Amplify Energy (AMPYW) 10-K 7 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Jun. 28, 2013	Feb. 28, 2014	Feb. 28, 2014	Feb. 28, 2014
			Common Units [Member]	Subordinated Units [Member]	General Partner [Member]
Document Information [Line Items]	'	'	'	'	'
Document Type	'10-K	'	'	'	'
Amendment Flag	'false	'	'	'	'
Document Period End Date	31-Dec-13	'	'	'	'
Document Fiscal Year Focus	'2013	'	'	'	'
Document Fiscal Period Focus	'FY	'	'	'	'
Trading Symbol	'MEMP	'	'	'	'
Entity Registrant Name	'MEMORIAL PRODUCTION PARTNERS LP	'	'	'	'
Entity Central Index Key	'0001521847	'	'	'	'
Current Fiscal Year End Date	'--12-31	'	'	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'	'	'
Entity Current Reporting Status	'Yes	'	'	'	'
Entity Voluntary Filers	'No	'	'	'	'
Entity Filer Category	'Accelerated Filer	'	'	'	'
Entity Common Stock, Shares Outstanding	'	'	55,890,998	5,360,912	61,313
Entity Public Float	'	$615.40	'	'	'

CONSOLIDATED_AND_COMBINED_BALA

CONSOLIDATED AND COMBINED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$13,139	$24,440
Restricted cash	'	2,013
Accounts receivable:	'	'
Oil and natural gas sales	31,132	27,830
Joint interest owners and other	4,634	7,653
Affiliates	4,473	8,497
Short-term derivative instruments	7,600	28,064
Prepaid expenses and other current assets	9,146	5,331
Total current assets	70,124	103,828
Property and equipment, at cost:	'	'
Oil and natural gas properties, successful efforts method	1,764,468	1,559,541
Other	2,900	5,168
Accumulated depreciation, depletion and impairment	-418,688	-268,163
Oil and natural gas properties, net	1,348,680	1,296,546
Long-term derivative instruments	42,657	14,095
Restricted investments	73,385	68,024
Other long-term assets	17,461	6,911
Total assets	1,552,307	1,489,404
Current liabilities:	'	'
Accounts payable	8,566	15,264
Accounts payable-affiliates	474	1,738
Revenues payable	16,291	6,881
Accrued liabilities	39,847	16,099
Short-term derivative instruments	7,996	3,217
Total current liabilities	73,174	43,199
Long-term debt	792,067	630,182
Asset retirement obligations	99,619	91,349
Long-term derivative instruments	5,875	10,466
Other long-term liabilities	1,956	2,443
Total liabilities	972,691	777,639
Commitments and contingencies (Note 13)	'	'
Partners' equity (deficit):	'	'
General partner (61,300 units outstanding at December 31, 2013 and 34,317 units outstanding at December 31, 2012)	728	450
Previous owners	'	384,694
Total partners' equity	574,088	706,504
Noncontrolling interest	5,528	5,261
Total equity	579,616	711,765
Total liabilities and equity	1,552,307	1,489,404
Limited Partners Common Units [Member]	'	'
Partners' equity (deficit):	'	'
Limited partners units	582,075	301,204
Total equity	582,075	301,204
Subordinated Units [Member]	'	'
Partners' equity (deficit):	'	'
Limited partners units	($8,715)	$20,156

CONSOLIDATED_AND_COMBINED_BALA1

CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
General partner, units outstanding	61,300	34,317	22,044
Limited Partners Common Units [Member]	'	'	'
Limited partners, units outstanding	55,877,831	28,921,903	16,661,294
Subordinated Units [Member]	'	'	'
Limited partners, units outstanding	5,360,912	5,360,912	5,360,912

STATEMENTS_OF_CONSOLIDATED_AND

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Oil & natural gas sales	$341,197	$255,608	$231,923
Pipeline tariff income and other	2,419	2,815	2,689
Total revenues	343,616	258,423	234,612
Costs and expenses:	'	'	'
Lease operating	88,893	80,116	62,909
Pipeline operating	1,835	2,114	2,526
Exploration	1,130	2,463	1,126
Production and ad valorem taxes	17,784	16,048	11,680
Depreciation, depletion, and amortization	97,269	76,036	61,882
Impairment of proved oil and natural gas properties	54,362	10,532	18,415
General and administrative	43,495	30,342	26,695
Accretion of asset retirement obligations	4,853	4,377	4,032
(Gain) loss on commodity derivative instruments	-26,281	-21,417	-58,407
(Gain) on sale of properties	-2,848	-9,759	-63,033
Other, net	647	138	2,282
Total costs and expenses	281,139	190,990	70,107
Operating income	62,477	67,433	164,505
Other income (expense):	'	'	'
Interest expense, net	-41,901	-20,436	-14,970
Amortization of investment premium	'	-194	-606
Total other income (expense)	-41,901	-20,630	-15,576
Income before income taxes	20,576	46,803	148,929
Income tax benefit (expense)	-308	-285	-139
Net income	20,268	46,518	148,790
Net income (loss) attributable to noncontrolling interest	267	104	-146
Net income attributable to Memorial Production Partners LP	20,001	46,414	148,936
Limited partners' interest in net income:	'	'	'
Net income attributable to Memorial Production Partners LP	20,001	46,414	148,936
Net (income) loss allocated to predecessor	'	'	-75,740
Net (income) loss allocated to previous owners	-11,275	-46,293	-66,604
Net (income) loss allocated to general partner	-49	'	-7
Limited partners' interest in net income	$8,677	$121	$6,585
Earnings per unit: (see Note 10)	'	'	'
Basic and diluted earnings per unit	$0.19	$0.01	$0.30
Weighted average limited partner units outstanding:	'	'	'
Basic and diluted	46,017	22,880	21,756

STATEMENTS_OF_CONSOLIDATED_AND1

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:	'	'	'
Net income	$20,268	$46,518	$148,790
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Depreciation, depletion, and amortization	97,269	76,036	61,882
Impairment of proved oil and natural gas properties	54,362	10,532	18,415
(Gain) loss on derivative instruments	-26,829	-16,578	-55,153
Cash settlements on derivative instruments	18,919	42,307	11,249
Premiums paid for derivatives	'	-411	-7,424
Premiums received for derivatives	'	'	2,520
Amortization of loan origination costs	5,845	1,991	1,459
Accretion of senior notes net discount	504	'	'
Amortization of investment premium	'	194	606
Accretion of asset retirement obligations	4,853	4,377	4,032
Amortization of equity awards	3,558	1,423	'
Gain on sale of properties	-2,848	-9,759	-63,033
Exploration costs	95	36	172
Non-cash compensation expense	1,057	'	'
Changes in operating assets and liabilities:	'	'	'
Accounts receivable	-2,492	-5,733	-24,986
Prepaid expenses and other assets	-1,210	-555	-3,300
Payables and accrued liabilities	20,113	7,164	27,172
Other	233	-698	-261
Net cash provided by operating activities	193,697	156,844	122,140
Cash flows from investing activities:	'	'	'
Acquisition of oil and natural gas properties	-38,664	-277,623	-404,467
Additions to oil and gas properties	-161,675	-107,789	-91,755
Additions to restricted investments	-5,361	-4,599	-5,261
Additions to other property and equipment	-238	-1,748	-1,999
Proceeds from the sale of oil and gas properties	4,525	34,521	3,333
Other	'	29	-750
Net cash used in investing activities	-201,413	-357,209	-500,899
Cash flows from financing activities:	'	'	'
Advances on revolving credit facilities	958,355	391,000	412,318
Payments on revolving credit facilities	-1,485,537	-121,819	-244,399
Deferred financing costs	-20,908	-2,225	-5,752
Proceeds from the issuances of senior notes	688,563	'	'
Predecessor capital contributions	'	'	48,885
Capital contributions from previous owners	7,233	64,597	161,503
Contribution related to sale of assets to NGP affiliate	2,013	38,125	'
Noncontrolling interest capital contributions	'	'	'
Proceeds from general partner contribution	521	206	419
Proceeds from the issuance of common units	511,204	202,572	181,659
Costs incurred in conjunction with issuance of common units	-21,066	-8,268	-24,540
Distributions to partners	-96,643	-34,436	'
Distribution to Memorial Resource (see Note 1)	-151,714	-45,489	-73,557
Distribution to NGP affiliates (see Note 1)	-355,495	-242,174	'
Transfer of operating subsidiary to Memorial Resource (see Note 12)	'	-3,751	'
Distributions made by previous owners	-31,098	-29,517	-66,577
Cash retained by predecessor	'	'	-14,977
Cash retained by previous owners	-9,013	'	'
Net cash (used in) provided by financing activities	-3,585	208,821	374,982
Net change in cash and cash equivalents	-11,301	8,456	-3,777
Cash and cash equivalents, beginning of year	24,440	15,984	19,761
Cash and cash equivalents, end of year	13,139	24,440	15,984
Supplemental cash flows:	'	'	'
Cash paid for interest	40,413	13,869	10,412
Cash paid for taxes	168	22	40
Noncash investing and financing activities:	'	'	'
Change in capital expenditures in payables and accrued liabilities	12,178	4,435	9,008
Environmental remediation liability-net (see Note 13)	'	'	968
Fair value of assets acquired in excess of cash paid and net book value of properties transferred	'	'	68,945
Assumptions of asset retirement obligations related to properties acquired	1,581	5,448	9,031
Contribution related to sale of assets to NGP affiliate-restricted cash	'	2,013	'
Accrued distribution to NGP affiliates related to Cinco Group acquisition	4,352	'	'
Accrued equity offering costs	'	170	'
Distributions to partners	'	$48	'

STATEMENTS_OF_CONSOLIDATED_AND2

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY (USD $)	Total	Noncontrolling Interest [Member]	Predecessor [Member]	Previous Owners [Member]	General Partner [Member]	Limited Partners Common Units [Member]	Limited Partners Subordinated [Member]
In Thousands
Beginning Balance at Dec. 31, 2010	$380,932	$5,303	$105,801	$269,828	'	'	'
Net income (loss)	148,790	-146	75,740	66,604	7	4,962	1,623
Contributions	210,807	'	48,885	161,503	419	'	'
Net assets retained by predecessor	-14,205	'	-17,385	3,180	'	'	'
Distributions	-66,577	'	'	-66,577	'	'	'
Other	38	'	'	38	'	'	'
Exchange of predecessor interests for units (Note 1)	'	'	-213,041	'	'	121,101	91,940
Deferred tax liability from initial public offering	-446	'	'	'	'	-335	-111
Net proceeds from the issuance of common units	157,119	'	'	'	'	157,119	'
Distribution to Memorial Resource (Note 1)	-73,557	'	'	'	'	-41,813	-31,744
Ending Balance at Dec. 31, 2011	742,901	5,157	'	434,576	426	241,034	61,708
Net income (loss)	46,518	104	'	46,293	'	114	7
Contributions	64,803	'	'	64,597	206	'	'
Distributions	-64,001	'	'	-29,517	-34	-26,152	-8,298
Other	32	'	'	-92	'	64	60
Net proceeds from the issuance of common units	194,134	'	'	'	'	194,134	'
Contribution of oil and gas properties	6,893	'	'	6,893	'	'	'
Distribution attributable to net assets acquired (Note 1)	-287,663	'	'	'	-242	-209,720	-77,701
Net book value of net assets acquired (Note 12)	'	'	'	-144,335	94	99,972	44,269
Contribution related to sale of assets to NGP affiliate	40,138	'	'	40,138	'	'	'
Net book value of net assets acquired by NGP affiliate	-33,859	'	'	-33,859	'	'	'
Amortization of equity awards	1,423	'	'	'	'	1,423	'
Deferred tax liability adjustments	446	'	'	'	'	335	111
Ending Balance at Dec. 31, 2012	711,765	5,261	'	384,694	450	301,204	20,156
Net income (loss)	20,268	267	'	11,275	49	7,880	797
Contributions	7,754	'	'	7,233	521	'	'
Distributions	-127,741	'	'	-31,098	-136	-85,342	-11,165
Other	-2,424	'	'	-2,302	'	-122	'
Net proceeds from the issuance of common units	490,138	'	'	'	'	490,138	'
Distribution attributable to net assets acquired (Note 1)	-502,920	'	'	55,281	-559	-490,400	-67,242
Net book value of net assets acquired (Note 12)	'	'	'	-404,301	403	355,159	48,739
Amortization of equity awards	3,558	'	'	'	'	3,558	'
Net assets retained by previous owners	-20,782	'	'	-20,782	'	'	'
Ending Balance at Dec. 31, 2013	$579,616	$5,528	'	'	$728	$582,075	($8,715)

Organization_and_Basis_of_Pres

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2013
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 business activities are conducted through our wholly owned subsidiary Memorial Production Operating LLC (“OLLC”) and its wholly-owned subsidiaries. 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).
	The Partnership was formed in April 2011 to own and acquire oil and natural gas properties in North America and completed its initial public offering (“IPO”) on December 14, 2011 (see Note 9). The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, Memorial Production Partners GP LLC, which is a wholly owned subsidiary of Memorial Resource Development LLC (“Memorial Resource”). Our general partner is responsible for managing all of the Partnership’s operations and activities.
	Memorial Production Finance Corporation (“Finance Corp.”), our wholly-owned subsidiary, has no material assets or any liabilities other than as a co-issuer of our debt securities and as a guarantor of certain of our other indebtedness. Its activities will be limited to co-issuing our debt securities and engaging in other activities incidental thereto.
	Memorial Resource is a Delaware limited liability company owned and formed by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. Memorial Resource provides management, administrative, and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds are private equity funds managed by Natural Gas Partners (“NGP”). The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). Our remaining IDRs are owned by our general partner.
	Predecessor
	References to “our predecessor” for accounting and financial reporting purposes refers collectively to: (i) BlueStone Natural Resources Holdings, LLC (“Bluestone”) and its wholly-owned subsidiaries in addition to certain carved-out oil and natural gas properties (“Classic Carve-Out”) owned by Classic Hydrocarbons Holdings, L.P. (“Classic”) for all periods prior to the closing of our IPO and (ii) certain oil and natural gas properties owned by WHT Energy Partners LLC (“WHT”) for periods after April 8, 2011 through the closing of our IPO.
	In connection with our IPO, the Funds contributed to Memorial Resource their respective ownership of five separate portfolio companies (including those comprising our predecessor) and we acquired substantially all of the oil and natural gas properties and related assets owned by BlueStone, certain carved-out oil and natural gas properties and related assets owned by Classic and a 40% undivided interest in certain oil and natural gas properties and related assets (the “WHT Assets”) controlled by WHT. We distributed approximately $73.6 million in cash, 7,061,294 common units, and 5,360,912 subordinated units to Memorial Resource to acquire the net assets of our predecessor and repaid $198.3 million of our predecessor’s credit facilities concurrent with the closing of our IPO. The cash portion of this consideration was financed with borrowings under a senior securing revolving credit facility (see Note 8) and the net cash proceeds generated from our IPO. This dropdown transaction was accounted for as a combination of entities under common control; therefore, the Partnership accounted for the acquisition at historical cost in a manner similar to the pooling of interest method.
	Previous Owners
	References to “the previous owners” for accounting and financial reporting purposes refer collectively to:
		•	Certain oil and natural gas properties the Partnership acquired from Memorial Resource in April and May 2012 (“Tanos/Classic Properties”) for periods after common control commenced through their respective date of acquisition.
		•	Rise Energy Operating, LLC and its wholly-owned subsidiaries (except for Rise Energy Operating, Inc.) (“REO”) from February 3, 2009 (inception) through the date of acquisition. The Partnership acquired REO, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, in December 2012 from Rise Energy Partners, LP (“Rise”). We refer to this transaction as the “Beta acquisition.” Rise is primarily owned by two of the Funds.
		•	Certain oil and natural gas properties and related assets in East Texas and North Louisiana that the Partnership acquired in March 2013 (the “WHT Properties”) owned by WHT from February 2, 2011 (inception) through the date of acquisition.
		•	Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that the Partnership acquired through equity and asset transactions on October 1, 2013 from both Memorial Resource and certain affiliates of NGP as discussed below. We refer to this transaction as the “Cinco Group acquisition.”
	Each of these aforementioned acquisitions 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 has been retrospectively revised to give effect to such acquisitions as if the Partnership owned the assets for periods after common control commenced through their respective acquisition dates. See Note 12 for additional information.
	Basis of Presentation
	Our consolidated results of operations following the completion of our IPO are presented together with the combined results of operations pertaining to our predecessor and the previous owners. The combined financial statements were derived from the historical accounting records of our predecessor and the previous owners and reflect the historical financial position, results of operations and cash flows for all periods presented.
	Our predecessor’s combined financial statements reflect the financial statements of BlueStone and Classic Carve-Out through the closing of our IPO and the WHT Assets for periods after April 8, 2011 through December 13, 2011. The Classic Carve-Out amounts included in the accompanying financial statements include allocations for various expenses. Certain expenses incurred by Classic were indirectly attributable to the Classic Carve-Out as Classic owned interests in numerous other oil and natural gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to our predecessor, so that the amounts included in the combined financial statements reflect substantially all of the cost of doing business. Such allocations may or may not reflect future costs associated with the operation of the Partnership.
	The previous owners combined financial statements reflect: (i) certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective date of acquisition on a combined basis for all periods presented, (ii) the consolidated financial statements of REO for all periods presented, (iii) the WHT Properties from February 2, 2011 (inception) through the date of acquisition, (iv) the financial statements of Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits overriding royalty interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), Stanolind Oil and Gas SPV LLC (“Stanolind SPV”), Tanos Energy, LLC (“Tanos”), together with its wholly-owned subsidiaries, Prospect Energy, LLC (“Prospect”), and certain oil and natural gas properties in Jackson County, Texas (the “MRD Assets”) (collectively, the “Cinco Group”) on a combined basis for periods after common control commenced through the date of acquisition. The Partnership acquired substantially all of the Cinco Group on October 1, 2013 from: (a) Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds, and (b) Memorial Resource.
	The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of REO, is presented as noncontrolling interest in the financial statements.
	All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain amounts in the prior year financial statements have been reclassified to conform to the presentation in the current year financial statements.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Note 2. Summary of Significant Accounting Policies
	Use of Estimates
	The preparation of 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.
	Principles of Consolidation and Combination
	Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated.
	Cash and Cash Equivalents
	Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.
	Concentrations of Credit Risk
	Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor and the previous owners have experienced any losses from such instruments.
	Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us, our predecessor, and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2013 and 2012, respectively.
	If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.
	Oil and Natural Gas Properties
	Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.
	As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.
	On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.
	There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2013, 2012 and 2011.
	Oil and Gas Reserves
	The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to prepare our reserves estimates at December 31, 2013.
	Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
	Other Property & Equipment
	Other property and equipment is stated at historical costs and is comprised primarily of vehicles, furniture, fixtures, and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to five years.
	Restricted Investments
	Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense – net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.
	Debt Issuance Costs
	These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2013, 2012, and 2011 was approximately $5.8 million, $2.0 million, and $1.5 million, respectively.
	Impairments
	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, such as a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. 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 gas properties. Impairment expense for the years ended December 31, 2013, 2012, and 2011 was approximately $54.4 million, $10.5 million, and $18.4 million, respectively.
	Asset Retirement Obligations
	An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized as a component of exploration costs to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.
	Revenue Recognition
	Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2013 or 2012.
	The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:
			Years Ending December 31,
			2013			2012			2011
	Major customers:
	Phillips 66 (1)			15	%		13	%		n/a
	ConocoPhillips (1)			n/a			14	%		27	%
	-1	Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips.
	General and Administrative Expense
	We and our general partner have entered into an omnibus agreement with Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. During the year ended December 31, 2013, Memorial Resource allocated indirect general and administrative costs based on production. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf. See Note 12 for additional information regarding the omnibus agreement.
	General and administrative expenses associated with our predecessor and the previous owners included the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production.
	Derivative Instruments
	Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.
	Income Tax
	We are organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income. Certain of our consolidated subsidiaries are taxed as corporations and subject to federal income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin. Deferred taxes arise due to temporary differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. We had a net deferred tax liability of $2.0 million at both December 31, 2013 and 2012.
	We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized. There were no uncertain tax positions that required recognition in the financial statements at December 31, 2013 or 2012.
	Earnings Per Unit
	Basic and diluted earnings per unit (“EPU”) is determined by dividing net income or loss available to the limited partners by the weighted average number of outstanding limited partner units during the period. Net income or loss available to the limited partners is determined by applying the two-class method. The two-class method of computing EPU is an earnings allocation formula that determines EPU based on distributions declared. The amount of net income or loss used in the determination of EPU is reduced (or increased) by the amount of available cash that has been or will be distributed to the limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the limited partners in accordance with the contractual terms of the partnership agreement. The total earnings allocated to the limited partners is determined by adding together the amount allocated for distributions declared and the amount allocated for the undistributed earnings or excess distributions over earnings. Basic and diluted EPU are equivalent, as all restricted common units and subordinated units participate in distributions. See Note 10 for additional information.
	Equity Compensation
	The fair value of equity-classified awards (e.g., restricted common unit awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. We currently have no awards subject to performance criteria; however, such awards vest when it is probable that the performance criteria will be met and the requisite service period has been met. Generally, no compensation expense is recognized for equity instruments that do not vest. See Note 11 for further information.
	Incentive Units
	The governing documents of certain entities within the Cinco Group provided for the issuance of incentive units. The incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. Tanos recognized compensation expense related to the forfeiture of incentive units during April 2013 as further discussed in Note 12.
	Current Liabilities
	Current accrued liabilities consisted of the following at the dates indicated (in thousands):
			December 31,
			2013			2012
	Accrued capital expenditures		$	16,193		$	4,741
	Accrued lease operating expense			10,666			5,412
	Accrued general and administrative expenses			1,547			1,385
	Accrued ad valorem taxes			1,531			1,152
	Accrued interest payable			8,931			748
	Accrued severance and production taxes			105			883
Other miscellaneous			874			1,778
		$	39,847		$	16,099
New Accounting Pronouncements
Offsetting Disclosure Requirements. In December 2011, the FASB issued an accounting standard update intended to enhance current disclosure requirements on offsetting financial assets and liabilities. In January 2013, the FASB issued an accounting standard update to clarify the scope of offsetting disclosure requirements. The new disclosure requirements required the disclosure of both gross and net information about derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions eligible for offset on the balance sheet or subject to a master netting arrangement or similar agreement. Disclosure of collateral received and posted in connection with master netting agreements or similar arrangements is also required. The disclosures became effective for annual and interim periods beginning on or after January 1, 2013 and were applied retrospectively. The adoption of this new guidance did not have a significant impact on our financial statements.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Acquisitions and Divestitures	'
	Note 3. Acquisitions and Divestitures
	The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we, our predecessor, and the previous owners conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through capital contributions and borrowings under credit facilities.
	The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural properties include 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.
	The Partnership has consummated several common control acquisitions since completing its IPO in December 2011, as further discussed in Note 12, directly or indirectly from Memorial Resource and certain affiliates of NGP. These acquisitions were each 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.
	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 Year Ended December 31,
	2013	2012
	$6,729	$4,135
	Approximately $2.1 million of acquisition costs related to 2011 acquisitions is included in either general and administrative expense or other expense in the accompanying statements of operations for the year ended December 31, 2011.
	2013 Acquisitions
	Third Party. We closed two separate transactions during the year ended December 31, 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.4 million in aggregate. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013. The following table summarizes the fair value of the third party assets acquired and liabilities assumed as of each acquisition date (in thousands):
		East Texas			Rockies
		Acquisition			Acquisition
	Oil and gas properties	$	9,974		$	20,744
	Asset retirement obligations		(78	)		(1,163	)
	Accrued liabilities		—			(118	)
	Total identifiable net assets	$	9,896		$	19,463
	The Cinco Group also acquired certain oil and gas properties and leases in Texas from third parties for a final purchase price of $9.3 million.
	2012 Acquisitions
	Third Party. On May 1, 2012, we acquired non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller (“Undisclosed Seller Acquisition”) for a final net purchase price of approximately $36.5 million after customary post-closing adjustments. The effective date of this transaction was January 1, 2012. This transaction was financed with borrowings under our revolving credit facility. Because this transaction was a joint acquisition with Memorial Resource, the transaction was approved by the board of directors of our general partner (the “Board”) and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. During the year ended December 31, 2012, approximately $4.8 million of revenue and $1.2 million of earnings were recorded in the statement of operations related to the Undisclosed Seller Acquisition subsequent to the closing date.
	On September 28, 2012, we acquired certain oil and natural gas properties in East Texas from Goodrich Petroleum Corporation (“Goodrich Acquisition”), for a final net purchase price of $90.4 million after customary post-closing adjustments. The effective date of this transaction was July 1, 2012. This transaction was financed with borrowings under our revolving credit facility. These properties are located in the East Henderson field of Rusk County, Texas. During the year ended December 31, 2012, approximately $4.6 million of revenue and $2.0 million of earnings were recorded in the statement of operations related to the Goodrich Acquisition subsequent to the closing date.
	Collectively, the previous owners consummated multiple acquisitions during 2012 by acquiring operating and non-operating interests in certain oil and natural gas properties primarily located in various Texas and New Mexico counties for an aggregate adjusted purchase price of $150.7 million, the largest of which was completed in July by Stanolind. In July 2012, Stanolind completed an acquisition of working interests, royalty interests and net revenue interests (the “Menemsha Acquisition”) located in various counties in Texas for a final purchase price of $74.7 million. During the year ended December 31, 2012, approximately $4.9 million of revenue and $0.9 million of earnings were recorded in the statements of operations related to the Menemsha Acquisition subsequent to the closing date.
	The following table summarizes the fair value of the third party assets acquired and liabilities assumed as of each acquisition date (in thousands).
		Undisclosed			Goodrich			Menemsha			Other
		Seller			Acquisition			Acquisition			Acquisitions
		Acquisition
	Oil and gas properties	$	36,865		$	91,187		$	75,114		$	80,591
	Prepaid expenses and other current assets		—			425			—			—
	Revenues payable		—			(875	)		—			—
	Asset retirement obligations		(321	)		(161	)		(408	)		(4,558	)
	Accrued liabilities		(83	)		(153	)		—			—
	Total identifiable net assets	$	36,461		$	90,423		$	74,706		$	76,033
	The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2012 and 2011 as though the Undisclosed Seller Acquisition, Goodrich Acquisition, and Menemsha Acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership, our predecessor, 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 acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on the basis assumed above, nor is such information indicative of expected future results of operations.
		For the Year
		Ended December 31,
		2012			2011
		(In thousands, except
		per unit amounts)
	Revenues	$	286,004		$	286,351
	Net income		58,472			174,138
	Basic and diluted earnings per unit		0.53			0.34
	2011 Predecessor and Previous Owner Acquisitions
	Effective January 1, 2011, our predecessor acquired BP’s interests in wells located in Duval, Jim Hogg, McMullen and Webb counties located in Texas in exchange for our predecessor’s interest in approximately 10,700 net acres located in the Nueces Field of the Eagle Ford Shale located in South Texas and $20.0 million in cash, subject to certain closing adjustments. The transaction closed on May 31, 2011 and our predecessor paid a total of approximately $12.9 million in cash consideration at closing, net of adjustments.
	The purchase price allocation resulted in the acquisition date fair value of $82.6 million allocated to proved oil and gas properties, $1.2 million allocated to asset retirement obligations, $0.5 million allocated to accrued liabilities and $0.6 million to deferred tax liabilities. After taking into consideration the net book value of the Nueces Field properties exchanged to BP of $5.2 million and the $12.9 million in cash consideration paid at closing, our predecessor recorded a $62.2 million gain during the year ended December 31, 2011.
	On April 8, 2011, our predecessor and the previous owners together acquired producing oil and natural gas properties in East Texas (the “Carthage Properties”) from a third party. Our predecessor and the previous owners estimated that as of April 8, 2011, the fair value of the Carthage Properties acquired was approximately $302.0 million, which was considered to be representative of the price paid by a typical market participant. The following table summarizes the fair value of the assets acquired and liabilities assumed as of April 8, 2011 (in thousands):
	Oil and gas properties		307,185
	Other property and equipment		1,046
	Suspense liabilities assumed		(1,659	)
	Environmental liabilities assumed		(968	)
	Asset retirement obligations		(3,653	)
	Total identifiable net assets		301,951
	During the year ended December 31, 2011, approximately $8.3 million and $46.2 million of revenue and $2.3 million and $32.2 million of earnings were recorded in the statement of operations related to the BP and Carthage Properties acquisitions subsequent to their respective closing dates.
	Effective July 1, 2011, our predecessor acquired producing oil and natural gas properties in Webb and Zapata counties located in South Texas. The net purchase price of $2.25 million was allocated to oil and natural gas properties. The acquisition closed on June 30, 2011.
	Collectively, the Cinco Group consummated several individually insignificant acquisitions during 2011 by acquiring operating and non-operating interests in certain oil and natural gas properties located primarily in various Texas counties and offshore Louisiana for an aggregate adjusted purchase price of $85.8 million. The following table summarizes the fair value of the assets acquired and liabilities assumed as of each acquisition date (in thousands).
	Oil and gas properties	$	90,351
	Other liabilities		(420	)
	Asset retirement obligations		(4,178	)
	Total identifiable net assets	$	85,753
	Previous Owners’ Divestitures
	On January 1, 2013, Tanos sold a natural gas gathering pipeline located in East Texas, which it had originally acquired in April 2010, to a privately held gas transportation company for a minimum of $1.5 million. The maximum allowable additional proceeds are $2.0 million. The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the next three years. The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration. Tanos also sold certain non-operated oil and gas properties in 2013 for $2.9 million and recorded a gain of $1.4 million.
	The previous owners sold certain interests in oil and gas properties located offshore Louisiana on October 11, 2012 for an aggregate $40.1 million to an NGP controlled entity, of which $38.1 million was received upon closing. As of December 31, 2012, the remaining proceeds were held in escrow and included as restricted cash in the balance sheet. The remaining proceeds were released from escrow in April 2013. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties sold by $6.3 million and is recognized in the equity statement as a net contribution.
	On July 11, 2012, the Cinco Group completed the sale of a portion of its oil and gas assets located in Garza County, Texas to a third party for $26.1 million and recognized a gain of approximately $7.6 million. On September 18, 2012, the Cinco Group completed the sale of a portion of its oil and gas assets located in Ector County, Texas to a third party for $4.7 million and recognized a gain of approximately $2.2 million.
The majority of the proceeds generated from these sales were used to acquire operating and non-operating interests in certain oil and natural gas properties located primarily in various Texas and New Mexico counties.

