Amplify Energy (AMPYW) 10-Q 8 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 30, 2015
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	FALSE
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Trading Symbol	MEMP
Entity Registrant Name	MEMORIAL PRODUCTION PARTNERS LP
Entity Central Index Key	1521847
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		84,017,738
General Partner [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		86,797

UNAUDITED_CONDENSED_CONSOLIDAT

UNAUDITED CONDENSED CONSOLIDATED AND COMBINED BALANCE SHEETS (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$1,073	$970
Accounts receivable:
Oil and natural gas sales	35,425	46,413
Joint interest owners and other (Note 2)	38,078	36,937
Short-term derivative instruments	214,986	208,585
Prepaid expenses and other current assets	19,687	14,201
Total current assets	309,249	307,106
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	3,414,510	3,329,338
Support equipment and facilities	200,242	198,088
Other	3,077	3,020
Accumulated depreciation, depletion and impairment	-1,367,545	-1,060,114
Property and equipment, net	2,250,284	2,470,332
Long-term derivative instruments	389,748	311,802
Restricted investments	78,787	77,361
Other long-term assets	23,122	23,159
Total assets	3,051,190	3,189,760
Current liabilities:
Accounts payable	29,127	23,609
Accounts payable - affiliates	9,145	6,409
Revenues payable	27,195	30,110
Accrued liabilities (Note 2)	93,026	90,974
Short-term derivative instruments	3,300	3,289
Total current liabilities	161,793	154,391
Long-term debt (Note 8)	1,754,045	1,595,413
Asset retirement obligations	116,727	112,702
Long-term derivative instruments	555
Deferred tax liabilities	2,164	30,940
Total liabilities	2,035,284	1,893,446
Commitments and contingencies (Note 13)
Partners' equity (deficit):
General partner (86,797 units outstanding at March 31, 2015 and December 31, 2014)	1,210	1,251
Previous owners		220,657
Total partners' equity	1,010,187	1,290,754
Noncontrolling interests	5,719	5,560
Total equity	1,015,906	1,296,314
Total liabilities and equity	3,051,190	3,189,760
Limited Partners Common Units [Member]
Partners' equity (deficit):
Limited partners units	1,008,977	1,085,265
Total equity	1,008,977	1,085,265
Subordinated Units [Member]
Partners' equity (deficit):
Limited partners units		($16,419)

UNAUDITED_CONDENSED_CONSOLIDAT1

UNAUDITED CONDENSED CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical)	Mar. 31, 2015	Dec. 31, 2014
General partner, units outstanding	86,797	86,797
Limited Partners Common Units [Member]
Limited partners, units outstanding	84,017,738	80,421,992
Subordinated Units [Member]
Limited partners, units outstanding	0	5,360,912

UNAUDITED_CONDENSED_STATEMENTS

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Revenues:
Oil & natural gas sales	$91,949	$115,977
Pipeline tariff income and other	869	908
Total revenues	92,818	116,885
Costs and expenses:
Lease operating	40,478	30,120
Pipeline operating	446	489
Gathering, processing, and transportation	8,220	5,563
Exploration	90	6
Production and ad valorem taxes	6,655	6,011
Depreciation, depletion, and amortization	51,266	32,550
Impairment of proved oil and natural gas properties	251,347
General and administrative	14,511	10,740
Accretion of asset retirement obligations	1,634	1,391
(Gain) loss on commodity derivative instruments	-145,459	46,766
Other, net		-12
Total costs and expenses	229,188	133,624
Operating income (loss)	-136,370	-16,739
Other income (expense):
Interest expense, net	-28,818	-16,078
Other income (expense)	160
Total other income (expense)	-28,658	-16,078
Income (loss) before income taxes	-165,028	-32,817
Income tax benefit (expense)	2,370	-75
Net income (loss)	-162,658	-32,892
Net income (loss) attributable to noncontrolling interest	159	55
Net income (loss) attributable to Memorial Production Partners LP	-162,817	-32,947
Limited partners' interest in net income (loss):
Net income (loss) attributable to Memorial Production Partners LP	-162,817	-32,947
Net (income) loss allocated to previous owners	2,268	-1,165
Net (income) loss allocated to general partner	138	14
Net (income) loss allocated to NGP IDRs	-28	-20
Limited partners' interest in net income (loss)	($160,439)	($34,118)
Earnings per unit: (Note 10)
Basic and diluted earnings per unit	($1.90)	($0.56)
Weighted average limited partner units outstanding:
Basic and diluted	84,339	61,251

UNAUDITED_CONDENSED_STATEMENTS1

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Cash flows from operating activities:
Net income (loss)	($162,658)	($32,892)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	51,266	32,550
Impairment of proved oil and natural gas properties	251,347
(Gain) loss on derivative instruments	-143,018	47,081
Cash settlements (paid) received on expired derivative instruments	59,236	-8,100
Cash settlements on terminated commodity derivatives	27,063
Premiums paid for commodity derivatives	-27,063
Deferred income tax expense (benefit)	-2,370
Amortization of deferred financing costs	1,860	839
Accretion of senior notes net discount	599	367
Accretion of asset retirement obligations	1,634	1,391
Amortization of equity awards	2,341	1,295
Changes in operating assets and liabilities:
Accounts receivable	13,000	-1,789
Prepaid expenses and other assets	-5,684	-1,716
Payables and accrued liabilities	4,410	13,930
Other		1,849
Net cash provided by operating activities	71,963	54,805
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	-3,305	-173,000
Additions to oil and gas properties	-74,375	-58,973
Additions to restricted investments	-1,426	-826
Net cash used in investing activities	-79,106	-232,799
Cash flows from financing activities:
Advances on revolving credit facilities	166,000	235,000
Payments on revolving credit facilities	-5,000	-39,000
Deferred financing costs	-10	-267
Repurchase of senior notes	-2,914
Capital contributions from previous owners	1,912	991
Distributions to partners	-46,315	-33,763
Distribution to Memorial Resource (see Note 1)	-78,000
Restricted units returned to plan	-7
Repurchases under unit repurchase program	-28,420
Net cash provided by financing activities	7,246	162,961
Net change in cash and cash equivalents	103	-15,033
Cash and cash equivalents, beginning of period	970	21,698
Cash and cash equivalents, end of period	$1,073	$6,665

UNAUDITED_CONDENSED_STATEMENTS2

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY (USD $)	Total	Limited Partners Common Units [Member]	Limited Partners Subordinated [Member]	General Partner [Member]	Previous Owners [Member]	NGP IDR [Member]	Noncontrolling Interest [Member]
In Thousands
Balance at Dec. 31, 2014	$1,296,314	$1,085,265	($16,419)	$1,251	$220,657		$5,560
Net income (loss)	-162,658	-160,469	30	-138	-2,268	28	159
Contributions	1,912				1,912
Distributions	-46,315	-43,262	-2,949	-76		-28
Distribution attributable to net assets transferred (Note 1)	-78,000	-77,922		-78
Net book value of net assets acquired	2,721	250,791		251	-248,321
Amortization of equity awards	2,341	2,341
Conversion of subordinated units to common units		-19,338	19,338
Common units repurchased under repurchase program (Note 9)	-28,420	-28,420
Restricted units repurchased and other	-9	-9
Deferred tax liability retained by previous owner (Note 2)	28,020				28,020
Balance at Mar. 31, 2015	$1,015,906	$1,008,977		$1,210			$5,719

