Amplify Energy (AMPYW) Inactive 10-K26 Feb 152014 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 20, 2015	Jun. 30, 2014
Document Information [Line Items]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	MEMP
Entity Registrant Name	MEMORIAL PRODUCTION PARTNERS LP
Entity Central Index Key	1521847
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		84,020,116
Entity Public Float			$1.34
General Partner [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		86,797

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$970	$13,139
Accounts receivable:
Oil and natural gas sales	44,105	31,132
Joint interest owners and other (Note 2)	35,458	4,634
Affiliates		4,473
Short-term derivative instruments	208,585	7,600
Prepaid expenses and other current assets	12,630	9,146
Total current assets	301,748	70,124
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	3,007,214	1,748,438
Support equipment and facilities	198,088	16,030
Other	3,006	2,900
Accumulated depreciation, depletion and impairment	-991,819	-418,688
Property and equipment, net	2,216,489	1,348,680
Long-term derivative instruments	311,802	42,657
Restricted investments	77,361	73,385
Other long-term assets	23,159	17,461
Total assets	2,930,559	1,552,307
Current liabilities:
Accounts payable	21,790	8,566
Accounts payable - affiliates	12,781	474
Revenues payable	25,073	16,291
Accrued liabilities (Note 2)	84,471	39,847
Short-term derivative instruments	3,289	7,996
Total current liabilities	147,404	73,174
Long-term debt (Note 8)	1,595,413	792,067
Asset retirement obligations	110,372	99,619
Long-term derivative instruments		5,875
Other long-term liabilities	1,713	1,956
Total liabilities	1,854,902	972,691
Commitments and contingencies (Note 13)
Partners' equity (deficit):
General partner (86,797 units outstanding at December 31, 2014 and 61,300 units outstanding at December 31, 2013)	1,251	728
Total partners' equity	1,070,097	574,088
Noncontrolling interests	5,560	5,528
Total equity	1,075,657	579,616
Total liabilities and equity	2,930,559	1,552,307
Limited Partners Common Units [Member]
Partners' equity (deficit):
Limited partners units	1,085,265	582,075
Total equity	1,085,265	582,075
Subordinated Units [Member]
Partners' equity (deficit):
Limited partners units	($16,419)	($8,715)

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
General partner, units outstanding	86,797	61,300	34,317	22,044
Limited Partners Common Units [Member]
Limited partners, units outstanding	80,421,992	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	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, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil & natural gas sales	$490,249	$341,197	$255,608
Pipeline tariff income and other	3,856	2,419	2,815
Total revenues	494,105	343,616	258,423
Costs and expenses:
Lease operating	134,654	88,893	80,116
Pipeline operating	2,068	1,835	2,114
Exploration	790	1,130	2,463
Production and ad valorem taxes	31,601	17,784	16,048
Depreciation, depletion, and amortization	155,404	97,269	76,036
Impairment of proved oil and natural gas properties	407,540	54,362	10,532
General and administrative	45,619	43,495	30,342
Accretion of asset retirement obligations	5,618	4,853	4,377
(Gain) loss on commodity derivative instruments	-492,254	-26,281	-21,417
(Gain) loss on sale of properties		-2,848	-9,759
Other, net	-12	647	138
Total costs and expenses	291,028	281,139	190,990
Operating income (loss)	203,077	62,477	67,433
Other income (expense):
Interest expense, net	-83,550	-41,901	-20,436
Other income (expense)	-327
Amortization of investment premium			-194
Total other income (expense)	-83,877	-41,901	-20,630
Income (loss) before income taxes	119,200	20,576	46,803
Income tax benefit (expense)	-1,121	-308	-285
Net income (loss)	118,079	20,268	46,518
Net income (loss) attributable to noncontrolling interest	32	267	104
Net income (loss) attributable to Memorial Production Partners LP	118,047	20,001	46,414
Limited partners' interest in net income (loss):
Net income (loss) attributable to Memorial Production Partners LP	118,047	20,001	46,414
Net (income) loss allocated to previous owners		-11,275	-46,293
Net (income) loss allocated to general partner	-206	-49
Net (income) loss allocated to NGP IDRs	-88
Limited partners' interest in net income (loss)	$117,753	$8,677	$121
Earnings per unit: (Note 10)
Basic and diluted earnings per unit	$1.66	$0.19	$0.01
Weighted average limited partner units outstanding:
Basic and diluted	70,859	46,017	22,880

