present value of future net revenues from proved reserves less estimated future capital expenditures, discounted at 10 percent, plus the cost of unproved oil and natural gas properties not being amortized, less related income tax effects.  Prior to the Acquisition, this ceiling test calculation was performed each quarter.  The prices used when performing the ceiling test were based on the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period. These prices were required to be held constant over the life of the reserves, even though actual prices of oil and natural gas changed from period to period.  If total capitalized costs exceeded the ceiling, a write down of capitalized costs to the ceiling was required. Any required write-down was included as a ceiling test charge in the consolidated income statement and as an increase to accumulated depreciation, depletion and amortization on the consolidated balance sheet. The present value of future net revenues used for these ceiling test calculations excluded the impact of derivatives and the estimated future cash outflows associated with asset retirement liabilities related to proved developed reserves.
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 three 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 9 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 5 for a further discussion of our derivatives.
Income Tax	Income Taxes
	We record current income taxes based on our estimates of current taxable income and provide for deferred income taxes to reflect estimated future income tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We 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 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.
	Prior to the Acquisition, the predecessor’s taxable income or loss was included in El Paso’s U.S. federal and certain state returns and we recorded income taxes on a separate return basis in our financial statements as if we had filed separate income tax returns under our then existing structure for the periods presented in accordance with a tax sharing agreement between us and El Paso. Under that agreement El Paso paid all consolidated U.S. federal and state income tax directly to the appropriate taxing jurisdictions and, under a separate tax billing agreement, El Paso billed or was refunded for their portion of these income taxes. In certain states, the predecessor filed and paid taxes directly to the state taxing authorities.

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2014
Acquisitions and Divestitures
Business Acquisition, Pro Forma Information
			Year ended
			December 31,
			2012
			(in millions)
	Operating Revenues		$	1,659
	Net Income		143
Summary of operating results and financial position data of discontinued operations
			Successor							Predecessor
			Year ended		Year ended			February 14		January 1
			December 31,		December 31,			to		to
			2014		2013			December 31,		May 24,
								2012		2012
								(in millions)
	Operating revenues		$	82	$	361		$	309	$	46
	Operating expenses
	Natural gas purchases		—		19			23		—
	Transportation costs		5		25			25		—
	Lease operating expense		31		92			74		16
	Depreciation, depletion and amortization		8		81			80		12
	Impairment and ceiling test charges(1)		18		44			—		—
	Other expense		17		53			58		20
	Total operating expenses		79		314			260		48
	Gain on sale of assets		2		468			—		—
	Other income (expense)		4		(2		)	3		(5		)
	Income (loss) from discontinued operations before income taxes		9		513			52		(7		)
	Income tax expense		5		7			2		2
	Income (loss) from discontinued operations		$	4	$	506		$	50	$	(9	)
		-1		During the year ended December 31, 2014, we recorded $18 million in impairment charges to impair earnings subsequent to entering into a Quota Purchase Agreement to sell our Brazil operations.  During the year ended December 31, 2013, we recorded $44 million in impairment charges ($34 million to impair earnings subsequent to entering into the Quota Purchase Agreement and $10 million based on a comparison of the fair value of our Brazil operations to its underlying carrying value).
			December 31,
			2013
			(in millions)
	Assets of discontinued operations
	Current assets		$	37
	Property, plant and equipment, net		246
	Other non-current assets		10
	Total assets of discontinued operations		$	293
	Liabilities of discontinued operations
	Accounts payable		$	50
	Other current liabilities		10
	Asset retirement obligations		60
	Other non-current liabilities		5
	Total liabilities of discontinued operations		$	125

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Taxes
Schedule of pretax income (loss) from continuing operations and the components of income tax expense (benefit) from continuing operations
		Successor									Predecessor
		Year ended			Year ended			February 14			January 1 to
		December 31,			December 31,			to			May 24,
		2014			2013			December 31,			2012
								2012
					(in millions)
	Pretax Income (Loss)
	U.S.	$	1,159		$	8		$	(306	)	$	384
	Foreign	—			—			—			(63		)
		$	1,159		$	8		$	(306	)	$	321
	Components of Income Tax Expense (Benefit)
	Current
	Federal	$	—		$	(2	)	$	—		$	(62	)
	State	—			—			—			(3		)
		—			(2		)	—			(65		)
	Deferred
	Federal	415			59			—			188
	State	17			7			—			11
		432			66			—			199
	Total income tax expense	$	432		$	64		$	—		$	134
Schedule of pretax income (loss), components of income tax expense (benefit) and effective tax rates
		Successor									Predecessor
		Year ended			Year ended			February 14			January 1 to
		December 31,			December 31,			to			May 24,
		2014			2013			December 31,			2012
								2012
								(in millions)
	Income taxes at the statutory federal rate of 35%	$	406		$	3		$	(107	)	$	112
	Increase (decrease)
	State income taxes, net of federal income tax effect	12			4			—			5
	Partnership earnings not subject to tax	—			57			107			—
	Earnings from unconsolidated affiliates where we received or will receive dividends	—			—			—			(2		)
	Foreign income taxed at different rates	—			—			—			22
	Non-deductible reorganization costs	10			—			—			—
	Other	4			—			—			(3		)
	Income tax expense	$	432		$	64		$	—		$	134
Schedule of deferred tax assets and liabilities
		December 31,			December 31,
		2014			2013
		(in millions)
	Deferred tax assets
	Net operating loss and tax credit carryovers	$	542		$	252
	Employee benefits	1			2
	Investment in partnership	—			11
	Financial derivatives	—			3
	Legal and other reserves	5			2
	Asset retirement obligations	15			19
	Transaction costs	21			21
	Total deferred tax assets	584			310
	Valuation allowance	(1		)	—
	Net deferred tax assets	583			310
	Deferred tax liabilities
	Property, plant and equipment	794			453
	Financial derivatives	367			—
	Total deferred tax liabilities	1,161			453
	Net deferred tax liabilities	$	578		$	143
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, 2014 (in millions):
		Expiration Period
		2031 - 2033
	U.S. federal net operating loss	$	1,466
		2016 - 2028
	State net operating loss	$	226