Organization_and_Basis_of_Pres

Organization and Basis of Presentation	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation
	General
	Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries.
	We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Colorado, Wyoming, New Mexico and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells (often referred to as wellbore assignments).
	Unless the context requires otherwise, references to: (i) “our general partner” or “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner; (ii) “Memorial Resource” refer collectively to Memorial Resource Development Corp. and its subsidiaries other than the Partnership; (iii) “MRD LLC” refer to Memorial Resource Development LLC, which is the predecessor of Memorial Resource; (iv) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (v) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refer to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; (vii) “MRD Holdco” refer to MRD Holdco LLC, which together with a group controls Memorial Resource; and  (viii) “NGP” refer to Natural Gas Partners.
	The Partnership is owned 99.9% by its limited partners and 0.1% by MEMP GP, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities. Memorial Resource provides management, administrative and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco. The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are owned by our general partner.  As of March 31, 2015, MRD Holdco owned approximately 6% of our outstanding common units.  On April 14, 2015, MRD Holdco sold 4,661,663 of our common units in an underwritten public secondary offering and granted the underwriters a 30-day option to purchase up to an additional 699,249 common units.  As of April 30, 2015, MRD Holdco owns less than 0.3% of our outstanding common units.
	Previous Owners
	References to “the previous owners” for accounting and financial reporting purposes refer to certain oil and gas properties primarily located in East Texas and West Louisiana that the Partnership acquired on February 23, 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana for periods after common control commenced through the date of acquisition.  We refer to this transaction as the “Property Swap.”  The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”).   The Property Swap was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information have been retrospectively revised to give effect to the Property Swap as if the Partnership owned the assets for periods after common control commenced through the acquisition date.
	Basis of Presentation
	Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements of the previous owners were derived from their historical accounting records and reflect their historical financial position, results of operations and cash flows. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item.
	The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of the Partnership, is presented as a noncontrolling interest in the financial statements.
	Our results of operations for the three months ended March 31, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). These unaudited condensed consolidated and combined financial statements and the notes thereto should be read in conjunction with the audited supplemental consolidated and combined financial statements and notes thereto included in our Current Report on Form 8-K filed on April 21, 2015 (our “Recast Form 8-K”), which retrospectively revised certain of our financial and other information to give effect to the Property Swap.
	All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements.
	Use of Estimates
	The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies
	A discussion of our significant accounting policies and estimates is included in our Recast Form 8-K.
	Accounts Receivable – Joint Interest Owners and Other
	Accounts receivable from joint interest owners and other consisted of the following at the dates indicated (in thousands):
		March 31,				December 31,
		2015				2014
	Derivatives expired positions	$	15,785			$	13,754
	July 2014 Wyoming Acquisition		—				9,569
	Joint interest owners		17,740				12,714
	Other		4,553				900
		$	38,078			$	36,937
	Accrued Liabilities
	Current accrued liabilities consisted of the following at the dates indicated (in thousands):
		March 31,				December 31,
		2015				2014
	Accrued capital expenditures	$	34,592			$	36,042
	Accrued interest payable		27,990				24,673
	Accrued lease operating expense		16,174				15,594
	Accrued ad valorem taxes		9,484				8,281
	Accrued general and administrative expenses		1,864				1,276
	Environmental liability		1,309				2,092
	Other		1,613				3,016
		$	93,026			$	90,974
	Income Tax
	A deferred tax liability was recorded in equity by the previous owners and related to Memorial Resource’s initial public offering and restructuring transactions as it represented a transaction among shareholders.  Subsequent to Memorial Resource’s initial public offering in June 2014, income tax related to the Property Swap was calculated on a separate return basis through February 2015.  The deferred tax liability of approximately $28.0 million associated with the previous owners was retained by them in connection with the closing of the Property Swap transaction and reflected in the equity statement.
	Supplemental Cash Flows
	Supplemental cash flow for the periods presented (in thousands):
			For the Three Months Ended
			March 31,
			2015				2014
	Supplemental cash flows:
	Cash paid for interest, net of amounts capitalized		$	21,298			$	1,421
	Noncash investing and financing activities:
	Change in capital expenditures in payables and accrued liabilities			(1,450	)			11,596
	Accounts receivable related to Eagle Ford Acquisition			—				3,879
	Assumptions of asset retirement obligations related to properties			2,266				285
	acquired
	New Accounting Pronouncements
	Presentation of Debt Issuance Cost.  In April 2015, the Financial Accounting Standards Board ("FASB") issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Partnership does not expect the impact of adopting this guidance to be material to the Partnership’s financial statements and related disclosures.
	Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions.  In April 2015, FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required.  The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. Since the Partnership has historically allocated the earnings (losses) of transferred businesses that occurred in periods before the date of the dropdown transaction entirely to affiliates of the general partner (i.e., the previous owners) and did not adjust previously reported earnings per unit of the limited partners, the Partnership does not expect the impact of adopting this guidance will be material to the Partnership’s financial statements and related disclosures.
	Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	3 Months Ended
	Mar. 31, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures
	Related Party Acquisitions
	See Note 12 for further information regarding related party acquisitions that have been accounted for as transactions between entities under common control that impact the basis of presentation for the periods presented.
	2014 Acquisitions
	Eagle Ford Acquisition. On March 25, 2014, we closed a transaction to acquire certain oil and natural gas producing properties in the Eagle Ford from a third party (the “Eagle Ford Acquisition”). In addition, we also acquired a 30% interest in the seller’s Eagle Ford leasehold.
	Acquisition-related Costs.  Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	1,299			$	1,894
	In March and July 2014, we closed two third-party acquisitions.  The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2014 as though these third-party acquisitions had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.
		For the Three-Months Ended
		March 31,
		2014
		(In thousands,
		except per unit amounts)
	Revenues	$	173,549
	Net income (loss)		(19,984	)
	Basic and diluted earnings per unit		(0.35	)

Fair_Value_Measurements_of_Fin

Fair Value Measurements of Financial Instruments	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments
	Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.
	The carrying values of accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at March 31, 2015 and December 31, 2014. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt.
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	The fair market values of the derivative financial instruments reflected on the balance sheets as of March 31, 2015 and December 31, 2014 were based on estimated forward commodity prices and forward interest rate yield curves. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2015 and December 31, 2014 for each of the fair value hierarchy levels:
		Fair Value Measurements at March 31, 2015 Using
		Quoted Prices in		Significant Other		Significant
		Active Market		Observable Inputs		Unobservable Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	670,973	$	—	$	670,973
	Interest rate derivatives		—		10		—		10
	Total assets	$	—	$	670,983	$	—	$	670,983
	Liabilities:
	Commodity derivatives	$	—	$	66,555	$	—	$	66,555
	Interest rate derivatives		—		3,549		—		3,549
	Total liabilities	$	—	$	70,104	$	—	$	70,104
		Fair Value Measurements at December 31, 2014 Using
		Quoted Prices in		Significant Other		Significant
		Active Market		Observable Inputs		Unobservable Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	564,913	$	—	$	564,913
	Interest rate derivatives		—		1,305		—		1,305
	Total assets		—	$	566,218		—	$	566,218
	Liabilities:
	Commodity derivatives	$	—	$	45,831	$	—	$	45,831
	Interest rate derivatives		—		3,289		—		3,289
	Total liabilities	$	—	$	49,120	$	—	$	49,120
	See Note 5 for additional information regarding our derivative instruments.
	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
	Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values:
	·	The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs.
	·	If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.
	·	Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties.
	·	During the three months ended March 31, 2015, we recognized $251.3 million of impairments primarily related to certain properties located in East Texas, Wyoming and Colorado.  The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable as a result of declining commodity prices.  The carrying value of these properties after the $251.3 million impairment was approximately $157.6 million.  We did not record any impairments for the three months ended March 31, 2014.

Risk_Management_and_Derivative

Risk Management and Derivative Instruments	3 Months Ended
	Mar. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments	Note 5. Risk Management and Derivative Instruments
	Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease.
	Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $272.6 million against amounts outstanding under our revolving credit facility, reducing our maximum credit exposure to approximately $328.4 million, of which approximately $113.4 million was with a single counterparty. See Note 8 for additional information regarding our revolving credit facility.
	Commodity Derivatives
	We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, costless collars, call spreads and basis swaps) to manage exposure to commodity price volatility. Historically, the Partnership has not paid or received premiums for put options. In February 2015, we restructured a portion of our commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor.  Cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives.
	We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At March 31, 2015, we had the following open commodity positions:
		Remaining
		2015				2016				2017				2018				2019
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		3,061,181				3,292,442				3,050,067				2,760,000				2,514,583
	Weighted-average fixed price	$	4.16			$	4.22			$	4.14			$	4.28			$	4.43
	Collar contracts:
	Average Monthly Volume (MMBtu)		350,000				—				—				—				—
	Weighted-average floor price	$	4.62			$	—			$	—			$	—			$	—
	Weighted-average ceiling price	$	5.8			$	—			$	—			$	—			$	—
	Call spreads (1):
	Average Monthly Volume (MMBtu)		80,000				—				—				—				—
	Weighted-average sold strike price	$	5.25			$	—			$	—			$	—			$	—
	Weighted-average bought strike price	$	6.75			$	—			$	—			$	—			$	—
	Basis swaps:
	Average Monthly Volume (MMBtu)		3,390,000				3,108,333				415,000				115,000				—
	Spread	$	(0.12	)		$	(0.05	)		$	—			$	0.15			$	—
	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		273,864				279,813				301,600				312,000				160,000
	Weighted-average fixed price	$	91.34			$	86.87			$	84.7			$	83.74			$	85.52
	Collar contracts:
	Average Monthly Volume (Bbls)		5,000				—				—				—				—
	Weighted-average floor price	$	80			$	—			$	—			$	—			$	—
	Weighted-average ceiling price	$	94			$	—			$	—			$	—			$	—
	Basis swaps:
	Average Monthly Volume (Bbls)		97,333				95,000				—				—				—
	Spread	$	(7.07	)		$	(9.56	)		$	—			$	—			$	—
	NGL Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		211,867				158,600				43,300				—				—
	Weighted-average fixed price	$	42.3			$	40.36			$	37.55			$	—			$	—
	-1	These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.
	Our basis swaps included in the table above are presented on a disaggregated basis below:
			Remaining
			2015				2016				2017				2018
	Natural Gas Derivative Contracts:
	NGPL TexOk basis swaps:
	Average Monthly Volume (MMBtu)			2,730,000				2,703,333				300,000				—
	Spread-Henry Hub		$	(0.12	)		$	(0.07	)		$	(0.05	)		$	—
	HSC basis swaps:
	Average Monthly Volume (MMBtu)			150,000				135,000				115,000				115,000
	Spread-Henry Hub		$	(0.08	)		$	0.07			$	0.14			$	0.15
	CIG basis swaps:
	Average Monthly Volume (MMBtu)			210,000				—				—				—
	Spread-Henry Hub		$	(0.25	)		$	—			$	—			$	—
	TETCO STX basis swaps:
	Average Monthly Volume (MMBtu)			300,000				270,000				—				—
	Spread-Henry Hub		$	(0.09	)		$	0.06			$	—			$	—
	Crude Oil Derivative Contracts:
	Midway-Sunset basis swaps:
	Average Monthly Volume (Bbls)			57,333				55,000				—				—
	Spread - Brent		$	(9.73	)		$	(13.35	)		$	—			$	—
	Midland basis swaps:
	Average Monthly Volume (Bbls)			40,000				40,000				—				—
	Spread - WTI		$	(3.25	)		$	(4.34	)		$	—			$	—
	Interest Rate Swaps
	Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At March 31, 2015, we had the following interest rate swap open positions:
		Remaining
		2015				2016				2017				2018
Average Monthly Notional (in thousands)		$	386,111			$	400,000			$	400,000			$	100,000
Weighted-average fixed rate			1.247	%			0.943	%			1.612	%			1.946	%
Floating rate		1 Month LIBOR				1 Month LIBOR				1 Month LIBOR				1 Month LIBOR
Balance Sheet Presentation
The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at March 31, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.
				Asset Derivatives								Liability Derivatives
				March 31,				December 31,				March 31,				December 31,
Type		Balance Sheet Location		2015				2014				2015				2014
				(In thousands)
Commodity contracts		Short-term derivative instruments		$	237,411			$	225,882			$	22,731			$	17,297
Interest rate swaps		Short-term derivative instruments			—				—				2,994				3,289
Gross fair value					237,411				225,882				25,725				20,586
Netting arrangements		Short-term derivative instruments			(22,425	)			(17,297	)			(22,425	)			(17,297	)
Net recorded fair value		Short-term derivative instruments		$	214,986			$	208,585			$	3,300			$	3,289
Commodity contracts		Long-term derivative instruments		$	433,562			$	339,031			$	43,824			$	28,534
Interest rate swaps		Long-term derivative instruments			10				1,305				555				—
Gross fair value					433,572				340,336				44,379				28,534
Netting arrangements		Long-term derivative instruments			(43,824	)			(28,534	)			(43,824	)			(28,534	)
Net recorded fair value		Long-term derivative instruments		$	389,748			$	311,802			$	555			$	—
(Gains) Losses on Derivatives
We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the three months ended March 31, 2015 and 2014 (in thousands):
		Statements of		March 31,
		Operations Location		2015				2014
Commodity derivative contracts		(Gain) loss on commodity derivatives		$	(145,459	)		$	46,766
Interest rate derivatives		Interest expense, net			2,441				315