Fair_Value_Measurements_of_Fin

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2013
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). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:
	Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
	Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2013 and 2012, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.
	Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	The carrying values of cash and cash equivalents, 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 December 31, 2013 and December 31, 2012. 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.
	The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2013 and December 31, 2012 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 derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2013 and December 31, 2012 for each of the fair value hierarchy levels:
			Fair Value Measurements at December 31, 2013 Using
			Quoted Prices in		Significant  Other		Significant		Fair Value
			Active Market		Observable Inputs		Unobservable Inputs
			(Level 1)		(Level 2)		(Level 3)
			(In thousands)
	Assets:
	Commodity derivatives		$	—	$	95,926	$	—	$	95,926
	Interest rate derivatives			—		872		—		872
	Total assets		$	—	$	96,798	$	—	$	96,798
	Liabilities :
	Commodity derivatives		$	—	$	55,576	$	—	$	55,576
	Interest rate derivatives			—		4,836		—		4,836
	Total liabilities		$	—	$	60,412	$	—	$	60,412
			Fair Value Measurements at December 31, 2012 Using
			Quoted Prices in		Significant Other		Significant		Fair Value
			Active Market		Observable Inputs		Unobservable Inputs
			(Level 1)		(Level 2)		(Level 3)
			(In thousands)
	Assets:
	Commodity derivatives		$	—	$	78,645	$	—	$	78,645
	Liabilities :
	Commodity derivatives		$	—	$	44,697	$	—	$	44,697
	Interest rate derivatives			—		5,472		—		5,472
	Total liabilities		$	—	$	50,169	$	—	$	50,169
	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 such factors 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 gas properties.
		•		During the year ended December 31, 2013, we recognized $54.4 million of impairments. The impairments related to certain properties located in both East Texas and South Texas. The estimated future cash flows expected from East Texas properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on updated well performance data. The carrying value of these properties after the $50.3 impairment was approximately $31.5 million. The estimated future cash flows expected from South Texas properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties. The carrying value of these properties after the $4.1 million impairment was approximately $7.3 million.
		•		During the year ended December 31, 2012, the previous owners recognized $10.5 million of impairments to proved oil and natural gas properties. Approximately $8.0 million related to a particular lease in the Elkhorn (Ellenburger) and Canyon Fields located in the Permian Basin as a result of a downward revision of estimated proved reserves due to unfavorable drilling results in the area.
		•		During the year ended December 31, 2011, our predecessor recognized impairments of $15.1 million. Approximately $3.1 million of impairments related to a well abandoned in the Burke Unit located in South Texas due to a situation encountered during drilling. As a result of declines in natural gas prices, the remaining $12.0 million of impairments in 2011 consisted of $6.9 million to the Craton field and $4.0 million to the Cayuga field. The previous owners recognized $3.3 million of impairments to proved oil and natural gas properties, of which approximately $1.7 million related to a particular lease in the Dimmitt (Delaware Cons) Field located in the Permian Basin as a result of a downward revision of estimated proved reserves due to unfavorable drilling results in the area.

Risk_Management_and_Derivative

Risk Management and Derivative Instruments	12 Months Ended
	Dec. 31, 2013
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 transactions 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 counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender in our credit agreement. 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 counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the 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 certain counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $25.4 million against amounts outstanding under our revolving credit facility at December 31, 2013, reducing our maximum credit exposure to approximately $19.5 million, of which approximately $12.3 million was with a single counterparty. See Note 8 for additional information regarding our revolving credit facility.
	Commodity Derivatives
	A combination of commodity derivatives (e.g., floating-for-fixed swaps, costless collars, call spreads and basis swaps) is used to manage exposure to commodity price volatility. Historically, the Partnership has not paid or received premiums for put options. 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 the Partnership’s areas of production. We also enter into oil derivative contracts indexed to NYMEX WTI, Inter-Continental Exchange (“ICE”) Brent and California Midway-Sunset. Our NGL derivative contracts are indexed to OPIS Mont Belvieu. At December 31, 2013, the Partnership had the following open commodity positions:
			2014				2015				2016				2017				2018		2019
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)			2,575,458				2,145,278				2,342,442				2,230,067				2,060,000		1,814,583
	Weighted-average fixed price		$	4.34			$	4.3			$	4.42			$	4.31			$	4.52	$	4.77
	Collar contracts:
	Average Monthly Volume (MMBtu)			340,000				350,000				—				—				—		—
	Weighted-average floor price		$	4.93			$	4.62			$	—			$	—			$	—	$	—
	Weighted-average ceiling price		$	6.12			$	5.8			$	—			$	—			$	—	$	—
	Call spreads (1):
	Average Monthly Volume (MMBtu)			120,000				80,000				—				—				—		—
	Weighted-average sold strike price		$	5.08			$	5.25			$	—			$	—			$	—	$	—
	Weighted-average bought strike price		$	6.31			$	6.75			$	—			$	—			$	—	$	—
	Basis swaps:
	Average Monthly Volume (MMBtu)			2,822,083				—				—				—				—		—
	Spread		$	(0.09	)		$	—			$	—			$	—			$	—	$	—
	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)			136,444				148,281				142,313				130,600				122,000		40,000
	Weighted-average fixed price		$	95.82			$	93.07			$	86.85			$	85.96			$	85.62	$	85
	Collar contracts:
	Average Monthly Volume (Bbls)			23,000				5,000				—				—				—		—
	Weighted-average floor price		$	82.83			$	80			$	—			$	—			$	—	$	—
	Weighted-average ceiling price		$	105.31			$	94			$	—			$	—			$	—	$	—
	Basis swaps
	Average Monthly Volume (Bbls)			57,292				57,500				—				—				—		—
	Spread		$	(9.21	)		$	(9.73	)		$	—			$	—			$	—	$	—
	NGL Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)			118,500				112,800				—				—				—		—
	Weighted-average fixed price		$	36.23			$	35.04			$	—			$	—			$	—	$	—
	-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.
	Interest Rate Swaps
	Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. At December 31, 2013, we had the following interest rate swap open positions:
			2014				2015				2016
	Average Monthly Notional (in thousands)		$	173,958			$	280,833			$	150,000
	Weighted-average fixed rate			1.306	%			1.416	%			1.193	%
	Floating rate			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 December 31, 2013 and 2012. There was no cash collateral received or pledged associated with our derivative instruments since each of the counterparties to our derivative contracts is a lender under our credit agreement.
					Asset Derivatives								Liability Derivatives
	Type		Balance Sheet Location		2013				2012				2013				2012
					(In thousands)
	Commodity contracts		Short-term derivative instruments		$	18,578			$	35,044			$	17,120			$	7,451
	Interest rate swaps		Short-term derivative instruments			845				—				2,699				2,746
	Gross fair value					19,423				35,044				19,819				10,197
	Netting arrangements		Short-term derivative instruments			(11,823	)			(6,980	)			(11,823	)			(6,980	)
	Net recorded fair value		Short-term derivative instruments		$	7,600			$	28,064			$	7,996			$	3,217
	Commodity contracts		Long-term derivative instruments		$	77,348			$	43,601			$	38,456			$	37,246
	Interest rate swaps		Long-term derivative instruments			27				—				2,137				2,726
	Gross fair value					77,375				43,601				40,593				39,972
	Netting arrangements		Long-term derivative instruments			(34,718	)			(29,506	)			(34,718	)			(29,506	)
	Net recorded fair value		Long-term derivative instruments		$	42,657			$	14,095			$	5,875			$	10,466
	Gains & Losses on Derivatives
	We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes and neither did our predecessor or the previous owners. 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 years ending December 31, 2013, 2012, and 2011:
			Statements of		Years Ended December 31,
	Derivative Instruments		Operations Location		2013				2012				2011
					(In thousands)
Commodity derivative contracts		(Gain) loss on commodity derivatives		$	(26,281	)		$	(21,417	)		$	(58,407	)
Interest rate swaps		Interest expense, net			(548	)			(4,839	)			(3,254	)

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
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 of wells and related facilities. The following table presents the changes in the asset retirement obligations for the years ended December 31, 2013, 2012, and 2011:
		2013			2012			2011
		(In thousands)
	Asset retirement obligations at beginning of year	$	91,349		$	82,722		$	70,891
	Liabilities added from acquisitions or drilling		2,116			5,958			9,700
	Liabilities removed upon sale of wells		—			(1,795	)		(64	)
	Liabilities settled		(20	)		(91	)		(229	)
	Accretion expense		4,853			4,377			4,032
	Revision of estimates		1,321			178			(774	)
	Liabilities retained by our predecessor		—			—			(834	)
	Asset retirement obligations at end of year	$	99,619		$	91,349		$	82,722

Restricted_Investments

Restricted Investments	12 Months Ended
	Dec. 31, 2013
Text Block [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 the offshore Southern California oil and gas properties. The components of the restricted investment balance are as follows at December 31:
		2013		2012
		(In thousands)
	BOEM platform abandonment (See Note 13)	$	66,373	$	61,389
	BOEM lease bonds		794		776
	SPBPC Collateral:
	Contractual pipeline and surface facilities abandonment (See Note 13)		2,306		1,959
	California State Lands Commission pipeline right-of-way bond		3,005		3,000
	City of Long Beach pipeline facility permit		500		500
	Federal pipeline right-of-way bond		307		300
	Port of Long Beach pipeline license		100		100
	Restricted investments	$	73,385	$	68,024

Long_Term_Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long Term Debt	'
	Note 8. Long Term Debt
	Our consolidated and combined debt obligations consisted of the following at the dates indicated:
			December 31,			December 31,
			2013			2012
			(In thousands)
	OLLC $2.0 billion multi-year revolving credit facility, variable-rate, due March 2018		$	103,000		$	371,000
	7.625% senior notes, fixed-rate, due May 1, 2021 (1)			700,000			—
	Previous owners variable-rate revolving credit facilities			—			259,182
	Unamortized discounts			(10,933	)		—
	Total long-term debt		$	792,067		$	630,182
	-1	The estimated fair value of our fixed-rate debt was $721.0 million. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
	Subsidiary Guarantors
	We filed a universal shelf registration statement with the SEC, which was declared effective on March 15, 2013, that allows us to issue up to $750.0 million in debt and equity securities. Any debt securities issued will be governed by an indenture. Furthermore, any debt securities issued may 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:
			December 31,
			2013
			(In thousands)
	OLLC $2.0 billion multi-year revolving credit facility, variable-rate, due March 2018		$	845,000
	OLLC Revolving Credit Facility
	OLLC is a party to a $2.0 billion revolving credit facility, which is guaranteed by us and certain of our current and future subsidiaries. On September 26, 2013, we entered into a sixth amendment to our credit agreement, which among other things: (i) increased the maximum aggregate credit amounts under the revolving facility from $1.0 billion to $2.0 billion and (ii) increased the borrowing base from $480.0 million to $920.0 million upon the closing of the Cinco Group acquisition on October 1, 2013. On October 10, 2013, the borrowing base was automatically reduced by $75.0 million in conjunction with the issuance of additional senior notes, as discussed below.
	The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base.
	Borrowings under our revolving credit facility bear interest, at our option, at either: (i) the Alternate Base Rate defined as the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index Rate plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.
	Our revolving credit facility requires us to maintain a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is defined under our revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under our revolving credit facility, of not less than 1.0 to 1.0.
	Additionally, our revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness.
	Events of default under our revolving credit facility include the failure to make payments when due, breach of any covenants continuing beyond the cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on the business of OLLC or us.
	If we fail to perform our obligations under these or any other covenants, the revolving credit commitments could be terminated and any outstanding indebtedness under our revolving credit facility, together with accrued interest, fees and other obligations under the credit agreement, could be declared immediately due and payable.
	During the year ended December 31, 2013, the revolving credit facility was primarily used to fund the acquisitions of oil and gas properties from both related parties and third parties. See Note 3 and 12 for additional information regarding these acquisitions.
	7.625% Senior Notes
	On April 17, 2013, we and Finance Corp. (collectively, the “Issuers”) completed a private placement of $300.0 million aggregate principal amount of 7.625% senior unsecured notes due 2021 (the “Senior Notes”). The Senior Notes were issued at 98.521% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership. On May 23, 2013, the Issuers issued an additional $100.0 million aggregate principal amount of the Senior Notes at 102.0% of par. On October 10, 2013, the Issuers issued an additional $300.0 million aggregate principal amount of the Senior Notes at 97.0% of par. The Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year, commencing November 1, 2013. The Senior Notes are governed by an indenture. The Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The Issuers may also be required to repurchase the Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers or any significant subsidiary, all outstanding Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Senior Notes may declare all the Senior Notes to be due and payable immediately.
	Previous Owner and Predecessor Revolving Credit Facilities
	REO, WHT, Stanolind, Boaz, Crown, Tanos, Propel, BlueStone and Classic each maintained multi-year variable-rate senior secured revolving credit facilities that were primarily used for both working capital needs and to fund acquisition and development expenditures. All of Stanolind’s indebtedness outstanding under the Stanolind revolving credit facility was attributable to Stanolind SPV. Likewise, all of Propel Energy’s indebtedness outstanding under the Propel Energy revolving credit facility was attributable to Propel SPV.
	On December 12, 2012, indebtedness then outstanding under the REO’s revolving credit facility of $28.5 million and all accrued interest was paid off in full and the revolving credit facility was terminated. On March 28, 2013, the debt balance then outstanding under the WHT revolving credit facility of $89.3 million and all accrued interest was paid off in full and the revolving credit facility was terminated. On April 1, 2013, indebtedness then outstanding under the Tanos revolving credit facility of $27.0 million was repaid and on April 25, 2013 all accrued interest was paid off in full and the revolving credit facility was terminated. On October 1, 2013, the debt balance then outstanding under the Boaz and Crown revolving credit facilities and all accrued interest was paid off in full and these revolving credit facilities were terminated. On October 1, 2013, the debt balance then outstanding under the Stanolind and Propel Energy revolving credit facilities and all accrued interest was paid off in full by the Partnership on behalf of Stanolind and Propel Energy, respectively.
	Weighted-Average Interest Rates
	The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented:
			For the Year Ended December 31,
			2013			2012			2011
	OLLC revolving credit facility			3.25	%		2.74	%		2.81	%
	WHT revolving credit facility			2.29	%		2.6	%		2.79	%
	REO revolving credit facility			n/a			3.4	%		3.03	%
	Stanolind revolving credit facility			3.52	%		3.76	%		3.88	%
	Boaz revolving credit facility			2.97	%		3.12	%		3.47	%
	Crown revolving credit facility			3.38	%		4.2	%		5.55	%
	Tanos revolving credit facility			3.1	%		2.31	%		2.55	%
	Propel Energy revolving credit facility			3.08	%		3.28	%		3.23	%
	BlueStone revolving credit facility			n/a			n/a			3.17	%
	Classic revolving credit facility			n/a			n/a			3.4	%
	Unamortized Deferred Financing Costs
	Unamortized deferred financing costs associated with our consolidated and combined debt obligations were as follows at the dates indicated:
			December 31,			December 31,
			2013			2012
			(In thousands)
	OLLC revolving credit facility (1)			5,413		$	3,359
	Senior Notes (2)			15,053			—
	Previous owner revolving credit facilities			—			2,900
			$	20,466		$	6,259
	(1)    Additional financing costs were incurred in connection with the borrowing base increases during the year ended December 31, 2013. The borrowing base was also automatically reduced upon issuance of the Senior Notes in April, May and October. As a result, approximately $1.4 million of deferred financing costs were written-off during the year ended December 31, 2013 and are included in interest expense in the accompanying statements of operations. 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 approximates the effective interest method.
	Advances and Repayments
	The following table presents borrowings and repayments under our consolidated and combined revolving credit facilities for the periods presented (in thousands):
			OLLC Revolving			Previous  Owner			Predecessor			Total
			Credit Facility			Revolving			Revolving
						Credit Facilities			Credit Facilities
For the Year Ended December 31, 2013:
Advances on revolving credit facility		$	941,000		$	17,355		$	—		$	958,355
Payments on revolving credit facility			(1,209,000	)		(276,537	)		—			(1,485,537	)
For the Year Ended December 31, 2012:
Advances on revolving credit facility		$	293,000		$	98,000		$	—		$	391,000
Payments on revolving credit facility			(42,000	)		(79,819	)		—			(121,819	)
For the Year Ended December 31, 2011:
Advances on revolving credit facility		$	130,000		$	196,400		$	85,918		$	412,318
Payments on revolving credit facility			(10,000	)		(33,053	)		(201,346	)		(244,399	)
For accounting and financial reporting purposes, the $198.3 million that was repaid concurrent with the closing of our IPO on behalf of our predecessor was a component of the net assets that were acquired by us and reflected on our consolidated and combined cash flow statement as “Payments on revolving credit facilities.” Similarly, any amounts that were repaid concurrent with the closing of the Beta acquisition, the WHT Properties, or the Cinco Group acquisition were also a component of the net assets that were acquired by us and reflected on our consolidated and combined cash flow statement as “Payments on revolving credit facilities.”