Financial_Instruments_Tables

Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Financial Instruments
Schedule of carrying amounts and estimated fair values of the financial instruments
			December 31, 2014						December 31, 2013
			Carrying			Fair Value			Carrying			Fair Value
			Amount						Amount
			(in millions)
	Long-term debt		$	4,598		$	4,582		$	4,421		$	4,841
	Derivative instruments		$	1,048		$	1,048		$	109		$	109
Schedule of volumes associated with derivative financial instruments
			2016		2017
			Volumes		Volumes
	Oil (MBbls)
	Fixed Price Swaps
	WTI(1)		3,294		4,015
	Basis Swaps
	LLS vs. WTI(2)		1,830		—
		-1		In February 2015, we unwound 3,294 MBbls of 2016 LLS three way collars in exchange for 3,294 MBbls of 2016 WTI fixed price swaps. No cash or other consideration was included as part of this exchange.
		-2		In February 2015, we unwound 1,830 MBbls of 2016 LLS vs. Brent basis swaps in exchange for 1,830 MBbls of 2016 LLS vs. WTI basis swaps. No cash or other consideration was included as part of this exchange.
Schedule of fair value associated with derivative financial instruments
			Level 2
			Derivative Assets												Derivative Liabilities
			Gross(1)						Balance Sheet Location						Gross(1)						Balance Sheet Location
			Fair			Impact of			Current			Non-			Fair			Impact of			Current			Non-
			Value			Netting						current			Value			Netting						current
						(in millions)												(in millions)
	December 31, 2014
	Derivative instruments		$	1,093		$	(44	)	$	752		$	297		$	(45	)	$	44	$		(1	)	$	—
	December 31, 2013
	Derivative instruments		$	164		$	(20	)	$	47		$	97		$	(55	)	$	20	$		(35	)	$	—
		-1		Gross derivative assets are comprised primarily of $1,088 million of oil and natural gas derivatives as of December 31, 2014, $157 million of oil and natural gas derivatives as of December 31, 2013, and $5 million and $7 million of interest rate derivatives as of December 31, 2014 and December 31, 2013, respectively.  Gross derivative liabilities are comprised primarily of $43 million of oil and natural gas derivatives as of December 31, 2014, $52 million of oil and natural gas derivatives as of December 31, 2013 and $2 million and $3 million of interest rate derivatives as of December 31, 2014 and December 31, 2013, respectively.
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position	The following table presents gains and losses on financial oil and natural gas derivative instruments presented in operating revenues and dedesignated cash flow hedges of the predecessor included in accumulated other comprehensive income (in millions):
			Successor										Predecessor
			Year ended			Year ended			February 14				January 1
			December 31,			December 31,			to				to
									December 31,				May 24,
			2014			2013			2012				2012
	Gains (losses) on financial derivative instruments		$	985		$	(52	)	$	(62	)		$	365
	Accumulated other comprehensive income		—			—			—				5

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment
Schedule of changes in net asset retirement liability
		2014			2013
		(in millions)
	Net asset retirement liability at January 1	$	30		$	24
	Liabilities incurred	10			6
	Liabilities settled	(2		)	(2		)
	Accretion expense	3			2
	Changes in estimate	2			1
	Property sales	—			(1		)
	Other	(1		)	—
	Net asset retirement liability at December 31	$	42		$	30

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Long-Term Debt
Schedule of debt obligations
			Interest Rate		December 31, 2014			December 31, 2013
					(in millions)
	EP Energy LLC
	$2.75 billion RBL credit facility - due May 24, 2017		Variable		$	852		$	295
	$750 million senior secured term loan - due May 24, 2018(1)(3)		Variable		496			495
	$400 million senior secured term loan - due April 30, 2019(2)(3)		Variable		150			149
	$750 million senior secured notes - due May 1, 2019(3)		6.875	%	750			750
	$2.0 billion senior unsecured notes - due May 1, 2020		9.375	%	2,000			2,000
	$350 million senior unsecured notes - due September 1, 2022		7.75	%	350			350
	EPE Holdings LLC
	$350 million senior PIK toggle note - due December 15, 2017(4)		8.125%/8.875	%	—			382
	Total				$	4,598		$	4,421
		-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, 2014 and 2013, 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, 2014 and 2013, the effective interest rate for the term loan was 4.50%.
		-3		The term loans and secured notes 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.
		-4		In 2014, we repaid our senior PIK toggle note with proceeds from our initial public offering.
Schedule of description of credit facility	Listed below is a further description of our credit facility as of December 31, 2014:
	Credit Facility		Maturity		Interest		Commitment fees
			Date		Rate
	$2.75 billion RBL		May 24, 2017		LIBOR + 1.75%(1)		0.375% commitment fee on unused capacity
					1.75% for LCs
		-1		Based on our December 31, 2014 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, 2014
Commitments and Contingencies
Schedule of Future Minimum Rental Payments for Operating Leases
	Year Ending December 31,	Operating Leases
		(in millions)
	2015	$	11
	2016	12
	2017	7
	Total	$	30