Asset_Retirement_Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. Asset Retirement Obligations
	The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2015 (in thousands):
	Asset retirement obligations at beginning of period	$	112,702
	Liabilities added from acquisitions or drilling		2,304
	Liabilities removed upon sale of wells		(62	)
	Accretion expense		1,634
	Revision of estimates		149
	Asset retirement obligations at end of period	$	116,727

Restricted_Investments

Restricted Investments	3 Months Ended
	Mar. 31, 2015
Investments Debt And Equity Securities [Abstract]
Restricted Investments	Note 7. Restricted Investments
	Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and gas properties.
	The components of the restricted investment balance consisted of the following at the dates indicated:
		March 31,		December 31,
		2015		2014
		(In thousands)
	BOEM platform abandonment (See Note 13)	$	71,263	$	69,954
	BOEM lease bonds		794		794
	SPBPC Collateral:
	Contractual pipeline and surface facilities abandonment		2,818		2,701
	California State Lands Commission pipeline right-of-way bond		3,005		3,005
	City of Long Beach pipeline facility permit		500		500
	Federal pipeline right-of-way bond		307		307
	Port of Long Beach pipeline license		100		100
	Restricted investments	$	78,787	$	77,361

Long_Term_Debt

Long Term Debt	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Long Term Debt	Note 8. Long Term Debt
	The following table presents our consolidated debt obligations at the dates indicated:
		March 31,			December 31,
		2015			2014
		(In thousands)
	MEMP:
	OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	573,000		$	412,000
	2021 Senior Notes, fixed-rate, due May 2021 (1)		700,000			700,000
	2022 Senior Notes, fixed-rate, due August 2022 (2)		496,990			500,000
	Unamortized discounts		(15,945	)		(16,587	)
	Total long-term debt	$	1,754,045		$	1,595,413
	-1	The estimated fair value of our 2021 Senior Notes was $640.5 million and $563.5 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
	-2	The estimated fair value of our 2022 Senior Notes was $437.4 million and $380.0 million at March 31, 2015 and December 31, 2014, respectively.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
	Subsidiary Guarantors
	We are a “Well-Known Seasoned Issuer” under SEC rules and have filed a universal shelf registration statement with the SEC that allows us to issue debt and equity securities. Any debt securities issued will be governed by an indenture. Our outstanding debt securities are, and any debt securities issued in the future will likely be, jointly and severally, fully and unconditionally guaranteed (subject to customary release provisions) by certain of the Partnership’s subsidiaries (collectively, the “Guarantor Subsidiaries”). The Guarantor Subsidiaries are 100% owned by the Partnership. The Partnership has no material assets or operations independent of the Guarantor Subsidiaries and there are no significant restrictions upon the ability of the Guarantor Subsidiaries to distribute funds to the Partnership.
	Borrowing Base
	Credit facilities tied to borrowing bases are common throughout the oil and gas industry. The borrowing base for our revolving credit facility was the following at the date indicated:
		March 31,
		2015
		(In thousands)
	OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	1,300,000
	OLLC Revolving Credit Facility
	OLLC is a party to a $2.0 billion revolving credit facility, which is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries).
	Weighted-Average Interest Rates
	The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented:
		For the Three Months Ended
		March 31,
		2015			2014
	OLLC revolving credit facility		1.9	%		1.66	%
	Unamortized Deferred Financing Costs
	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:
		March 31,			December 31,
		2015			2014
		(In thousands)
	OLLC $2.0 billion revolving credit facility, variable-rate, due	$	5,395		$	6,468
	March 2018 (1)
	2021 Senior Notes (2)		12,779			13,308
	2022 Senior Notes (2)		7,656			7,958
	Total	$	25,830		$	27,734
	-1	Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.
	-2	Unamortized deferred financing costs are amortized using the straight line method, which generally approximates the effective interest method.
	Letters of Credit
	At March 31, 2015, we had $4.8 million of letters of credit outstanding, all related to operations at our Wyoming properties.

Equity_and_Distributions

Equity and Distributions	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Equity and Distributions	Note 9. Equity & Distributions
	Equity Outstanding
	The following table summarizes changes in the number of outstanding units since December 31, 2014:
										General
		Common				Subordinated				Partner
	Balance, December 31, 2014		80,421,992				5,360,912				86,797
	Restricted common units issued		157,360				—				—
	Restricted common units forfeited		(12,467	)			—				—
	Restricted common units repurchased (1)		(476	)			—				—
	Common units repurchased under repurchase program		(1,909,583	)			—				—
	Subordinated units converted to common units		5,360,912				(5,360,912	)			—
	Balance, March 31, 2015		84,017,738				—				86,797
	-1	Restricted common units are generally net-settled by unitholders to cover the required withholding tax upon vesting. Unitholders surrendered units with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were less than $0.1 million for the three months ended March 31, 2015. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership.
	Restricted common units are a component of common units as presented on our unaudited condensed consolidated balance sheets. See Note 11 for additional information regarding restricted common units that were granted during the three months ended March 31, 2015.
	On February 13, 2015, all of the 5,360,912 outstanding subordinated units owned by MRD Holdco were converted into common units. The subordinated units converted on a one-for-one basis into common units upon the payment of MEMP's fourth quarter 2014 distribution.  As discussed in Note 1, MRD Holdco sold 4,661,663 of our common units in an underwritten public secondary offering on April 14, 2015 and granted the underwriters a 30-day option to purchase up to an additional 699,249 common units.  As of April 30, 2015, MRD Holdco owns less than 0.3% of our outstanding common units.
	2015 Repurchases of Common Units
	In December 2014, the board of directors of our general partner authorized the repurchase of up to $150.0 million of our common units (“MEMP Repurchase Program”). Under the MEMP Repurchase Program, units may be repurchased and retired from time to time at our discretion on the open market. The MEMP Repurchase Program does not obligate us to repurchase any dollar amount or specific number of common units and may be discontinued at any time. During the three months ended March 31, 2015, we repurchased $28.4 million in common units, which represents a repurchase and retirement of 1,909,583 common units under the MEMP Repurchase Program.  At March 31, 2015, we have approximately $106.2 million of authorized repurchases remaining under the MEMP Repurchase Program.
	Allocations of Net Income (Loss)
	Net income (loss) attributable to the Partnership is allocated between our general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner and the Funds. Net income (loss) attributable to acquisitions accounted for as a transaction between entities under common control in a manner similar to the pooling of interest method prior to their acquisition date is allocated to the previous owners since they are affiliates of our general partner.
	Cash Distributions to Unitholders
	The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts):
														Distribution
									Amount			Aggregate		Received by
	Quarter		Declaration Date		Record Date		Payable Date		Per Unit			Distribution		Affiliates
	1st Quarter 2015		24-Apr-15		6-May-15		13-May-15		$	0.55		$	46.3	$	0.2
	4th Quarter 2014		26-Jan-15		5-Feb-15		12-Feb-15		$	0.55		$	46.3	$	3.1
	3rd Quarter 2014		23-Oct-14		5-Nov-14		12-Nov-14		$	0.55		$	47.8	$	3.1
	2nd Quarter 2014		24-Jul-14		5-Aug-14		12-Aug-14		$	0.55		$	39.5	$	3
	1st Quarter 2014		24-Apr-14		6-May-14		13-May-14		$	0.55		$	33.8	$	3
	4th Quarter 2013		24-Jan-14		6-Feb-14		13-Feb-14		$	0.55		$	33.8	$	3

Earnings_per_Unit

Earnings per Unit	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Earnings per Unit	Note 10. Earnings per Unit
	The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts):
		For the Three Months Ended
		March 31,
		2015			2014
	Net income (loss) attributable to Memorial Production Partners LP	$	(162,817	)	$	(32,947	)
	Less: Previous owners interest in net income (loss)		(2,268	)		1,165
	Less: General partner's 0.1% interest in net income (loss) (1)		(166	)		(34	)
	Less: IDRs attributable to corresponding period		56			40
	Net income (loss) available to limited partners	$	(160,439	)	$	(34,118	)
	Weighted average limited partner units outstanding:
	Common units		81,778			55,890
	Subordinated units		2,561			5,361
	Total		84,339			61,251
	Basic and diluted EPU	$	(1.90	)	$	(0.56	)
	-1	As a result of repurchases under the MEMP Repurchase Program, our general partner had an average 0.1023% interest in us for the three months ended March 31, 2015.