Equity_and_Distributions

Equity and Distributions	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Equity and Distributions	'
	Note 9. Equity and Distributions
	2013 Public Equity Offerings
	On March 25, 2013, we issued 9,775,000 common units representing limited partner interests in the Partnership (including 1,275,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $18.35 per unit generating total net proceeds of approximately $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering, including our general partner’s proportionate capital contribution, partially funded the acquisition of all of the outstanding equity interests in WHT as further discussed under Note 12.
	On October 8, 2013, we issued 16,675,000 common units representing limited partner interests in the Partnership (including 2,175,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $19.90 per unit generating total net proceeds of approximately $318.3 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering, including our general partner’s proportional capital contribution, were used to repay a portion of outstanding borrowings under our revolving credit facility.
	2012 Public Equity Offering
	On December 12, 2012, we issued 10,500,000 common units representing limited partner interests in the Partnership to the public at an offering price of $17.00 per unit generating total net proceeds of $170.0 million after deducting underwriting discounts and offering expenses. Concurrent with the closing of this equity offering, the Partnership distributed cash to Rise and repaid all amounts outstanding under REO’s credit facility as consideration for the Beta acquisition as further discussed under Notes 8 and 12. The net proceeds from this equity offering, including our general partner’s proportionate capital contribution, partially funded the Beta acquisition.
	On December 21, 2012, the underwriters purchased an additional 1,475,000 common units pursuant to their over-allotment option. We used the net proceeds of approximately $24.1 million from the sale of the additional common units, including our general partner’s proportionate capital contribution, to repay indebtedness under our revolving credit facility.
	Initial Public Offering of Memorial Production Partners LP
	On December 14, 2011, we completed our IPO of 9,000,000 common units representing limited partner interests in the Partnership at $19.00 per common unit for total net proceeds of approximately $146.5 million. In connection with the closing of the IPO, the Partnership distributed a combination of cash, common units, and subordinated units to Memorial Resource to acquire the net assets of our predecessor and repaid $198.3 million of our predecessor’s credit facilities concurrent with the closing of our IPO. The net cash proceeds generated from our IPO partially funded the cash portion of this consideration.
	On December 22, 2011, the underwriters exercised their over-allotment option to purchase an additional 600,000 common units issued by the Partnership under the IPO terms. Total net proceeds from the exercise of the underwriters’ over-allotment option, after deducting underwriting discounts, were $10.7 million. Of this amount, $10.0 million of these net proceeds were used to repay indebtedness under our revolving credit facility.
	Equity Outstanding
	The following table summarizes changes in the number of outstanding units since December 31, 2011:
			Common				Subordinated				General
											Partner
	Balance December 31, 2011			16,661,294				5,360,912				22,044
	Common units issued			11,975,000				—				—
	Restricted common units issued			287,943				—				—
	Restricted common units forfeited			(2,334	)			—				—
	General partner units issued			—				—				12,273
	Balance December 31, 2012			28,921,903				5,360,912				34,317
	Common units issued			26,450,000				—				—
	Restricted common units issued			524,717				—				—
	Restricted common units forfeited			(11,734	)			—				—
	Restricted common units repurchased (1)			(7,055	)
	General partner units issued			—				—				26,983
	Balance December 31, 2013			55,877,831				5,360,912				61,300
	-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 $0.1 million. 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 consolidated and combined balance sheets. See Note 11 for additional information regarding restricted common units that were granted during the years ended December 31, 2013 and 2012.
	As of December 31, 2013, Memorial Resource owned 100% of the subordinated units. Memorial Resource owns 100% of our general partner, which owns 50% of our incentive distribution rights. The Funds collectively indirectly own 50% of our incentive distribution rights.
	Common & Subordinated Units. The common units and the subordinated units are separate classes of the limited partner interest in us and have limited voting rights as set forth in our partnership agreement. The holders of units are entitled to participate in partnership distributions as discussed further below under “Cash Distribution Policy” and exercise the rights or privileges available to limited partners under our partnership agreement.
	Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement.
	General Partner Interest and IDRs. Our general partner owns a 0.1% interest in us. Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders, general partner and holders of our IDRs will receive. The general partner has the management rights as set forth in our partnership agreement.
	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. Net income (loss) attributable to acquisitions accounted for as a transaction between entities under common control prior to their acquisition date is allocated to the previous owners. For periods prior to our IPO, net income (loss) was attributable to both our predecessor and the previous owners.
	Cash Distribution Policy
	We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Additionally, under our revolving credit facility, we will not be able to pay distributions to unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with our revolving credit facility after giving effect to such distribution.
	Available Cash. Our partnership agreement requires that within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2011, we distribute all of our available cash (as defined in our partnership agreement) to our general partner and unitholders of record on the applicable record date. Generally, available cash refers to all cash on hand at the end of the quarter less cash reserves established by our general partner to: (i) operate our business (e.g., future capital expenditures, working capital and operating expenses); (ii) comply with applicable law, debt, and other agreements; and (iii) provide funds for distribution to our unitholders (including our general partner) for any one or more of the next four quarters. If our general partner so determines, available cash may include borrowings made after the end of the quarter.
	General Partner Interest and Incentive Distribution Rights. Our general partner is entitled to 0.1% of all distributions of available cash that we make prior to our liquidation. Our general partner’s initial 0.1% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 0.1% general partner interest. Our general partner is not obligated to contribute a proportionate amount of capital to us to maintain its current general partner interest. We have also issued IDRs, which entitle the holder(s) thereof to additional increasing percentages, up to a maximum of 24.9%, of the cash we distribute in excess of $0.54625 per common unit per quarter. Our general partner owns 50%, and the Funds indirectly own 50%, of the IDRs.
	Minimum Quarterly Distribution. During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4750 per common unit plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.
	Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
		•		first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
		•		second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
		•		third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
		•		thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages in the table below.
	The holders of the IDRs are entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:
			Total Quarterly  Distributions		Marginal Percentage Interest in Distributions
			Target Amount		Unitholders				General				IDR (1)
									Partner
	Minimum Quarterly Distribution		$0.48			99.9	%			0.1	%			—
	First Target Distribution		above $0.4750 up to $0.54625			99.9	%			0.1	%			—
	Second Target Distribution		above $0.54625 up to $0.59375			85	%			0.1	%			14.9	%
	Thereafter		above $0.59375			75	%			0.1	%			24.9	%
	-1	Our general partner owns 50%, and the Funds own 50%, of the IDRs.
	Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
		•		first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
		•		thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders, the general partner and the holders of the IDRs based on the percentages in the table above.
	The subordination period will extend until the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2014 that each of the following tests are met:
		•		Distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions payable with respect to a period of twelve consecutive quarters immediately preceding such date;
		•		The “adjusted operating surplus” (as defined in our partnership agreement) generated during the period of twelve consecutive quarters immediately preceding that date equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units that were outstanding during these periods payable with respect to such period on a fully diluted weighted average basis; and
		•		there are no arrearages in payment of the minimum quarterly distribution on the common units.
	When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash.
	In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:
		•		the subordination period will end and each subordinated unit will immediately convert into one common unit;
	•		any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
	•		our general partner will have the right to convert its general partner units into common units or to receive cash in exchange for such general partner units at the equivalent common unit fair market value
The subordination period will also automatically terminate, and all of the subordinated units will convert into an equal number of common units, on the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2012, if the following tests are met:
	•		distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded $0.59375 (125% of the minimum quarterly distribution) per quarter for the four quarter period immediately preceding that date;
	•		the “adjusted operating surplus” generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.3750 (125% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units, in each case that were outstanding during such four quarter period on a fully diluted weighted average basis, and the corresponding distributions on the incentive distribution rights; and
	•		there are no arrearages in payment of the minimum quarterly distribution on the common units.
Our general partner has the right (but not the obligation), at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%, assuming it has maintained its 0.1% general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election.
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):
Quarter		Declaration Date				Record Date				Payable Date				Amount			Aggregate			Distribution
														Per Unit  (1)			Distribution  (2)			Received by
																				Memorial
																				Resource
4th Quarter 2013			January 27, 2014				6-Feb-14				13-Feb-14			$	0.55		$	33.8		$	3
3rd Quarter 2013			October 22, 2013				November 1, 2013				November 12, 2013			$	0.55		$	33.8		$	6.9
2nd Quarter 2013			18-Jul-13				1-Aug-13				12-Aug-13			$	0.5125		$	22.9		$	6.4
1st Quarter 2013			18-Apr-13				1-May-13				13-May-13			$	0.5125		$	22.6		$	6.4
4th Quarter 2012			15-Jan-13				1-Feb-13				13-Feb-13			$	0.5075		$	17.4		$	6.3
3rd Quarter 2012			19-Oct-12				1-Nov-12				12-Nov-12			$	0.495		$	11.1		$	6.2
2nd Quarter 2012			19-Jul-12				1-Aug-12				13-Aug-12			$	0.48		$	10.7		$	6
1st Quarter 2012			19-Apr-12				1-May-12				14-May-12			$	0.48		$	10.7		$	6
4th Quarter 2011			26-Jan-12				6-Feb-12				13-Feb-12			$	0.0929		$	2		$	1.2
-1	The $0.0929 per unit pro-rated distribution paid on February 13, 2012 was based upon the minimum quarterly distribution of $0.4750 per unit adjusted to take into account the 18-day period of the fourth quarter of 2011 during which the Partnership was a public entity.
-2	The aggregate distribution for the third quarter of 2013 reflects the October 2013 public equity offering.
Predecessor & Previous Owners Capital
The following table summarizes our predecessor’s equity transactions with respect to the period indicated (dollars in thousands):
		BlueStone				Classic				WHT				Total
						Carve-Out				Assets				Predecessor
Balance December 31, 2010		$	65,776			$	40,025			$	—			$	105,801
Net income (loss)			72,728				(7,567	)			10,579				75,740
Contributions (distributions)			—				(2,876	)			51,761				48,885
Net assets retained by predecessor			(13,150	)			(1,062	)			(3,173	)			(17,385	)
Exchange of predecessor interests for units			(125,354	)			(28,520	)			(59,167	)			(213,041	)
Balance December 31, 2011		$	—			$	—			$	—			$	—
The following table summarizes our previous owners’ equity transactions with respect to the period indicated (dollars in thousands):
		Tanos/Classic				REO				WHT				Cinco			Total
		Properties								Properties				Group			Previous
																	Owners
Balance December 31, 2010			43,313				100,925				—				125,590			269,828
Net income (loss)			3,621				31,816				18,703				12,464			66,604
Contributions			3,919				5,010				77,641				74,933			161,503
Net assets retained by predecessor			—				—				3,180				—			3,180
Distributions			—				(64,996	)			—				(1,581	)		(66,577	)
Other			—				—				—				38			38
Balance December 31, 2011			50,853				72,755				99,524				211,444			434,576
Net income (loss)			1,000				28,691				8,369				8,233			46,293
Contributions			—				—				—				64,597			64,597
Contribution of oil and gas properties			—				—				—				6,893			6,893
Net book value of net assets acquired by Partnership			(50,639	)			(93,696	)			—				—			(144,335	)
Contribution related to sale of assets to NGP affiliate			—				—				—				40,138			40,138
Net book value of net assets acquired by NGP affiliate			—				—				—				(33,859	)		(33,859	)
Distributions			(1,214	)			(7,750	)			—				(20,553	)		(29,517	)
Other			—				—				—				(92	)		(92	)
Balance December 31, 2012			—				—				107,893				276,801			384,694
Net income (loss)			—				—				(1,219	)			12,494			11,275
Contributions			—				—				—				7,233			7,233
Distribution attributable to net assets acquired			—				—				—				55,281			55,281
Net book value of net assets acquired by Partnership			—				—				(106,674	)			(297,627	)		(404,301	)
Distributions			—				—				—				(31,098	)		(31,098	)
Other			—				—				—				(2,302	)		(2,302	)
Net assets retained by predecessor			—				—				—				(20,782	)		(20,782	)
Balance December 31, 2013		$	—			$	—			$	—			$	—		$	—

Earnings_per_Unit

Earnings per Unit	12 Months Ended
	Dec. 31, 2013
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 Year Ended December 31,
		2013		2012		2011
	Net income attributable to Memorial Production Partners LP	$	20,001	$	46,414	$	148,936
	Less: Previous owners interest in net income (loss)		11,275		46,293		66,604
	Less: Predecessor interest in net income (loss)		—		—		75,740
	Less: General partners’ 0.1% interest in net income (loss)		9		—		7
	Less: IDRs attributable to corresponding period		81		—		—
	Net income (loss) available to limited partners	$	8,636	$	121	$	6,585
	Weighted average limited partner units outstanding:
	Common units		40,656		17,519		16,395
	Subordinated units		5,361		5,361		5,361
	Total		46,017		22,880		21,756
	Basic and diluted EPU	$	0.19	$	0.01	$	0.3
	The following sets forth the calculation of our supplemental EPU, for the periods indicated (in thousands, except per unit amounts):
		For the Year Ended December 31,
		2013		2012		2011
	Net income attributable to Memorial Production Partners LP	$	20,001	$	46,414	$	148,936
	Less: General partners’ 0.1% interest in net income (loss)		20		46		149
	Less: IDRs attributable to corresponding period		81		—		—
	Net income (loss) available to limited partners	$	19,900	$	46,368	$	148,787
	Weighted average limited partner units outstanding:
	Common units		40,656		17,519		16,395
	Subordinated units		5,361		5,361		5,361
	Total		46,017		22,880		21,756
	Supplemental basic and diluted EPU	$	0.43	$	2.03	$	6.83
	Our supplemental basic and diluted EPU includes all the earnings generated by the Partnership’s previous owners and predecessor for all periods presented due to common control considerations. As discussed under Note 1, transactions between entities under common control are accounted for retrospectively.

Equitybased_Awards

Equity-based Awards	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Equity-based Awards	'
	Note 11. Equity-based Awards
	Long-Term Incentive Plan
	In December 2011, the Board adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for employees, officers, consultants and directors of the general partner and any of its affiliates, including Memorial Resource, who perform services for the Partnership. The LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP is administered by the Board or a committee thereof. During the years ended December 31, 2013 and 2012, there were multiple awards of restricted common units that were granted under the LTIP to both executive officers and independent directors of our general partners and other Memorial Resource employees.
	The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions in which one-third of each award vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in the partnership with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by the Partnership to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.
	Based on the market price per unit on the date of grant, the aggregate fair value of the restricted common units awarded to our general partner’s executive officers and other Memorial Resource employees during the years ended December 31, 2013 and 2012 was $9.7 million and $5.0 million, respectively. The restricted common units granted are accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basis over the requisite service period. The fair value of the restricted unit awards granted to the independent directors of our general partner are also recognized as compensation cost on a straight-line basis over the requisite service period.
	The following table summarizes information regarding restricted common unit awards for the periods presented:
			Number				Weighted-
			of Units				Average  Grant
							Date Fair Value
							per Unit (1)
	Restricted common units outstanding at December 31, 2011			—			$	—
	Granted (2)			287,943			$	18.07
	Forfeited			(2,334	)		$	17.14
	Restricted common units outstanding at December 31, 2012			285,609			$	18.08
	Granted (3)			524,718			$	18.83
	Forfeited			(11,734	)		$	17.24
	Vested			(91,666	)		$	18.31
	Restricted common units outstanding at December 31, 2013			706,927			$	18.62
	-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 2012 was $5.2 million based on grant date market prices ranging from of $17.14 to $18.58 per unit.
	-3	The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 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 Year
	Ended December 31,
	2013				2012
		$3,558			$	1,423
	The unrecognized compensation cost associated with restricted common unit awards was an aggregate $9.9 million at December 31, 2013. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years.
	Since the restricted common units are participating securities, any distributions received by the restricted common unitholders are included in distributions to partners as presented on our statements of consolidated and combined cash flows. During the years ended December 31, 2013 and 2012, the restricted common unitholders received a distribution of approximately $1.0 million and $0.2 million, respectively.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Note 12. Related Party Transactions
	Amounts due to (due from) Memorial Resource, NGP and their respective affiliates at December 31, 2013 and December 31, 2012 are presented as “Accounts receivable—affiliates” and “Accounts payable—affiliates” in the accompanying balance sheets.
	Common Control Acquisitions
	Acquisition of the Net Assets of Our Predecessor in Connection with IPO
	In connection with the closing of our IPO on December 14, 2011, the Partnership acquired the following net assets of our predecessor:
	Oil and natural gas properties, net		$	399,967
	Short-term derivative instruments, net			15,779
	Long-term derivative instruments, net			10,772
	Asset retirement obligations			(13,560	)
	Credit facilities—predecessor (2)			(198,267	)
	Accrued liabilities			(1,650	)
	Net assets (1)		$	213,041
	-1	Due to the timing of our IPO and the fact that we did not acquire working capital from our predecessor, our consolidated balance sheet as of December 31, 2011 did not include any trade receivables or payables.
	-2	Although the Partnership did not legally assume the debt of its predecessor, for accounting and financial reporting purposes the $198.3 million that was repaid concurrent with the closing of our IPO on behalf of our predecessor has been included as a component of the net assets that were acquired by us and reflected on our consolidated and combined cash flow statement as “Payments on revolving credit facilities.”
	Acquisition of Tanos/Classic Properties from Memorial Resource Subsequent to our IPO
	On April 2, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a final purchase price of $18.5 million after customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of certain commodity positions with effective dates 2012 through 2013. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Willow Springs field in Gregg County, as well as in Upshur, Rusk, Panola, Smith and Leon counties in East Texas. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):
	Oil and natural gas properties, net		$	15,164
	Short-term derivative instruments, net			715
	Long-term derivative instruments, net			674
	Asset retirement obligations			(466	)
	Accrued liabilities			(17	)
	Net assets		$	16,070
	On May 14, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a final purchase price of $27.0 million after customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of certain commodity derivative positions with effective dates 2012 through 2014. The transaction was approved by the Board and by its conflicts committee. These properties are located primarily in the Joaquin and Carthage fields in Panola and Shelby counties in East Texas. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):
	Oil and natural gas properties, net		$	31,716
	Accounts receivable			612
	Short-term derivative instruments, net			1,017
	Long-term derivative instruments, net			1,337
	Asset retirement obligations			(43	)
	Accrued liabilities			(70	)
	Net assets		$	34,569
	Beta Acquisition
	On December 12, 2012, we acquired REO, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, from Rise for a purchase price of $270.6 million, which included $3.0 million of working capital and other customary adjustments. The Beta acquisition was funded with borrowings under our credit facility and the net proceeds generated from our December 12, 2012 public offering of common units (including our general partner’s proportionate capital contribution). Terms of the transaction were approved by the Board and by its conflicts committee. The acquired properties, which we refer to as the Beta properties, primarily consist of a 51.75% working interest in three Pacific Outer Continental Shelf blocks covering the Beta Field, and are located in federal waters approximately eleven miles offshore the Port of Long Beach, California. Associated facilities include three conventional wellhead and production processing platforms, a 17.5-mile pipeline and an onshore tankage and metering facility. Two of the platforms are bridge connected and stand in approximately 260 feet of water, while the third platform stands in approximately 700 feet of water. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):
	Cash and cash equivalents		$	6,021
	Accounts receivable			16,284
	Short-term derivative instruments, net			2,926
	Prepaid expenses and other current assets			4,521
	Oil and natural gas properties, net			108,342
	Restricted investments			68,009
	Accounts payable			(9,092	)
	Accrued liabilities			(9,140	)
	Asset retirement obligations			(58,746	)
	Credit facilities			(28,500	)
	Deferred tax liability			(1,674	)
	Noncontrolling interest			(5,255	)
	Net assets		$	93,696
	On December 12, 2012, in connection with the Beta acquisition, the Partnership contributed to Memorial Resource the entity that employs those who operate and support the Beta properties in exchange for approximately $3.0 million. The net book value of the assets contributed to Memorial Resource was as follows (in thousands):
	Cash and cash equivalents		$	3,751
	Accounts receivable			11,125
	Prepaid expenses and other current assets			3,470
	Property, plant and equipment, net			416
	Accounts payable			(7,898	)
	Accrued liabilities			(7,864	)
	Net assets		$	3,000
	Acquisition of WHT
	On March 28, 2013, we acquired all of the outstanding equity interests in WHT from operating subsidiaries of Memorial Resource for a purchase price of $200.0 million, which included $4.0 million of working capital and other customary adjustments. This acquisition was funded with borrowings under our revolving credit facility and the net proceeds from our March 25, 2013 public offering of common units (including our general partner’s proportionate capital contribution). Terms of the transaction were approved by our general partner’s Board and by its conflicts committee. The WHT Properties consist of additional working interests in properties that we originally acquired in December 2011 in conjunction with our initial public offering. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):
	Cash and cash equivalents		$	1,354
	Accounts receivable			3,866
	Short-term derivative instruments, net			1,206
	Prepaid expenses and other current assets			98
	Oil and natural gas properties, net			192,280
	Long-term derivative instruments, net			3,528
	Accrued liabilities			(3,494	)
	Asset retirement obligations			(2,753	)
Credit facilities			(89,300	)
Other long-term liabilities			(111	)
Net assets		$	106,674
Acquisition of Cinco Group Properties from Memorial Resource & NGP Subsequent to our IPO
On October 1, 2013, we acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from Memorial Resource and certain affiliates of NGP for an aggregate purchase price of approximately $603 million, subject to customary post-closing adjustments. The Cinco Group acquisition was funded with borrowings under our revolving credit facility. Terms of the transaction were approved by the Board and by its conflicts committee. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):
Cash and cash equivalents		$	3,265
Accounts receivable			10,615
Prepaid expenses and other current assets			1,824
Oil and natural gas properties, net			457,439
Long-term derivative instruments, net			3,056
Other long-term assets			356
Accounts payable			(4,063	)
Revenue payable			(4,519	)
Accrued liabilities			(3,311	)
Short-term derivative instruments, net			(1,505	)
Asset retirement obligations			(13,575	)
Credit facilities			(151,690	)
Other long-term liabilities			(265	)
Net assets		$	297,627
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 continues to provide 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 Year
Ended December 31,
2013				2012
	$9,440			$	1,771
Beta Management Agreement
In connection with the December 2012 Beta acquisition, Memorial Resource entered into a management agreement with its wholly-owned subsidiary, Beta Operating Company, LLC, pursuant to which Memorial Resource agreed to provide management and administrative oversight with respect to the services provided by such subsidiary under certain operating agreements with our subsidiary, Rise Energy Beta, LLC, related to the Beta properties in exchange for an annual management fee. Pursuant to such management agreement and in connection with such operating agreements, Memorial Resource will receive approximately $0.4 million from Rise Energy Beta, LLC annually.
An affiliate of REO collected a management fee for providing administrative services to REO prior to the Beta acquisition. These administrative services included accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. The following table summarizes the amount of management fees REO incurred and paid, which are included in general and administrative expenses in the accompanying statements of operations for the periods presented (in thousands):
For the Year Ended
December 31,
2012				2011
	$1,552			$	1,693
WHT Management Agreement
WildHorse Resources, LLC (“WildHorse”) and Tanos, collectively owned the outstanding equity interests in WHT prior to March 28, 2013. Under the terms of a management agreement dated April 8, 2011, WildHorse provided executive, financial, accounting and land services to WHT. WildHorse also managed day-to-day field operations and drilling activities. Geological, executive and other services were provided by Tanos. To compensate for these services, WHT paid WildHorse and Tanos management fees totaling approximately $0.2 million per month. In connection with the WHT acquisition, the management agreement was terminated as of March 28, 2013. WildHorse collected an additional $0.6 million under a transitional agreement that was in place from April 2013 through July 2013.
As the designated operator, WildHorse received both operated and non-operated revenues on behalf of WHT and billed and received joint interest billings. WildHorse also paid for lease operating expenses, drilling cost and general and administrative costs on behalf of WHT. Receivable and payable balances were settled monthly between WHT and WildHorse.
Cinco Group Transition Service Agreements
The Partnership entered into transition service agreements with Propel Energy, Stanolind, and Boaz Energy Partners to ensure that ownership, operation, and maintenance of acquired properties can be smoothly transitioned. The term of these agreements are from October 1, 2013 through February 28, 2014. The Partnership expects to pay transition service fees of approximately $0.8 million in the aggregate under these agreements.
Other Related Party Transactions
Director, Advisory & Financing Fees
The majority partner of our predecessor, NGP VIII, is an affiliate of certain directors of the entities comprising our predecessor. For the period ended December 31, 2011, our predecessor expensed advisory and directors’ fees of approximately $0.2 million to NGP VIII. Certain of the Cinco Group entities entered into an advisory service, reimbursement, and indemnification agreements with NGP. These agreements generally required that an annual advisory fee be paid to NGP. Fees paid under these agreements for the years ended December 31, 2013, 2012, and 2011 were approximately $0.3 million, $0.4 million, and $0.4 million, respectively. Certain of the Cinco Group entities also paid a financing fee equal to a percentage of the capital contributions raised by NGP. These fees were considered a syndication cost and reduced equity contributions for financing fees paid. Fees for the years ended December 31, 2012 and 2011 were approximately $0.4 million and $1.4 million, respectively. There were no fees for the year ended December 31, 2013.
Tanos Management Team Equity Interest
On April 1, 2013, Tanos’ management team sold its 1.066% membership interest in Tanos to Memorial Resource and all incentive units held were forfeited. In connection with this sale, all of Tanos’ employees resigned and became employees of Tanos Exploration II, LLC (“Tanos II”), a Texas limited liability company controlled by the former management team of Tanos. Effective April 1, 2013, Tanos II entered into a Transition Services Agreement with Tanos, whereby Tanos II would manage the operations of Tanos for up to a 6-month period of time. Tanos II is an unrelated entity.
The governing documents of Tanos provided for the issuance of incentive units. Tanos granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions when declared, but only after cumulative distribution thresholds had been achieved (i.e., recovery of specified members’ capital contributions plus a rate of return). These incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. No compensation cost was recorded related to incentive units prior to the incentive units being forfeited on April 1, 2013. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as general and administrative expense during April 2013.
Miscellaneous
For the years ended December 31, 2013 and 2012, the Partnership incurred gathering and salt water disposal fees of approximately $0.6 million and $0.8 million, respectively, from a subsidiary of Memorial Resource.
During 2012, the Cinco Group received an equity contribution of $6.9 million of oil and gas properties in the Hendricks Field located in the Permian Basin of Texas by an NGP controlled entity. Due to common control considerations, this equity contribution was recorded at historical cost of the properties.
During 2012, Boaz reimbursed a member of its management team approximately $0.3 million in general, administrative, and lease operating expenses related to an oral lease agreement between the member of management and a third party for a field office and yard located in Bronte, Texas.
See Note 3 for additional information regarding the divestiture of certain interests in oil and gas properties offshore Louisiana that the Cinco Group sold during 2012 to an NGP controlled entity.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
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.
	Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2013, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable.
	The following table presents the activity of our environmental reserves for the periods presented:
		2013			2012			2011
		(In thousands)
	Balance at beginning of period	$	1,051		$	1,747		$	1,450
	Charged to costs and expenses		—			(225	)		—
	Acquisition-related additions		—			—			968
	Payments		(614	)		(471	)		(671	)
	Balance at end of period	$	437		$	1,051		$	1,747
	At December 31, 2013 and 2012, $0.4 million and $0.6 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities.
	Sinking Fund Trust Agreement
	REO assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Beta properties, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within State waters and the surface facilities. Under the terms of the agreement, REO, as the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2013, the gross account balance included in restricted investments was approximately $2.3 million. REO’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was $1.0 million at December 31, 2013.
	Supplemental Bond for Decommissioning Liabilities Trust Agreement
	REO assumed an obligation with the BOEM in connection with its 2009 acquisition of the Beta properties. Under the terms of the agreement dated March 1, 2007, the seller of the Beta properties was obligated to deliver a $90.0 million U.S. Treasury Note into a trust account for the decommissioning of the offshore production facilities. At the time of acquisition, all obligations under this existing agreement had been met.
	In January 2010, the BOEM issued a report that revised upward, the estimated cost of decommissioning. In June 2010, REO agreed to make additional quarterly payments to the trust account attributable to its net working interest of approximately $0.6 million beginning on June 30, 2010 until the payments and accrued interest attributable to REO equal $78.7 million by December 31, 2016. The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):
	June 30, 2014	$	68,310
	June 30, 2015	$	72,450
	June 30, 2016	$	76,590
	December 31, 2016	$	78,660
	In the event the account balance is less than the contractual amount, the working interest owners must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by the working interest owners. As of December 31, 2013, the maximum remaining obligation net to REO’s interest was approximately $12.2 million.
	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 December 31, 2013 (in thousands):
	Investment	Amortized			Unrealized			Fair Market
		Cost			Gain (Loss)			Value
	U.S. Bank Money Market Cash Equivalent	$	105,184		$	—		$	105,184
	U.S. Government Treasury Note, maturity of March 31, 2014, and 1.75% coupon		23,073			93			23,166
	Less: Outside working interest owners share		(61,884	)		(45	)		(61,929	)
		$	66,373		$	48		$	66,421
	Operating Leases
	We have leases for offshore Southern California pipeline right-of-way use as well as office space in our operating regions. We also lease equipment and incur surface rentals related to our business operations. Our predecessor and the previous owners also leased equipment and office space under various operating leases and incurred surface rentals related to their operations.
	For the years ended December 31, 2013 and 2012, we recognized $2.4 million and $1.0 million of rent expense, respectively. We recognized an immaterial amount of allocated rent expense from the closing our IPO through December 31, 2011, primarily for office space. Our predecessor and the previous owners leased equipment and office space under various operating leases. Our predecessor and the previous owners recorded rent expense of approximately $2.3 million, $2.1 million and $1.6 million for the years ended December 31, 2013, 2012 and 2011, respectively.
	Amounts shown in the following table represent minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year:
		Payment or Settlement due by Period
	Lease Obligations	Total			2014			2015			2016		2017		2018		Thereafter
		(In thousands)
	Operating leases	$	3,985		$	549		$	560		$	416	$	205	$	205	$	2,050

Defined_Contribution_Plans

Defined Contribution Plans	12 Months Ended
	Dec. 31, 2013
Postemployment Benefits [Abstract]	'
Defined Contribution Plans	'
	Note 14. Defined Contribution Plans
	Memorial Resource sponsors a defined contribution plan for the benefit of substantially all employees who have attained 18 years of age. The plan allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. Memorial Resource makes matching contributions of 100% of employee contributions that does not exceed 6% of compensation. Employees are immediately vested in these matching contributions. This plan became effective on January 1, 2012. The plan received employer contributions of approximately $0.9 million and $0.4 million in 2013 and 2012, respectively. Approximately $0.3 million and $0.1 million associated with this plan are reflected as costs and expenses in the accompanying statements of operations for the years ended December 31, 2013 and 2012, respectively.
	Effective January 1, 2012, REO assumed sponsorship of a separate defined contribution plan. This plan specifically benefits substantially all those employed by the Memorial Resource subsidiary that operates and supports the Beta properties that have attained 21 years of age. Eligible employees are permitted to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. Employer matching contributions of 100% of employee contributions that does not exceed 6% of compensation are made to the plan as well. The employer matching contributions associated with this plan were subject to a three-year graded vesting schedule through February 28, 2012. Effective March 1, 2012, the plan was amended to offer immediate vesting of employer matching contributions. The plan received employer contributions of approximately $0.6 million, $0.5 million, and $0.5 million in 2013, 2012, and 2011, respectively. Approximately $0.3 million associated with this plan are reflected as costs and expenses in the accompanying statements of operations for the each of the years ended December 31, 2013, 2012, and 2011.
	Our predecessor also sponsored defined contribution plans for the benefit of substantially all their employees who attained 18 years of age. Matching contributions of up to 6% of an employee’s compensation were made and additional discretionary contributions for eligible employees meeting certain plan requirements was also an option under these plans. Employer contributions of approximately $0.2 million were made to these other plans in 2011.
	Certain Cinco Group entities made matching contributions to defined contribution plans for the benefit of their eligible employees. Matching employer contributions of approximately $0.1 million, $0.2 million, and $0.1 million were made to these plans in 2013, 2012, and 2011, respectively. Such contributions to these plans are included in general and administrative expenses in the accompanying combined statements of operations.