LongTerm_Incentive_Compensatio1

Long-Term Incentive Compensation / Retirement 401(k) Plan (Tables)	12 Months Ended
	Dec. 31, 2014
Long-Term Incentive Compensation / Retirement 401(k) Plan
Schedule of the changes in non-vested restricted shares
		Number of Shares		Weighted Average
				Grant Date Fair Value
				per Share
	Non-vested at December 31, 2013	—		$	—
	Granted	1,131,154		19.8
	Vested	(1,929	)	19.82
	Forfeited	(95,831	)	19.82
	Non-vested at December 31, 2014	1,033,394		$	19.8
Schedule of stock option
		Number of Shares		Weighted		Weighted	Aggregate
		Underlying		Average		Average	Intrinsic Value
		Options		Exercise Price		Remaining
				per Share		Contractual
						Term
						(in years)	(in millions)
	Outstanding at December 31, 2013	—		—
	Granted	253,740		$	19.82
	Forfeited or canceled	(34,388	)	19.82
	Outstanding at December 31, 2014	219,352		$	19.82	9.25	—
Schedule weighted average of each assumption	Listed below is the weighted average of each assumption based on grants in 2014:
	Expected Term in Years	7.0
	Expected Volatility	40	%
	Expected Dividends	—
	Risk-Free Interest Rate	2.3	%

Investment_in_Unconsolidated_A1

Investment in Unconsolidated Affiliate (Tables)	12 Months Ended
	Dec. 31, 2014
Investment in Unconsolidated Affiliate
Schedule of operating results of Four Star
		Successor				Predecessor
		Year Ended		February 14		January 1
		December 31,		to		to
		2013		December 31, 2012		May 24, 2012
				(in millions)
	Operating revenues	$	142	$	105	$	75
	Operating expenses	94		87		58
	Net income	30		11		11

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions
Schedule of revenues and charges to/from affiliates	The following table shows revenues and charges to/from affiliates for the following predecessor period (in millions):
		January 1
		to May 24,
		2012
	Operating revenues	$	143
	Operating expenses	44
	Reimbursements of operating expenses	—

Basis_of_Presentation_and_Sign2

Basis of Presentation and Significant Accounting Policies (Details) (USD $)	12 Months Ended	0 Months Ended	1 Months Ended	0 Months Ended
In Billions, unless otherwise specified	Dec. 31, 2014	Feb. 14, 2012	Aug. 31, 2013	24-May-12
	segment	item
Acquisitions
Number of operating segments	1
EPE Acquisition LLC
Acquisitions
Ownership interest held in EPE Acquisition LLC			100.00%
Number of classes of membership interests		2
EP Energy Global LLC
Acquisitions
Ownership interest held by subsidiary	100.00%
Cash paid for acquisition of EP Energy Global LLC				$7.20

Basis_of_Presentation_and_Sign3

Basis of Presentation and Significant Accounting Policies (Details 2) (Customer concentration risk)	12 Months Ended			5 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	24-May-12
	item	item	item	item
Total revenues
Revenue Recognition
Number of major customers	2	2	2
Member's Equity Predecessor
Revenue Recognition
Number of major customers				3
Member's Equity Predecessor | Total revenues
Revenue Recognition
Number of major customers	1

Basis_of_Presentation_and_Sign4

Basis of Presentation and Significant Accounting Policies (Details 3) (Maximum, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Maximum
Cash and Cash Equivalents
Restricted cash	$1	$1

Basis_of_Presentation_and_Sign5

Basis of Presentation and Significant Accounting Policies (Details 4) (Member's Equity Predecessor)	12 Months Ended
	Dec. 31, 2014
Member's Equity Predecessor
Full Cost
Discount rate for estimated present value of future net revenues from proved reserves less estimated future capital expenditures (as a percent)	10.00%
Period for calculation of unweighted arithmetic average of the price	12 months

Basis_of_Presentation_and_Sign6

Basis of Presentation and Significant Accounting Policies (Details 5)	12 Months Ended
	Dec. 31, 2014
Minimum
Property, plant and equipment (other than oil and natural gas properties)
Estimated useful lives of the assets	3 years
Maximum
Property, plant and equipment (other than oil and natural gas properties)
Estimated useful lives of the assets	15 years