Equitybased_Awards

Equity-based Awards	3 Months Ended
	Mar. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Equity-based Awards	Note 11. Equity-Based Awards
	The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for the periods presented:
						Weighted-
						Average Grant
						Date Fair Value
		Number of Units				per Unit (1)
	Restricted common units outstanding at December 31, 2014		1,093,520			$	20.93
	Granted (2)		157,360			$	15.45
	Forfeited		(12,467	)		$	20.73
	Vested		(78,307	)		$	19.16
	Restricted common units outstanding at March 31, 2015		1,160,106			$	20.31
	-1	Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
	-2	The aggregate grant date fair value of restricted common unit awards issued in the three months ended March 31, 2015 was $2.4 million based on a grant date market price of $15.45 per unit.
	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	2,341			$	1,295
	The unrecognized compensation cost associated with restricted common unit awards was $16.3 million at March 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.99 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to partners as presented on our unaudited condensed statements of consolidated and combined cash flows.

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Note 12. Related Party Transactions
	Amounts due to (due from) Memorial Resource and certain affiliates of NGP at March 31, 2015 and December 31, 2014 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.
	Common Control Acquisitions
	On February 23, 2015, we consummated a common control transaction whereby Memorial Resource exchanged its East Texas and West Louisiana properties for all of our interest in the Terryville Field in North Louisiana and cash consideration of approximately $78.0 million, subject to customary purchase price adjustments. The transaction had an effective date of January 1, 2015. The properties MEMP received are primarily located in the Joaquin Field in Shelby and Panola counties in East Texas.  The Partnership recorded the following net assets (in thousands):
	Accounts receivable	$	2,372
	Other receivables		5,478
	Prepaid expenses and other current assets		1,874
	Property and equipment, net		263,210
	Accounts payable		(3,586	)
	Accounts payable - affiliate		(1,290	)
	Revenues payable		(1,110	)
	Accrued liabilities		(11,347	)
	Asset retirement obligations		(4,559	)
	Net assets	$	251,042
	Related Party Agreements
	We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.
	Omnibus Agreement
	Memorial Resource provides management, administrative and operating services for us and our general partner pursuant to our omnibus agreement. The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	8,553			$	4,848
	Beta Management Agreement
	Memorial Resource through its wholly-owned subsidiary, Beta Operating Company, LLC provides management and administrative oversight related to our offshore Southern California oil and gas properties in exchange for an annual management fee. Memorial Resource will receive approximately $0.4 million from us annually.
	Classic Agreements
	In November 2011, Classic Hydrocarbons Operating, LLC, a subsidiary of Memorial Resource (“Classic Operating”) and Classic Pipeline & Gathering, LLC (“Classic Pipeline”), a subsidiary of MRD Holdco, entered into a gas gathering agreement.  Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election.
	In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. In February 2015, in connection with and as part of the Property Swap, Classic Hydrocarbons Holdings, L.P. sold all of the equity interests owned by it in Classic Operating as well as Craton Energy GP III, LLC (“Craton GP”) and Craton Energy Holdings III, LP (“Craton LP”), two subsidiaries of Memorial Resource, to OLLC, and Classic Operating, Craton GP and Craton LP were merged into OLLC.  OLLC is therefore the successor to Classic Operating under the amended gas gathering agreement and water disposal agreement.

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 13. Commitments and Contingencies
	Litigation & Environmental
	As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows.
	At March 31, 2015 and December 31, 2014, we had $1.3 million and $2.1 million of environmental reserves recorded on our balance sheets, respectively.
	Supplemental Bond for Decommissioning Liabilities Trust Agreement
	In connection with its 2009 acquisition of the Beta properties, Rise Energy Operating, LLC (“REO”), our wholly-owned subsidiary, assumed an obligation with the BOEM for the decommissioning of the offshore production facilities.  The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of March 31, 2015 (in thousands):
		Amortized
	Investment	Cost
	U.S. Bank Money Market Cash Equivalent	$	137,705
	Less: Outside working interest owners share		(66,442	)
		$	71,263
	The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):
	30-Jun-15	$	72,450
	30-Jun-16	$	76,590
	31-Dec-16	$	78,660
	As of March 31, 2015, the maximum remaining obligation net to REO’s interest was approximately $7.4 million.

Organization_and_Basis_of_Pres1

Organization and Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
General	General
	Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries.
	We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Colorado, Wyoming, New Mexico and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells (often referred to as wellbore assignments).
	Unless the context requires otherwise, references to: (i) “our general partner” or “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner; (ii) “Memorial Resource” refer collectively to Memorial Resource Development Corp. and its subsidiaries other than the Partnership; (iii) “MRD LLC” refer to Memorial Resource Development LLC, which is the predecessor of Memorial Resource; (iv) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (v) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refer to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; (vii) “MRD Holdco” refer to MRD Holdco LLC, which together with a group controls Memorial Resource; and  (viii) “NGP” refer to Natural Gas Partners.
	The Partnership is owned 99.9% by its limited partners and 0.1% by MEMP GP, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities. Memorial Resource provides management, administrative and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco. The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are owned by our general partner.  As of March 31, 2015, MRD Holdco owned approximately 6% of our outstanding common units.  On April 14, 2015, MRD Holdco sold 4,661,663 of our common units in an underwritten public secondary offering and granted the underwriters a 30-day option to purchase up to an additional 699,249 common units.  As of April 30, 2015, MRD Holdco owns less than 0.3% of our outstanding common units.
Previous Owners	Previous Owners
	References to “the previous owners” for accounting and financial reporting purposes refer to certain oil and gas properties primarily located in East Texas and West Louisiana that the Partnership acquired on February 23, 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana for periods after common control commenced through the date of acquisition.  We refer to this transaction as the “Property Swap.”  The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”).   The Property Swap was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information have been retrospectively revised to give effect to the Property Swap as if the Partnership owned the assets for periods after common control commenced through the acquisition date.
Basis of Presentation	Basis of Presentation
	Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements of the previous owners were derived from their historical accounting records and reflect their historical financial position, results of operations and cash flows. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item.
	The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of the Partnership, is presented as a noncontrolling interest in the financial statements.
	Our results of operations for the three months ended March 31, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). These unaudited condensed consolidated and combined financial statements and the notes thereto should be read in conjunction with the audited supplemental consolidated and combined financial statements and notes thereto included in our Current Report on Form 8-K filed on April 21, 2015 (our “Recast Form 8-K”), which retrospectively revised certain of our financial and other information to give effect to the Property Swap.
	All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements.
Use of Estimates	Use of Estimates
	The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
	Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.
Accrued Liabilities	Accrued Liabilities
	Current accrued liabilities consisted of the following at the dates indicated (in thousands):
		March 31,				December 31,
		2015				2014
	Accrued capital expenditures	$	34,592			$	36,042
	Accrued interest payable		27,990				24,673
	Accrued lease operating expense		16,174				15,594
	Accrued ad valorem taxes		9,484				8,281
	Accrued general and administrative expenses		1,864				1,276
	Environmental liability		1,309				2,092
	Other		1,613				3,016
		$	93,026			$	90,974
Income Tax	Income Tax
	A deferred tax liability was recorded in equity by the previous owners and related to Memorial Resource’s initial public offering and restructuring transactions as it represented a transaction among shareholders.  Subsequent to Memorial Resource’s initial public offering in June 2014, income tax related to the Property Swap was calculated on a separate return basis through February 2015.  The deferred tax liability of approximately $28.0 million associated with the previous owners was retained by them in connection with the closing of the Property Swap transaction and reflected in the equity statement.
Supplemental Cash Flows	Supplemental Cash Flows
	Supplemental cash flow for the periods presented (in thousands):
			For the Three Months Ended
			March 31,
			2015				2014
	Supplemental cash flows:
	Cash paid for interest, net of amounts capitalized		$	21,298			$	1,421
	Noncash investing and financing activities:
	Change in capital expenditures in payables and accrued liabilities			(1,450	)			11,596
	Accounts receivable related to Eagle Ford Acquisition			—				3,879
	Assumptions of asset retirement obligations related to properties			2,266				285
	acquired
New Accounting Pronouncements	New Accounting Pronouncements
	Presentation of Debt Issuance Cost.  In April 2015, the Financial Accounting Standards Board ("FASB") issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Partnership does not expect the impact of adopting this guidance to be material to the Partnership’s financial statements and related disclosures.
	Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions.  In April 2015, FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required.  The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. Since the Partnership has historically allocated the earnings (losses) of transferred businesses that occurred in periods before the date of the dropdown transaction entirely to affiliates of the general partner (i.e., the previous owners) and did not adjust previously reported earnings per unit of the limited partners, the Partnership does not expect the impact of adopting this guidance will be material to the Partnership’s financial statements and related disclosures.
	Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Summary of Accounts Receivable from Joint Interest Owners and Other	Accounts receivable from joint interest owners and other consisted of the following at the dates indicated (in thousands):
		March 31,				December 31,
		2015				2014
	Derivatives expired positions	$	15,785			$	13,754
	July 2014 Wyoming Acquisition		—				9,569
	Joint interest owners		17,740				12,714
	Other		4,553				900
		$	38,078			$	36,937
Summary of Current Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands):
		March 31,				December 31,
		2015				2014
	Accrued capital expenditures	$	34,592			$	36,042
	Accrued interest payable		27,990				24,673
	Accrued lease operating expense		16,174				15,594
	Accrued ad valorem taxes		9,484				8,281
	Accrued general and administrative expenses		1,864				1,276
	Environmental liability		1,309				2,092
	Other		1,613				3,016
		$	93,026			$	90,974
Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands):
			For the Three Months Ended
			March 31,
			2015				2014
	Supplemental cash flows:
	Cash paid for interest, net of amounts capitalized		$	21,298			$	1,421
	Noncash investing and financing activities:
	Change in capital expenditures in payables and accrued liabilities			(1,450	)			11,596
	Accounts receivable related to Eagle Ford Acquisition			—				3,879
	Assumptions of asset retirement obligations related to properties			2,266				285
	acquired