Quarterly_Financial_Informatio

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Financial Information (Unaudited)	'
	Note 15. Quarterly Financial Information (Unaudited)
	The following tables present selected quarterly financial data for the periods indicated. Earnings per unit are computed independently for each of the quarters presented and the sum of the quarterly earnings per unit may not necessarily equal the total for the year.
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	For the Year Ended December 31, 2013:	(In thousands, except per unit amounts)
	Revenues	$	68,102		$	90,174		$	93,240		$	92,100
	Operating income (loss)		2,245			60,814			(27,368	)		26,786
	Net income (loss)		(4,297	)		52,695			(39,039	)		10,909
	Net income attributable to Memorial Production Partners LP		(4,293	)		52,597			(39,165	)		10,862
	Net income allocated to previous owners		729			6,418			4,128			—
	Net income (loss) noncontrolling interest		(4	)		98			126			47
	Limited partners’ interest in net income		(5,017	)		46,133			(43,250	)		10,811
	Basic and diluted earnings per unit		(0.14	)		1.04			(0.97	)		0.18
	For the Year Ended December 31, 2012:
	Revenues	$	63,960		$	56,409		$	67,132		$	70,922
	Operating income (loss)		39,923			28,221			(9,220	)		8,509
	Net income (loss)		35,941			22,238			(15,107	)		3,446
	Net income attributable to Memorial Production Partners LP		36,032			22,222			(15,199	)		3,359
	Net income allocated to previous owners		15,138			22,476			10,133			(1,454	)
	Net income (loss) noncontrolling interest		(91	)		16			92			87
	Limited partners’ interest in net income		20,873			(254	)		(25,307	)		4,809
	Basic and diluted earnings per unit		0.94			(0.01	)		(1.13	)		0.19
	As discussed in Note 1, we closed our IPO on December 14, 2011. The Partnership has consummated several common control acquisitions since completing its IPO in December 2011, as further discussed in Note 12, directly or indirectly from Memorial Resource and certain affiliates of NGP. The quarterly financial information presented above has been retrospectively revised for these common control transactions. See Notes 2 and 10 for additional information regarding earnings per unit.

Supplemental_Oil_and_Gas_Infor

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Supplemental Oil and Gas Information (Unaudited)	'
	Note 16. Supplemental Oil and Gas Information (Unaudited)
	Capitalized Costs Relating to Oil and Natural Gas Producing Activities
	The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.
			Years Ended December 31,
			2013			2012			2011
			(In thousands)
	Evaluated oil and natural gas properties (1)		$	1,758,953		$	1,545,402		$	1,217,597
	Unevaluated oil and natural gas properties			—			5,004			4,494
	Accumulated depletion, depreciation, and amortization (1)			(417,617	)		(265,710	)		(187,022	)
	Total		$	1,342,336		$	1,284,696		$	1,035,069
	-1	Amounts do not include costs for SPBPC and related support equipment.
	Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
	Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:
			Years Ended December 31,
			2013			2012			2011
			(In thousands)
	Property acquisition costs, proved		$	37,786		$	278,246		$	404,116
	Exploration			—			42,430			40,034
	Development (1)			145,830			62,472			62,411
	Total		$	183,616		$	383,148		$	506,561
	-1	Amounts do not include costs for SPBPC and related support equipment.
	Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
	As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Partnership’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.
	Oil and Natural Gas Reserves
	Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
	Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
	We engaged NSAI to prepare reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2013. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.
	The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:
			2013			2012			2011
	Oil ($/Bbl):
	West Texas Intermediate spot (1)		$	93.42		$	91.22		$	92.75
	NGL ($/Bbl):
	West Texas Intermediate spot (1)		$	93.42		$	91.27		$	93.19
	Natural Gas ($/MMbtu):
	Henry Hub spot (2)		$	3.67		$	2.757		$	4.118
	-1	The weighted average West Texas Intermediate spot price was adjusted by lease for quality, transportation fees, and a regional price differential.
	-2	The weighted average Henry Hub spot price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
	The following tables set forth estimates of the net reserves as of December 31, 2013, 2012 and 2011, respectively:
			Year Ended December 31, 2013
			Oil			Gas			NGLs			Equivalent
			(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of year			39,089			604,440			29,352			1,015,095
	Extensions and discoveries			5,655			40,770			1,747			85,180
	Purchase of minerals in place			119			16,294			258			18,554
	Production			(1,764	)		(35,924	)		(1,632	)		(56,303	)
	Sales of minerals in place			—			—			—			—
	Revision of previous estimates			(3,950	)		(18,441	)		(879	)		(47,421	)
	End of year			39,149			607,139			28,846			1,015,105
	Proved developed reserves:
	Beginning of year			24,515			376,932			15,947			619,704
	End of year			22,265			387,548			15,959			616,893
	Proved undeveloped reserves:
	Beginning of year			14,574			227,508			13,405			395,391
	End of year			16,884			219,591			12,887			398,212
			Year Ended December 31, 2012
			Oil			Gas			NGLs			Equivalent
			(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of year			27,150			579,751			15,045			832,913
	Extensions and discoveries			7,501			19,869			1,053			71,192
	Purchase of minerals in place			11,336			113,617			7,095			224,202
	Production			(1,519	)		(29,744	)		(745	)		(43,329	)
Sales of minerals in place			(4,214	)		(4,214	)		—			(29,499	)
Revision of previous estimates			(1,165	)		(74,839	)		6,904			(40,384	)
End of year			39,089			604,440			29,352			1,015,095
Proved developed reserves:
Beginning of year			19,332			413,431			10,015			589,504
End of year			24,515			376,932			15,947			619,704
Proved undeveloped reserves:
Beginning of year			7,818			166,320			5,030			243,409
End of year			14,574			227,508			13,405			395,391
		Year Ended December 31, 2011
		Oil			Gas			NGLs			Equivalent
		(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
Beginning of year			16,280			291,074			1,326			396,708
Extensions and discoveries			1,739			55,454			2,371			80,120
Purchase of minerals in place			7,518			269,653			10,142			376,580
Production			(1,112	)		(25,829	)		(375	)		(34,755	)
Reserves retained by our predecessor			(23	)		(3,198	)		—			(3,335	)
Sales of minerals in place			(1	)		(132	)		—			(138	)
Revision of previous estimates			2,749			(7,271	)		1,581			17,733
End of year			27,150			579,751			15,045			832,913
Proved developed reserves:
Beginning of year			12,967			214,916			992			298,671
End of year			19,332			413,431			10,015			589,504
Proved undeveloped reserves:
Beginning of year			3,313			76,158			334			98,037
End of year			7,818			166,320			5,030			243,409
Noteworthy amounts included in the categories of proved reserve changes in the above tables include:
	•		We acquired 224.2 Bcfe in multiple acquisitions during the year ended December 31, 2012, the largest being the Goodrich Acquisition of 148.9 Bcfe. Stanolind acquired 43.6 Bcfe through multiple acquisitions, the largest being the Menemsha Acquisition of 23.9 Bcfe. During the year ended December 31, 2012, Propel divested 19.0 Bcfe of offshore Louisiana oil and gas properties to an NGP controlled entity.
	•		Our predecessor and the previous owners together acquired 376.6 Bcfe in multiple acquisitions, the largest being the Carthage Properties of 277.7 Bcfe, during the year ended December 31, 2011.
See Note 3 for additional information on acquisitions and divestitures.
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
The standardized measure of discounted future net cash flows is as follows:
		Years Ended December 31,
		2013			2012			2011
		(In thousands)
Future cash inflows		$	6,892,150		$	6,511,776		$	5,747,123
Future production costs			(2,719,024	)		(2,258,554	)		(1,920,497	)
Future development costs			(685,858	)		(620,944	)		(432,144	)
Future income tax expense (1)			—			—			(4,420	)
Future net cash flows for estimated timing of cash flows			3,487,268			3,632,278			3,390,062
10% annual discount for estimated timing of cash flows			(1,879,156	)		(2,042,362	)		(1,890,648	)
Standardized measure of discounted future net cash flows		$	1,608,112		$	1,589,916		$	1,499,414
-1	We are subject to the Texas franchise tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax for the years ended December 31, 2013 and 2012.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2013:
		Years Ended December 31,
		2013			2012			2011
		(In thousands)
Beginning of year		$	1,589,916		$	1,499,414		$	596,696
Sale of oil and natural gas produced, net of production costs			(234,520	)		(160,023	)		(153,621	)
Purchase of minerals in place			23,160			375,953			565,760
Sale of minerals in place			—			(154,963	)		(282	)
Reserves retained by predecessor			—			—			(1,940	)
Extensions and discoveries			136,423			265,108			114,482
Changes in income taxes, net			—			1,947			(1,947	)
Changes in prices and costs			(74,395	)		(331,760	)		197,939
Previously estimated development costs incurred			174,490			66,360			4,721
Net changes in future development costs			(74,867	)		(1,140	)		(17,054	)
Revisions of previous quantities			(141,122	)		(90,587	)		99,514
Accretion of discount			158,991			150,136			80,999
Change in production rates and other			50,036			(30,529	)		14,147
End of year		$	1,608,112		$	1,589,916		$	1,499,414

Subsequent_Event

Subsequent Event	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Event	'
	Note 17. Subsequent Event
	Definitive Agreement to Acquire Certain Oil and Natural Gas Properties
	On March 4, 2014, we announced the entry into a definitive agreement to acquire certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource for a purchase price of $35.0 million, subject to customary purchase price adjustments. The transaction is expected to close on or about April 1, 2014 and will be financed with borrowings under our revolving credit facility. Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee. The acquired properties primarily represent additional working interests in wells currently owned by MEMP and located primarily in Polk and Tyler Counties in the Double A Field of East Texas, as well as the Sunflower, Segno and Sugar Creek Fields.

Organization_and_Basis_of_Pres1

Organization and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2013
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 business activities are conducted through our wholly owned subsidiary Memorial Production Operating LLC (“OLLC”) and its wholly-owned subsidiaries. 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).
	The Partnership was formed in April 2011 to own and acquire oil and natural gas properties in North America and completed its initial public offering (“IPO”) on December 14, 2011 (see Note 9). The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, Memorial Production Partners GP LLC, which is a wholly owned subsidiary of Memorial Resource Development LLC (“Memorial Resource”). Our general partner is responsible for managing all of the Partnership’s operations and activities.
	Memorial Production Finance Corporation (“Finance Corp.”), our wholly-owned subsidiary, has no material assets or any liabilities other than as a co-issuer of our debt securities and as a guarantor of certain of our other indebtedness. Its activities will be limited to co-issuing our debt securities and engaging in other activities incidental thereto.
	Memorial Resource is a Delaware limited liability company owned and formed by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. Memorial Resource provides management, administrative, and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds are private equity funds managed by Natural Gas Partners (“NGP”). The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). Our remaining IDRs are owned by our general partner.
Predecessor	'
	Predecessor
	References to “our predecessor” for accounting and financial reporting purposes refers collectively to: (i) BlueStone Natural Resources Holdings, LLC (“Bluestone”) and its wholly-owned subsidiaries in addition to certain carved-out oil and natural gas properties (“Classic Carve-Out”) owned by Classic Hydrocarbons Holdings, L.P. (“Classic”) for all periods prior to the closing of our IPO and (ii) certain oil and natural gas properties owned by WHT Energy Partners LLC (“WHT”) for periods after April 8, 2011 through the closing of our IPO.
	In connection with our IPO, the Funds contributed to Memorial Resource their respective ownership of five separate portfolio companies (including those comprising our predecessor) and we acquired substantially all of the oil and natural gas properties and related assets owned by BlueStone, certain carved-out oil and natural gas properties and related assets owned by Classic and a 40% undivided interest in certain oil and natural gas properties and related assets (the “WHT Assets”) controlled by WHT. We distributed approximately $73.6 million in cash, 7,061,294 common units, and 5,360,912 subordinated units to Memorial Resource to acquire the net assets of our predecessor and repaid $198.3 million of our predecessor’s credit facilities concurrent with the closing of our IPO. The cash portion of this consideration was financed with borrowings under a senior securing revolving credit facility (see Note 8) and the net cash proceeds generated from our IPO. This dropdown transaction was accounted for as a combination of entities under common control; therefore, the Partnership accounted for the acquisition at historical cost in a manner similar to the pooling of interest method.
Previous Owners	'
	Previous Owners
	References to “the previous owners” for accounting and financial reporting purposes refer collectively to:
		•		Certain oil and natural gas properties the Partnership acquired from Memorial Resource in April and May 2012 (“Tanos/Classic Properties”) for periods after common control commenced through their respective date of acquisition.
		•		Rise Energy Operating, LLC and its wholly-owned subsidiaries (except for Rise Energy Operating, Inc.) (“REO”) from February 3, 2009 (inception) through the date of acquisition. The Partnership acquired REO, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, in December 2012 from Rise Energy Partners, LP (“Rise”). We refer to this transaction as the “Beta acquisition.” Rise is primarily owned by two of the Funds.
		•		Certain oil and natural gas properties and related assets in East Texas and North Louisiana that the Partnership acquired in March 2013 (the “WHT Properties”) owned by WHT from February 2, 2011 (inception) through the date of acquisition.
		•		Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that the Partnership acquired through equity and asset transactions on October 1, 2013 from both Memorial Resource and certain affiliates of NGP as discussed below. We refer to this transaction as the “Cinco Group acquisition.”
	Each of these aforementioned acquisitions 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 has been retrospectively revised to give effect to such acquisitions as if the Partnership owned the assets for periods after common control commenced through their respective acquisition dates. See Note 12 for additional information.
Basis of Presentation	'
	Basis of Presentation
	Our consolidated results of operations following the completion of our IPO are presented together with the combined results of operations pertaining to our predecessor and the previous owners. The combined financial statements were derived from the historical accounting records of our predecessor and the previous owners and reflect the historical financial position, results of operations and cash flows for all periods presented.
	Our predecessor’s combined financial statements reflect the financial statements of BlueStone and Classic Carve-Out through the closing of our IPO and the WHT Assets for periods after April 8, 2011 through December 13, 2011. The Classic Carve-Out amounts included in the accompanying financial statements include allocations for various expenses. Certain expenses incurred by Classic were indirectly attributable to the Classic Carve-Out as Classic owned interests in numerous other oil and natural gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to our predecessor, so that the amounts included in the combined financial statements reflect substantially all of the cost of doing business. Such allocations may or may not reflect future costs associated with the operation of the Partnership.
	The previous owners combined financial statements reflect: (i) certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective date of acquisition on a combined basis for all periods presented, (ii) the consolidated financial statements of REO for all periods presented, (iii) the WHT Properties from February 2, 2011 (inception) through the date of acquisition, (iv) the financial statements of Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits overriding royalty interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), Stanolind Oil and Gas SPV LLC (“Stanolind SPV”), Tanos Energy, LLC (“Tanos”), together with its wholly-owned subsidiaries, Prospect Energy, LLC (“Prospect”), and certain oil and natural gas properties in Jackson County, Texas (the “MRD Assets”) (collectively, the “Cinco Group”) on a combined basis for periods after common control commenced through the date of acquisition. The Partnership acquired substantially all of the Cinco Group on October 1, 2013 from: (a) Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds, and (b) Memorial Resource.
	The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of REO, is presented as noncontrolling interest in the financial statements.
	All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain amounts in the prior year financial statements have been reclassified to conform to the presentation in the current year financial statements.
Use of Estimates	'
	Use of Estimates
	The preparation of 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.
Principles of Consolidation and Combination	'
	Principles of Consolidation and Combination
	Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents
	Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.
Concentrations of Credit Risk	'
	Concentrations of Credit Risk
	Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor and the previous owners have experienced any losses from such instruments.
	Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us, our predecessor, and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2013 and 2012, respectively.
	If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.
Oil and Natural Gas Properties	'
	Oil and Natural Gas Properties
	Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.
	As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.
	On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.
	There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2013, 2012 and 2011.
Oil and Gas Reserves	'
	Oil and Gas Reserves
	The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to prepare our reserves estimates at December 31, 2013.
	Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
Other Property & Equipment	'
	Other Property & Equipment
	Other property and equipment is stated at historical costs and is comprised primarily of vehicles, furniture, fixtures, and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to five years.
Restricted Investments	'
	Restricted Investments
	Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense – net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.
Debt Issuance Costs	'
	Debt Issuance Costs
	These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2013, 2012, and 2011 was approximately $5.8 million, $2.0 million, and $1.5 million, respectively.
Impairments	'
	Impairments
	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, such as a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. 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 gas properties. Impairment expense for the years ended December 31, 2013, 2012, and 2011 was approximately $54.4 million, $10.5 million, and $18.4 million, respectively.
Asset Retirement Obligations	'
	Asset Retirement Obligations
	An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized as a component of exploration costs to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.
Revenue Recognition	'
	Revenue Recognition
	Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2013 or 2012.
	The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:
			Years Ending December 31,
			2013			2012			2011
	Major customers:
	Phillips 66 (1)			15	%		13	%		n/a
	ConocoPhillips (1)			n/a			14	%		27	%
	-1	Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips.
General and Administrative Expense	'
	General and Administrative Expense
	We and our general partner have entered into an omnibus agreement with Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. During the year ended December 31, 2013, Memorial Resource allocated indirect general and administrative costs based on production. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf. See Note 12 for additional information regarding the omnibus agreement.
	General and administrative expenses associated with our predecessor and the previous owners included the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production.
Derivative Instruments	'
	Derivative Instruments
	Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.
Income Tax	'
	Income Tax
	We are organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income. Certain of our consolidated subsidiaries are taxed as corporations and subject to federal income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin. Deferred taxes arise due to temporary differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. We had a net deferred tax liability of $2.0 million at both December 31, 2013 and 2012.
	We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized. There were no uncertain tax positions that required recognition in the financial statements at December 31, 2013 or 2012.
Earnings Per Unit	'
	Earnings Per Unit
	Basic and diluted earnings per unit (“EPU”) is determined by dividing net income or loss available to the limited partners by the weighted average number of outstanding limited partner units during the period. Net income or loss available to the limited partners is determined by applying the two-class method. The two-class method of computing EPU is an earnings allocation formula that determines EPU based on distributions declared. The amount of net income or loss used in the determination of EPU is reduced (or increased) by the amount of available cash that has been or will be distributed to the limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the limited partners in accordance with the contractual terms of the partnership agreement. The total earnings allocated to the limited partners is determined by adding together the amount allocated for distributions declared and the amount allocated for the undistributed earnings or excess distributions over earnings. Basic and diluted EPU are equivalent, as all restricted common units and subordinated units participate in distributions. See Note 10 for additional information.
Equity Compensation	'
	Equity Compensation
	The fair value of equity-classified awards (e.g., restricted common unit awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. We currently have no awards subject to performance criteria; however, such awards vest when it is probable that the performance criteria will be met and the requisite service period has been met. Generally, no compensation expense is recognized for equity instruments that do not vest. See Note 11 for further information.
Incentive Units	'
	Incentive Units
	The governing documents of certain entities within the Cinco Group provided for the issuance of incentive units. The incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. Tanos recognized compensation expense related to the forfeiture of incentive units during April 2013 as further discussed in Note 12.
Current Liabilities	'
	Current Liabilities
	Current accrued liabilities consisted of the following at the dates indicated (in thousands):
			December 31,
			2013			2012
	Accrued capital expenditures		$	16,193		$	4,741
	Accrued lease operating expense			10,666			5,412
	Accrued general and administrative expenses			1,547			1,385
	Accrued ad valorem taxes			1,531			1,152
	Accrued interest payable			8,931			748
	Accrued severance and production taxes			105			883
	Other miscellaneous			874			1,778
			$	39,847		$	16,099
New Accounting Pronouncements	'
	New Accounting Pronouncements
	Offsetting Disclosure Requirements. In December 2011, the FASB issued an accounting standard update intended to enhance current disclosure requirements on offsetting financial assets and liabilities. In January 2013, the FASB issued an accounting standard update to clarify the scope of offsetting disclosure requirements. The new disclosure requirements required the disclosure of both gross and net information about derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions eligible for offset on the balance sheet or subject to a master netting arrangement or similar agreement. Disclosure of collateral received and posted in connection with master netting agreements or similar arrangements is also required. The disclosures became effective for annual and interim periods beginning on or after January 1, 2013 and were applied retrospectively. The adoption of this new guidance did not have a significant impact on our financial statements.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Major Customers	'
	The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:
			Years Ending December 31,
			2013			2012			2011
	Major customers:
	Phillips 66 (1)			15	%		13	%		n/a
	ConocoPhillips (1)			n/a			14	%		27	%
	-1	Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips.
Summary of Current Accrued Liabilities	'
	Current accrued liabilities consisted of the following at the dates indicated (in thousands):
			December 31,
			2013			2012
	Accrued capital expenditures		$	16,193		$	4,741
	Accrued lease operating expense			10,666			5,412
	Accrued general and administrative expenses			1,547			1,385
	Accrued ad valorem taxes			1,531			1,152
	Accrued interest payable			8,931			748
	Accrued severance and production taxes			105			883
	Other miscellaneous			874			1,778
			$	39,847		$	16,099