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures (Details) (USD $)	0 Months Ended	11 Months Ended	12 Months Ended			5 Months Ended	11 Months Ended
	Apr. 30, 2014	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	24-May-12	Dec. 31, 2012
Other Acquisitions and Divestitures
Cash paid for acquisitions, net of cash acquired		$7,126,000,000	$165,000,000	$2,000,000
Goodwill recorded	0
Bargain purchase recorded	0
Contributed member equity		3,323,000,000
Unaudited pro forma information
Operating Revenues					1,659,000,000
Net Income					143,000,000
EP Energy Global LLC
Other Acquisitions and Divestitures
Contributed member equity						3,300,000,000
Proceeds from issuance of debt used to fund acquisition						4,250,000,000
Unaudited pro forma information
Payment of transaction, advisory and other fees						330,000,000
Transaction costs reflected in general and administrative expense						173,000,000
Transition and restructuring costs							48,000,000
Severance Costs					17,000,000
EP Energy Global LLC | Oil and natural gas properties located in the Gulf of Mexico and interest in Egypt
Unaudited pro forma information
Severance Costs							4,000,000
EP Energy Global LLC | Debt issue costs
Unaudited pro forma information
Payment of transaction, advisory and other fees						142,000,000
EP Energy Global LLC | Prepaid costs in other assets
Unaudited pro forma information
Payment of transaction, advisory and other fees						15,000,000
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)	37,000
Aggregate cash purchase price	152,000,000
Expansion of current Wolfcamp acreage (as a percent)	25.00%
Member's Equity Predecessor
Other Acquisitions and Divestitures
Cash paid for acquisitions, net of cash acquired						1,000,000
Member's Equity Predecessor | EP Energy Global LLC
Other Acquisitions and Divestitures
Acquisition price						7,200,000,000
Repayment of revolving line of credit						$960,000,000

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures (Details 2) (USD $)	11 Months Ended	12 Months Ended			5 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	24-May-12
Divestitures
Proceeds from sale of certain non-core acreage eagle ford properties		$28
Proceeds from the sale of assets and investments, net of cash transferred	110	154	1,451
Operating expenses
(Loss) income from discontinued operations, net of tax	50	4	506
Assets of discontinued operations
Current assets			293
Oil and natural gas properties located in the Gulf of Mexico
Divestitures
Proceeds from sale of oil and gas properties net of purchase price adjustments				79
Unevaluated property interests in Egypt
Divestitures
Proceeds from the sale of assets and investments, net of cash transferred				22
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	309	82	361
Other income
Natural gas purchases	23		19
Transportation costs	25	5	25
Lease operating expense	74	31	92
Depreciation, depletion and amortization	80	8	81
Impairment and ceiling test charges		18	44
Other expense	58	17	53
Total operating expenses	260	79	314
Operating expenses
Gain or loss on sale of assets		2	468
Other (expense) income	3	4	-2
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax, Total	52	9	513
Income tax (benefit) expense	2	5	7
(Loss) income from discontinued operations, net of tax	50	4	506
Assets of discontinued operations
Current assets			37
Property, plant and equipment, net			246
Other non-current assets			10
Total assets of discontinued operations			293
Liabilities of discontinued operations
Accounts payable			50
Other current liabilities			10
Asset retirement obligations			60
Other non-current liabilities			5
Total liabilities of discontinued operations			125
Domestic oil and natural gas properties
Divestitures
Proceeds from the sale of assets and investments, net of cash transferred			10
Brazil operations
Other income
Impairment charges			34
Impairment charges based on the comparison of fair value			10
Four Star
Divestitures
Net proceeds from sale of equity investment			183
Equity interest			49.00%
Other income
Impairment charges			20
Member's Equity Predecessor
Divestitures
Proceeds from the sale of assets and investments, net of cash transferred					9
Operating expenses
(Loss) income from discontinued operations, net of tax					-9
Member's Equity Predecessor | Brazil operations
Summary of operating results and financial position data of discontinued operations
Operating revenues					46
Other income
Lease operating expense					16
Depreciation, depletion and amortization					12
Other expense					20
Total operating expenses					48
Operating expenses
Other (expense) income					-5
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax, Total					-7
Income tax (benefit) expense					2
(Loss) income from discontinued operations, net of tax					($9)

Income_Taxes_Details

Income Taxes (Details) (USD $)	4 Months Ended	11 Months Ended	12 Months Ended		5 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	24-May-12
Pretax Income (Loss)
U.S.		($306)	$1,159	$8
Income (Loss) from Continuing Operations before Income Taxes		-306	1,159	8
Current
Federal				-2
Current				-2
Deferred
Federal			415	59
State			17	7
Deferred		1	435	67
Income tax expense (benefit)			432	64
Effective tax rate reconciliation
(Loss) income from continuing operations		-306	727	-56
Increase (decrease)
Income taxes at the statutory federal rate of 35%		-107	406	3
Income Taxes Recorded Upon C Corp Conversion	78
State income taxes, net of federal income tax effect			12	4
Partnership earnings not subject to tax		107		57
Non-deductible reorganization costs			10
Other			4
Income Taxes Recorded Upon C Corp Conversion	78
Total income tax expense			432	64
Effective tax rates (as a percent)			37.30%
Pro forma
Effective tax rate reconciliation
(Loss) income from continuing operations				5
Statutory federal income tax rate (as a percent)			35.00%
Member's Equity Predecessor
Pretax Income (Loss)
U.S.					384
Foreign					-63
Income (Loss) from Continuing Operations before Income Taxes					321
Current
Federal					-62
State					-3
Current					-65
Deferred
Federal					188
State					11
Deferred					199
Income tax expense (benefit)					134
Effective tax rate reconciliation
(Loss) income from continuing operations					187
Statutory federal income tax rate (as a percent)				35.00%
Increase (decrease)
Income taxes at the statutory federal rate of 35%					112
State income taxes, net of federal income tax effect					5
Earnings from unconsolidated affiliates where we received or will receive dividends					-2
Foreign income (loss) taxed at different rates					22
Other					-3
Total income tax expense					$134