STATEMENTS_OF_CONSOLIDATED_AND1

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income (loss)	$118,079	$20,268	$46,518
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	155,404	97,269	76,036
Impairment of proved oil and natural gas properties	407,540	54,362	10,532
(Gain) loss on derivative instruments	-492,405	-26,829	-16,578
Cash settlements (paid) received on derivative instruments	11,693	18,919	42,307
Premiums paid for derivatives			-411
Deferred income tax expense (benefit)	994
Amortization of deferred financing costs	4,227	5,845	1,991
Accretion of senior notes net discount	1,921	504
Amortization of investment premium			194
Accretion of asset retirement obligations	5,618	4,853	4,377
Amortization of equity awards	7,874	3,558	1,423
(Gain) loss on sale of properties		-2,848	-9,759
Exploration costs		95	36
Non-cash compensation expense		1,057
Changes in operating assets and liabilities:
Accounts receivable	-23,126	-2,492	-5,733
Prepaid expenses and other assets	-2,111	-1,210	-555
Payables and accrued liabilities	29,842	20,113	7,164
Other	-652	233	-698
Net cash provided by operating activities	224,898	193,697	156,844
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	-1,083,761	-38,664	-277,623
Additions to oil and gas properties	-264,245	-161,675	-107,789
Additions to restricted investments	-3,976	-5,361	-4,599
Additions to other property and equipment	-89	-238	-1,748
Proceeds from the sale of oil and natural gas properties		4,525	34,521
Other			29
Net cash used in investing activities	-1,352,071	-201,413	-357,209
Cash flows from financing activities:
Advances on revolving credit facilities	1,446,000	958,355	391,000
Payments on revolving credit facilities	-1,137,000	-1,485,537	-121,819
Deferred financing costs	-11,494	-20,908	-2,225
Proceeds from senior notes	492,425	688,563
Capital contributions from previous owners		7,233	64,597
Contributions related to sale of assets to NGP affiliate		2,013	38,125
Proceeds from general partner contribution	570	521	206
Proceeds from the issuance of common units	553,288	511,204	202,572
Costs incurred in conjunction with issuance of common units	-12,510	-21,066	-8,268
Distributions to partners	-154,852	-96,643	-34,436
Distribution to Memorial Resource (see Note 1)	-48,880	-151,714	-45,489
Restricted units returned to plan	-1,012
Distribution to NGP affiliates (see Note 1)		-355,495	-242,174
Repurchases under unit repurchase program	-11,531
Transfer of operating subsidiary to Memorial Resource (see Note 12)			-3,751
Distributions made by previous owners		-31,098	-29,517
Cash retained by previous owners		-9,013
Net cash (used in) provided by financing activities	1,115,004	-3,585	208,821
Net change in cash and cash equivalents	-12,169	-11,301	8,456
Cash and cash equivalents, beginning of period	13,139	24,440	15,984
Cash and cash equivalents, end of period	$970	$13,139	$24,440

STATEMENTS_OF_CONSOLIDATED_AND2

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY (USD $)	Total	Limited Partners Common Units [Member]	Limited Partners Subordinated [Member]	General Partner [Member]	Previous Owners [Member]	NGP IDR [Member]	Noncontrolling Interest [Member]
In Thousands	Total	Limited Partners Common Units [Member]	Limited Partners Subordinated [Member]	General Partner [Member]	Previous Owners [Member]	NGP IDR [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2011	$742,901	$241,034	$61,708	$426	$434,576		$5,157
Net income (loss)	46,518	114	7		46,293		104
Net proceeds from the issuance of common units	194,134	194,134
Contributions	64,803			206	64,597
Contribution of oil and gas properties	6,893				6,893
Distribution attributable to net assets acquired	-287,663	-209,720	-77,701	-242
Net book value of net assets acquired (Note 12)		99,972	44,269	94	-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
Amortization of equity awards	1,423	1,423
Distributions	-64,001	-26,152	-8,298	-34	-29,517
Deferred tax liability adjustments	446	335	111
Other	32	64	60		-92
Balance at Dec. 31, 2012	711,765	301,204	20,156	450	384,694		5,261
Net income (loss)	20,268	7,880	797	49	11,275		267
Net proceeds from the issuance of common units	490,138	490,138
Contributions	7,754			521	7,233
Distribution attributable to net assets acquired	-502,920	-490,400	-67,242	-559	55,281
Net book value of net assets acquired (Note 12)		355,159	48,739	403	-404,301
Amortization of equity awards	3,558	3,558
Distributions	-127,741	-85,342	-11,165	-136	-31,098
Other	-2,424	-122			-2,302
Net assets retained by previous owners	-20,782				-20,782
Balance at Dec. 31, 2013	579,616	582,075	-8,715	728			5,528
Net income (loss)	118,079	113,573	4,180	206		88	32
Net proceeds from the issuance of common units	540,698	540,698
Contributions	570			570
Distribution attributable to net assets acquired	-2,413	-2,321	-90	-2
Amortization of equity awards	7,874	7,874
Distributions	-154,852	-142,719	-11,794	-251		-88
Common units repurchased under repurchase program (Note 9)	-12,903	-12,903
Restricted units repurchased (See Note 9)	-1,012	-1,012
Balance at Dec. 31, 2014	$1,075,657	$1,085,265	($16,419)	$1,251			$5,560

Related_Party_Transactions

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	ERROR: Could not retrieve Word content for note block

Organization_and_Basis_of_Pres

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Organization and Basis of Presentation	MEMORIAL PRODUCTION PARTNERS LP
	NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
	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.

	The Partnership was formed in April 2011 by Memorial Resource Development LLC (“MRD LLC”) to own, acquire and exploit oil and natural gas properties in North America. Memorial Resource Development Corp. (“MRD”) was formed by MRD LLC in January 2014 to exploit, develop and acquire natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed in April 2011 by Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P. (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. In June 2014, (i) the Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”), after which MRD Holdco owned 100% of MRD LLC, and (ii) MRD LLC distributed certain assets, including all of our subordinated units, to MRD Holdco. On June 18, 2014, MRD LLC contributed substantially all of its assets, including its interest in our general partner, to MRD in connection with MRD’s initial public offering. On June 27, 2014, MRD LLC merged into MRD Operating LLC, a subsidiary of MRD. 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”). The remaining IDRs are owned by our general partner.