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2013
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 Year Ended December 31,
	2013	2012
	$6,729	$4,135
Summary of Fair Value of Assets Acquired and Liabilities Assumed	'
	The following table summarizes the fair value of the third party assets acquired and liabilities assumed as of each acquisition date (in thousands):
		East Texas			Rockies
		Acquisition			Acquisition
	Oil and gas properties	$	9,974		$	20,744
	Asset retirement obligations		(78	)		(1,163	)
	Accrued liabilities		—			(118	)
	Total identifiable net assets	$	9,896		$	19,463
		Undisclosed			Goodrich			Menemsha			Other
		Seller			Acquisition			Acquisition			Acquisitions
		Acquisition
	Oil and gas properties	$	36,865		$	91,187		$	75,114		$	80,591
	Prepaid expenses and other current assets		—			425			—			—
	Revenues payable		—			(875	)		—			—
	Asset retirement obligations		(321	)		(161	)		(408	)		(4,558	)
	Accrued liabilities		(83	)		(153	)		—			—
	Total identifiable net assets	$	36,461		$	90,423		$	74,706		$	76,033
	Oil and gas properties		307,185
	Other property and equipment		1,046
	Suspense liabilities assumed		(1,659	)
	Environmental liabilities assumed		(968	)
	Asset retirement obligations		(3,653	)
	Total identifiable net assets		301,951
	Oil and gas properties	$	90,351
	Other liabilities		(420	)
	Asset retirement obligations		(4,178	)
	Total identifiable net assets	$	85,753
Supplemental Pro Forma Information	'
		For the Year
		Ended December 31,
		2012			2011
		(In thousands, except
		per unit amounts)
	Revenues	$	286,004		$	286,351
	Net income		58,472			174,138
	Basic and diluted earnings per unit		0.53			0.34

Fair_Value_Measurements_of_Fin1

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Assets and Liabilities Measured at Fair Value on Recurring Basis	'
	The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2013 and December 31, 2012 for each of the fair value hierarchy levels:
		Fair Value Measurements at December 31, 2013 Using
		Quoted Prices in		Significant  Other		Significant		Fair Value
		Active Market		Observable Inputs		Unobservable Inputs
		(Level 1)		(Level 2)		(Level 3)
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	95,926	$	—	$	95,926
	Interest rate derivatives		—		872		—		872
	Total assets	$	—	$	96,798	$	—	$	96,798
	Liabilities :
	Commodity derivatives	$	—	$	55,576	$	—	$	55,576
	Interest rate derivatives		—		4,836		—		4,836
	Total liabilities	$	—	$	60,412	$	—	$	60,412
		Fair Value Measurements at December 31, 2012 Using
		Quoted Prices in		Significant Other		Significant		Fair Value
		Active Market		Observable Inputs		Unobservable Inputs
		(Level 1)		(Level 2)		(Level 3)
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	78,645	$	—	$	78,645
	Liabilities :
	Commodity derivatives	$	—	$	44,697	$	—	$	44,697
	Interest rate derivatives		—		5,472		—		5,472
	Total liabilities	$	—	$	50,169	$	—	$	50,169

Risk_Management_and_Derivative1

Risk Management and Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments And Hedging Activities Disclosure [Abstract]	'
Open Commodity Positions	'
	At December 31, 2013, the Partnership had the following open commodity positions:
			2014				2015				2016				2017				2018		2019
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)			2,575,458				2,145,278				2,342,442				2,230,067				2,060,000		1,814,583
	Weighted-average fixed price		$	4.34			$	4.3			$	4.42			$	4.31			$	4.52	$	4.77
	Collar contracts:
	Average Monthly Volume (MMBtu)			340,000				350,000				—				—				—		—
	Weighted-average floor price		$	4.93			$	4.62			$	—			$	—			$	—	$	—
	Weighted-average ceiling price		$	6.12			$	5.8			$	—			$	—			$	—	$	—
	Call spreads (1):
	Average Monthly Volume (MMBtu)			120,000				80,000				—				—				—		—
	Weighted-average sold strike price		$	5.08			$	5.25			$	—			$	—			$	—	$	—
	Weighted-average bought strike price		$	6.31			$	6.75			$	—			$	—			$	—	$	—
	Basis swaps:
	Average Monthly Volume (MMBtu)			2,822,083				—				—				—				—		—
	Spread		$	(0.09	)		$	—			$	—			$	—			$	—	$	—
	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)			136,444				148,281				142,313				130,600				122,000		40,000
	Weighted-average fixed price		$	95.82			$	93.07			$	86.85			$	85.96			$	85.62	$	85
	Collar contracts:
	Average Monthly Volume (Bbls)			23,000				5,000				—				—				—		—
	Weighted-average floor price		$	82.83			$	80			$	—			$	—			$	—	$	—
	Weighted-average ceiling price		$	105.31			$	94			$	—			$	—			$	—	$	—
	Basis swaps
	Average Monthly Volume (Bbls)			57,292				57,500				—				—				—		—
	Spread		$	(9.21	)		$	(9.73	)		$	—			$	—			$	—	$	—
	NGL Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)			118,500				112,800				—				—				—		—
	Weighted-average fixed price		$	36.23			$	35.04			$	—			$	—			$	—	$	—
	-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.
Interest Rate Swap Open Positions	'
	At December 31, 2013, we had the following interest rate swap open positions:
			2014				2015				2016
	Average Monthly Notional (in thousands)		$	173,958			$	280,833			$	150,000
	Weighted-average fixed rate			1.306	%			1.416	%			1.193	%
	Floating rate			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 December 31, 2013 and 2012. There was no cash collateral received or pledged associated with our derivative instruments since each of the counterparties to our derivative contracts is a lender under our credit agreement.
					Asset Derivatives								Liability Derivatives
	Type		Balance Sheet Location		2013				2012				2013				2012
					(In thousands)
	Commodity contracts		Short-term derivative instruments		$	18,578			$	35,044			$	17,120			$	7,451
	Interest rate swaps		Short-term derivative instruments			845				—				2,699				2,746
	Gross fair value					19,423				35,044				19,819				10,197
	Netting arrangements		Short-term derivative instruments			(11,823	)			(6,980	)			(11,823	)			(6,980	)
	Net recorded fair value		Short-term derivative instruments		$	7,600			$	28,064			$	7,996			$	3,217
	Commodity contracts		Long-term derivative instruments		$	77,348			$	43,601			$	38,456			$	37,246
	Interest rate swaps		Long-term derivative instruments			27				—				2,137				2,726
	Gross fair value					77,375				43,601				40,593				39,972
	Netting arrangements		Long-term derivative instruments			(34,718	)			(29,506	)			(34,718	)			(29,506	)
	Net recorded fair value		Long-term derivative instruments		$	42,657			$	14,095			$	5,875			$	10,466
Unrealized and Realized Gains and Losses Related to Derivative Instruments	'
	The following table details the gains and losses related to derivative instruments for the years ending December 31, 2013, 2012, and 2011:
			Statements of		Years Ended December 31,
	Derivative Instruments		Operations Location		2013				2012				2011
					(In thousands)
	Commodity derivative contracts		(Gain) loss on commodity derivatives		$	(26,281	)		$	(21,417	)		$	(58,407	)
	Interest rate swaps		Interest expense, net			(548	)			(4,839	)			(3,254	)

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
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 years ended December 31, 2013, 2012, and 2011:
		2013			2012			2011
		(In thousands)
	Asset retirement obligations at beginning of year	$	91,349		$	82,722		$	70,891
	Liabilities added from acquisitions or drilling		2,116			5,958			9,700
	Liabilities removed upon sale of wells		—			(1,795	)		(64	)
	Liabilities settled		(20	)		(91	)		(229	)
	Accretion expense		4,853			4,377			4,032
	Revision of estimates		1,321			178			(774	)
	Liabilities retained by our predecessor		—			—			(834	)
	Asset retirement obligations at end of year	$	99,619		$	91,349		$	82,722

Restricted_Investments_Tables

Restricted Investments (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Restricted Investment Balance	'
	The components of the restricted investment balance are as follows at December 31:
		2013		2012
		(In thousands)
	BOEM platform abandonment (See Note 13)	$	66,373	$	61,389
	BOEM lease bonds		794		776
	SPBPC Collateral:
	Contractual pipeline and surface facilities abandonment (See Note 13)		2,306		1,959
	California State Lands Commission pipeline right-of-way bond		3,005		3,000
	City of Long Beach pipeline facility permit		500		500
	Federal pipeline right-of-way bond		307		300
	Port of Long Beach pipeline license		100		100
	Restricted investments	$	73,385	$	68,024

Long_Term_Debt_Tables

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Consolidated and Combined Debt Obligations	'
	Our consolidated and combined debt obligations consisted of the following at the dates indicated:
			December 31,			December 31,
			2013			2012
			(In thousands)
	OLLC $2.0 billion multi-year revolving credit facility, variable-rate, due March 2018		$	103,000		$	371,000
	7.625% senior notes, fixed-rate, due May 1, 2021 (1)			700,000			—
	Previous owners variable-rate revolving credit facilities			—			259,182
	Unamortized discounts			(10,933	)		—
	Total long-term debt		$	792,067		$	630,182
	-1	The estimated fair value of our fixed-rate debt was $721.0 million. 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	'
	The borrowing base for our revolving credit facility was the following at the date indicated:
			December 31,
			2013
			(In thousands)
	OLLC $2.0 billion multi-year revolving credit facility, variable-rate, due March 2018		$	845,000
Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations	'
	The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented:
			For the Year Ended December 31,
			2013			2012			2011
	OLLC revolving credit facility			3.25	%		2.74	%		2.81	%
	WHT revolving credit facility			2.29	%		2.6	%		2.79	%
	REO revolving credit facility			n/a			3.4	%		3.03	%
	Stanolind revolving credit facility			3.52	%		3.76	%		3.88	%
	Boaz revolving credit facility			2.97	%		3.12	%		3.47	%
	Crown revolving credit facility			3.38	%		4.2	%		5.55	%
	Tanos revolving credit facility			3.1	%		2.31	%		2.55	%
	Propel Energy revolving credit facility			3.08	%		3.28	%		3.23	%
	BlueStone revolving credit facility			n/a			n/a			3.17	%
	Classic revolving credit facility			n/a			n/a			3.4	%
Summary of Unamortized Deferred Financing Costs Associated with Consolidated and Combined Debt Obligations	'
	Unamortized deferred financing costs associated with our consolidated and combined debt obligations were as follows at the dates indicated:
			December 31,			December 31,
			2013			2012
			(In thousands)
	OLLC revolving credit facility (1)			5,413		$	3,359
	Senior Notes (2)			15,053			—
	Previous owner revolving credit facilities			—			2,900
			$	20,466		$	6,259
	(1)    Additional financing costs were incurred in connection with the borrowing base increases during the year ended December 31, 2013. The borrowing base was also automatically reduced upon issuance of the Senior Notes in April, May and October. As a result, approximately $1.4 million of deferred financing costs were written-off during the year ended December 31, 2013 and are included in interest expense in the accompanying statements of operations. 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 approximates the effective interest method.
Advances and Repayments	'
	The following table presents borrowings and repayments under our consolidated and combined revolving credit facilities for the periods presented (in thousands):
			OLLC Revolving			Previous  Owner			Predecessor			Total
			Credit Facility			Revolving			Revolving
						Credit Facilities			Credit Facilities
	For the Year Ended December 31, 2013:
	Advances on revolving credit facility		$	941,000		$	17,355		$	—		$	958,355
	Payments on revolving credit facility			(1,209,000	)		(276,537	)		—			(1,485,537	)
	For the Year Ended December 31, 2012:
	Advances on revolving credit facility		$	293,000		$	98,000		$	—		$	391,000
	Payments on revolving credit facility			(42,000	)		(79,819	)		—			(121,819	)
	For the Year Ended December 31, 2011:
	Advances on revolving credit facility		$	130,000		$	196,400		$	85,918		$	412,318
	Payments on revolving credit facility			(10,000	)		(33,053	)		(201,346	)		(244,399	)

Equity_and_Distributions_Table

Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 2013
Summary of Changes in Number of Outstanding Units	'
	The following table summarizes changes in the number of outstanding units since December 31, 2011:
			Common				Subordinated				General
											Partner
	Balance December 31, 2011			16,661,294				5,360,912				22,044
	Common units issued			11,975,000				—				—
	Restricted common units issued			287,943				—				—
	Restricted common units forfeited			(2,334	)			—				—
	General partner units issued			—				—				12,273
	Balance December 31, 2012			28,921,903				5,360,912				34,317
	Common units issued			26,450,000				—				—
	Restricted common units issued			524,717				—				—
	Restricted common units forfeited			(11,734	)			—				—
	Restricted common units repurchased (1)			(7,055	)
	General partner units issued			—				—				26,983
	Balance December 31, 2013			55,877,831				5,360,912				61,300
	(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 $0.1 million. 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 Incentive Distributions	'
	The holders of the IDRs are entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:
			Total Quarterly  Distributions		Marginal Percentage Interest in Distributions
			Target Amount		Unitholders				General				IDR (1)
									Partner
	Minimum Quarterly Distribution		$0.48			99.9	%			0.1	%			—
	First Target Distribution		above $0.4750 up to $0.54625			99.9	%			0.1	%			—
	Second Target Distribution		above $0.54625 up to $0.59375			85	%			0.1	%			14.9	%
	Thereafter		above $0.59375			75	%			0.1	%			24.9	%
	-1	Our general partner owns 50%, and the Funds own 50%, of the IDRs.
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):
	Quarter		Declaration Date				Record Date				Payable Date				Amount			Aggregate			Distribution
															Per Unit  (1)			Distribution  (2)			Received by
																					Memorial
																					Resource
	4th Quarter 2013			January 27, 2014				6-Feb-14				13-Feb-14			$	0.55		$	33.8		$	3
	3rd Quarter 2013			October 22, 2013				November 1, 2013				November 12, 2013			$	0.55		$	33.8		$	6.9
	2nd Quarter 2013			18-Jul-13				1-Aug-13				12-Aug-13			$	0.5125		$	22.9		$	6.4
	1st Quarter 2013			18-Apr-13				1-May-13				13-May-13			$	0.5125		$	22.6		$	6.4
	4th Quarter 2012			15-Jan-13				1-Feb-13				13-Feb-13			$	0.5075		$	17.4		$	6.3
	3rd Quarter 2012			19-Oct-12				1-Nov-12				12-Nov-12			$	0.495		$	11.1		$	6.2
	2nd Quarter 2012			19-Jul-12				1-Aug-12				13-Aug-12			$	0.48		$	10.7		$	6
	1st Quarter 2012			19-Apr-12				1-May-12				14-May-12			$	0.48		$	10.7		$	6
	4th Quarter 2011			26-Jan-12				6-Feb-12				13-Feb-12			$	0.0929		$	2		$	1.2
	-1	The $0.0929 per unit pro-rated distribution paid on February 13, 2012 was based upon the minimum quarterly distribution of $0.4750 per unit adjusted to take into account the 18-day period of the fourth quarter of 2011 during which the Partnership was a public entity.
	-2	The aggregate distribution for the third quarter of 2013 reflects the October 2013 public equity offering.
Predecessor [Member]	'
Summary of Predecessor's Equity Transactions	'
	The following table summarizes our predecessor’s equity transactions with respect to the period indicated (dollars in thousands):
			BlueStone				Classic				WHT				Total
							Carve-Out				Assets				Predecessor
	Balance December 31, 2010		$	65,776			$	40,025			$	—			$	105,801
	Net income (loss)			72,728				(7,567	)			10,579				75,740
	Contributions (distributions)			—				(2,876	)			51,761				48,885
	Net assets retained by predecessor			(13,150	)			(1,062	)			(3,173	)			(17,385	)
	Exchange of predecessor interests for units			(125,354	)			(28,520	)			(59,167	)			(213,041	)
	Balance December 31, 2011		$	—			$	—			$	—			$	—
Previous Owners [Member]	'
Summary of Predecessor's Equity Transactions	'
	The following table summarizes our previous owners’ equity transactions with respect to the period indicated (dollars in thousands):
			Tanos/Classic				REO				WHT				Cinco			Total
			Properties								Properties				Group			Previous
																		Owners
	Balance December 31, 2010			43,313				100,925				—				125,590			269,828
	Net income (loss)			3,621				31,816				18,703				12,464			66,604
	Contributions			3,919				5,010				77,641				74,933			161,503
	Net assets retained by predecessor			—				—				3,180				—			3,180
	Distributions			—				(64,996	)			—				(1,581	)		(66,577	)
	Other			—				—				—				38			38
	Balance December 31, 2011			50,853				72,755				99,524				211,444			434,576
	Net income (loss)			1,000				28,691				8,369				8,233			46,293
	Contributions			—				—				—				64,597			64,597
	Contribution of oil and gas properties			—				—				—				6,893			6,893
	Net book value of net assets acquired by Partnership			(50,639	)			(93,696	)			—				—			(144,335	)
	Contribution related to sale of assets to NGP affiliate			—				—				—				40,138			40,138
	Net book value of net assets acquired by NGP affiliate			—				—				—				(33,859	)		(33,859	)
	Distributions			(1,214	)			(7,750	)			—				(20,553	)		(29,517	)
	Other			—				—				—				(92	)		(92	)
	Balance December 31, 2012			—				—				107,893				276,801			384,694
	Net income (loss)			—				—				(1,219	)			12,494			11,275
	Contributions			—				—				—				7,233			7,233
	Distribution attributable to net assets acquired			—				—				—				55,281			55,281
	Net book value of net assets acquired by Partnership			—				—				(106,674	)			(297,627	)		(404,301	)
	Distributions			—				—				—				(31,098	)		(31,098	)
	Other			—				—				—				(2,302	)		(2,302	)
	Net assets retained by predecessor			—				—				—				(20,782	)		(20,782	)
	Balance December 31, 2013		$	—			$	—			$	—			$	—		$	—

Earnings_per_Unit_Tables

Earnings per Unit (Tables)	12 Months Ended
	Dec. 31, 2013
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 Year Ended December 31,
		2013		2012		2011
	Net income attributable to Memorial Production Partners LP	$	20,001	$	46,414	$	148,936
	Less: Previous owners interest in net income (loss)		11,275		46,293		66,604
	Less: Predecessor interest in net income (loss)		—		—		75,740
	Less: General partners’ 0.1% interest in net income (loss)		9		—		7
	Less: IDRs attributable to corresponding period		81		—		—
	Net income (loss) available to limited partners	$	8,636	$	121	$	6,585
	Weighted average limited partner units outstanding:
	Common units		40,656		17,519		16,395
	Subordinated units		5,361		5,361		5,361
	Total		46,017		22,880		21,756
	Basic and diluted EPU	$	0.19	$	0.01	$	0.3
Supplemental EPU [Member]	'
Calculation of Earnings (Loss) Per Unit	'
	The following sets forth the calculation of our supplemental EPU, for the periods indicated (in thousands, except per unit amounts):
		For the Year Ended December 31,
		2013		2012		2011
	Net income attributable to Memorial Production Partners LP	$	20,001	$	46,414	$	148,936
	Less: General partners’ 0.1% interest in net income (loss)		20		46		149
	Less: IDRs attributable to corresponding period		81		—		—
	Net income (loss) available to limited partners	$	19,900	$	46,368	$	148,787
	Weighted average limited partner units outstanding:
	Common units		40,656		17,519		16,395
	Subordinated units		5,361		5,361		5,361
	Total		46,017		22,880		21,756
	Supplemental basic and diluted EPU	$	0.43	$	2.03	$	6.83

Equitybased_Awards_Tables

Equity-based Awards (Tables)	12 Months Ended
	Dec. 31, 2013
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 for the periods presented:
			Number				Weighted-
			of Units				Average  Grant
							Date Fair Value
							per Unit (1)
	Restricted common units outstanding at December 31, 2011			—			$	—
	Granted (2)			287,943			$	18.07
	Forfeited			(2,334	)		$	17.14
	Restricted common units outstanding at December 31, 2012			285,609			$	18.08
	Granted (3)			524,718			$	18.83
	Forfeited			(11,734	)		$	17.24
	Vested			(91,666	)		$	18.31
	Restricted common units outstanding at December 31, 2013			706,927			$	18.62
	-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 2012 was $5.2 million based on grant date market prices ranging from of $17.14 to $18.58 per unit.
	-3	The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 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 Year
	Ended December 31,
	2013				2012
		$3,558			$	1,423

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2013
Schedule of Acquisition of Net Assets	'
	Oil and natural gas properties, net		$	399,967
	Short-term derivative instruments, net			15,779
	Long-term derivative instruments, net			10,772
	Asset retirement obligations			(13,560	)
	Credit facilities—predecessor (2)			(198,267	)
	Accrued liabilities			(1,650	)
	Net assets (1)		$	213,041
	-1	Due to the timing of our IPO and the fact that we did not acquire working capital from our predecessor, our consolidated balance sheet as of December 31, 2011 did not include any trade receivables or payables.
	-2	Although the Partnership did not legally assume the debt of its predecessor, for accounting and financial reporting purposes the $198.3 million that was repaid concurrent with the closing of our IPO on behalf of our predecessor has been included as a component of the net assets that were acquired by us and reflected on our consolidated and combined cash flow statement as “Payments on revolving credit facilities.”
	Oil and natural gas properties, net		$	15,164
	Short-term derivative instruments, net			715
	Long-term derivative instruments, net			674
	Asset retirement obligations			(466	)
	Accrued liabilities			(17	)
	Net assets		$	16,070
	Oil and natural gas properties, net		$	31,716
	Accounts receivable			612
	Short-term derivative instruments, net			1,017
	Long-term derivative instruments, net			1,337
	Asset retirement obligations			(43	)
	Accrued liabilities			(70	)
	Net assets		$	34,569
Schedule of Net Assets Recorded by the Partnership	'
	Cash and cash equivalents		$	6,021
	Accounts receivable			16,284
	Short-term derivative instruments, net			2,926
	Prepaid expenses and other current assets			4,521
	Oil and natural gas properties, net			108,342
	Restricted investments			68,009
	Accounts payable			(9,092	)
	Accrued liabilities			(9,140	)
	Asset retirement obligations			(58,746	)
	Credit facilities			(28,500	)
	Deferred tax liability			(1,674	)
	Noncontrolling interest			(5,255	)
	Net assets		$	93,696
	Cash and cash equivalents		$	1,354
	Accounts receivable			3,866
	Short-term derivative instruments, net			1,206
	Prepaid expenses and other current assets			98
	Oil and natural gas properties, net			192,280
	Long-term derivative instruments, net			3,528
	Accrued liabilities			(3,494	)
	Asset retirement obligations			(2,753	)
	Credit facilities			(89,300	)
	Other long-term liabilities			(111	)
	Net assets		$	106,674
	Cash and cash equivalents		$	3,265
	Accounts receivable			10,615
	Prepaid expenses and other current assets			1,824
	Oil and natural gas properties, net			457,439
	Long-term derivative instruments, net			3,056
	Other long-term assets			356
	Accounts payable			(4,063	)
	Revenue payable			(4,519	)
	Accrued liabilities			(3,311	)
	Short-term derivative instruments, net			(1,505	)
	Asset retirement obligations			(13,575	)
	Credit facilities			(151,690	)
	Other long-term liabilities			(265	)
	Net assets		$	297,627
Net Book Value of Assets Contributed to Memorial Resource	'
	The net book value of the assets contributed to Memorial Resource was as follows (in thousands):
	Cash and cash equivalents		$	3,751
	Accounts receivable			11,125
	Prepaid expenses and other current assets			3,470
	Property, plant and equipment, net			416
	Accounts payable			(7,898	)
	Accrued liabilities			(7,864	)
	Net assets		$	3,000
REO [Member]	'
Schedule of Amount of General and Administrative Costs and Expenses Recognized	'
	The following table summarizes the amount of management fees REO incurred and paid, which are included in general and administrative expenses in the accompanying statements of operations for the periods presented (in thousands):
	For the Year Ended
	December 31,
	2012				2011
		$1,552			$	1,693
Omnibus Plans [Member]	'
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 Year
	Ended December 31,
	2013				2012
		$9,440			$	1,771

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]	'
Environmental Reserves	'
	The following table presents the activity of our environmental reserves for the periods presented:
		2013			2012			2011
		(In thousands)
	Balance at beginning of period	$	1,051		$	1,747		$	1,450
	Charged to costs and expenses		—			(225	)		—
	Acquisition-related additions		—			—			968
	Payments		(614	)		(471	)		(671	)
	Balance at end of period	$	437		$	1,051		$	1,747
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):
	June 30, 2014	$	68,310
	June 30, 2015	$	72,450
	June 30, 2016	$	76,590
	December 31, 2016	$	78,660
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 December 31, 2013 (in thousands):
	Investment	Amortized			Unrealized			Fair Market
		Cost			Gain (Loss)			Value
	U.S. Bank Money Market Cash Equivalent	$	105,184		$	—		$	105,184
	U.S. Government Treasury Note, maturity of March 31, 2014, and 1.75% coupon		23,073			93			23,166
	Less: Outside working interest owners share		(61,884	)		(45	)		(61,929	)
		$	66,373		$	48		$	66,421
Lease Obligations	'
	Amounts shown in the following table represent minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year:
		Payment or Settlement due by Period
	Lease Obligations	Total			2014			2015			2016		2017		2018		Thereafter
		(In thousands)
	Operating leases	$	3,985		$	549		$	560		$	416	$	205	$	205	$	2,050