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	3 Months Ended
	Mar. 31, 2015
Business Combinations [Abstract]
Acquisition-Related Costs	Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	1,299			$	1,894
Supplemental Pro Forma Information	The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2014 as though these third-party acquisitions had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.
		For the Three-Months Ended
		March 31,
		2014
		(In thousands,
		except per unit amounts)
	Revenues	$	173,549
	Net income (loss)		(19,984	)
	Basic and diluted earnings per unit		(0.35	)

Fair_Value_Measurements_of_Fin1

Fair Value Measurements of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2015 and December 31, 2014 for each of the fair value hierarchy levels:
		Fair Value Measurements at March 31, 2015 Using
		Quoted Prices in		Significant Other		Significant
		Active Market		Observable Inputs		Unobservable Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	670,973	$	—	$	670,973
	Interest rate derivatives		—		10		—		10
	Total assets	$	—	$	670,983	$	—	$	670,983
	Liabilities:
	Commodity derivatives	$	—	$	66,555	$	—	$	66,555
	Interest rate derivatives		—		3,549		—		3,549
	Total liabilities	$	—	$	70,104	$	—	$	70,104
		Fair Value Measurements at December 31, 2014 Using
		Quoted Prices in		Significant Other		Significant
		Active Market		Observable Inputs		Unobservable Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	564,913	$	—	$	564,913
	Interest rate derivatives		—		1,305		—		1,305
	Total assets		—	$	566,218		—	$	566,218
	Liabilities:
	Commodity derivatives	$	—	$	45,831	$	—	$	45,831
	Interest rate derivatives		—		3,289		—		3,289
	Total liabilities	$	—	$	49,120	$	—	$	49,120

Risk_Management_and_Derivative1

Risk Management and Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
Open Commodity Positions	At March 31, 2015, we had the following open commodity positions:
		Remaining
		2015				2016				2017				2018				2019
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		3,061,181				3,292,442				3,050,067				2,760,000				2,514,583
	Weighted-average fixed price	$	4.16			$	4.22			$	4.14			$	4.28			$	4.43
	Collar contracts:
	Average Monthly Volume (MMBtu)		350,000				—				—				—				—
	Weighted-average floor price	$	4.62			$	—			$	—			$	—			$	—
	Weighted-average ceiling price	$	5.8			$	—			$	—			$	—			$	—
	Call spreads (1):
	Average Monthly Volume (MMBtu)		80,000				—				—				—				—
	Weighted-average sold strike price	$	5.25			$	—			$	—			$	—			$	—
	Weighted-average bought strike price	$	6.75			$	—			$	—			$	—			$	—
	Basis swaps:
	Average Monthly Volume (MMBtu)		3,390,000				3,108,333				415,000				115,000				—
	Spread	$	(0.12	)		$	(0.05	)		$	—			$	0.15			$	—
	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		273,864				279,813				301,600				312,000				160,000
	Weighted-average fixed price	$	91.34			$	86.87			$	84.7			$	83.74			$	85.52
	Collar contracts:
	Average Monthly Volume (Bbls)		5,000				—				—				—				—
	Weighted-average floor price	$	80			$	—			$	—			$	—			$	—
	Weighted-average ceiling price	$	94			$	—			$	—			$	—			$	—
	Basis swaps:
	Average Monthly Volume (Bbls)		97,333				95,000				—				—				—
	Spread	$	(7.07	)		$	(9.56	)		$	—			$	—			$	—
	NGL Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		211,867				158,600				43,300				—				—
	Weighted-average fixed price	$	42.3			$	40.36			$	37.55			$	—			$	—
	·	These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.
Interest Rate Swap Open Positions	At March 31, 2015, we had the following interest rate swap open positions:
			Remaining
			2015				2016				2017				2018
	Average Monthly Notional (in thousands)		$	386,111			$	400,000			$	400,000			$	100,000
	Weighted-average fixed rate			1.247	%			0.943	%			1.612	%			1.946	%
	Floating rate		1 Month LIBOR				1 Month LIBOR				1 Month LIBOR				1 Month LIBOR
Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet	The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at March 31, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.
					Asset Derivatives								Liability Derivatives
					March 31,				December 31,				March 31,				December 31,
	Type		Balance Sheet Location		2015				2014				2015				2014
					(In thousands)
	Commodity contracts		Short-term derivative instruments		$	237,411			$	225,882			$	22,731			$	17,297
	Interest rate swaps		Short-term derivative instruments			—				—				2,994				3,289
	Gross fair value					237,411				225,882				25,725				20,586
	Netting arrangements		Short-term derivative instruments			(22,425	)			(17,297	)			(22,425	)			(17,297	)
	Net recorded fair value		Short-term derivative instruments		$	214,986			$	208,585			$	3,300			$	3,289
	Commodity contracts		Long-term derivative instruments		$	433,562			$	339,031			$	43,824			$	28,534
	Interest rate swaps		Long-term derivative instruments			10				1,305				555				—
	Gross fair value					433,572				340,336				44,379				28,534
	Netting arrangements		Long-term derivative instruments			(43,824	)			(28,534	)			(43,824	)			(28,534	)
	Net recorded fair value		Long-term derivative instruments		$	389,748			$	311,802			$	555			$	—
Unrealized and Realized Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the three months ended March 31, 2015 and 2014 (in thousands):
			Statements of		March 31,
			Operations Location		2015				2014
	Commodity derivative contracts		(Gain) loss on commodity derivatives		$	(145,459	)		$	46,766
	Interest rate derivatives		Interest expense, net			2,441				315
Disaggregated Basis Swap [Member]
Open Commodity Positions	Our basis swaps included in the table above are presented on a disaggregated basis below:
			Remaining
			2015				2016				2017				2018
	Natural Gas Derivative Contracts:
	NGPL TexOk basis swaps:
	Average Monthly Volume (MMBtu)			2,730,000				2,703,333				300,000				—
	Spread-Henry Hub		$	(0.12	)		$	(0.07	)		$	(0.05	)		$	—
	HSC basis swaps:
	Average Monthly Volume (MMBtu)			150,000				135,000				115,000				115,000
	Spread-Henry Hub		$	(0.08	)		$	0.07			$	0.14			$	0.15
	CIG basis swaps:
	Average Monthly Volume (MMBtu)			210,000				—				—				—
	Spread-Henry Hub		$	(0.25	)		$	—			$	—			$	—
	TETCO STX basis swaps:
	Average Monthly Volume (MMBtu)			300,000				270,000				—				—
	Spread-Henry Hub		$	(0.09	)		$	0.06			$	—			$	—
	Crude Oil Derivative Contracts:
	Midway-Sunset basis swaps:
	Average Monthly Volume (Bbls)			57,333				55,000				—				—
	Spread - Brent		$	(9.73	)		$	(13.35	)		$	—			$	—
	Midland basis swaps:
	Average Monthly Volume (Bbls)			40,000				40,000				—				—
	Spread - WTI		$	(3.25	)		$	(4.34	)		$	—			$	—

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2015 (in thousands):
	Asset retirement obligations at beginning of period	$	112,702
	Liabilities added from acquisitions or drilling		2,304
	Liabilities removed upon sale of wells		(62	)
	Accretion expense		1,634
	Revision of estimates		149
	Asset retirement obligations at end of period	$	116,727

Restricted_Investments_Tables

Restricted Investments (Tables)	3 Months Ended
	Mar. 31, 2015
Investments Debt And Equity Securities [Abstract]
Restricted Investment Balance	The components of the restricted investment balance consisted of the following at the dates indicated:
		March 31,		December 31,
		2015		2014
		(In thousands)
	BOEM platform abandonment (See Note 13)	$	71,263	$	69,954
	BOEM lease bonds		794		794
	SPBPC Collateral:
	Contractual pipeline and surface facilities abandonment		2,818		2,701
	California State Lands Commission pipeline right-of-way bond		3,005		3,005
	City of Long Beach pipeline facility permit		500		500
	Federal pipeline right-of-way bond		307		307
	Port of Long Beach pipeline license		100		100
	Restricted investments	$	78,787	$	77,361

Long_Term_Debt_Tables

Long Term Debt (Tables)	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations at the dates indicated:
		March 31,			December 31,
		2015			2014
		(In thousands)
	MEMP:
	OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	573,000		$	412,000
	2021 Senior Notes, fixed-rate, due May 2021 (1)		700,000			700,000
	2022 Senior Notes, fixed-rate, due August 2022 (2)		496,990			500,000
	Unamortized discounts		(15,945	)		(16,587	)
	Total long-term debt	$	1,754,045		$	1,595,413
	-1	The estimated fair value of our 2021 Senior Notes was $640.5 million and $563.5 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
	-2	The estimated fair value of our 2022 Senior Notes was $437.4 million and $380.0 million at March 31, 2015 and December 31, 2014, respectively.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
Borrowing Base Credit Facility	Credit facilities tied to borrowing bases are common throughout the oil and gas industry. The borrowing base for our revolving credit facility was the following at the date indicated:
		March 31,
		2015
		(In thousands)
	OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	1,300,000
Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations	The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented:
		For the Three Months Ended
		March 31,
		2015			2014
	OLLC revolving credit facility		1.9	%		1.66	%
Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:
		March 31,			December 31,
		2015			2014
		(In thousands)
	OLLC $2.0 billion revolving credit facility, variable-rate, due	$	5,395		$	6,468
	March 2018 (1)
	2021 Senior Notes (2)		12,779			13,308
	2022 Senior Notes (2)		7,656			7,958
	Total	$	25,830		$	27,734
	-1	Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.
	-2	Unamortized deferred financing costs are amortized using the straight line method, which generally approximates the effective interest method.