	Unless the context requires otherwise, references to “Memorial Resource” refer collectively to MRD and its subsidiaries other than the Partnership. 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. Our general partner is responsible for managing all of the Partnership’s operations and activities.

	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).

	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.


	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 MRD LLC 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 was 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 owned by WHT Energy Partners (“WHT”) (the “WHT Properties”) 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 MRD LLC 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 are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements were derived from the historical accounting records of the previous owners and reflect the historical financial position, results of operations and cash flows for all periods presented.

	The previous owners combined financial statements reflect: (i) certain oil and gas properties acquired from MRD LLC 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) MRD LLC.

	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 current presentation.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2014
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 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 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 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, 2014 and 2013, 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. Support equipment and facilities are depreciated using the straight-line method generally based on estimated useful lives of fifteen to forty years.

	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, 2014, 2013 and 2012.

	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. We engaged Netherland, Sewell & Associates, Inc. (“NSAI”) and Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2014.

	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 cost 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 may 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 and generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2014, 2013 and 2012 was approximately $4.2 million, $5.8 million, and $2.0 million, respectively.

	Impairments

	Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to 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, 2014, 2013 and 2012 was approximately $407.5 million, $54.4 million, and $10.5 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 in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.

	Book Overdrafts

	Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.

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, 2014 or 2013.
The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:

	Years Ending December 31,
	2014		2013			2012
Major customers:
Phillips 66 (1)		13%		15%			13%
ConocoPhillips (1)	n/a		n/a				14%
Sinclair Oil & Gas Company		12%	n/a			n/a


(1)Phillips 66 purchased production pursuant to existing marketing agreements with terms that are currently on “evergreen” status. Evergreen contracts automatically renew on a month-to-month basis until either party gives 30 or 60 days advance written notice of non-renewal. 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 a wholly-owned subsidiary of 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. Memorial Resource allocated indirect general and administrative costs based on time allocations for the year ended December 31, 2014, on production for the year ended December 31, 2013 and on a reserve basis methodology for the year ended December 31, 2012. 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 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.

Capitalized Interest

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2014, we had $2.8 million in capitalized interest. We did not have any capitalized interest for the years ended December 31, 2013 and 2012.


Income Tax

We are organized as a pass-through entity for federal and most state income tax purposes. As a result, our partners are responsible for federal and state income taxes on their share of our taxable income. Certain of our consolidated subsidiaries are taxed as corporations for federal and state income tax purposes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. Deferred income 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 income tax liability of $3.1 million and $2.0 million at December 31, 2014 and 2013, respectively.

We must recognize the income 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 income 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, 2014 or 2013.

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.

Accounts Receivable – Joint Interest Owners and Other

Accounts receivable from joint interest owners and other consisted of the following at the dates indicated (in thousands):

	December 31,			December 31,
	2014			2013
Derivatives expired positions	$	13,754		$	—
Wyoming Acquisition		9,569			—
Joint interest owners		11,235			4,147
Other		900			487
	$	35,458		$	4,634


Accrued Liabilities

Current accrued liabilities consisted of the following at the dates indicated (in thousands):

	December 31,			December 31,
	2014			2013
Accrued capital expenditures	$	30,598		$	16,193
Accrued interest payable		24,673			8,931
Accrued lease operating expense		14,632			10,666
Accrued ad valorem taxes		8,231			1,531
Accrued general and administrative expenses		1,276			1,547
Environmental liability		2,092			437
Other		2,969			542
	$	84,471		$	39,847

Supplemental Cash Flows

Supplemental cash flow for the periods presented (in thousands):

	For the Year Ended
	December 31,
	2014			2013				2012
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$	63,709		$	40,413			$	13,869
Cash paid for taxes		151			168				22
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities		14,405			12,178				4,435
Repurchases under unit repurchase program		1,372			—				—
Accounts receivable related to Wyoming Acquisition		9,569			—				—
Accounts receivable related to Double A Acquisition		586			—				—
Assumptions of asset retirement obligations related to properties acquired		4,265			1,581				5,448
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

New Accounting Pronouncements

Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Partnership beginning on January 1, 2017. The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures.

Reporting Discontinued Operations. In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures. The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition. We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Acquisitions_and_Divestitures

Acquisitions and Divestitures	12 Months Ended
Acquisitions and Divestitures	Dec. 31, 2014
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 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.