Quarterly_Financial_Informatio1

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Financial Data	'
	The following tables present selected quarterly financial data for the periods indicated. Earnings per unit are computed independently for each of the quarters presented and the sum of the quarterly earnings per unit may not necessarily equal the total for the year.
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	For the Year Ended December 31, 2013:	(In thousands, except per unit amounts)
	Revenues	$	68,102		$	90,174		$	93,240		$	92,100
	Operating income (loss)		2,245			60,814			(27,368	)		26,786
	Net income (loss)		(4,297	)		52,695			(39,039	)		10,909
	Net income attributable to Memorial Production Partners LP		(4,293	)		52,597			(39,165	)		10,862
	Net income allocated to previous owners		729			6,418			4,128			—
	Net income (loss) noncontrolling interest		(4	)		98			126			47
	Limited partners’ interest in net income		(5,017	)		46,133			(43,250	)		10,811
	Basic and diluted earnings per unit		(0.14	)		1.04			(0.97	)		0.18
	For the Year Ended December 31, 2012:
	Revenues	$	63,960		$	56,409		$	67,132		$	70,922
	Operating income (loss)		39,923			28,221			(9,220	)		8,509
	Net income (loss)		35,941			22,238			(15,107	)		3,446
	Net income attributable to Memorial Production Partners LP		36,032			22,222			(15,199	)		3,359
	Net income allocated to previous owners		15,138			22,476			10,133			(1,454	)
	Net income (loss) noncontrolling interest		(91	)		16			92			87
	Limited partners’ interest in net income		20,873			(254	)		(25,307	)		4,809
	Basic and diluted earnings per unit		0.94			(0.01	)		(1.13	)		0.19

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities	'
	The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.
			Years Ended December 31,
			2013			2012			2011
			(In thousands)
	Evaluated oil and natural gas properties (1)		$	1,758,953		$	1,545,402		$	1,217,597
	Unevaluated oil and natural gas properties			—			5,004			4,494
	Accumulated depletion, depreciation, and amortization (1)			(417,617	)		(265,710	)		(187,022	)
	Total		$	1,342,336		$	1,284,696		$	1,035,069
	-1	Amounts do not include costs for SPBPC and related support equipment.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities	'
	Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:
			Years Ended December 31,
			2013			2012			2011
			(In thousands)
	Property acquisition costs, proved		$	37,786		$	278,246		$	404,116
	Exploration			—			42,430			40,034
	Development (1)			145,830			62,472			62,411
	Total		$	183,616		$	383,148		$	506,561
	-1	Amounts do not include costs for SPBPC and related support equipment.
Schedule of Product Prices Used for Valuing the Reserves	'
	The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:
			2013			2012			2011
	Oil ($/Bbl):
	West Texas Intermediate spot (1)		$	93.42		$	91.22		$	92.75
	NGL ($/Bbl):
	West Texas Intermediate spot (1)		$	93.42		$	91.27		$	93.19
	Natural Gas ($/MMbtu):
	Henry Hub spot (2)		$	3.67		$	2.757		$	4.118
	-1	The weighted average West Texas Intermediate spot price was adjusted by lease for quality, transportation fees, and a regional price differential.
	-2	The weighted average Henry Hub spot price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
Schedule of Net Reserves	'
	The following tables set forth estimates of the net reserves as of December 31, 2013, 2012 and 2011, respectively:
			Year Ended December 31, 2013
			Oil			Gas			NGLs			Equivalent
			(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of year			39,089			604,440			29,352			1,015,095
	Extensions and discoveries			5,655			40,770			1,747			85,180
	Purchase of minerals in place			119			16,294			258			18,554
	Production			(1,764	)		(35,924	)		(1,632	)		(56,303	)
	Sales of minerals in place			—			—			—			—
	Revision of previous estimates			(3,950	)		(18,441	)		(879	)		(47,421	)
	End of year			39,149			607,139			28,846			1,015,105
	Proved developed reserves:
	Beginning of year			24,515			376,932			15,947			619,704
	End of year			22,265			387,548			15,959			616,893
	Proved undeveloped reserves:
	Beginning of year			14,574			227,508			13,405			395,391
	End of year			16,884			219,591			12,887			398,212
			Year Ended December 31, 2012
			Oil			Gas			NGLs			Equivalent
			(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of year			27,150			579,751			15,045			832,913
	Extensions and discoveries			7,501			19,869			1,053			71,192
	Purchase of minerals in place			11,336			113,617			7,095			224,202
	Production			(1,519	)		(29,744	)		(745	)		(43,329	)
	Sales of minerals in place			(4,214	)		(4,214	)		—			(29,499	)
	Revision of previous estimates			(1,165	)		(74,839	)		6,904			(40,384	)
	End of year			39,089			604,440			29,352			1,015,095
	Proved developed reserves:
	Beginning of year			19,332			413,431			10,015			589,504
	End of year			24,515			376,932			15,947			619,704
	Proved undeveloped reserves:
	Beginning of year			7,818			166,320			5,030			243,409
	End of year			14,574			227,508			13,405			395,391
			Year Ended December 31, 2011
			Oil			Gas			NGLs			Equivalent
			(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of year			16,280			291,074			1,326			396,708
	Extensions and discoveries			1,739			55,454			2,371			80,120
	Purchase of minerals in place			7,518			269,653			10,142			376,580
	Production			(1,112	)		(25,829	)		(375	)		(34,755	)
	Reserves retained by our predecessor			(23	)		(3,198	)		—			(3,335	)
	Sales of minerals in place			(1	)		(132	)		—			(138	)
	Revision of previous estimates			2,749			(7,271	)		1,581			17,733
	End of year			27,150			579,751			15,045			832,913
	Proved developed reserves:
	Beginning of year			12,967			214,916			992			298,671
	End of year			19,332			413,431			10,015			589,504
	Proved undeveloped reserves:
	Beginning of year			3,313			76,158			334			98,037
	End of year			7,818			166,320			5,030			243,409
Standardized Measure of Discounted Future Net Cash Flows	'
	The standardized measure of discounted future net cash flows is as follows:
			Years Ended December 31,
			2013			2012			2011
			(In thousands)
	Future cash inflows		$	6,892,150		$	6,511,776		$	5,747,123
	Future production costs			(2,719,024	)		(2,258,554	)		(1,920,497	)
	Future development costs			(685,858	)		(620,944	)		(432,144	)
	Future income tax expense (1)			—			—			(4,420	)
	Future net cash flows for estimated timing of cash flows			3,487,268			3,632,278			3,390,062
	10% annual discount for estimated timing of cash flows			(1,879,156	)		(2,042,362	)		(1,890,648	)
	Standardized measure of discounted future net cash flows		$	1,608,112		$	1,589,916		$	1,499,414
	-1	We are subject to the Texas franchise tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax for the years ended December 31, 2013 and 2012.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves	'
	The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2013:
			Years Ended December 31,
			2013			2012			2011
			(In thousands)
	Beginning of year		$	1,589,916		$	1,499,414		$	596,696
	Sale of oil and natural gas produced, net of production costs			(234,520	)		(160,023	)		(153,621	)
	Purchase of minerals in place			23,160			375,953			565,760
	Sale of minerals in place			—			(154,963	)		(282	)
	Reserves retained by predecessor			—			—			(1,940	)
	Extensions and discoveries			136,423			265,108			114,482
	Changes in income taxes, net			—			1,947			(1,947	)
	Changes in prices and costs			(74,395	)		(331,760	)		197,939
	Previously estimated development costs incurred			174,490			66,360			4,721
	Net changes in future development costs			(74,867	)		(1,140	)		(17,054	)
	Revisions of previous quantities			(141,122	)		(90,587	)		99,514
	Accretion of discount			158,991			150,136			80,999
	Change in production rates and other			50,036			(30,529	)		14,147
	End of year		$	1,608,112		$	1,589,916		$	1,499,414

Organization_and_Basis_of_Pres2

Organization and Basis of Presentation - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Companies
Organization And Basis Of Presentation Textual [Abstract]	'	'	'
Repayment amount of credit facilities	$1,485,537,000	$121,819,000	$244,399,000
Number of separate portfolio companies	5	'	'
Predecessor [Member]	'	'	'
Organization And Basis Of Presentation Textual [Abstract]	'	'	'
WHT assets acquired	'	'	40.00%
Distributed amount of cash to acquire predecessor's net assets	'	'	73,600,000
Number of common units issued to acquire predecessor's net assets	'	'	7,061,294
Number of subordinated units issued to acquire predecessor's net assets	'	'	5,360,912
Repayment amount of credit facilities	$198,300,000	'	$198,300,000
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]	'	'	'
Partnership ownership percentage	100.00%	'	'
Percentage of economic interest in incentive distribution rights	50.00%	'	'

Summary_of_Significant_Account2

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Significant Accounting Policies [Line Items]	'	'	'
Contractual maturities of cash and cash equivalents	'Three months or less	'	'
Amortization expense including write-off of debt issuance costs	$5,800,000	$2,000,000	$1,500,000
Impairment expense	54,362,000	10,532,000	18,415,000
Percentage of total revenue	10.00%	'	'
Percentage of taxable margin	1.00%	'	'
Deferred tax liability, net	2	2	'
Chance of tax effect being realized	'More than a 50%	'	'
Uncertain tax positions that required recognition	$0	$0	'
Minimum [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'3 years	'	'
Maximum [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'5 years	'	'

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Major Customers (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Significant Accounting Policies [Line Items]	'	'	'
Total Reported Revenues	10.00%	'	'
Revenues [Member] | Phillips 66 [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Total Reported Revenues	15.00%	13.00%	'
Revenues [Member] | ConocoPhillips [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Total Reported Revenues	'	14.00%	27.00%

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Summary of Current Accrued Liabilities (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accrued Liabilities Current [Abstract]	'	'
Accrued capital expenditures	$16,193	$4,741
Accrued lease operating expense	10,666	5,412
Accrued general and administrative expenses	1,547	1,385
Accrued ad valorem taxes	1,531	1,152
Accrued interest payable	8,931	748
Accrued severance and production taxes	105	883
Other miscellaneous	874	1,778
Accrued liabilities, Total	$39,847	$16,099

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures - Acquisition-Related Costs (Detail) (General and Administrative Expenses [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
General and Administrative Expenses [Member]	'	'
Acquisitions And Divestitures Textual [Abstract]	'	'
Acquisition-related costs	$6,729	$4,135

Acquisitions_and_Divestitures_2

Acquisitions and Divestitures - Acquisitions - Additional Information (Detail) (USD $)

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

1-May-12

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Sep. 28, 2012

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2012

Jul. 31, 2012

Dec. 31, 2012

General and Administrative Expense or Other Expense [Member]

East Texas And Rockies [Member]

Undisclosed Seller Acquisition [Member]

Undisclosed Seller Acquisition [Member]

Undisclosed Seller Acquisition [Member]

2012 Acquisition [Member]

Goodrich Acquisition [Member]

Goodrich Acquisition [Member]

Goodrich Acquisition [Member]

Texas And New Mexico [Member]

Menemsha Acquisition [Member]

Menemsha Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Acquisition-related costs

'

$2,100,000

'

'

'

'

'

'

'

'

'

'

'

Purchase price

'

'

29,400,000

36,500,000

'

'

'

90,400,000

'

'

150,700,000

74,700,000

'

Oil and gas properties

9,300,000

'

'

'

'

'

'

'

'

'

'

'

'

Revenue recorded in statement of operations

'

'

'

'

'

4,800,000

'

'

'

4,600,000

'

'

4,900,000

Earnings recorded in statement of operations

'

'

'

'

'

$1,200,000

'

'

'

$2,000,000

'

'

$900,000

Date of acquisition

'

'

'

'

1-May-12

'

1-Jan-12

'

1-Jul-12

'

'

'

'

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures - Summary of Fair Value of Assets Acquired and Liabilities Assumed (Detail) (USD $)	Jul. 01, 2011	Apr. 08, 2011	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013
In Thousands, unless otherwise specified			Undisclosed Seller Acquisition [Member]	Goodrich Acquisition [Member]	Menemsha Acquisition [Member]	Other Acquisition [Member]	East Texas Properties [Member]	Rockies [Member]
Business Acquisition And Divestiture [Line Items]	'	'	'	'	'	'	'	'
Oil and gas properties	$90,351	$307,185	$36,865	$91,187	$75,114	$80,591	$9,974	$20,744
Asset retirement obligations	-4,178	-3,653	-321	-161	-408	-4,558	-78	-1,163
Accrued liabilities	'	'	-83	-153	'	'	'	-118
Total identifiable net assets	85,753	301,951	36,461	90,423	74,706	76,033	9,896	19,463
Prepaid expenses and other current assets	'	'	'	425	'	'	'	'
Revenues payable	'	'	'	-875	'	'	'	'
Other property and equipment	'	1,046	'	'	'	'	'	'
Suspense liabilities assumed	'	-1,659	'	'	'	'	'	'
Environmental liabilities assumed	'	-968	'	'	'	'	'	'
Other liabilities	($420)	'	'	'	'	'	'	'

Acquisitions_and_Divestitures_4

Acquisitions and Divestitures - Supplemental Pro Forma Information (Detail) (2012 Acquisition [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
2012 Acquisition [Member]	'	'
Business Acquisition [Line Items]	'	'
Revenues	$286,004	$286,351
Net income (loss)	$58,472	$174,138
Basic and diluted earnings per unit	$0.53	$0.34

Acquisitions_and_Divestitures_5

Acquisitions and Divestitures - Predecessor and Previous Owner Acquisitions - Additional Information (Detail) (USD $)

Jul. 01, 2011

Apr. 08, 2011

31-May-11

Dec. 31, 2012

Apr. 08, 2011

Jun. 30, 2011

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2011

Predecessor [Member]

Predecessor [Member]

Cash Consideration [Member]

Other Properties Acquired [Member]

BP America Production Company [Member]

BP America Production Company [Member]

BP America Production Company [Member]

Carthage Properties [Member]

Carthage Properties [Member]

Texas And Louisiana [Member]

acre

Business Acquisition And Divestiture [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Net acres exchanged

'

'

'

10,700

'

'

'

'

'

'

'

'

Cash consideration prior to closing adjustments

'

'

'

$20,000,000

'

'

'

'

'

'

'

'

Purchase price

'

'

12,900,000

'

'

2,250,000

'

'

'

'

'

85,800,000

Date of acquisition

'

'

'

'

'

'

1-Jan-11

'

'

8-Apr-12

'

'

Oil and gas properties

90,351,000

307,185,000

'

'

'

'

'

'

82,600,000

'

'

'

Fair value allocated to suspense liabilities assumed

4,178,000

3,653,000

'

'

'

'

'

'

1,200,000

'

'

'

Fair value allocated to deferred tax liabilities

'

'

'

'

'

'

'

'

600,000

'

'

'

Fair value allocated to accrued liabilities

'

'

'

'

'

'

'

'

0.5

'

'

'

Net book value of net acres exchanged

'

'

'

5,200,000

'

'

'

'

'

'

'

'

Predecessor recorded gain

'

'

'

62,200,000

'

'

'

'

'

'

'

'

Business combination consideration transferred

'

'

'

'

302,000,000

'

'

'

'

'

'

'

Revenue recorded in statement of operations

'

'

'

'

'

'

'

8,300,000

'

'

46,200,000

'

Earnings recorded in statement of operations

'

'

'

'

'

'

'

$2,300,000

'

'

$32,200,000

'

Acquisitions_and_Divestitures_6

Acquisitions and Divestitures - Divestitures - Additional Information (Detail) (USD $)	0 Months Ended	12 Months Ended			0 Months Ended			1 Months Ended
	Oct. 11, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Oct. 11, 2012	Jul. 11, 2012	Sep. 18, 2013	Jan. 31, 2013	Jan. 31, 2013	Jan. 31, 2013
					Louisiana [Member]	Garza County [Member]	Ector County [Member]	Tanos [Member]	Tanos [Member]	Tanos [Member]
						Cinco Group acquisition [Member]	Cinco Group acquisition [Member]		Non Operated Oil And Gas Properties [Member]	Minimum [Member]
Business Acquisition And Divestiture [Line Items]	'	'	'	'	'	'	'	'	'	'
Assets sold	'	'	'	'	'	'	'	'	'	$1,500,000
Maximum allowable additional proceeds	'	'	'	'	'	'	'	2,000,000	'	'
Aggregate gain of acquisition	'	'	'	'	38,100,000	7,600,000	2,200,000	1,400,000	1,400,000	'
Contingent consideration	'	'	'	'	'	'	'	400,000	'	'
Asset sold	'	'	'	'	'	'	'	'	2,900,000	'
Interest Sold In Oil And Gas Properties	'	4,525,000	34,521,000	3,333,000	40,100,000	26,100,000	4,700,000	'	'	'
Proceeds in excess of book value of properties sold	$6,300,000	'	'	'	'	'	'	'	'	'

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 $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	$96,798	'
Liabilities	60,412	50,169
Interest rate derivatives [Member]	'	'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	872	'
Liabilities	4,836	5,472
Quoted Prices in Active Market (Level 1) [Member]	'	'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	'	'
Liabilities	'	'
Quoted Prices in Active Market (Level 1) [Member] | Interest rate derivatives [Member]	'	'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	'	'
Liabilities	'	'
Significant Other Observable Inputs (Level 2) [Member]	'	'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	96,798	'
Liabilities	60,412	50,169
Significant Other Observable Inputs (Level 2) [Member] | Interest rate derivatives [Member]	'	'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	872	'
Liabilities	4,836	5,472
Significant Unobservable Inputs (Level 3) [Member]	'	'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	'	'
Liabilities	'	'
Significant Unobservable Inputs (Level 3) [Member] | Interest rate derivatives [Member]	'	'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	'	'
Liabilities	'	'
Commodity derivatives [Member]	'	'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	95,926	78,645
Liabilities	55,576	44,697
Commodity derivatives [Member] | Quoted Prices in Active Market (Level 1) [Member]	'	'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	'	'
Liabilities	'	'
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]	'	'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	95,926	78,645
Liabilities	55,576	44,697
Commodity derivatives [Member] | Significant Unobservable Inputs (Level 3) [Member]	'	'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'	'
Assets	'	'
Liabilities	'	'

Fair_Value_Measurements_of_Fin3

Fair Value Measurements of Financial Instruments - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Assets And Liabilities Carrying Value And Fair Value [Line Items]	'	'	'
Impairment charges	$54,362,000	$10,532,000	$18,415,000
Carrying value of properties after impairment charges	1,348,680,000	1,296,546,000	'
Predecessor [Member]	'	'	'
Assets And Liabilities Carrying Value And Fair Value [Line Items]	'	'	'
Impairment charges	'	'	15,100,000
East Texas Properties [Member]	'	'	'
Assets And Liabilities Carrying Value And Fair Value [Line Items]	'	'	'
Impairment charges	50,300,000	'	'
Carrying value of properties after impairment charges	31,500,000	'	'
South Texas [Member]	'	'	'
Assets And Liabilities Carrying Value And Fair Value [Line Items]	'	'	'
Impairment charges	4,100,000	'	'
Carrying value of properties after impairment charges	7,300,000	'	'
Oil And Natural Gas [Member] | Predecessor [Member]	'	'	'
Assets And Liabilities Carrying Value And Fair Value [Line Items]	'	'	'
Impairment charges	'	'	3,300,000
Permian Basin [Member]	'	'	'
Assets And Liabilities Carrying Value And Fair Value [Line Items]	'	'	'
Impairment charges	'	8,000,000	'
Burke Unit [Member] | Predecessor [Member]	'	'	'
Assets And Liabilities Carrying Value And Fair Value [Line Items]	'	'	'
Impairment charges	'	'	12,000,000
Burke Unit [Member] | Abandoned Well [Member] | Predecessor [Member]	'	'	'
Assets And Liabilities Carrying Value And Fair Value [Line Items]	'	'	'
Impairments related to a well abandoned	'	'	3,100,000
Craton Field [Member]	'	'	'
Assets And Liabilities Carrying Value And Fair Value [Line Items]	'	'	'
Impairment charges	'	'	6,900,000
Cayuga Field [Member]	'	'	'
Assets And Liabilities Carrying Value And Fair Value [Line Items]	'	'	'
Impairment charges	'	'	4,000,000
Dimmitt (Delaware Cons) Field [Member] | Predecessor [Member]	'	'	'
Assets And Liabilities Carrying Value And Fair Value [Line Items]	'	'	'
Impairment charges	'	'	$1,700,000

Risk_Management_and_Derivative2

Risk Management and Derivative Instruments - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
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	$25.40
Maximum amount of loss due to credit risk	19.5
Single Counterparty [Member]	'
Concentration Risks, Types, No Concentration Percentage [Abstract]	'
Maximum amount of loss due to credit risk	$12.30

Risk_Management_and_Derivative3

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	12 Months Ended
	Dec. 31, 2013
	MMBTU
2014 [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)	2,575,458
Weighted-average fixed price	4.34
2014 [Member] | Natural Gas Derivative Contracts Collar Contracts [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	340,000
Weighted-average floor price	4.93
Weighted-average ceiling price	6.12
2014 [Member] | Natural Gas Derivative Contracts Call Spreads [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	120,000
Weighted-average sold strike price	5.08
Weighted-average bought strike price	6.31
2014 [Member] | Natural Gas Derivative Contracts Basis Swaps [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	2,822,083
Spread	-0.09
2014 [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)	136,444
Weighted-average fixed price	95.82
2014 [Member] | Crude Oil Derivative Contracts Collar Contracts [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (Bbls)	23,000
Weighted-average floor price	82.83
Weighted-average ceiling price	105.31
2014 [Member] | Crude Oil Derivative Contracts Basis Swaps [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (Bbls)	57,292
Spread	-9.21
2014 [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)	118,500
Weighted-average fixed price	36.23
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)	2,145,278
Weighted-average fixed price	4.3
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
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
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)	'
Spread	'
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)	148,281
Weighted-average fixed price	93.07
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
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)	57,500
Spread	-9.73
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)	112,800
Weighted-average fixed price	35.04
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)	2,342,442
Weighted-average fixed price	4.42
2016 [Member] | Natural Gas Derivative Contracts Collar Contracts [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	'
Weighted-average floor price	'
Weighted-average ceiling price	'
2016 [Member] | Natural Gas Derivative Contracts Call Spreads [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	'
Weighted-average sold strike price	'
Weighted-average bought strike price	'
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)	'
Spread	'
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)	142,313
Weighted-average fixed price	86.85
2016 [Member] | Crude Oil Derivative Contracts Collar Contracts [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (Bbls)	'
Weighted-average floor price	'
Weighted-average ceiling price	'
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)	'
Spread	'
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)	'
Weighted-average fixed price	'
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)	2,230,067
Weighted-average fixed price	4.31
2017 [Member] | Natural Gas Derivative Contracts Collar Contracts [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	'
Weighted-average floor price	'
Weighted-average ceiling price	'
2017 [Member] | Natural Gas Derivative Contracts Call Spreads [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	'
Weighted-average sold strike price	'
Weighted-average bought strike price	'
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)	'
Spread	'
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)	130,600
Weighted-average fixed price	85.96
2017 [Member] | Crude Oil Derivative Contracts Collar Contracts [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (Bbls)	'
Weighted-average floor price	'
Weighted-average ceiling price	'
2017 [Member] | Crude Oil Derivative Contracts Basis Swaps [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (Bbls)	'
Spread	'
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)	'
Weighted-average fixed price	'
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)	2,060,000
Weighted-average fixed price	4.52
2018 [Member] | Natural Gas Derivative Contracts Collar Contracts [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	'
Weighted-average floor price	'
Weighted-average ceiling price	'
2018 [Member] | Natural Gas Derivative Contracts Call Spreads [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	'
Weighted-average sold strike price	'
Weighted-average bought strike price	'
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)	'
Spread	'
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)	122,000
Weighted-average fixed price	85.62
2018 [Member] | Crude Oil Derivative Contracts Collar Contracts [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (Bbls)	'
Weighted-average floor price	'
Weighted-average ceiling price	'
2018 [Member] | Crude Oil Derivative Contracts Basis Swaps [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (Bbls)	'
Spread	'
2018 [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)	'
Weighted-average fixed price	'
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)	1,814,583
Weighted-average fixed price	4.77
2019 [Member] | Natural Gas Derivative Contracts Collar Contracts [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	'
Weighted-average floor price	'
Weighted-average ceiling price	'
2019 [Member] | Natural Gas Derivative Contracts Call Spreads [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	'
Weighted-average sold strike price	'
Weighted-average bought strike price	'
2019 [Member] | Natural Gas Derivative Contracts Basis Swaps [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (MMBtu)	'
Spread	'
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)	40,000
Weighted-average fixed price	85
2019 [Member] | Crude Oil Derivative Contracts Collar Contracts [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (Bbls)	'
Weighted-average floor price	'
Weighted-average ceiling price	'
2019 [Member] | Crude Oil Derivative Contracts Basis Swaps [Member]	'
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]	'
Average Monthly Volume (Bbls)	'
Spread	'
2019 [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)	'
Weighted-average fixed price	'

Risk_Management_and_Derivative4

Risk Management and Derivative Instruments - Interest Rate Swap Open Positions (Detail) (Interest rate swaps [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
2014 [Member]	'
Derivative [Line Items]	'
Average Monthly Notional	$173,958
Weighted-average fixed rate	1.31%
Floating rate	'1 Month LIBOR
2015 [Member]	'
Derivative [Line Items]	'
Average Monthly Notional	280,833
Weighted-average fixed rate	1.42%
Floating rate	'1 Month LIBOR
2016 [Member]	'
Derivative [Line Items]	'
Average Monthly Notional	$150,000
Weighted-average fixed rate	1.19%
Floating rate	'1 Month LIBOR