Income_Taxes_Details_2

Income Taxes (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Deferred tax assets
Net operating loss and tax credit carryovers	$542	$252
Employee benefits	1	2
Investment in partnership		11
Financial derivatives		3
Legal and other reserves	5	2
Asset retirement obligations	15	19
Transaction costs	21	21
Total deferred tax assets	584	310
Valuation allowance	-1
Net deferred tax assets	583	310
Deferred tax liabilities
Property, plant and equipment	794	453
Financial derivatives	367
Total deferred tax liabilities	1,161	453
Net deferred tax liabilities	578	143
Uncertain tax benefits	$0

Income_Taxes_Details_3

Income Taxes (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Income Taxes
Valuation allowance	$1
Operating loss carryforwards expiration period	5 years
U.S. federal alternative minimum tax credits	10
Capital loss carryovers	23
Utilization federal carryover	320
Maximum
Income Taxes
Net operating loss carryforwards	1
Valuation allowance	1
2031-2033 | U.S. federal
Income Taxes
Net operating loss carryforwards	1,466
2016-2028 | State
Income Taxes
Net operating loss carryforwards	$226

Earnings_Per_Share_Details

Earnings Per Share (Details) (USD $)	0 Months Ended	12 Months Ended	0 Months Ended
Share data in Millions, except Per Share data, unless otherwise specified	Jan. 02, 2014	Dec. 31, 2014	Jan. 23, 2014	Dec. 31, 2013
Earnings Per Share
Stock split ratio	62.553
Earnings per share
Dilutive securities for purposes of calculating diluted earnings per share		$0
Class A Stock
Earnings per share
Number of shares issued		35	35.2
Par value per share (in dollars per share)		$0.01	$0.01	$0.01

Financial_Instruments_Details

Financial Instruments (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Carrying Amount
Carrying amounts and estimated fair values of financial instruments
Long-term debt	$4,598	$4,421
Derivative instruments	1,048	109
Fair Value
Carrying amounts and estimated fair values of financial instruments
Long-term debt	4,582	4,841
Derivative instruments	$1,048	$109

Financial_Instruments_Details_

Financial Instruments (Details 2) (USD $)	11 Months Ended	12 Months Ended		0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Feb. 16, 2015
				MBbls
Financial Instruments
Number of contracts that are designated as accounting hedges		0
Derivatives not designated as accounting hedges | Interest rate derivative instruments
Financial Instruments
Monetary notional amount		$600
Net asset related to interest rate derivatives		3	4
Interest expense related to the change in fair market value and cash settlements of interest rate derivative instruments	3	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
Financial Instruments
Nonmonetary Notional amount		37	47
Derivatives not designated as accounting hedges | Natural gas derivatives
Financial Instruments
Nonmonetary Notional amount		69	135
Derivatives not designated as accounting hedges | WTI | Fixed price hedges | 2016 Volumes | Subsequent event
Financial Instruments
Nonmonetary Notional Amount				3,294
Cash or other considerations on exchange of derivative instruments				0
Derivatives not designated as accounting hedges | WTI | Fixed price hedges | 2017 Volumes | Subsequent event
Financial Instruments
Nonmonetary Notional Amount				4,015
Derivatives not designated as accounting hedges | LLS vs WTI | Basis Swaps | 2016 Volumes | Subsequent event
Financial Instruments
Nonmonetary Notional Amount				1,830
Cash or other considerations on exchange of derivative instruments				$0
Derivatives not designated as accounting hedges | LLS derivative | Three way oil collar hedges | 2016 Volumes | Subsequent event
Financial Instruments
Nonmonetary Notional Amount				3,294
Derivatives not designated as accounting hedges | LLS vs Brent | Basis Swaps | 2016 Volumes | Subsequent event
Financial Instruments
Nonmonetary Notional Amount				1,830

Financial_Instruments_Details_1

Financial Instruments (Details 3) (Level 2, USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative Assets
Gross Fair Value	$1,093	$164
Impact of Netting	-44	-20
Derivative Liabilities
Gross Fair Value	-45	-55
Impact of Netting	44	20
Current
Derivative Assets
Derivatives instruments	752	47
Derivative Liabilities
Derivatives instruments	-1	-35
Non-current
Derivative Assets
Derivatives instruments	297	97
Oil, natural gas and NGLs derivative
Derivative Assets
Gross Fair Value	1,088	157
Derivative Liabilities
Gross Fair Value	-43	-52
Interest rate derivative instruments
Derivative Assets
Gross Fair Value	5	7
Derivative Liabilities
Gross Fair Value	($2)	($3)

Financial_Instruments_Details_2

Financial Instruments (Details 4) (USD $)	11 Months Ended	12 Months Ended		5 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	24-May-12
Gains and losses on financial derivative instruments and dedesignated cash flow hedges included in accumulated other comprehensive income
Gains (Losses) on financial derivative instruments	($62)	$985	($52)
Member's Equity Predecessor
Gains and losses on financial derivative instruments and dedesignated cash flow hedges included in accumulated other comprehensive income
Gains (Losses) on financial derivative instruments				365
Accumulated other comprehensive income				$5