	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,
	2014				2013				2012
	$	4,363			$	6,729			$	4,135

	2014 Acquisitions

	Wyoming Acquisition. On July 1, 2014, we consummated a transaction to acquire certain oil and natural gas liquids properties in Wyoming from a third party for an aggregate purchase price of approximately $906.1 million, including estimated post-closing adjustments (the “Wyoming Acquisition”). We recorded revenues of $72.0 million in the statement of operations and generated earnings of approximately $22.9 million related to the Wyoming Acquisition subsequent to the closing date. The following table summarizes the preliminary fair value of the third party assets acquired and liabilities assumed in the Wyoming Acquisition (in thousands):

		Wyoming
		Acquisition
	Oil and gas properties	$	930,168
	Asset retirement obligations		(3,980	)
	Revenues payable		(375	)
	Accrued liabilities		(19,693	)
	Total identifiable net assets	$	906,120
	Eagle Ford Acquisition. On March 25, 2014, we closed a transaction to acquire certain oil and natural gas producing properties in the Eagle Ford from a third party for approximately $168.1 million (the “Eagle Ford Acquisition”). In addition, we acquired a 30% interest in the seller’s Eagle Ford leasehold. During the year ended December 31, 2014, revenues of approximately $36.5 million were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and we generated earnings of approximately $16.3 million for the year ended December 31, 2014.

	The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):

		Eagle Ford
		Acquisition
	Oil and gas properties	$	168,606
	Asset retirement obligations		(285	)
	Accrued liabilities		(250	)
	Total identifiable net assets	$	168,071

	The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2014 and 2013 as though the Eagle Ford Acquisition and Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

		For the Year Ended December 31,
		2014 (1)				2013
		(In thousands, except per unit amounts)
	Revenues	$	594,570			$	583,823
	Net income (loss)		156,308				153,355
	Basic and diluted earnings per unit		2.2				3.08


	(1)Amounts represent historical revenues and expenses from January 1, 2014 through the respective dates of acquisition.

	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 MRD LLC, 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 Seller				Goodrich				Menemsha			Other
	Acquisition				Acquisition				Acquisition			Acquisitions
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 year ended December 31, 2012 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 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
	(In thousands,
	except per unit amounts)
Revenues	$	286,004
Net income		58,472
Basic and diluted earnings per unit		0.53

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 following 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 and 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
Fair Value Measurements of Financial Instruments	Dec. 31, 2014
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, 2014 and 2013, 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, 2014 and December 31, 2013. 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, 2014 and December 31, 2013 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. 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, 2014 and December 31, 2013 for each of the fair value hierarchy levels:


		Fair Value Measurements at December 31, 2014 Using
		Quoted Prices in		Significant Other		Significant
		Active Market		Observable Inputs		Unobservable Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	564,913	$	—	$	564,913
	Interest rate derivatives		—		1,305		—		1,305
	Total assets	$	—	$	566,218	$	—	$	566,218

	Liabilities:
	Commodity derivatives	$	—	$	45,831	$	—	$	45,831
	Interest rate derivatives		—		3,289		—		3,289
	Total liabilities	$	—	$	49,120	$	—	$	49,120


		Fair Value Measurements at December 31, 2013 Using
		Quoted Prices in		Significant Other		Significant
		Active Market		Observable Inputs		Unobservable Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	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

	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. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations is commonly estimated using the depreciated replacement cost approach.
	·	Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. 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, 2014, we recognized $407.5 million of impairments. The impairments primarily related to certain properties located in the Permian Basin, East Texas, and South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable. In the Permian Basin, the impairments were in due to a downward revision of estimated proved reserves based on declining commodity prices and updated well performance data. In South Texas, the impairments were due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs. In East Texas, the impairments were due to downward revisions based on declining commodity prices. The carrying value of the: (i) Permian Basin properties after the $234.2 million impairment was approximately $88.7 million; (ii) East Texas properties after the $107.6 million impairment was approximately $88.8 million; and (iii) South Texas properties after the $65.6 million impairment was $71.2 million.
	·	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.

Risk_Management_and_Derivative

Risk Management and Derivative Instruments	12 Months Ended
Risk Management and Derivative Instruments	Dec. 31, 2014
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 creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into 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 $207.3 million against amounts outstanding under our revolving credit facility at December 31, 2014, reducing our maximum credit exposure to approximately $309.8 million, of which approximately $109.7 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 a variety of locations such as NYMEX WTI, Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At December 31, 2014, the Partnership had the following open commodity positions:


		2015				2016				2017				2018				2019
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		2,605,278				2,692,442				2,450,067				2,160,000				1,914,583
	Weighted-average fixed price	$	4.28			$	4.4			$	4.31			$	4.51			$	4.75

	Collar contracts:
	Average Monthly Volume (MMBtu)		350,000				—				—				—				—
	Weighted-average floor price	$	4.62			$	—			$	—			$	—			$	—
	Weighted-average ceiling price	$	5.8			$	—			$	—			$	—			$	—

	Call spreads (1):
	Average Monthly Volume (MMBtu)		80,000				—				—				—				—
	Weighted-average sold strike price	$	5.25			$	—			$	—			$	—			$	—
	Weighted-average bought strike price	$	6.75			$	—			$	—			$	—			$	—

	Basis swaps:
	Average Monthly Volume (MMBtu)		2,940,000				2,508,333				415,000				115,000				—
	Spread	$	(0.12	)		$	(0.04	)		$	0			$	0.15			$	—

	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		314,281				332,813				326,600				312,000				160,000
	Weighted-average fixed price	$	90.96			$	85.83			$	84.38			$	83.74			$	85.52

	Collar contracts:
	Average Monthly Volume (Bbls)		5,000				—				—				—				—
	Weighted-average floor price	$	80			$	—			$	—			$	—			$	—
	Weighted-average ceiling price	$	94			$	—			$	—			$	—			$	—

	Basis swaps:
	Average Monthly Volume (Bbls)		97,500				95,000				—				—				—
	Spread	$	(7.07	)		$	(9.56	)		$	—			$	—			$	—

	NGL Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		149,200				84,600				—				—				—
	Weighted-average fixed price	$	43.02			$	41.49			$	—			$	—			$	—



	(1)These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.