Risk_Management_and_Derivative5

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Instruments and Hedges, Assets [Abstract]	'	'
Asset Derivatives, Net recorded fair value	$7,600	$28,064
Asset Derivatives, Net recorded fair value	42,657	14,095
Liability Derivatives, Net recorded fair value	7,996	3,217
Liability Derivatives, Net recorded fair value	5,875	10,466
Short-Term Derivative Instruments [Member]	'	'
Derivative Instruments and Hedges, Assets [Abstract]	'	'
Asset Derivatives, Gross fair value	19,423	35,044
Asset Derivatives, Netting arrangements	-11,823	-6,980
Asset Derivatives, Net recorded fair value	7,600	28,064
Liability Derivatives, Gross fair value	19,819	10,197
Liability Derivatives, Netting arrangements	-11,823	-6,980
Liability Derivatives, Net recorded fair value	7,996	3,217
Short-Term Derivative Instruments [Member] | Commodity derivative contracts [Member]	'	'
Derivative Instruments and Hedges, Assets [Abstract]	'	'
Asset Derivatives, Gross fair value	18,578	35,044
Liability Derivatives, Gross fair value	17,120	7,451
Short-Term Derivative Instruments [Member] | Interest rate swaps [Member]	'	'
Derivative Instruments and Hedges, Assets [Abstract]	'	'
Asset Derivatives, Gross fair value	845	'
Liability Derivatives, Gross fair value	2,699	2,746
Long-Term Derivative Instruments [Member]	'	'
Derivative Instruments and Hedges, Assets [Abstract]	'	'
Asset Derivatives, Gross fair value	77,375	43,601
Asset Derivatives, Netting arrangements	-34,718	-29,506
Asset Derivatives, Net recorded fair value	42,657	14,095
Liability Derivatives, Gross fair value	40,593	39,972
Liability Derivatives, Netting arrangements	-34,718	-29,506
Liability Derivatives, Net recorded fair value	5,875	10,466
Long-Term Derivative Instruments [Member] | Commodity derivative contracts [Member]	'	'
Derivative Instruments and Hedges, Assets [Abstract]	'	'
Asset Derivatives, Gross fair value	77,348	43,601
Liability Derivatives, Gross fair value	38,456	37,246
Long-Term Derivative Instruments [Member] | Interest rate swaps [Member]	'	'
Derivative Instruments and Hedges, Assets [Abstract]	'	'
Asset Derivatives, Gross fair value	27	'
Liability Derivatives, Gross fair value	$2,137	$2,726

Risk_Management_and_Derivative6

Risk Management and Derivative Instruments - Unrealized and Realized Gains and Losses Related to Derivative Instruments (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]	'	'	'
(Gain) loss on commodity derivatives	($26,281)	($21,417)	($58,407)
Interest expense, net	41,901	20,436	14,970
Commodity derivative contracts [Member]	'	'	'
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]	'	'	'
(Gain) loss on commodity derivatives	-26,281	-21,417	-58,407
Interest rate swaps [Member]	'	'	'
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]	'	'	'
Interest expense, net	($548)	($4,839)	($3,254)

Asset_Retirement_Obligations_S

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation Roll Forward Analysis [Roll Forward]	'	'	'
Asset retirement obligations at beginning of year	$91,349	$82,722	$70,891
Liabilities added from acquisitions or drilling	2,116	5,958	9,700
Liabilities removed upon sale of wells	'	-1,795	-64
Liabilities settled	-20	-91	-229
Accretion expense	4,853	4,377	4,032
Revision of estimates	1,321	178	-774
Liabilities retained by our predecessor	'	'	-834
Asset retirement obligations at end of year	$99,619	$91,349	$82,722

Restricted_Investments_Restric

Restricted Investments - Restricted Investment Balance (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Restricted Cash and Investments [Abstract]	'	'
Restricted investments	$73,385	$68,024
BOEM platform abandonment [Member]	'	'
Restricted Cash and Investments [Abstract]	'	'
Restricted investments	66,373	61,389
BOEM lease bonds [Member]	'	'
Restricted Cash and Investments [Abstract]	'	'
Restricted investments	794	776
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]	'	'
Restricted Cash and Investments [Abstract]	'	'
Restricted investments	2,306	1,959
SPBPC Collateral California State Lands Commission pipeline right-of-way bond [Member]	'	'
Restricted Cash and Investments [Abstract]	'	'
Restricted investments	3,005	3,000
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	300
SPBPC Collateral Port of Long Beach pipeline license [Member]	'	'
Restricted Cash and Investments [Abstract]	'	'
Restricted investments	$100	$100

Long_Term_Debt_Consolidated_an

Long Term Debt - Consolidated and Combined Debt Obligations (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Debt Obligations [Abstract]	'	'
Unamortized discounts	($10,933)	'
Total long-term debt	792,067	630,182
OLLC $2.0 billion multi-year revolving credit facility [Member]	'	'
Debt Obligations [Abstract]	'	'
Revolving credit facility	103,000	371,000
7.625% senior notes [Member]	'	'
Debt Obligations [Abstract]	'	'
7.625% senior notes, fixed-rate, due May 1, 2021	700,000	'
Previous Owner Variable Rate Revolving Credit Facility [Member]	'	'
Debt Obligations [Abstract]	'	'
Revolving credit facility	'	$259,182

Long_Term_Debt_Consolidated_an1

Long Term Debt - Consolidated and Combined Debt Obligations (Parenthetical) (Detail) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Debt Obligations [Abstract]	'
Estimated fair value of fixed rate debt	$721
OLLC $2.0 billion multi-year revolving credit facility [Member]	'
Debt Obligations [Abstract]	'
Revolving credit facility	$2,000
7.625% senior notes [Member]	'
Debt Obligations [Abstract]	'
Senior notes	7.63%

Long_Term_Debt_Additional_Info

Long Term Debt - Additional Information (Detail) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Oct. 10, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 02, 2013

Sep. 26, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 12, 2012

Dec. 31, 2013

Mar. 28, 2013

Dec. 31, 2013

Apr. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 10, 2013

23-May-13

Apr. 17, 2013

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Mar. 15, 2013

Minimum [Member]

Maximum [Member]

OLLC revolving credit facility [Member]

OLLC revolving credit facility [Member]

7.625% Senior Notes [Member]

REO revolving credit facility [Member]

REO revolving credit facility [Member]

WHT revolving credit facility [Member]

WHT revolving credit facility [Member]

Tanos revolving credit facility [Member]

Tanos revolving credit facility [Member]

Boaz And Crown [Member]

Stanolind And Propel Energy [Member]

Private Placement [Member]

Private Placement [Member]

Private Placement [Member]

Predecessor [Member]

Predecessor [Member]

Universal Shelf Registration Statement [Member]

Universal Shelf Registration Statement [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

7.625% Senior Notes [Member]

7.625% Senior Notes [Member]

7.625% Senior Notes [Member]

Credit Facilities [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Universal shelf registration statement on file with the SEC

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$750,000,000

Universal shelf guarantor subsidiaries ownership percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

Revolving credit facility

'

'

'

'

'

'

2,000,000,000

1,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Borrowing Base

'

'

'

'

'

'

920,000,000

480,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Borrowing base reduced amount

'

'

'

75,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Federal funds effective rate

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

One month adjusted LIBOR

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Variable borrowing, Minimum

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Variable borrowing, Maximum

1.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Variable LIBOR plus margin, Minimum

1.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Variable LIBOR plus margin, Maximum

2.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Variable LIBOR Market index plus margin, Maximum

'

'

'

'

1.50%

2.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Variable commitment fee

'

'

'

'

0.38%

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest coverage ratio on EBITDAX to net interest expenses

2.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest coverage ratio consolidated current assets to consolidated current liabilities

1.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.625% senior unsecured notes maturity period

'

'

'

'

'

'

'

'

1-May-21

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Face amount of 7.625% Senior Notes due 2021 at time of issuance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300,000,000

100,000,000

300,000,000

'

'

'

'

Senior notes issued at a discount or premium to par

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

97.00%

102.00%

98.52%

'

'

'

'

Other events of default minimum note holder percentage to accelerate

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revolving Credit Facility Balance at Termination

'

'

'

'

'

'

'

'

'

'

28,500,000

'

89,300,000

'

27,000,000

'

'

'

'

'

'

'

'

'

Termination date of revolving credit facility

'

'

'

'

'

'

'

'

'

12-Dec-12

'

28-Mar-13

'

1-Apr-13

'

1-Oct-13

1-Oct-13

'

'

'

'

'

'

'

Revolving credit facility repayments

$1,485,537,000

$121,819,000

$244,399,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$198,300,000

$198,300,000

'

'

Long_Term_Debt_Borrowing_Base_

Long Term Debt - Borrowing Base Credit Facility (Detail) (OLLC $2.0 billion multi-year revolving credit facility [Member], USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
OLLC $2.0 billion multi-year revolving credit facility [Member]	'
Line of Credit Facility [Line Items]	'
Borrowing Base	$845,000

Long_Term_Debt_Summary_of_Weig

Long Term Debt - Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
OLLC revolving credit facility [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Revolving credit facility, weighted-average interest rates	3.25%	2.74%	2.81%
WHT revolving credit facility [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Revolving credit facility, weighted-average interest rates	2.29%	2.60%	2.79%
REO revolving credit facility [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Revolving credit facility, weighted-average interest rates	'	3.40%	3.03%
Stanolind revolving credit facility [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Revolving credit facility, weighted-average interest rates	3.52%	3.76%	3.88%
Boaz revolving credit facility [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Revolving credit facility, weighted-average interest rates	2.97%	3.12%	3.47%
Crown revolving credit facility [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Revolving credit facility, weighted-average interest rates	3.38%	4.20%	5.55%
Tanos revolving credit facility [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Revolving credit facility, weighted-average interest rates	3.10%	2.31%	2.55%
Propel Energy revolving credit facility [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Revolving credit facility, weighted-average interest rates	3.08%	3.28%	3.23%
BlueStone revolving credit facility [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Revolving credit facility, weighted-average interest rates	'	'	3.17%
Classic revolving credit facility [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Revolving credit facility, weighted-average interest rates	'	'	3.40%

Long_Term_Debt_Summary_of_Unam

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated and Combined Debt Obligations (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Credit Facilities [Line Items]	'	'
Unamortized deferred financing costs	$20,466	$6,259
Previous Owners Revolving Credit Facilities [Member]	'	'
Credit Facilities [Line Items]	'	'
Unamortized deferred financing costs	'	2,900
Senior Notes [Member]	'	'
Credit Facilities [Line Items]	'	'
Unamortized deferred financing costs	15,053	'
OLLC revolving credit facility [Member]	'	'
Credit Facilities [Line Items]	'	'
Unamortized deferred financing costs	$5,413	$3,359

Long_Term_Debt_Summary_of_Unam1

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated and Combined Debt Obligations (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Deferred finance cost written off	$1.40

Long_Term_Debt_Advances_and_Re

Long Term Debt - Advances and Repayments (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Credit Facilities [Line Items]	'	'	'
Advances on revolving credit facility	$958,355	$391,000	$412,318
Payments on revolving credit facility	-1,485,537	-121,819	-244,399
OLLC revolving credit facility [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Advances on revolving credit facility	941,000	293,000	130,000
Payments on revolving credit facility	-1,209,000	-42,000	-10,000
Previous Owners Revolving Credit Facilities [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Advances on revolving credit facility	17,355	98,000	196,400
Payments on revolving credit facility	-276,537	-79,819	-33,053
Predecessor Revolving Credit Facilities [Member]	'	'	'
Credit Facilities [Line Items]	'	'	'
Advances on revolving credit facility	'	'	85,918
Payments on revolving credit facility	'	'	($201,346)

Equity_and_Distributions_Addit

Equity and Distributions - Additional Information (Detail) (USD $)

0 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

Mar. 25, 2013

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 08, 2013

Dec. 21, 2012

Dec. 12, 2012

Dec. 22, 2011

Dec. 14, 2011

Dec. 22, 2011

Memorial Resource [Member]

Subordinated Units [Member]

Maximum [Member]

The Funds [Member]

General Partner [Member]

General Partner [Member]

General Partner [Member]

Public Equity Offerings 2013 [Member]

Public Equity Offerings 2012 [Member]

Public Equity Offerings 2012 [Member]

IPO [Member]

IPO [Member]

IPO [Member]

Memorial Resource [Member]

IDR [Member]

IDR [Member]

The Funds [Member]

Senior Secured Revolving Credit Facility [Member]

Equity And Distributions Textual [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of common units issued in public offering

9,775,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

16,675,000

'

10,500,000

'

9,000,000

'

Number of over-allotment common units issued by Partnership

1,275,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,175,000

'

'

600,000

'

'

Public offering price per common unit

$18.35

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$19.90

'

$17

'

$19

'

Net cash proceeds from public offering

$171,800,000

'

'

'

'

$490,138,000

$194,134,000

$157,119,000

'

'

'

'

'

'

'

$318,300,000

'

$170,000,000

'

$146,500,000

'

Additional common units granted to underwriters

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,475,000

'

'

'

'

Addition of net proceeds

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

24,100,000

'

'

'

'

Revolving credit facility repayments

'

'

'

'

'

1,485,537,000

121,819,000

244,399,000

'

'

'

'

'

'

'

'

'

'

'

198,300,000

10,000,000

Net cash proceeds from over-allotment option

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$10,700,000

'

'

Partnership ownership percentage

'

'

'

'

'

'

'

'

'

100.00%

'

50.00%

0.10%

50.00%

100.00%

'

'

'

'

'

'

Percentage of economic interest in incentive distribution rights

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

50.00%

'

'

'

'

'

'

Percentage of general partner interest incentive distribution

'

'

'

'

'

0.10%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Additional increasing percentages

'

'

'

'

'

'

'

'

'

'

24.90%

'

'

'

'

'

'

'

'

'

'

Incentive Distribution of common unit per quarter

'

'

'

'

'

0.54625

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum Quarterly Distribution amount per common unit

'

'

'

'

'

0.475

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common unitholders, pro rata percentage

'

'

99.90%

99.90%

99.90%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Distribution Percentage For General Partners

'

'

0.10%

0.10%

0.10%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of subordinated units issued to acquire predecessor's net assets

'

0.59375

'

'

'

0.59375

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of Subordinated units, minimum quarterly distribution

'

125.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annualized Minimum Quarterly Distribution Amount

'

2.375

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annualized Minimum Quarterly Distribution Percentage

'

125.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of General Partner incentive when no subordinated units outstanding

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity_and_Distributions_Summa

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
			Limited Partners Common Units [Member]	Limited Partners Common Units [Member]	Subordinated Units [Member]	Subordinated Units [Member]	Subordinated Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]	'	'	'	'	'	'	'
Beginning balance, General Partner	34,317	22,044	'	'	'	'	'
Beginning balance	'	'	28,921,903	16,661,294	5,360,912	5,360,912	5,360,912
Common units issued	'	'	26,450,000	11,975,000	'	'	'
Restricted common units issued	'	'	524,717	287,943	'	'	'
Restricted common units forfeited	'	'	-11,734	-2,334	'	'	'
General partner units issued	26,983	12,273	'	'	'	'	'
Ending balance	'	'	55,877,831	28,921,903	5,360,912	5,360,912	5,360,912
Ending balance, General Partner	61,300	34,317	'	'	'	'	'
Restricted common units repurchased	'	'	-7,055	'	'	'	'

Equity_and_Distributions_Summa1

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Summary Of Changes In Number Of Outstanding Units [Abstract]	'
Withholding tax withheld and paid related to vesting of restricted common units	$0.10

Equity_and_Distributions_Summa2

Equity and Distributions - Summary of Incentive Distributions (Detail)	12 Months Ended
	Dec. 31, 2013
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Minimum total quarterly distribution, per unit	0.475
IDR [Member]	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Marginal Percentage Interest In Second Target Distributions	14.90%
Marginal Percentage Interest In Distributions Thereafter	24.90%
Unitholders [Member]	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Minimum Marginal Percentage Interest In Quarterly Distributions	99.90%
Marginal Percentage Interest In First Target Distributions	99.90%
Marginal Percentage Interest In Second Target Distributions	85.00%
Marginal Percentage Interest In Distributions Thereafter	75.00%
General Partner [Member]	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Minimum Marginal Percentage Interest In Quarterly Distributions	0.10%
Marginal Percentage Interest In First Target Distributions	0.10%
Marginal Percentage Interest In Second Target Distributions	0.10%
Marginal Percentage Interest In Distributions Thereafter	0.10%
Minimum [Member]	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
First Target Total Quarterly Distribution, per unit	0.475
Second Target Quarterly Distribution Minimum, per unit	0.54625
Total Quarterly Distributions Thereafter, per unit	0.59375
Maximum [Member]	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
First Target Total Quarterly Distribution, per unit	0.54625
Second Target Quarterly Distribution Minimum, per unit	0.59375

Equity_and_Distributions_Summa3

Equity and Distributions - Summary of Incentive Distributions (Parenthetical) (Detail) (IDR [Member])	Dec. 31, 2013
General Partner [Member]	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Percentage of IDRs owned	50.00%
The Funds [Member]	'
Incentive Distribution Made to Managing Member or General Partner [Line Items]	'
Percentage of IDRs owned	50.00%

Equity_and_Distributions_Summa4

Equity and Distributions - Summary of Quarterly Cash Distribution Rates (Detail) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011
Equity [Abstract]	'	'	'	'	'	'	'	'	'
Distribution made to member or limited partner, date of declaration	27-Jan-14	22-Oct-13	18-Jul-13	18-Apr-13	15-Jan-13	19-Oct-12	19-Jul-12	19-Apr-12	26-Jan-12
Distribution made to member or limited partner, date of record	6-Feb-14	1-Nov-13	1-Aug-13	1-May-13	1-Feb-13	1-Nov-12	1-Aug-12	1-May-12	6-Feb-12
Distribution made to member or limited partner, date of distribution	13-Feb-14	12-Nov-13	12-Aug-13	13-May-13	13-Feb-13	12-Nov-12	13-Aug-12	14-May-12	13-Feb-12
Distribution per unit	$0.55	$0.55	$0.51	$0.51	$0.51	$0.50	$0.48	$0.48	$0.09
Aggregate Distribution	$33.80	$33.80	$22.90	$22.60	$17.40	$11.10	$10.70	$10.70	$2
Distribution Received by Memorial Resource	$3	$6.90	$6.40	$6.40	$6.30	$6.20	$6	$6	$1.20

Equity_and_Distributions_Summa5

Equity and Distributions - Summary of Quarterly Cash Distribution Rates (Parenthetical) (Detail) (USD $)	1 Months Ended	3 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011
Cash Distributions to Unitholders [Line Items]	'	'	'	'	'	'	'	'	'	'
Distribution per unit	'	$0.55	$0.55	$0.51	$0.51	$0.51	$0.50	$0.48	$0.48	$0.09
Cash distribution adjustment period	'18 days	'	'	'	'	'	'	'	'	'
Fourth Quarter 2011 Prorated [Member]	'	'	'	'	'	'	'	'	'	'
Cash Distributions to Unitholders [Line Items]	'	'	'	'	'	'	'	'	'	'
Distribution per unit	0.0929	'	'	'	'	'	'	'	'	'
Fourth Quarter 2011 [Member]	'	'	'	'	'	'	'	'	'	'
Cash Distributions to Unitholders [Line Items]	'	'	'	'	'	'	'	'	'	'
Distribution per unit	0.475	'	'	'	'	'	'	'	'	'

Equity_and_Distributions_Summa6

Equity and Distributions - Summary of Predecessor's Equity Transactions (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity Structure And Transactions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Beginning Balance	'	'	'	$711,765	'	'	'	$742,901	$711,765	$742,901	$380,932
Net income (loss)	10,909	-39,039	52,695	-4,297	3,446	-15,107	22,238	35,941	20,268	46,518	148,790
Net assets retained by predecessor	'	'	'	'	'	'	'	'	'	'	-14,205
Ending Balance	579,616	'	'	'	711,765	'	'	'	579,616	711,765	742,901
BlueStone revolving credit facility [Member]	'	'	'	'	'	'	'	'	'	'	'
Equity Structure And Transactions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Beginning Balance	'	'	'	'	'	'	'	'	'	'	65,776
Net income (loss)	'	'	'	'	'	'	'	'	'	'	72,728
Net assets retained by predecessor	'	'	'	'	'	'	'	'	'	'	-13,150
Exchange of predecessor interests for units	'	'	'	'	'	'	'	'	'	'	-125,354
Ending Balance	'	'	'	'	'	'	'	'	'	'	'
Classic Carve Out [Member]	'	'	'	'	'	'	'	'	'	'	'
Equity Structure And Transactions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Beginning Balance	'	'	'	'	'	'	'	'	'	'	40,025
Net income (loss)	'	'	'	'	'	'	'	'	'	'	-7,567
Contributions (distributions)	'	'	'	'	'	'	'	'	'	'	-2,876
Net assets retained by predecessor	'	'	'	'	'	'	'	'	'	'	-1,062
Exchange of predecessor interests for units	'	'	'	'	'	'	'	'	'	'	-28,520
Ending Balance	'	'	'	'	'	'	'	'	'	'	'
WHT Assets [Member]	'	'	'	'	'	'	'	'	'	'	'
Equity Structure And Transactions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Beginning Balance	'	'	'	'	'	'	'	'	'	'	'
Net income (loss)	'	'	'	'	'	'	'	'	'	'	10,579
Contributions (distributions)	'	'	'	'	'	'	'	'	'	'	51,761
Net assets retained by predecessor	'	'	'	'	'	'	'	'	'	'	-3,173
Exchange of predecessor interests for units	'	'	'	'	'	'	'	'	'	'	-59,167
Ending Balance	'	'	'	'	'	'	'	'	'	'	'
Predecessor [Member]	'	'	'	'	'	'	'	'	'	'	'
Equity Structure And Transactions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Beginning Balance	'	'	'	'	'	'	'	'	'	'	105,801
Net income (loss)	'	'	'	'	'	'	'	'	'	'	75,740
Contributions (distributions)	'	'	'	'	'	'	'	'	'	'	48,885
Net assets retained by predecessor	'	'	'	'	'	'	'	'	'	'	-17,385
Exchange of predecessor interests for units	'	'	'	'	'	'	'	'	'	'	-213,041
Ending Balance	'	'	'	'	'	'	'	'	'	'	'

Equity_and_Distributions_Summa7

Equity and Distributions - Summary of Previous Owners' Equity Transactions (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity Structure And Transactions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Beginning Balance	'	'	'	$711,765	'	'	'	$742,901	$711,765	$742,901	$380,932
Net income (loss)	10,909	-39,039	52,695	-4,297	3,446	-15,107	22,238	35,941	20,268	46,518	148,790
Contributions	'	'	'	'	'	'	'	'	7,754	64,803	210,807
Net assets retained by predecessor	'	'	'	'	'	'	'	'	'	'	14,205
Contribution of oil and gas properties	'	'	'	'	'	'	'	'	'	6,893	'
Distribution attributable to net assets acquired	'	'	'	'	'	'	'	'	502,920	287,663	'
Distributions	'	'	'	'	'	'	'	'	-127,741	-64,001	-66,577
Other	'	'	'	'	'	'	'	'	2,424	-32	-38
Ending Balance	579,616	'	'	'	711,765	'	'	'	579,616	711,765	742,901
Tanos Classic Properties [Member]	'	'	'	'	'	'	'	'	'	'	'
Equity Structure And Transactions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Beginning Balance	'	'	'	'	'	'	'	50,853	'	50,853	43,313
Net income (loss)	'	'	'	'	'	'	'	'	'	1,000	3,621
Contributions	'	'	'	'	'	'	'	'	'	'	3,919
Net book value of net assets acquired by Partnership	'	'	'	'	'	'	'	'	'	-50,639	'
Distributions	'	'	'	'	'	'	'	'	'	-1,214	'
Ending Balance	'	'	'	'	'	'	'	'	'	'	50,853
REO revolving credit facility [Member]	'	'	'	'	'	'	'	'	'	'	'
Equity Structure And Transactions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Beginning Balance	'	'	'	'	'	'	'	72,755	'	72,755	100,925
Net income (loss)	'	'	'	'	'	'	'	'	'	28,691	31,816
Contributions	'	'	'	'	'	'	'	'	'	'	5,010
Net book value of net assets acquired by Partnership	'	'	'	'	'	'	'	'	'	-93,696	'
Distributions	'	'	'	'	'	'	'	'	'	-7,750	-64,996
Ending Balance	'	'	'	'	'	'	'	'	'	'	72,755
Wht Properties [Member]	'	'	'	'	'	'	'	'	'	'	'
Equity Structure And Transactions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Beginning Balance	'	'	'	107,893	'	'	'	99,524	107,893	99,524	'
Net income (loss)	'	'	'	'	'	'	'	'	-1,219	8,369	18,703
Contributions	'	'	'	'	'	'	'	'	'	'	77,641
Net assets retained by predecessor	'	'	'	'	'	'	'	'	'	'	3,180
Net book value of net assets acquired by Partnership	'	'	'	'	'	'	'	'	-106,674	'	'
Ending Balance	'	'	'	'	107,893	'	'	'	'	107,893	99,524
Cinco Group [Member]	'	'	'	'	'	'	'	'	'	'	'
Equity Structure And Transactions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Beginning Balance	'	'	'	276,801	'	'	'	211,444	276,801	211,444	125,590
Net income (loss)	'	'	'	'	'	'	'	'	12,494	8,233	12,464
Contributions	'	'	'	'	'	'	'	'	7,233	64,597	74,933
Net assets retained by predecessor	'	'	'	'	'	'	'	'	-20,782	'	'
Contribution of oil and gas properties	'	'	'	'	'	'	'	'	'	6,893	'
Distribution attributable to net assets acquired	'	'	'	'	'	'	'	'	55,281	'	'
Net book value of net assets acquired by Partnership	'	'	'	'	'	'	'	'	-297,627	'	'
Contribution related to sale of assets to NGP affiliate	'	'	'	'	'	'	'	'	'	40,138	'
Net book value of net assets acquired by NGP affiliate	'	'	'	'	'	'	'	'	'	-33,859	'
Distributions	'	'	'	'	'	'	'	'	-31,098	-20,553	-1,581
Other	'	'	'	'	'	'	'	'	-2,302	-92	38
Ending Balance	'	'	'	'	276,801	'	'	'	'	276,801	211,444
Previous Owners [Member]	'	'	'	'	'	'	'	'	'	'	'
Equity Structure And Transactions [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Beginning Balance	'	'	'	384,694	'	'	'	434,576	384,694	434,576	269,828
Net income (loss)	'	'	'	'	'	'	'	'	11,275	46,293	66,604
Contributions	'	'	'	'	'	'	'	'	7,233	64,597	161,503
Net assets retained by predecessor	'	'	'	'	'	'	'	'	-20,782	'	3,180
Contribution of oil and gas properties	'	'	'	'	'	'	'	'	'	6,893	'
Distribution attributable to net assets acquired	'	'	'	'	'	'	'	'	55,281	'	'
Net book value of net assets acquired by Partnership	'	'	'	'	'	'	'	'	-404,301	-144,335	'
Contribution related to sale of assets to NGP affiliate	'	'	'	'	'	'	'	'	'	40,138	'
Net book value of net assets acquired by NGP affiliate	'	'	'	'	'	'	'	'	'	-33,859	'
Distributions	'	'	'	'	'	'	'	'	-31,098	-29,517	-66,577
Other	'	'	'	'	'	'	'	'	-2,302	-92	38
Ending Balance	'	'	'	'	$384,694	'	'	'	'	$384,694	$434,576