Equity_and_Distributions_Table

Equity and Distributions (Tables)	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Summary of Changes in Number of Outstanding Units	The following table summarizes changes in the number of outstanding units since December 31, 2014:
										General
		Common				Subordinated				Partner
	Balance, December 31, 2014		80,421,992				5,360,912				86,797
	Restricted common units issued		157,360				—				—
	Restricted common units forfeited		(12,467	)			—				—
	Restricted common units repurchased (1)		(476	)			—				—
	Common units repurchased under repurchase program		(1,909,583	)			—				—
	Subordinated units converted to common units		5,360,912				(5,360,912	)			—
	Balance, March 31, 2015		84,017,738				—				86,797
	-1	Restricted common units are generally net-settled by unitholders to cover the required withholding tax upon vesting. Unitholders surrendered units with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were less than $0.1 million for the three months ended March 31, 2015. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership.
Summary of Quarterly Cash Distribution Rates	The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts):
														Distribution
									Amount			Aggregate		Received by
	Quarter		Declaration Date		Record Date		Payable Date		Per Unit			Distribution		Affiliates
	1st Quarter 2015		24-Apr-15		6-May-15		13-May-15		$	0.55		$	46.3	$	0.2
	4th Quarter 2014		26-Jan-15		5-Feb-15		12-Feb-15		$	0.55		$	46.3	$	3.1
	3rd Quarter 2014		23-Oct-14		5-Nov-14		12-Nov-14		$	0.55		$	47.8	$	3.1
	2nd Quarter 2014		24-Jul-14		5-Aug-14		12-Aug-14		$	0.55		$	39.5	$	3
	1st Quarter 2014		24-Apr-14		6-May-14		13-May-14		$	0.55		$	33.8	$	3
	4th Quarter 2013		24-Jan-14		6-Feb-14		13-Feb-14		$	0.55		$	33.8	$	3

Earnings_per_Unit_Tables

Earnings per Unit (Tables)	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Calculation of Earnings (Loss) Per Unit	The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts):
		For the Three Months Ended
		March 31,
		2015			2014
	Net income (loss) attributable to Memorial Production Partners LP	$	(162,817	)	$	(32,947	)
	Less: Previous owners interest in net income (loss)		(2,268	)		1,165
	Less: General partner's 0.1% interest in net income (loss) (1)		(166	)		(34	)
	Less: IDRs attributable to corresponding period		56			40
	Net income (loss) available to limited partners	$	(160,439	)	$	(34,118	)
	Weighted average limited partner units outstanding:
	Common units		81,778			55,890
	Subordinated units		2,561			5,361
	Total		84,339			61,251
	Basic and diluted EPU	$	(1.90	)	$	(0.56	)
	·	As a result of repurchases under the MEMP Repurchase Program, our general partner had an average 0.1023% interest in us for the three months ended March 31, 2015.

Equitybased_Awards_Tables

Equity-based Awards (Tables)	3 Months Ended
	Mar. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Information Regarding Restricted Common Unit Awards	The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for the periods presented:
						Weighted-
						Average Grant
						Date Fair Value
		Number of Units				per Unit (1)
	Restricted common units outstanding at December 31, 2014		1,093,520			$	20.93
	Granted (2)		157,360			$	15.45
	Forfeited		(12,467	)		$	20.73
	Vested		(78,307	)		$	19.16
	Restricted common units outstanding at March 31, 2015		1,160,106			$	20.31
	·	Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
	·	The aggregate grant date fair value of restricted common unit awards issued in the three months ended March 31, 2015 was $2.4 million based on a grant date market price of $15.45 per unit.
Summary of Amount of Compensation Expense Recognized	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	2,341			$	1,295

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2015
Related Party Transaction [Line Items]
Schedule of Net Assets Recorded by Partnership	The Partnership recorded the following net assets (in thousands):
	Accounts receivable	$	2,372
	Other receivables		5,478
	Prepaid expenses and other current assets		1,874
	Property and equipment, net		263,210
	Accounts payable		(3,586	)
	Accounts payable - affiliate		(1,290	)
	Revenues payable		(1,110	)
	Accrued liabilities		(11,347	)
	Asset retirement obligations		(4,559	)
	Net assets	$	251,042
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
Schedule of Amount of General and Administrative Costs and Expenses Recognized	The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands):
	For the Three Months Ended
	March 31,
	2015				2014
	$	8,553			$	4,848

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Gross Held-to-Maturity Investments	The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of March 31, 2015 (in thousands):
		Amortized
	Investment	Cost
	U.S. Bank Money Market Cash Equivalent	$	137,705
	Less: Outside working interest owners share		(66,442	)
		$	71,263
Minimum Balances Attributable to Net Working Interest	The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):
	30-Jun-15	$	72,450
	30-Jun-16	$	76,590
	31-Dec-16	$	78,660

Organization_and_Basis_of_Pres2

Organization and Basis of Presentation - Additional Information (Detail)	0 Months Ended
	Apr. 14, 2015	Mar. 31, 2015	Apr. 30, 2015
MRD Holdco [Member]
Organization And Basis Of Presentation (Textual) [Abstract]
Percentage of outstanding common units		6.00%
MRD Holdco [Member] | Subsequent Event [Member]
Organization And Basis Of Presentation (Textual) [Abstract]
Common units sold in underwritten public secondary offering	4,661,663
Period granted to underwriters for purchase of common units	30 days
Additional common units available to purchase	699,249
MRD Holdco [Member] | Maximum [Member] | Subsequent Event [Member]
Organization And Basis Of Presentation (Textual) [Abstract]
Percentage of outstanding common units			0.30%
Limited Partners Common Units [Member]
Organization And Basis Of Presentation (Textual) [Abstract]
Partnership ownership percentage		99.90%
General Partner [Member]
Organization And Basis Of Presentation (Textual) [Abstract]
Partnership ownership percentage		0.10%
General Partner [Member] | The Funds [Member]
Organization And Basis Of Presentation (Textual) [Abstract]
Percentage of economic interest in incentive distribution rights		50.00%

Summary_of_Significant_Account2

Summary of Significant Accounting Policies - Summary of Accounts Receivable from Joint Interest Owners and Other (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Accounts Notes And Loans Receivable [Line Items]
Derivatives expired positions	$15,785	$13,754
Joint interest owners	17,740	12,714
Other	4,553	900
Accounts receivable from joint interest owners and other	38,078	36,937
Wyoming Acquisition [Member]
Accounts Notes And Loans Receivable [Line Items]
July 2014 Wyoming Acquisition		$9,569

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Summary of Current Accrued Liabilities (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Accrued Liabilities Current [Abstract]
Accrued capital expenditures	$34,592	$36,042
Accrued interest payable	27,990	24,673
Accrued lease operating expense	16,174	15,594
Accrued ad valorem taxes	9,484	8,281
Accrued general and administrative expenses	1,864	1,276
Environmental liability	1,309	2,092
Other	1,613	3,016
Accrued liabilities, Total	$93,026	$90,974

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Additional Information (Detail) (Previous Owners [Member], USD $)	Feb. 23, 2015
In Millions, unless otherwise specified
Previous Owners [Member]
Significant Accounting Policies [Line Items]
Deferred Tax Liabilities Retained by Previous Owners	$28

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Summary of Supplemental Cash Flows (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$21,298	$1,421
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities	-1,450	11,596
Assumptions of asset retirement obligations related to properties acquired	2,266	285
Eagle Ford Acquisition [Member]
Noncash investing and financing activities:
Accounts receivable related to Eagle Ford Acquisition		$3,879

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures - Additional Information (Detail) (Eagle Ford [Member], Leasehold [Member])	0 Months Ended
	Mar. 25, 2014
Eagle Ford [Member] | Leasehold [Member]
Business Acquisition And Divestiture [Line Items]
Percentage of leasehold interest acquired	30.00%

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures - Acquisition-Related Costs (Detail) (General and Administrative Expense, USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
General and Administrative Expense
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	$1,299	$1,894

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures - Supplemental Pro Forma Information (Detail) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2014
Business Acquisition Pro Forma Information [Abstract]
Revenues	$173,549
Net income (loss)	($19,984)
Basic and diluted earnings per unit	($0.35)

Fair_Value_Measurements_of_Fin2

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (Fair Value [Member], USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	$670,983	$566,218
Interest rate derivatives, Assets	10	1,305
Liabilities	70,104	49,120
Interest rate derivatives, Liabilities	3,549	3,289
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	670,983	566,218
Interest rate derivatives, Assets	10	1,305
Liabilities	70,104	49,120
Interest rate derivatives, Liabilities	3,549	3,289
Commodity derivatives [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	670,973	564,913
Liabilities	66,555	45,831
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	670,973	564,913
Liabilities	$66,555	$45,831

Fair_Value_Measurements_of_Fin3

Fair Value Measurements of Financial Instruments - Additional Information (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	$251,347
Carrying value of properties after impairment charges	2,250,284		2,470,332
East Texas, Wyoming and Colorado [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	251,300	0
Carrying value of properties after impairment charges	$157,600

Risk_Management_and_Derivative2

Risk Management and Derivative Instruments - Additional Information (Detail) (USD $)	1 Months Ended	3 Months Ended
In Millions, unless otherwise specified	Feb. 28, 2015	Mar. 31, 2015
Concentration Risks, Types, No Concentration Percentage [Abstract]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk		$272.60
Maximum amount of loss due to credit risk		328.4
Cash settlement receipt	27.1
Single Counterparty [Member]
Concentration Risks, Types, No Concentration Percentage [Abstract]
Maximum amount of loss due to credit risk		$113.40