	Our basis swaps included in the table above are presented on a disaggregated basis below:


		2015				2016				2017				2018
	Natural Gas Derivative Contracts:
	NGPL TexOk basis swaps:
	Average Monthly Volume (MMBtu)		2,280,000				2,103,333				300,000				—
	Spread	$	(0.11	)		$	(0.06	)		$	(0.05	)		$	—

	HSC basis swaps:
Average Monthly Volume (MMBtu)		150,000				135,000				115,000				115,000
Spread	$	(0.08	)		$	0.07			$	0.14			$	0.15

CIG basis swaps:
Average Monthly Volume (MMBtu)		210,000				—				—				—
Spread	$	(0.25	)		$	—			$	—			$	—

TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		300,000				270,000				—				—
Spread	$	(0.09	)		$	0.06			$	—			$	—

Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		57,500				55,000				—				—
Spread - Brent	$	(9.73	)		$	(13.35	)		$	—			$	—

Midland basis swaps:
Average Monthly Volume (Bbls)		40,000				40,000				—				—
Spread - WTI	$	(3.25	)		$	(4.34	)		$	—			$	—


Interest Rate Swaps

Periodically, 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, 2014, we had the following interest rate swap open positions:


		2015				2016				2017
Average Monthly Notional (in thousands)		$	314,167			$	250,000			$	250,000
Weighted-average fixed rate			1.349	%			1.029	%			1.62	%
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, 2014 and 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.

				Asset Derivatives								Liability Derivatives
				December 31,				December 31,				December 31,				December 31,
Type		Balance Sheet Location		2014				2013				2014				2013
				(In thousands)
Commodity contracts		Short-term derivative instruments		$	225,882			$	18,578			$	17,297			$	17,120
Interest rate swaps		Short-term derivative instruments			—				845				3,289				2,699
Gross fair value					225,882				19,423				20,586				19,819
Netting arrangements		Short-term derivative instruments			(17,297	)			(11,823	)			(17,297	)			(11,823	)
Net recorded fair value		Short-term derivative instruments		$	208,585			$	7,600			$	3,289			$	7,996

Commodity contracts		Long-term derivative instruments		$	339,031			$	77,348			$	28,534			$	38,456
Interest rate swaps		Long-term derivative instruments			1,305				27				—				2,137
Gross fair value					340,336				77,375				28,534				40,593
Netting arrangements		Long-term derivative instruments			(28,534	)			(34,718	)			(28,534	)			(34,718	)
Net recorded fair value		Long-term derivative instruments		$	311,802			$	42,657			$	—			$	5,875

(Gains) Losses on Derivatives

We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes and neither did 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, 2014, 2013, and 2012:

		Statements of		For the Year Ended December 31,
		Operations Location		2014				2013				2012
Commodity derivative contracts		(Gain) loss on commodity derivatives		$	(492,254	)		$	(26,281	)		$	(21,417	)
Interest rate derivatives		Interest expense, net			(151	)			(548	)			4,839

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2014
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, 2014, 2013, and 2012:

		2014			2013			2012
		(in thousands)
	Asset retirement obligations at beginning of period	$	99,619		$	91,349		$	82,722
	Liabilities added from acquisitions or drilling		5,815			2,116			5,958
	Liabilities removed upon sale of wells		—			—			(1,795	)
	Liabilities settled		(651	)		(20	)		(91	)
	Accretion expense		5,618			4,853			4,377
	Revision of estimates		(29	)		1,321			178
	Asset retirement obligations at end of period	$	110,372		$	99,619		$	91,349

Restricted_Investments

Restricted Investments	12 Months Ended
Restricted Investments	Dec. 31, 2014
Investments Debt And Equity Securities [Abstract]
Restricted Investments	Note 7. Restricted Investments

	Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. The components of the restricted investment balance are as follows:

		December 31,		December 31,
		2014		2013
		(In thousands)
	BOEM platform abandonment (See Note 13)	$	69,954	$	66,373
	BOEM lease bonds		794		794

	SPBPC Collateral:
	Contractual pipeline and surface facilities abandonment		2,701		2,306
	California State Lands Commission pipeline right-of-way bond		3,005		3,005
	City of Long Beach pipeline facility permit		500		500
	Federal pipeline right-of-way bond		307		307
	Port of Long Beach pipeline license		100		100
	Restricted investments	$	77,361	$	73,385

Long_Term_Debt

Long Term Debt	12 Months Ended
Long Term Debt	Dec. 31, 2014
Debt Disclosure [Abstract]
Long Term Debt
	Note 8. Long Term Debt

	Our consolidated debt obligations consisted of the following at the dates indicated:

		December 31,				December 31,
		2014				2013
		(In thousands)
	OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	412,000			$	103,000
	2021 Senior Notes, fixed-rate, due May 2021 (1)		700,000				700,000
	2022 Senior Notes, fixed-rate, due August 2022 (2)		500,000				—
	Unamortized discounts		(16,587	)			(10,933	)
	Total long-term debt	$	1,595,413			$	792,067


	(1) The estimated fair value of our 2021 Senior Notes was $563.5 million and $721.0 million at December 31, 2014 and 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
	(2) The estimated fair value of our 2022 Senior Notes was $380.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

	Subsidiary Guarantors

	We are a “Well-Known Seasoned Issuer” under SEC rules and have filed a universal shelf registration statement with the SEC that allows us to issue debt and equity securities. Any debt securities issued will be governed by an indenture. Our outstanding debt securities are, and any debt securities issued in the future will likely be, jointly and severally, fully and unconditionally guaranteed (subject to customary release provisions) by certain of the Partnership’s subsidiaries (collectively, the “Guarantor Subsidiaries”). The Guarantor Subsidiaries are 100% owned by the Partnership. The Partnership has no material assets or operations independent of the Guarantor Subsidiaries and there are no significant restrictions upon the ability of the Guarantor Subsidiaries to distribute funds to the Partnership.









	Borrowing Base

	Credit facilities tied to a borrowing base 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,
		2014
		(In thousands)
	OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	1,440,000

	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.

	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, 2014, the revolving credit facility was primarily used to fund the acquisitions of oil and gas properties. See Note 3 for additional information regarding these acquisitions.

	2022 Senior Notes

	On July 17, 2014, we and Finance Corp. (collectively, the “Issuers”) completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes due 2022 (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% 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. The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year, commencing February 1, 2015.

	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 2022 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, all outstanding 2022 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 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately.

	2021 Senior Notes

On April 17, 2013, May 23, 2013 and October 10, 2013, the Issuers issued $300.0 million, $100.0 million and $300.0 million, respectively, of 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes 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. The 2021 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. The 2021 Senior Notes are governed by an indenture and 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 2021 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 2021 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 subsidiary guarantor that is a significant subsidiary, all outstanding 2021 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 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately.

Previous Owner Revolving Credit Facilities

REO, WHT, Stanolind, Boaz, Crown, Tanos and Propel 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,
	2014				2013				2012
OLLC revolving credit facility		2.67	%			3.25	%			2.74	%
WHT revolving credit facility	n/a					2.29	%			2.6	%
REO revolving credit facility	n/a				n/a					3.4	%
Stanolind revolving credit facility	n/a					3.52	%			3.76	%
Boaz revolving credit facility	n/a					2.97	%			3.12	%
Crown revolving credit facility	n/a					3.38	%			4.2	%
Tanos revolving credit facility	n/a					3.1	%			2.31	%
Propel Energy revolving credit facility	n/a					3.08	%			3.28	%

Unamortized Deferred Financing Costs

Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:

	December 31,				December 31,
	2014				2013
	(In thousands)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1)	$	6,468			$	5,413
2021 Senior Notes (2)		13,308				15,053
2022 Senior Notes (2)		7,958				—
Total	$	27,734			$	20,466


(1) Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.
(2) Unamortized deferred financing costs are amortized using the straight line method which generally approximates the effective interest method.

Advances and Repayments

The following table presents borrowings and repayments under our consolidated and combined revolving credit facilities for the periods presented (in thousands):

					Previous Owner
	OLLC Revolving				Revolving
	Credit Facility				Credit Facility				Total
For the Twelve Months Ended December 31, 2014:
Advances on revolving credit facility	$	1,446,000			$	—			$	1,446,000
Payments on revolving credit facility		(1,137,000	)			—				(1,137,000	)

For the Twelve Months 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 Twelve Months 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 accounting and financial reporting purposes, any amounts that were repaid concurrent with the closing of the Beta acquisition, the WHT Properties, or the Cinco Group acquisition were 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.”

Letters of credit

At December 31, 2014, we had $6.7 million of letters of credit outstanding related to operations at our properties acquired in the Wyoming Acquisition.

Equity_and_Distributions

Equity and Distributions	12 Months Ended
Equity and Distributions	Dec. 31, 2014
Equity [Abstract]
Equity and Distributions
	Note 9. Equity and Distributions

	2014 Public Equity Offerings

	On September 9, 2014, we issued 14,950,000 common units representing limited partner interests in the Partnership (including 1,950,000 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 $22.29 per unit generating total net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility.

	On July 15, 2014, we issued 9,890,000 common units representing limited partner interests in the Partnership (including 1,290,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the underwriters at a negotiated price of $22.25 per unit generating total net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility.

	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.
	Equity Outstanding

	The following table summarizes changes in the number of outstanding units since December 31, 2011:

									General
		Common			Subordinated				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
	Common units issued		24,840,000			—				—
	Restricted common units issued		684,954			—				—
	Restricted common units forfeited		(38,294	)		—				—
	Restricted common units repurchased (1)		(42,587	)		—				—
	Common units repurchased under repurchase program		(899,912	)		—				—
	General partner units issued		—			—				25,497
	Balance, December 31, 2014		80,421,992			5,360,912				86,797


	(1)Restricted common units are generally net-settled by unitholders to cover the required withholding tax upon vesting. Unitholders surrendered units with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were $1.0 million and $0.1 million for the years ended December 31, 2014 and 2013, respectively. 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, 2014, 2013 and 2012.