Earnings_Per_Unit_Calculation_

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Net income attributable to Memorial Production Partners LP	$10,862	($39,165)	$52,597	($4,293)	$3,359	($15,199)	$22,222	$36,032	$20,001	$46,414	$148,936
Less: Previous owners interest in net income (loss)	'	'	'	'	'	'	'	'	11,275	46,293	66,604
Less: Predecessor interest in net income (loss)	'	'	'	'	'	'	'	'	'	'	75,740
Less: General partners' 0.1% interest in net income (loss)	'	'	'	'	'	'	'	'	9	'	7
Less: IDRs attributable to corresponding period	'	'	'	'	'	'	'	'	81	'	'
Net income (loss) available to limited partners	'	'	'	'	'	'	'	'	8,636	121	6,585
Weighted average limited partner units outstanding:	'	'	'	'	'	'	'	'	'	'	'
Common units	'	'	'	'	'	'	'	'	40,656	17,519	16,395
Subordinated units	'	'	'	'	'	'	'	'	5,361	5,361	5,361
Total	'	'	'	'	'	'	'	'	46,017	22,880	21,756
Basic and diluted EPU	'	'	'	'	'	'	'	'	$0.19	$0.01	$0.30
Supplemental EPU [Member]	'	'	'	'	'	'	'	'	'	'	'
Earnings Per Share [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Net income attributable to Memorial Production Partners LP	'	'	'	'	'	'	'	'	20,001	46,414	148,936
Less: General partners' 0.1% interest in net income (loss)	'	'	'	'	'	'	'	'	20	46	149
Less: IDRs attributable to corresponding period	'	'	'	'	'	'	'	'	81	'	'
Net income (loss) available to limited partners	'	'	'	'	'	'	'	'	$19,900	$46,368	$148,787
Weighted average limited partner units outstanding:	'	'	'	'	'	'	'	'	'	'	'
Common units	'	'	'	'	'	'	'	'	40,656	17,519	16,395
Subordinated units	'	'	'	'	'	'	'	'	5,361	5,361	5,361
Total	'	'	'	'	'	'	'	'	46,017	22,880	21,756
Basic and diluted EPU	'	'	'	'	'	'	'	'	$0.43	$2.03	$6.83

Earnings_Per_Unit_Calculation_1

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share [Line Items]	'	'	'
General partner's interest in net income, percentage	0.10%	0.10%	0.10%
Supplemental EPU [Member]	'	'	'
Earnings Per Share [Line Items]	'	'	'
General partner's interest in net income, percentage	0.10%	0.10%	0.10%

Equitybased_Awards_Additional_

Equity-based Awards - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Restricted Common Units [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Unrecognized compensation cost	$9.90	'
Weighted-average period of unrecognized compensation cost	'2 years 2 months 12 days	'
Cash distributions paid	1	0.2
Long-Term Incentive Plan [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Number of common units for awards authorized	2,142,221	'
Long-Term Incentive Plan [Member] | Executive officers and employees [Member] | Restricted Common Units [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Fair value of the restricted common units	$9.70	$5

Equitybased_Awards_Summary_of_

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Detail) (Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Restricted common units outstanding, Beginning Balance	285,609	'
Granted, Number of Units	524,718	287,943
Forfeited, Number of Units	-11,734	-2,334
Restricted common units outstanding, Ending Balance	706,927	285,609
Vested, Number of Units	-91,666	'
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance	$18.08	'
Granted, Weighted-Average Grant Date Fair Value per Unit	$18.83	$18.07
Forfeited, Weighted-Average Grant Date Fair Value per Unit	$17.24	$17.14
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance	$18.62	$18.08
Vested, Weighted-Average Grant Date Fair Value per Unit	$18.31	'

Equitybased_Awards_Summary_of_1

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) (Restricted Stock [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, except Per Share data, unless otherwise specified
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Aggregate grant date fair value of restricted common unit awards issued	$9.90	$5.20
Minimum [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Range of grant date market price	$18.33	$17.14
Maximum [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Range of grant date market price	$20.35	$18.58

Equitybased_Awards_Summary_of_2

Equity-based Awards - Summary of Amount of Compensation Expense Recognized (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'	'
Compensation expense	$3,558	$1,423

Related_Party_Transactions_Sch

Related Party Transactions - Schedule of Net Assets Recorded by Partnership (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 14, 2011	Mar. 28, 2013	Dec. 12, 2012	Oct. 31, 2013	Apr. 02, 2012	14-May-12
In Thousands, unless otherwise specified				WHT Acquisition [Member]	Beta [Member]	Cinco Group Acquisition [Member]	Tanos Classic Properties [Member]	East Texas Properties [Member]
Related Party Transaction [Line Items]	'	'	'	'	'	'	'	'
Oil and natural gas properties, net	'	'	$399,967	$192,280	$108,342	$457,439	$15,164	$31,716
Short-term derivative instruments, net	'	'	15,779	1,206	2,926	-1,505	715	1,017
Long-term derivative instruments, net	'	'	10,772	3,528	'	3,056	674	1,337
Asset retirement obligations	'	'	-13,560	-2,753	-58,746	-13,575	-466	-43
Credit facilities	'	'	-198,267	-89,300	-28,500	-151,690	'	'
Accrued liabilities	'	'	-1,650	-3,494	-9,140	-3,311	-17	-70
Net assets	'	'	213,041	106,674	93,696	297,627	16,070	34,569
Accounts receivable	'	'	'	3,866	16,284	10,615	'	612
Cash and cash equivalents	'	'	'	1,354	6,021	3,265	'	'
Prepaid expenses and other current assets	'	'	'	98	4,521	1,824	'	'
Restricted investments	'	'	'	'	68,009	'	'	'
Accounts payable	'	'	'	'	-9,092	-4,063	'	'
Deferred tax liability	'	'	'	'	-1,674	'	'	'
Noncontrolling interest	-5,528	-5,261	'	'	-5,255	'	'	'
Other long-term liabilities	'	'	'	-111	'	-265	'	'
Other long-term assets	'	'	'	'	'	356	'	'
Revenue payable	'	'	'	'	'	($4,519)	'	'

Related_Party_Transactions_Sch1

Related Party Transactions - Schedule of Net Assets Recorded by Partnership (Parenthetical) (Detail) (USD $)	0 Months Ended
In Millions, unless otherwise specified	Dec. 14, 2011
Related Party Transactions [Abstract]	'
Payments on revolving credit facilities	$198.30

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (USD $)

0 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

4 Months Ended

12 Months Ended

Mar. 28, 2013

Apr. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

14-May-12

Apr. 02, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 12, 2012

Dec. 31, 2013

Mar. 28, 2013

Dec. 31, 2013

Oct. 31, 2013

Dec. 31, 2012

Jul. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2013

Dec. 12, 2012

Tanos/Classic Acquisition [Member]

Tanos/Classic Acquisition [Member]

Tanos/Classic Acquisition [Member]

Beta [Member]

Beta [Member]

Beta [Member]

WHT Acquisition [Member]

WHT Acquisition [Member]

Cinco Group Acquisition [Member]

Cinco Group Acquisition [Member]

Cinco Group Acquisition [Member]

Additional Management Fee Collected Under Transactional Agreement [Member]

Additional Management Fee Collected Under Transactional Agreement [Member]

Boaz revolving credit facility [Member]

Memorial Resource [Member]

Memorial Resource [Member]

Memorial Resource [Member]

Memorial Resource [Member]

mi

ft

Related Party Transaction [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Date of Acquisition Common control

'

'

14-May-12

'

'

2-Apr-12

'

'

12-Dec-12

'

'

28-Mar-13

'

1-Oct-13

'

'

'

'

'

'

'

'

'

Acquisition cost of Assets

'

'

'

'

'

'

$27,000,000

$18,500,000

'

'

$270,600,000

'

$200,000,000

'

$603,000,000

'

'

'

'

'

'

'

'

Working capital and other customary adjustments

'

'

'

'

'

'

'

'

'

'

3,000,000

'

4,000,000

'

'

'

'

'

'

'

'

'

'

Working interest

'

'

'

'

'

'

'

'

'

51.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of feet of water in which two platforms stand

'

'

'

'

'

'

'

'

'

260

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of feet of water in which third platform stand

'

'

'

'

'

'

'

'

'

700

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of miles of pipeline and onshore tankage and metering facility

'

'

'

'

'

'

'

'

'

17.5

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount in exchange for partnership contribution to memorial resources

'

'

'

'

'

'

'

'

'

'

3,000,000

'

'

'

'

6,900,000

'

'

'

'

'

'

3,000,000

Amount receivable under management agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

400,000

'

'

'

Management fee per month

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600,000

800,000

'

'

'

'

'

Predecessor expensed advisory and directors fees

'

'

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Annual Advisory fee paid

'

'

300,000

400,000

400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Management fee paid under agreement

'

'

0

400,000

1,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage interest in Tanos sold

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.07%

'

Compensation expense

'

5,800,000

43,495,000

30,342,000

26,695,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Salt water disposal fee

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600,000

800,000

'

'

Agreement related expense

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$300,000

'

'

'

'

Related_Party_Transactions_Net

Related Party Transactions - Net Book Value of Assets Contributed to Memorial Resource (Detail) (Memorial Resource [Member], USD $)	Dec. 12, 2012
In Thousands, unless otherwise specified
Memorial Resource [Member]	'
Related Party Transaction [Line Items]	'
Cash and cash equivalents	$3,751
Accounts receivable	11,125
Prepaid expenses and other current assets	3,470
Property, plant and equipment, net	416
Accounts payable	-7,898
Accrued liabilities	-7,864
Net assets	$3,000

Related_Party_Transactions_Sch2

Related Party Transactions - Schedule of Amount of General and Administrative Costs and Expenses Recognized (Detail) (Omnibus Agreement [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Omnibus Agreement [Member]	'	'
Related Party Transaction Due From To Related Party [Line Items]	'	'
General and administrative costs and expenses under omnibus agreement	$9,440	$1,771

Related_Party_Transactions_Sch3

Related Party Transactions - Schedule of Summarized General and Administrative Costs and Expenses (Detail) (REO [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
REO [Member]	'	'
Related Party Transaction [Line Items]	'	'
Management fees	$1,552	$1,693

Commitments_and_Contingencies_1

Commitments and Contingencies - Environmental Reserves (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Commitments And Contingencies Disclosure [Abstract]	'	'	'
Balance at beginning of period	$1,051	$1,747	$1,450
Charged to costs and expenses	'	-225	'
Acquisition-related additions	'	'	968
Payments	-614	-471	-671
Balance at end of period	$437	$1,051	$1,747

Commitments_and_Contingencies_2

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Jun. 10, 2010	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Mar. 01, 2007	Dec. 31, 2013
				Predecessor [Member]	Predecessor [Member]	Predecessor [Member]	REO revolving credit facility [Member]	SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Loss Contingencies [Line Items]	'	'	'	'	'	'	'	'
Remaining environmental accrued liability recorded	$400,000	$600,000	'	'	'	'	'	'
Amount per barrel of oil	0.25	'	'	'	'	'	'	'
Aggregate value to ceases fund	4,300,000	'	'	'	'	'	'	'
Restricted Investment - decommissioning of offshore production facilities	73,385,000	68,024,000	'	'	'	'	90,000,000	2,300,000
Percentage of working interest under sinking fund trust agreement	51.75%	'	'	'	'	'	'	'
Maximum remaining obligation	1,000,000	'	'	'	'	'	'	'
Additional quarterly payments	'	'	600,000	'	'	'	'	'
Minimum balances attributable to net working interest	78,660,000	'	'	'	'	'	'	'
Maximum remaining obligation	12,200,000	'	'	'	'	'	'	'
Rent expense	$2,400,000	$1,000,000	'	$2,300,000	$2,100,000	$1,600,000	'	'

Commitments_and_Contingencies_3

Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Asset retirement obligations	'
Minimum balances attributable to REO's net working interest	$78,660
June 30, 2014 [Member]	'
Asset retirement obligations	'
Minimum balances attributable to REO's net working interest	68,310
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

Commitments_and_Contingencies_4

Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Held To Maturity Securities [Abstract]	'
Less: Outside working interest owners share	($61,884)
Amortized Cost	66,373
Less: Outside working interest owners share unrealized gain (loss)	-45
Unrealized Gain (Loss)	48
Less: Outside working interest owners share fair market value	-61,929
Fair Market Value	66,421
U.S. Bank Money Market Cash Equivalent [Member]	'
Held To Maturity Securities [Abstract]	'
Amortized Cost	105,184
Unrealized Gain (Loss)	'
Fair Market Value	105,184
U.S. Government Treasury Note 1.75% Coupon [Member]	'
Held To Maturity Securities [Abstract]	'
Amortized Cost	23,073
Unrealized Gain (Loss)	93
Fair Market Value	$23,166

Commitments_and_Contingencies_5

Commitments and Contingencies - Gross Held-to-Maturity Investments (Parenthetical) (Detail)	Dec. 31, 2013
Held To Maturity Securities [Abstract]	'
Coupon Rate, Two	1.75%
U.S. Government Treasury Note 1.75% Coupon [Member]	'
Held To Maturity Securities [Abstract]	'
Maturity date of treasury notes	31-Mar-14

Commitments_and_Contingencies_6

Commitments and Contingencies - Lease Obligations (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Commitments And Contingencies Disclosure [Abstract]	'
Total	$3,985
2014	549
2015	560
2016	416
2017	205
2018	205
Thereafter	$2,050

Defined_Contribution_Plans_Add

Defined Contribution Plans - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Contribution Plan [Line Items]	'	'	'
Tax-deferred contributions	100.00%	'	'
Matching contributions	100.00%	'	'
Percentage of compensation	6.00%	'	'
Employer contributions to the plan	$0.90	$0.40	'
Cost and expenses to the plan	0.3	0.1	'
REO revolving credit facility [Member]	'	'	'
Defined Contribution Plan [Line Items]	'	'	'
Tax-deferred contributions	100.00%	'	'
Matching contributions	100.00%	'	'
Employer contributions to the plan	0.6	0.5	0.5
Cost and expenses to the plan	0.3	0.3	0.3
Vesting Schedule Period	'3 years	'	'
Cinco Group [Member]	'	'	'
Defined Contribution Plan [Line Items]	'	'	'
Employer contributions to the plan	0.1	0.2	0.1
Predecessor [Member]	'	'	'
Defined Contribution Plan [Line Items]	'	'	'
Tax-deferred contributions	6.00%	'	'
Employer contributions to the plan	'	'	$0.20

Quarterly_Financial_Informatio2

Quarterly Financial Information (Unaudited) - Quarterly Financial Data (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Revenues	$92,100	$93,240	$90,174	$68,102	$70,922	$67,132	$56,409	$63,960	$343,616	$258,423	$234,612
Operating income (loss)	26,786	-27,368	60,814	2,245	8,509	-9,220	28,221	39,923	62,477	67,433	164,505
Net income (loss)	10,909	-39,039	52,695	-4,297	3,446	-15,107	22,238	35,941	20,268	46,518	148,790
Net income attributable to Memorial Production Partners LP	10,862	-39,165	52,597	-4,293	3,359	-15,199	22,222	36,032	20,001	46,414	148,936
Net income allocated to previous owners	'	4,128	6,418	729	-1,454	10,133	22,476	15,138	11,275	46,293	66,604
Net income (loss) noncontrolling interest	47	126	98	-4	87	92	16	-91	267	104	-146
Limited partners' interest in net income	$10,811	($43,250)	$46,133	($5,017)	$4,809	($25,307)	($254)	$20,873	$8,677	$121	$6,585
Basic and diluted earnings per unit	$0.18	($0.97)	$1.04	($0.14)	$0.19	($1.13)	($0.01)	$0.94	'	'	'

Supplemental_Oil_and_Gas_Infor2

Supplemental Oil and Gas Information (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Extractive Industries [Abstract]	'	'	'
Evaluated oil and natural gas properties	$1,758,953	$1,545,402	$1,217,597
Unevaluated oil and natural gas properties	'	5,004	4,494
Accumulated depletion, depreciation, and amortization	-417,617	-265,710	-187,022
Total	$1,342,336	$1,284,696	$1,035,069

Supplemental_Oil_and_Gas_Infor3

Supplemental Oil and Gas Information (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Property acquisition costs, proved	$37,786	$278,246	$404,116
Exploration	'	42,430	40,034
Development	145,830	62,472	62,411
Total	$183,616	$383,148	$506,561

Supplemental_Oil_and_Gas_Infor4

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
		MMcf	MMcf
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Percent of discount factor to proved reserves	10.00%	'	'
Multiple acquisitions	'	224,200	376,600
Multiple acquisitions, Largest acquisition	'	'	277,700
Goodrich [Member]	'	'	'
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Multiple acquisitions, Largest acquisition	'	148,900	'
Stanolind revolving credit facility [Member]	'	'	'
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Multiple acquisitions	'	43,600	'
Menemsha [Member]	'	'	'
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Multiple acquisitions, Largest acquisition	'	23,900	'
Propel [Member]	'	'	'
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Divestiture of Oil and Gas Properties	'	19,000	'

Supplemental_Oil_and_Gas_Infor5

Supplemental Oil and Gas Information (Unaudited) - Schedule of Product Prices Used for Valuing the Reserves (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil [Member]	'	'	'
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Product prices for reserves	93.42	91.22	92.75
NGL [Member]	'	'	'
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Product prices for reserves	93.42	91.27	93.19
Natural Gas [Member]	'	'	'
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Product prices for reserves	3.67	2.757	4.118

Supplemental_Oil_and_Gas_Infor6

Supplemental Oil and Gas Information (Unaudited) - Schedule of Net Reserves (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Mcfe	Mcfe	Mcfe
Equivalent [Member]	'	'	'
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Proved developed and undeveloped reserves, Beginning of year	1,015,095,000	832,913,000	396,708,000
Extensions and discoveries	85,180,000	71,192,000	80,120,000
Purchase of minerals in place	18,554,000	224,202,000	376,580,000
Production	-56,303,000	-43,329,000	-34,755,000
Reserves retained by our predecessor	'	'	-3,335,000
Sales of minerals in place	'	-29,499,000	-138,000
Revision of previous estimates	-47,421,000	-40,384,000	17,733,000
Proved developed and undeveloped reserves, End of year	1,015,105,000	1,015,095,000	832,913,000
Proved developed reserves, Beginning of year	619,704,000	589,504,000	298,671,000
Proved developed reserves, End of year	616,893,000	619,704,000	589,504,000
Proved undeveloped reserves, Beginning of year	395,391,000	243,409,000	98,037,000
Proved undeveloped reserves, End of year	398,212,000	395,391,000	243,409,000
Natural Gas [Member]	'	'	'
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Proved developed and undeveloped reserves, Beginning of year	604,440,000	579,751,000	291,074,000
Extensions and discoveries	40,770,000	19,869,000	55,454,000
Purchase of minerals in place	16,294,000	113,617,000	269,653,000
Production	-35,924,000	-29,744,000	-25,829,000
Reserves retained by our predecessor	'	'	-3,198,000
Sales of minerals in place	'	-4,214,000	-132,000
Revision of previous estimates	-18,441,000	-74,839,000	-7,271,000
Proved developed and undeveloped reserves, End of year	607,139,000	604,440,000	579,751,000
Proved developed reserves, Beginning of year	376,932,000	413,431,000	214,916,000
Proved developed reserves, End of year	387,548,000	376,932,000	413,431,000
Proved undeveloped reserves, Beginning of year	227,508,000	166,320,000	76,158,000
Proved undeveloped reserves, End of year	219,591,000	227,508,000	166,320,000
Oil [Member]	'	'	'
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Proved developed and undeveloped reserves, Beginning of year	39,089,000	27,150,000	16,280,000
Extensions and discoveries	5,655,000	7,501,000	1,739,000
Purchase of minerals in place	119,000	11,336,000	7,518,000
Production	-1,764,000	-1,519,000	-1,112,000
Reserves retained by our predecessor	'	'	-23,000
Sales of minerals in place	'	-4,214,000	-1,000
Revision of previous estimates	-3,950,000	-1,165,000	2,749,000
Proved developed and undeveloped reserves, End of year	39,149,000	39,089,000	27,150,000
Proved developed reserves, Beginning of year	24,515,000	19,332,000	12,967,000
Proved developed reserves, End of year	22,265,000	24,515,000	19,332,000
Proved undeveloped reserves, Beginning of year	14,574,000	7,818,000	3,313,000
Proved undeveloped reserves, End of year	16,884,000	14,574,000	7,818,000
NGL [Member]	'	'	'
Supplemental Oil And Gas Reserve Information [Line Items]	'	'	'
Proved developed and undeveloped reserves, Beginning of year	29,352,000	15,045,000	1,326,000
Extensions and discoveries	1,747,000	1,053,000	2,371,000
Purchase of minerals in place	258,000	7,095,000	10,142,000
Production	-1,632,000	-745,000	-375,000
Reserves retained by our predecessor	'	'	'
Sales of minerals in place	'	'	'
Revision of previous estimates	-879,000	6,904,000	1,581,000
Proved developed and undeveloped reserves, End of year	28,846,000	29,352,000	15,045,000
Proved developed reserves, Beginning of year	15,947,000	10,015,000	992,000
Proved developed reserves, End of year	15,959,000	15,947,000	10,015,000
Proved undeveloped reserves, Beginning of year	13,405,000	5,030,000	334,000
Proved undeveloped reserves, End of year	12,887,000	13,405,000	5,030,000

Supplemental_Oil_and_Gas_Infor7

Supplemental Oil and Gas Information (Unaudited) -Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Future cash inflows	$6,892,150	$6,511,776	$5,747,123
Future production costs	-2,719,024	-2,258,554	-1,920,497
Future development costs	-685,858	-620,944	-432,144
Future income tax expense	'	'	-4,420
Future net cash flows for estimated timing of cash flows	3,487,268	3,632,278	3,390,062
10% annual discount for estimated timing of cash flows	-1,879,156	-2,042,362	-1,890,648
Standardized measure of discounted future net cash flows	$1,608,112	$1,589,916	$1,499,414

Supplemental_Oil_and_Gas_Infor8

Supplemental Oil and Gas Information (Unaudited) -Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Maximum effective rate of Texas franchise tax	0.70%

Supplemental_Oil_and_Gas_Infor9

Supplemental Oil and Gas Information (Unaudited) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Beginning of year	$1,589,916	$1,499,414	$596,696
Sale of oil and natural gas produced, net of production costs	-234,520	-160,023	-153,621
Purchase of minerals in place	23,160	375,953	565,760
Sale of minerals in place	'	-154,963	-282
Reserves retained by predecessor	'	'	-1,940
Extensions and discoveries	136,423	265,108	114,482
Changes in income taxes, net	'	1,947	-1,947
Changes in prices and costs	-74,395	-331,760	197,939
Previously estimated development costs incurred	174,490	66,360	4,721
Net changes in future development costs	-74,867	-1,140	-17,054
Revisions of previous quantities	-141,122	-90,587	99,514
Accretion of discount	158,991	150,136	80,999
Change in production rates and other	50,036	-30,529	14,147
End of year	$1,608,112	$1,589,916	$1,499,414

Subsequent_Event_Additional_In

Subsequent Event - Additional Information (Detail) (Subsequent Event [Member], USD $)	Mar. 04, 2014
In Millions, unless otherwise specified
Subsequent Event [Member]	'
Subsequent Event [Line Items]	'
Payments to acquire oil and natural gas properties	$35