Risk_Management_and_Derivative3

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	3 Months Ended
	Mar. 31, 2015
	MMBTU
Remaining 2015 [Member] | Natural Gas Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	3,061,181
Weighted-average fixed price	4.16
Remaining 2015 [Member] | Natural Gas Derivative Contracts Collar Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	350,000
Weighted-average floor price	4.62
Weighted-average ceiling price	5.8
Remaining 2015 [Member] | Natural Gas Derivative Contracts Call Spreads [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	80,000
Weighted-average sold strike price	5.25
Weighted-average bought strike price	6.75
Remaining 2015 [Member] | Natural Gas Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	3,390,000
Spread	-0.12
Remaining 2015 [Member] | Crude Oil Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	273,864
Weighted-average fixed price	91.34
Remaining 2015 [Member] | Crude Oil Derivative Contracts Collar Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	5,000
Weighted-average floor price	80
Weighted-average ceiling price	94
Remaining 2015 [Member] | Crude Oil Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	97,333
Spread	-7.07
Remaining 2015 [Member] | NGL Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	211,867
Weighted-average fixed price	42.3
2016 [Member] | Natural Gas Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	3,292,442
Weighted-average fixed price	4.22
2016 [Member] | Natural Gas Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	3,108,333
Spread	-0.05
2016 [Member] | Crude Oil Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	279,813
Weighted-average fixed price	86.87
2016 [Member] | Crude Oil Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	95,000
Spread	-9.56
2016 [Member] | NGL Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	158,600
Weighted-average fixed price	40.36
2017 [Member] | Natural Gas Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	3,050,067
Weighted-average fixed price	4.14
2017 [Member] | Natural Gas Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	415,000
2017 [Member] | Crude Oil Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	301,600
Weighted-average fixed price	84.7
2017 [Member] | NGL Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	43,300
Weighted-average fixed price	37.55
2018 [Member] | Natural Gas Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	2,760,000
Weighted-average fixed price	4.28
2018 [Member] | Natural Gas Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	115,000
Spread	0.15
2018 [Member] | Crude Oil Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	312,000
Weighted-average fixed price	83.74
2019 [Member] | Natural Gas Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	2,514,583
Weighted-average fixed price	4.43
2019 [Member] | Crude Oil Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	160,000
Weighted-average fixed price	85.52

Risk_Management_and_Derivative4

Risk Management and Derivative Instruments - Open Commodity Positions Disaggregated Basis (Detail) (Disaggregated Basis Swap [Member])	3 Months Ended
	Mar. 31, 2015
	MMBTU
Remaining 2015 [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	2,730,000
Remaining 2015 [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	150,000
Remaining 2015 [Member] | Natural Gas Derivative Contracts CIG Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	210,000
Remaining 2015 [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	300,000
Remaining 2015 [Member] | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	57,333
Remaining 2015 [Member] | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	40,000
Remaining 2015 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-0.12
Remaining 2015 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-0.08
Remaining 2015 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts CIG Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-0.25
Remaining 2015 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-0.09
Remaining 2015 [Member] | Brent | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-9.73
Remaining 2015 [Member] | WTI | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-3.25
2016 [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	2,703,333
2016 [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	135,000
2016 [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	270,000
2016 [Member] | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	55,000
2016 [Member] | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	40,000
2016 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-0.07
2016 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	0.07
2016 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	0.06
2016 [Member] | Brent | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-13.35
2016 [Member] | WTI | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-4.34
2017 [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	300,000
2017 [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	115,000
2017 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-0.05
2017 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	0.14
2018 [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	115,000
2018 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	0.15

Risk_Management_and_Derivative5

Risk Management and Derivative Instruments - Interest Rate Swap Open Positions (Detail) (Interest rate swaps [Member], USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015
2015 [Member]
Derivative [Line Items]
Average Monthly Notional	$386,111
Weighted-average fixed rate	1.25%
Floating rate	1 Month LIBOR
2016 [Member]
Derivative [Line Items]
Average Monthly Notional	400,000
Weighted-average fixed rate	0.94%
Floating rate	1 Month LIBOR
2017 [Member]
Derivative [Line Items]
Average Monthly Notional	400,000
Weighted-average fixed rate	1.61%
Floating rate	1 Month LIBOR
2018 [Member]
Derivative [Line Items]
Average Monthly Notional	$100,000
Weighted-average fixed rate	1.95%
Floating rate	1 Month LIBOR

Risk_Management_and_Derivative6

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$214,986	$208,585
Asset Derivatives, Net recorded fair value	389,748	311,802
Liability Derivatives, Net recorded fair value	3,300	3,289
Liability Derivatives, Net recorded fair value	555
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	237,411	225,882
Asset Derivatives, Netting arrangements	-22,425	-17,297
Asset Derivatives, Net recorded fair value	214,986	208,585
Liability Derivatives, Gross fair value	25,725	20,586
Liability Derivatives, Netting arrangements	-22,425	-17,297
Liability Derivatives, Net recorded fair value	3,300	3,289
Short-Term Derivative Instruments [Member] | Commodity derivative contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	237,411	225,882
Liability Derivatives, Gross fair value	22,731	17,297
Short-Term Derivative Instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Liability Derivatives, Gross fair value	2,994	3,289
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	433,572	340,336
Asset Derivatives, Netting arrangements	-43,824	-28,534
Asset Derivatives, Net recorded fair value	389,748	311,802
Liability Derivatives, Gross fair value	44,379	28,534
Liability Derivatives, Netting arrangements	-43,824	-28,534
Liability Derivatives, Net recorded fair value	555
Long-Term Derivative Instruments [Member] | Commodity derivative contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	433,562	339,031
Liability Derivatives, Gross fair value	43,824	28,534
Long-Term Derivative Instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	10	1,305
Liability Derivatives, Gross fair value	$555

Risk_Management_and_Derivative7

Risk Management and Derivative Instruments - Unrealized and Realized Gains and Losses Related to Derivative Instruments (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	($145,459)	$46,766
Interest expense, net	-28,818	-16,078
Commodity derivative contracts [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	-145,459	46,766
Interest rate derivatives [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
Interest expense, net	$2,441	$315

Asset_Retirement_Obligations_S

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Asset Retirement Obligation Roll Forward Analysis Roll Forward
Asset retirement obligations at beginning of period	$112,702
Liabilities added from acquisitions or drilling	2,304
Liabilities removed upon sale of wells	-62
Accretion expense	1,634	1,391
Revision of estimates	149
Asset retirement obligations at end of period	$116,727

Restricted_Investments_Restric

Restricted Investments - Restricted Investment Balance (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Restricted Cash and Investments [Abstract]
Restricted investments	$78,787	$77,361
BOEM platform abandonment [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	71,263	69,954
BOEM lease bonds [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	794	794
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	2,818	2,701
SPBPC Collateral California State Lands Commission pipeline right-of-way bond [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	3,005	3,005
SPBPC Collateral City of Long Beach pipeline facility permit [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	500	500
SPBPC Collateral Federal pipeline right-of-way bond [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	307	307
SPBPC Collateral Port of Long Beach pipeline license [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	$100	$100

Long_Term_Debt_Consolidated_De

Long Term Debt - Consolidated Debt Obligations (Detail) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Thousands, unless otherwise specified
Debt Obligations [Abstract]
Unamortized discounts	($15,945)		($16,587)
Total long-term debt	1,754,045		1,595,413
OLLC $2.0 billion revolving credit facility [Member]
Debt Obligations [Abstract]
Revolving credit facility	573,000		412,000
Senior Secured Notes [Member] | Notes Due 2021 [Member]
Debt Obligations [Abstract]
Senior Notes, fixed-rate	700,000	[1]	700,000	[1]
Senior Secured Notes [Member] | Notes Due 2022 [Member]
Debt Obligations [Abstract]
Senior Notes, fixed-rate	$496,990	[2]	$500,000	[2]
[1]	The estimated fair value of our 2021 Senior Notes was $640.5 million and $563.5 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[2]	The estimated fair value of our 2022 Senior Notes was $437.4 million and $380.0 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Long_Term_Debt_Consolidated_De1

Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
OLLC $2.0 billion revolving credit facility [Member]
Debt Obligations [Abstract]
Maturity date	19-Mar-18
Revolving credit facility	$2,000,000,000
Senior Secured Notes [Member] | Notes Due 2021 [Member]
Debt Obligations [Abstract]
Maturity date	1-May-21
Estimated fair value of fixed rate debt	640,500,000	563,500,000
Senior Secured Notes [Member] | Notes Due 2022 [Member]
Debt Obligations [Abstract]
Maturity date	1-Aug-22
Estimated fair value of fixed rate debt	$437,400,000	$380,000,000

Long_Term_Debt_Additional_Info

Long Term Debt - Additional Information (Detail) (USD $)	Mar. 31, 2015
Line Of Credit Facility [Line Items]
Letters of credit outstanding	$4,800,000
OLLC $2.0 billion revolving credit facility [Member]
Line Of Credit Facility [Line Items]
Line of credit facility, aggregate maximum borrowing amount	$2,000,000,000
Universal Shelf Registration Statement [Member]
Line Of Credit Facility [Line Items]
Universal shelf guarantor subsidiaries ownership percentage	100.00%

Long_Term_Debt_Borrowing_Base_

Long Term Debt - Borrowing Base Credit Facility (Detail) (OLLC $2.0 billion revolving credit facility [Member], USD $)	Mar. 31, 2015
In Thousands, unless otherwise specified
OLLC $2.0 billion revolving credit facility [Member]
Line Of Credit Facility [Line Items]
Borrowing Base	$1,300,000

Long_Term_Debt_Borrowing_Base_1

Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail) (OLLC $2.0 billion revolving credit facility [Member], USD $)	Mar. 31, 2015
OLLC $2.0 billion revolving credit facility [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$2,000,000,000

Long_Term_Debt_Summary_of_Weig

Long Term Debt - Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations (Detail) (OLLC Revolving Credit Facility [Member])	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
OLLC Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	1.90%	1.66%

Long_Term_Debt_Summary_of_Unam

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Thousands, unless otherwise specified
Credit Facilities [Line Items]
Unamortized deferred financing costs	$25,830		$27,734
2021 [Member] | Senior Notes [Member]
Credit Facilities [Line Items]
Unamortized deferred financing costs	12,779	[1]	13,308	[1]
2022 [Member] | Senior Notes [Member]
Credit Facilities [Line Items]
Unamortized deferred financing costs	7,656	[1]	7,958	[1]
OLLC $2.0 billion revolving credit facility [Member]
Credit Facilities [Line Items]
Unamortized deferred financing costs	$5,395	[2]	$6,468	[2]
[1]	Unamortized deferred financing costs are amortized using the straight line method, which generally approximates the effective interest method.
[2]	Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.