	As of December 31, 2014, MRD Holdco 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. The subordination period ended on February 13, 2015.

	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 and NGP. 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.

	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 had 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 were deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units were not entitled to receive any distributions from operating surplus until the common units had received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages were paid on the subordinated units. The practical effect of the subordinated units was to increase the likelihood that during the subordination period there would be available cash from operating surplus to be distributed on the common units. The subordination period ended on February 13, 2015.

Our partnership agreement required 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 distributed 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 distributed 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 distributed 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 was 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:

		Target Quarterly Distributions			Marginal Percentage Interest in Distributions
		Target Amount			Unitholders				General Partner				IDR (1)
Minimum Quarterly Distribution		$	0.475			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)The Funds collectively indirectly own 50% of our incentive distribution rights. The remaining IDRs are owned by our general partner.

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period (i.e., the first quarter of 2015) 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 extended 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 were 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.
On February 13, 2015, each outstanding subordinated unit converted into one common unit and will 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, 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

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):

															Distribution
							Amount				Aggregate				Received by
Quarter		Declaration Date		Record Date	Payable Date		Per Unit				Distribution				Affiliates
4th Quarter 2014		26-Jan-15		5-Feb-15	12-Feb-15		$	0.55			$	46.3			$	3.1
3rd Quarter 2014		23-Oct-14		5-Nov-14	12-Nov-14		$	0.55			$	47.8			$	3.1
2nd Quarter 2014		24-Jul-14		5-Aug-14	12-Aug-14		$	0.55			$	39.5			$	3
1st Quarter 2014		24-Apr-14		6-May-14	13-May-14		$	0.55			$	33.8			$	3
4th Quarter 2013		27-Jan-14		6-Feb-14	13-Feb-14		$	0.55			$	33.8			$	3
3rd Quarter 2013		22-Oct-13		1-Nov-13	12-Nov-13		$	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

Previous Owners Capital

The following table summarizes our previous owners’ equity transactions with respect to the period indicated (dollars in thousands):

		Tanos/Classic Properties			REO				WHT Properties				Cinco Group				Total Previous Owners
Balance, December 31, 2011		$	50,853		$	72,755			$	99,524			$	211,444			$	434,576
Net income			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 previous owners			—			—				—				(20,782	)			(20,782	)
Balance, December 31, 2013		$	—		$	—			$	—			$	—			$	—

Earnings_per_Unit

Earnings per Unit	12 Months Ended
Earnings per Unit	Dec. 31, 2014
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,
		2014		2013		2012
	Net income (loss) attributable to Memorial Production Partners LP	$	118,047	$	20,001	$	46,414
	Less: Previous owners interest in net income (loss)		—		11,275		46,293
	Less: General partner's 0.1% interest in net income (loss)		118		9		—
	Less: IDRs attributable to corresponding period		202		81		—
	Net income (loss) available to limited partners	$	117,727	$	8,636	$	121

	Weighted average limited partner units outstanding:
	Common units		65,498		40,656		17,519
	Subordinated units		5,361		5,361		5,361
	Total		70,859		46,017		22,880
	Basic and diluted EPU	$	1.66	$	0.19	$	0.01

	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,
		2014		2013		2012
	Net income (loss) attributable to Memorial Production Partners LP	$	118,047	$	20,001	$	46,414
	Less: General partner's 0.1% interest in net income (loss)		118		20		46
	Less: IDRs attributable to corresponding period		202		81		—
	Net income (loss) available to limited partners	$	117,727	$	19,900	$	46,368

	Weighted average limited partner units outstanding:
	Common units		65,498		40,656		17,519
	Subordinated units		5,361		5,361		5,361
	Total		70,859		46,017		22,880
	Supplemental basic and diluted EPU	$	1.66	$	0.43	$	2.03

	Our supplemental basic and diluted EPU includes all the earnings generated by the Partnership’s previous owners for all periods presented due to common control considerations. As discussed under Note 1, material transactions between entities under common control are accounted for retrospectively.

Equitybased_Awards

Equity-based Awards	12 Months Ended
Equity-based Awards	Dec. 31, 2014
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, 2014, 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 typically 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, 2014, 2013 and 2012 was $15.0 million, $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. Compensation costs are recorded as direct general and administrative expenses.

	The following table summarizes information regarding restricted common unit awards for the periods presented:

						Weighted-
						Average Grant
						Date Fair Value
		Number of Units				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
	Granted (4)		684,954			$	22.39
	Forfeited		(38,294	)		$	20.54
	Vested		(260,067	)		$	18.56
	Restricted common units outstanding at December 31, 2014		1,093,520			$	20.93


	(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.
	(4)The aggregate grant date fair value of restricted common unit awards issued in 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 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,
	2014				2013			2012
	$	7,874			$	3,558		$	1,423

	The unrecognized compensation cost associated with restricted common unit awards was an aggregate $16.5 million at December 31, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.1 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, 2014, 2013 and 2012, the restricted common unitholders received a distribution of approximately $1.9 million, $1.0 million and $0.2 million, respectively.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2014
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, 2014, 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:

		2014				2013			2012
		(In thousands)
	Balance at beginning of period	$	437			$	1,051		$	1,747
	Charged to costs and expenses		2,852				—			(225	)
	Payments		(1,197	)			(614	)		(471	)
	Balance at end of period	$	2,092			$	437		$	1,051

	At December 31, 2014 and 2013, $2.1 million and $0.4 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, 2014, the gross account balance included in restricted investments was approximately $2.7 million. REO’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was $0.8 million at December 31, 2014.