Financial_Instruments_Details_3

Financial Instruments (Details 5) (USD $)	Dec. 31, 2014
In Billions, unless otherwise specified	item
Credit Risk
Number of counterparties	12
$2.75 billion RBL credit facility redetermination - due May 24, 2017
Debt and Available Credit Facility
Borrowing capacity	2.75

Property_Plant_and_Equipment_D

Property, Plant and Equipment (Details) (USD $)	11 Months Ended	12 Months Ended		5 Months Ended
	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	24-May-12
Unproved Oil and Natural Gas Properties
Property, plant, and equipment associated with unproven oil and natural gas properties		$8,700,000,000	$7,400,000,000
Cost of unproved oil and natural gas properties		700,000,000	1,400,000,000
Transfer from unproved properties to proved properties		700,000,000
Amortization of unproved leasehold costs	23,000,000	18,000,000	36,000,000
Asset Retirement Obligations
Projected inflation rate (as a percent)		2.50%
Changes in net asset retirement liability
Net asset retirement liability at the beginning of period		30,000,000	24,000,000
Liabilities incurred		10,000,000	6,000,000
Liabilities settled		-2,000,000	-2,000,000
Accretion expense		3,000,000	2,000,000
Changes in estimate		2,000,000	1,000,000
Property sale			-1,000,000
Other		-1,000,000
Net asset retirement liability at the end of period	24,000,000	42,000,000	30,000,000
Capitalized Interest
Capitalized Interest	12,000,000	21,000,000	19,000,000
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%
Member's Equity Predecessor
Impairment Assessment / Ceiling Test Charges
Ceiling test charges				62,000,000
Capitalized Interest
Capitalized Interest				4,000,000
Wolfcamp
Impairment Assessment / Ceiling Test Charges
Unproved property costs		400,000,000
Altamont
Impairment Assessment / Ceiling Test Charges
Unproved property costs		200,000,000
Eagle Ford
Impairment Assessment / Ceiling Test Charges
Unproved property costs		100,000,000
Egypt | Member's Equity Predecessor
Impairment Assessment / Ceiling Test Charges
Non-cash charge related to equipment				$2,000,000

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	11 Months Ended	12 Months Ended		5 Months Ended
	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	24-May-12	Oct. 31, 2014
Debt and Available Credit Facility
Long-term debt		$4,598,000,000	$4,421,000,000
Deferred financing costs		90,000,000	116,000,000
Amortization of deferred financing costs	12,000,000	21,000,000	22,000,000
Loss on extinguishment of debt	14,000,000	17,000,000	9,000,000
Repayments of Long-term Debt	1,139,000,000	2,293,000,000	2,190,000,000
EP Energy Global LLC
Debt and Available Credit Facility
Long-term debt		4,598,000,000	4,421,000,000
Member's Equity Predecessor
Debt and Available Credit Facility
Amortization of deferred financing costs				7,000,000
Repayments of Long-term Debt				1,065,000,000
Minimum
Debt and Available Credit Facility
Debt to EBITDAX multiple		1
Maximum
Debt and Available Credit Facility
Debt to EBITDAX multiple		4.5
$2.75 billion RBL credit facility redetermination - due May 24, 2017
Debt and Available Credit Facility
Borrowing capacity		2,750,000,000
$2.75 billion RBL credit facility redetermination - due May 24, 2017 | EP Energy Global LLC
Debt and Available Credit Facility
Borrowing capacity		2,750,000,000			2,750,000,000
Face amount of debt instrument		2,750,000,000
Long-term debt		852,000,000	295,000,000
Letters of credit outstanding		83,000,000
Remaining capacity		1,800,000,000
Commitment fees (as a percent)		0.38%
$2.75 billion RBL credit facility redetermination - due May 24, 2017 | Minimum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt and Available Credit Facility
Reference rate for variable interest rate		LIBOR
Specified margin on reference rate (as a percent)		1.50%
$2.75 billion RBL credit facility redetermination - due May 24, 2017 | Minimum | Alternate base rate | EP Energy Global LLC
Debt and Available Credit Facility
Reference rate for variable interest rate		ABR
Specified margin on reference rate (as a percent)		0.50%
$2.75 billion RBL credit facility redetermination - due May 24, 2017 | Maximum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt and Available Credit Facility
Reference rate for variable interest rate		LIBOR
Specified margin on reference rate (as a percent)		2.50%
$2.75 billion RBL credit facility redetermination - due May 24, 2017 | Maximum | Alternate base rate | EP Energy Global LLC
Debt and Available Credit Facility
Reference rate for variable interest rate		ABR
Specified margin on reference rate (as a percent)		1.50%
Letter of credit | EP Energy Global LLC
Debt and Available Credit Facility
Interest rate (as a percent)		1.75%
$750 million senior secured term loan - due May 24, 2018 | EP Energy Global LLC
Debt and Available Credit Facility
Face amount of debt instrument		750,000,000
Long-term debt		496,000,000	495,000,000
Debt instrument issuance as a percentage of the par value		99.00%
Repayments of Long-term Debt		250,000,000
$750 million senior secured term loan - due May 24, 2018 | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt and Available Credit Facility
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%	3.50%
$750 million senior secured term loan - due May 24, 2018 | Minimum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt and Available Credit Facility
Reference rate for variable interest rate		LIBOR
Reference rate floor for variable interest rate (as a percent)		0.75%
$400 million senior secured term loan - due April 30, 2019 | EP Energy Global LLC
Debt and Available Credit Facility
Face amount of debt instrument		400,000,000
Long-term debt		150,000,000	149,000,000
Effective interest rate (as a percent)		4.50%	4.50%
$400 million senior secured term loan - due April 30, 2019 | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt and Available Credit Facility
Reference rate for variable interest rate		LIBOR
Specified margin on reference rate (as a percent)		3.50%
$400 million senior secured term loan - due April 30, 2019 | Minimum | London Interbank Offered Rate LIBOR | EP Energy Global LLC
Debt and Available Credit Facility
Reference rate for variable interest rate		LIBOR
Reference rate floor for variable interest rate (as a percent)		1.00%
$750 million senior secured notes - due May 1, 2019 | EP Energy Global LLC
Debt and Available Credit Facility
Face amount of debt instrument		750,000,000
Interest rate (as a percent)		6.88%
Long-term debt		750,000,000	750,000,000
$2.0 billion senior unsecured notes - due May 1, 2020 | EP Energy Global LLC
Debt and Available Credit Facility
Face amount of debt instrument		2,000,000
Interest rate (as a percent)		9.38%
Long-term debt		2,000,000,000	2,000,000,000
$350 million senior unsecured notes - due September 1, 2022 | EP Energy Global LLC
Debt and Available Credit Facility
Face amount of debt instrument		350,000,000
Interest rate (as a percent)		7.75%
Long-term debt		350,000,000	350,000,000
$350 million senior pik toggle note - due December 15,2017 | EP Energy Global LLC
Debt and Available Credit Facility
Face amount of debt instrument		350,000,000
Long-term debt			$382,000,000
$350 million senior pik toggle note - due December 15,2017 | Minimum | EP Energy Global LLC
Debt and Available Credit Facility
Interest rate (as a percent)		8.13%
$350 million senior pik toggle note - due December 15,2017 | Maximum | EP Energy Global LLC
Debt and Available Credit Facility
Interest rate (as a percent)		8.88%