Long_Term_Debt_Summary_of_Unam1

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Parenthetical) (Detail) (OLLC $2.0 billion revolving credit facility [Member], USD $)	Mar. 31, 2015
OLLC $2.0 billion revolving credit facility [Member]
Credit Facilities [Line Items]
Revolving credit facility	$2,000,000,000

Equity_and_Distributions_Summa

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Detail)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance		86,797
Ending balance	86,797	86,797
Limited Partners Common Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	80,421,992
Restricted common units issued	157,360
Restricted common units forfeited	-12,467
Restricted common units repurchased	-476
Common units repurchased under repurchase program	-1,909,583
Subordinated units converted to common units	5,360,912
Ending balance	84,017,738
Subordinated Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	5,360,912
Subordinated units converted to common units	-5,360,912
Ending balance	0

Equity_and_Distributions_Summa1

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Parenthetical) (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015
Summary Of Changes In Number Of Outstanding Units [Abstract]
Withholding tax withheld and paid related to vesting of restricted common units	$7
Maximum [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Withholding tax withheld and paid related to vesting of restricted common units	$100

Equity_and_Distributions_Addit

Equity and Distributions - Additional Information (Detail) (USD $)	3 Months Ended	0 Months Ended
	Mar. 31, 2015	Feb. 13, 2015	Apr. 14, 2015	Dec. 31, 2014	Apr. 30, 2015
Limited Partners Capital Account [Line Items]
Common units amount repurchased under repurchase program	$28,420,000
MEMP Repurchase Program [Member]
Limited Partners Capital Account [Line Items]
Stock repurchase program, authorized amount				150,000,000
Common units amount repurchased under repurchase program	28,420,000
Common units repurchased under repurchase program	1,909,583
Amount remaining under repurchase program	$106,200,000
MRD Holdco [Member]
Limited Partners Capital Account [Line Items]
Percentage of outstanding common units	6.00%
Subordinated Units [Member]
Limited Partners Capital Account [Line Items]
Subordinated units converted to common units	-5,360,912
Subordinated Units [Member] | MRD Holdco [Member]
Limited Partners Capital Account [Line Items]
Subordinated units converted to common units		5,360,912
Conversion of subordinated units, Description	The subordinated units converted on a one-for-one basis into common units upon the payment of MEMP's fourth quarter 2014 distribution.
Subsequent Event [Member] | MRD Holdco [Member]
Limited Partners Capital Account [Line Items]
Common units sold in underwritten public secondary offering			4,661,663
Period granted to underwriters for purchase of common units			30 days
Additional common units granted to underwriters			699,249
Maximum [Member] | Subsequent Event [Member] | MRD Holdco [Member]
Limited Partners Capital Account [Line Items]
Percentage of outstanding common units					0.30%

Equity_and_Distributions_Summa2

Equity and Distributions - Summary of Quarterly Cash Distribution Rates (Detail) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013
Equity [Abstract]
Distribution made to member or limited partner, date of declaration	24-Apr-15	26-Jan-15	23-Oct-14	24-Jul-14	24-Apr-14	24-Jan-14
Distribution made to member or limited partner, date of record	6-May-15	5-Feb-15	5-Nov-14	5-Aug-14	6-May-14	6-Feb-14
Distribution made to member or limited partner, date of distribution	13-May-15	12-Feb-15	12-Nov-14	12-Aug-14	13-May-14	13-Feb-14
Distribution per unit	$0.55	$0.55	$0.55	$0.55	$0.55	$0.55
Aggregate Distribution	$46.30	$46.30	$47.80	$39.50	$33.80	$33.80
Distribution Received by Affiliates	$0.20	$3.10	$3.10	$3	$3	$3

Earnings_Per_Unit_Calculation_

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Detail) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Earnings Per Unit [Line Items]
Net income (loss) attributable to Memorial Production Partners LP	($162,817)	($32,947)
Less: Previous owners interest in net income (loss)	-2,268	1,165
Less: General partner's 0.1% interest in net income (loss)	-166	-34
Less: IDRs attributable to corresponding period	56	40
Net income (loss) available to limited partners	($160,439)	($34,118)
Weighted average limited partner units outstanding:
Basic and diluted	84,339	61,251
Basic and diluted EPU	($1.90)	($0.56)
Common Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding	81,778	55,890
Subordinated Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding	2,561	5,361

Earnings_Per_Unit_Calculation_1

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Parenthetical) (Detail)	3 Months Ended
	Mar. 31, 2015
Earnings Per Unit [Line Items]
General partner's interest in net income, percentage	0.10%
MEMP Repurchase Program [Member]
Earnings Per Unit [Line Items]
General partner's interest in net income, percentage	0.10%

Equitybased_Awards_Summary_of_

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Detail) (Restricted Stock [Member], USD $)	3 Months Ended
	Mar. 31, 2015
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted common units outstanding, Beginning Balance	1,093,520
Granted, Number of Units	157,360
Restricted common units forfeited	-12,467
Vested, Number of Units	-78,307
Restricted common units outstanding, Ending Balance	1,160,106
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance	$20.93
Granted, Weighted-Average Grant Date Fair Value per Unit	$15.45
Forfeited, Weighted-Average Grant Date Fair Value per Unit	$20.73
Vested, Weighted-Average Grant Date Fair Value per Unit	$19.16
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance	$20.31

Equitybased_Awards_Summary_of_1

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) (Restricted Stock [Member], USD $)	Mar. 31, 2015
In Millions, except Per Share data, unless otherwise specified
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted common unit awards issued	$2.40
Grant date market price	$15.45

Equitybased_Awards_Summary_of_2

Equity-based Awards - Summary of Amount of Compensation Expense Recognized (Detail) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Compensation expense	$2,341	$1,295

Equitybased_Awards_Additional_

Equity-based Awards - Additional Information (Detail) (Restricted Common Units [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$16.30
Weighted-average period of unrecognized compensation cost	1 year 11 months 27 days

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (USD $)	3 Months Ended	1 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Nov. 30, 2011	31-May-14	Feb. 23, 2015
Related Party Transaction [Line Items]
Effective date of acquisition common control	1-Jan-15
Common Control Acquisition Purchase Price				$78
Memorial Resource [Member]
Related Party Transaction [Line Items]
Amount receivable under management agreement	0.4
Classic Pipeline Gas Gathering Agreement [Member]
Related Party Transaction [Line Items]
Pipeline transportation agreement expiration year		2020
Pipeline transportation agreement extension		1 year
Amended gas gathering agreement terms disclosure	Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel
Agreement expired, date	31-Dec-23
Classic Pipeline Gas Gathering Agreement [Member] | November 2011 to December 2020 [Member]
Related Party Transaction [Line Items]
Maximum dedication of natural gas produced	50,000
Classic Pipeline Gas Gathering Agreement [Member] | May 2014 to December 2020 [Member]
Related Party Transaction [Line Items]
Annual inflationary escalation, rate	3.50%
Classic Pipeline Gas Gathering Agreement [Member] | Volume [Member] | May 2014 to December 2020 [Member]
Related Party Transaction [Line Items]
Base gas gathering fee per MMBtu	0.3
Classic Pipeline Gas Gathering Agreement [Member] | Compression [Member] | May 2014 to December 2020 [Member]
Related Party Transaction [Line Items]
Base stage of compression fee per MMBtu	0.07
Classic Pipeline Water Disposal Agreement [Member]
Related Party Transaction [Line Items]
Pipeline water disposal agreement extension			1 year
Primary term of agreement			3 years
Agreed SWD fees per barrel			1.1

Related_Party_Transactions_Sch

Related Party Transactions - Schedule of Net Assets Recorded by Partnership (Detail) (Property Swap [Member], USD $)	Feb. 23, 2015
In Thousands, unless otherwise specified
Property Swap [Member]
Related Party Transaction [Line Items]
Accounts receivable	$2,372
Other receivables	5,478
Prepaid expenses and other current assets	1,874
Property and equipment, net	263,210
Accounts payable	-3,586
Accounts payable - affiliate	-1,290
Revenues payable	-1,110
Accrued liabilities	-11,347
Asset retirement obligations	-4,559
Net assets	$251,042

Related_Party_Transactions_Sch1

Related Party Transactions - Schedule of Amount of General and Administrative Costs and Expenses Recognized (Detail) (Omnibus Agreement [Member], USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
General and administrative costs and expenses under omnibus agreement	$8,553	$4,848

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Commitments And Contingencies Additional Textual [Abstract]
Environmental liability	$1,309,000	$2,092,000
Maximum remaining obligation	$7,400,000

Commitments_and_Contingencies_2

Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) (USD $)	Mar. 31, 2015
In Thousands, unless otherwise specified
Held-to-maturity Securities [Abstract]
Amortized Cost	$71,263
Less: Outside working interest owners share	-66,442
U.S. Bank Money Market Cash Equivalent [Member]
Held-to-maturity Securities [Abstract]
Amortized Cost	$137,705

Commitments_and_Contingencies_3

Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) (USD $)	Mar. 31, 2015
In Thousands, unless otherwise specified
June 30, 2015 [Member]
Asset retirement obligations
Minimum balances attributable to REO's net working interest	$72,450
June 30, 2016 [Member]
Asset retirement obligations
Minimum balances attributable to REO's net working interest	76,590
December 31, 2016 [Member]
Asset retirement obligations
Minimum balances attributable to REO's net working interest	$78,660