Commitments_and_Contingencies_1

Commitments and Contingencies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2010
		item
Southeast Louisiana Flood Protection Authority v. EP Energy Management, L.L.C.
Legal Matters
Number of oil, gas and pipeline companies against which a suit was filed by the levee authority	97
Number of wells operated in area from mid-1970s to 1980	5
Legal Matters
Legal Matters
Amount accrued	$2
Indemnification and Other Matters
Legal Matters
Amount accrued	8
Sales Tax Audits
Legal Matters
Number of operating entities for whom state of Texas asserted additional taxes plus penalties and interest		2
Audit settlement amount, including penalties and fees	3
Reduction in taxes, other than income taxes recorded on settlement	$13

Commitments_and_Contingencies_2

Commitments and Contingencies (Details 2) (USD $)	11 Months Ended	12 Months Ended		5 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	24-May-12
		item
Environmental Matters
Accrued environmental remediation costs		$1
Number of estimation methodologies		2
Maximum exposure		1
Rental expense	10	13	13
Annual minimum lease payments under non-cancelable future operating lease commitments
2015		11
2016		12
2017		7
Total		30
Various commercial commitments due
2015		184
2016		185
2017		83
2018		83
Thereafter		274
Total		809
Member's Equity Predecessor
Environmental Matters
Rental expense				1
Maximum | Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters
Environmental Matters
Estimated environmental remediation costs		1
Subsequent event
Annual minimum lease payments under non-cancelable future operating lease commitments
2017		5
2018		$9

LongTerm_Incentive_Compensatio2

Long-Term Incentive Compensation / Retirement 401(k) Plan (Details) (USD $)	11 Months Ended	12 Months Ended			0 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 18, 2013	24-May-12
Cash-Based Long Term Incentive
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%
Compensation cost recorded	$8	$8	$16
Long-Term Incentive Compensation / Retirement 401(k) Plan
Fair value of cash-based awards on the grant date			22	24
Unrecognized compensation cost		3
Vesting period		3 years
Income tax expense (benefit)		432	64
Recognition period of fair value as compensation cost		2 years
Retirement 401(k) Plan
Maximum matching contributions as a percentage of eligible compensation		6.00%
Non-elective employer contributions as a percentage of eligible compensation		5.00%
Matching and non-elective employer contributions by employer	7	11	12
Number of Restricted stock
Remaining available for issuance (in shares)		11,179,603
Class B Stock
Number of Restricted stock
Additional		0
EP Energy Corporation
Number of Restricted stock
Common stock authorized to grant (in shares)		12,433,749
EPE Holdings II
Long-Term Incentive Compensation / Retirement 401(k) Plan
Additional stock issued					70,000
Compensation expense recorded					0
Retirement 401(k) Plan
Compensation expense that will occur until those events that give rise to a payout become probable of occurring		0
Class A Matching Grants
Long-Term Incentive Compensation / Retirement 401(k) Plan
Unrecognized compensation cost		4
Guaranteed cash bonus		12
Unrecognized compensation cost to be recognized in 2015		3
Compensation expense recorded	11	2	6
Recognition period of fair value as compensation cost		4 years
Grants as a percentage of the Class A units purchased		50.00%
Fair value		12
MIPs
Long-Term Incentive Compensation / Retirement 401(k) Plan
Unrecognized compensation cost		9
Vesting period		5 years
Fair value on the grant date						74
Compensation expense recorded	15	6	19
Percentage of vested awards forfeitable in the event of certain termination events		25.00%
Risk free rate (as a percent)						0.77%
Expected Term in Years						5 years
Expected Volatility (as a percent)						73.00%
Unrecognized compensation cost to be recognized on an accelerated basis for each tranche of the award		6
Unrecognized compensation cost to be recognized upon a specified capital transaction		16
Requisite service period		5 years
Retirement 401(k) Plan
Award issuance cost		0
Assumptions used for estimating weighted-average grant-date fair value of stock options
Expected Term in Years						5 years
Expected Volatility (as a percent)						73.00%
Risk free rate (as a percent)						0.77%
MIPs | Class B Stock
Long-Term Incentive Compensation / Retirement 401(k) Plan
Conversion basis		1
Restricted stock
Long-Term Incentive Compensation / Retirement 401(k) Plan
Compensation expense recorded		5
Income tax expense (benefit)		-2
Unrecognized compensation cost		14
Recognition period of fair value as compensation cost		4 years
Number of Restricted stock
Granted (in shares)		1,131,154
Vested (in shares)		-1,929
Forfeited (in shares)		-95,831
Non-vested at the end of the period (in shares)		1,033,394
Granted (in dollars per share)		$19.80
Weighted-Average Grant-Date Fair Value
Granted (in dollars per share)		$19.80
Vested (in dollars per share)		$19.82
Forfeited (in dollars per share)		$19.82
Non-vested at the end of the period (in dollars per share)		$19.80
Restricted stock | EP Energy Corporation
Number of Restricted stock
Vesting Period		3 years
Stock options
Long-Term Incentive Compensation / Retirement 401(k) Plan
Unrecognized compensation cost		2
Risk free rate (as a percent)		2.30%
Expected Term in Years		7 years
Expected Volatility (as a percent)		40.00%
Number of Restricted stock
Contractual term		10 years
Number of tranches		3
Number of Options
Granted (in shares)		253,740
Forfeited or canceled (in shares)		-34,388
Outstanding at the end of the period (in shares)		219,352
Weighted-Average Exercise Price
Granted (in dollars per share)		$19.82
Forfeited or canceled (in dollars per share)		$19.82
Outstanding at the end of the period (in dollars per share)		$19.82
Weighted Average Remaining Contractual Term		9 years 3 months
Stock options granted		0
Assumptions used for estimating weighted-average grant-date fair value of stock options
Grant date fair value (in dollars per share)		$9.03
Expected Term in Years		7 years
Expected Volatility (as a percent)		40.00%
Dividend yield (as a percent)		0.00%
Risk free rate (as a percent)		2.30%
Stock options | Maximum
Long-Term Incentive Compensation / Retirement 401(k) Plan
Compensation expense recorded		$1

Investment_in_Unconsolidated_A2

Investment in Unconsolidated Affiliate (Details) (Four Star, USD $)	1 Months Ended	5 Months Ended	11 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	24-May-12	Dec. 31, 2012	Dec. 31, 2013
Four Star
Investments in unconsolidated affiliate
Net proceeds from sale of equity investment	$183
Impairment charges	20
Operating revenues		75	105	142
Operating expenses		58	87	94
Net income		11	11	30
Amortization of investment in unconsolidated affiliates		12	7	8
Dividend received		$8	$13	$24

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	8 Months Ended	11 Months Ended	12 Months Ended		5 Months Ended	1 Months Ended	11 Months Ended
	Aug. 31, 2013	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	24-May-12	Jan. 31, 2014	Dec. 31, 2012
Related party transactions
Payments of Capital Distribution		$337,000,000		$205,000,000
Leveraged distribution	-205,000,000	-337,000,000
Capital expenditures		877,000,000	2,033,000,000	1,924,000,000
Percentage of participant basic contributions matched			6.00%
Member's Equity Predecessor
Related party transactions
Capital expenditures					636,000,000
Contributions					1,481,000,000
Member Distribution
Related party transactions
Payments of Capital Distribution				205,000,000
Leveraged distribution				200,000,000
Affiliate Supply Agreement
Related party transactions
Number of supply agreements			2
Affiliate Supply Agreement | Eagle Ford drilling operations
Related party transactions
Capital expenditures			112,000,000
Sponsors | Transaction Fee Agreement
Related party transactions
General and administrative expense					71,500,000
Sponsors | Amended and Restated Management Fee Agreement
Related party transactions
Transaction fee paid						6,250,000
Capital expenditures						83,000,000
El Paso
Related party transactions
Maximum percentage of eligible compensation for which contributions are made							75.00%
El Paso | Maximum
Related party transactions
Percentage of participant basic contributions matched							6.00%
El Paso | Member's Equity Predecessor
Related party transactions
Contributions					1,500,000,000
Non-cash contributions					500,000,000
Cash contribution					960,000,000
Revenues and charges to/from affiliates
Operating revenues					143,000,000
Operating expenses					$44,000,000

Uncategorized_Items

Uncategorized Items	2/14/2012 - 12/31/2012
	USD ($)
[us-gaap_PartnersCapitalAccountContributions]	3,323,000,000
[us-gaap_PartnersCapitalAccountUnitBasedCompensation]	18,000,000