	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):

	30-Jun-15	$	72,450
	30-Jun-16	$	76,590
	31-Dec-16	$	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, 2014, the maximum remaining obligation net to REO’s interest was approximately $8.7 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, 2014 (in thousands):

			Amortized
	Investment		Cost
	U.S. Bank Money Market Cash Equivalent		$	135,176
	Less: Outside working interest owners share			(65,222	)
			$	69,954

	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. 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, 2014, 2013 and 2012, we recognized $6.4 million, $2.4 million and $1.0 million of rent expense, respectively. The previous owners recorded rent expense of approximately $2.3 million and $2.1 million for the years ended December 31, 2013 and 2012, 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 (in thousands):

							Payment or Settlement Due by Period
	Purchase commitment		Total				2015			2016		2017		2018		2019		Thereafter
	Operating leases		$	3,665			$	788		$	416	$	205	$	205	$	205	$	1,846


	Purchase Commitment Assumed

	At December 31, 2014, we had a CO2 purchase commitment with a third party that was assumed in our Wyoming Acquisition. The table below outlines our purchase commitment under the contract (in thousands):

							Payment or Settlement Due by Period
	Purchase commitment		Total				2015			2016		2017		2018		2019		Thereafter
	CO2 minimum purchase commitment:		$	50,495			$	9,608		$	10,179	$	10,151	$	6,995	$	7,060	$	6,502

Defined_Contribution_Plans

Defined Contribution Plans	12 Months Ended
Defined Contribution Plans	Dec. 31, 2014
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 $1.4 million, $0.9 million, and $0.4 million in 2014, 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 and $0.5 million in 2013 and 2012, respectively. Approximately $0.3 million associated with this plan are reflected as costs and expenses in the accompanying statements of operations for each of the years ended December 31, 2013, and 2012. This plan was terminated effective December 31, 2013.

	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 and $0.2 million were made to these plans in 2013 and 2012, 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
Quarterly Financial Information (Unaudited)	Dec. 31, 2014
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
		(In thousands, except per unit amounts)
	For the Year Ended December 31, 2014:
	Revenues	$	100,977		$	123,310		$	147,243		$	122,575
	Operating income (loss)		(17,904	)		(96,170	)		129,685			187,466
	Net income (loss)		(34,057	)		(114,206	)		103,226			163,116
	Net income (loss) attributable to Memorial Production Partners LP		(34,112	)		(114,194	)		103,076			163,277
	Net income (loss) noncontrolling interest		55			(12	)		150			(161	)
	Limited partners’ interest in net income (loss)		(34,118	)		(114,120	)		102,925			163,066
	Basic and diluted earnings per unit		(0.56	)		(1.86	)		1.39			1.88

		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(In thousands, except per unit amounts)
	For the Year Ended December 31, 2013:
	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 (loss) 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 (loss)		(5,017	)		46,133			(43,290	)		10,811
	Basic and diluted earnings per unit		(0.14	)		1.04			(0.97	)		0.18

	The Partnership consummated several common control acquisitions in 2013, as further discussed in Note 12, directly or indirectly from Memorial Resource and certain affiliates of NGP. The quarterly financial information for the year ended December 31, 2013 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
Supplemental Oil and Gas Information (Unaudited)	Dec. 31, 2014
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,
			2014			2013			2012
			(In thousands)
	Evaluated oil and natural gas properties (1)		$	3,007,214		$	1,748,438		$	1,539,642
	Support equipment and facilities			185,997			5,910			5,760
	Unevaluated oil and natural gas properties			—			—			5,004
	Accumulated depletion, depreciation, and amortization (1)			(989,103	)		(416,617	)		(265,710	)
	Total		$	2,204,108		$	1,337,731		$	1,284,696

	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,
			2014			2013			2012
			(In thousands)
	Property acquisition costs, proved		$	983,076		$	37,786		$	278,246
	Exploration			—			—			42,430
	Development (1)			279,318			145,830			62,472
	Total		$	1,262,394		$	183,616		$	383,148


	(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 and Ryder Scott to audit our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2014. 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:

			2014			2013			2012
	Oil ($/Bbl):
	WTI (1)		$	91.48		$	93.42		$	91.22

	NGL ($/Bbl):
	WTI (1)		$	91.48		$	93.42		$	91.27

	Natural Gas ($/MMbtu):
	Henry Hub (2)		$	4.35		$	3.67		$	2.76


	(1)The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential.
	(2)The weighted average Henry Hub 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, 2014, 2013 and 2012, respectively:

			Year Ended December 31, 2014
			Oil			Gas			NGLs			Equivalent
			(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
	Beginning of year		39,149			607,139			28,846			1,015,105
	Extensions and discoveries		849			12,723			711			22,085
	Purchase of minerals in place		69,095			13,036			22,351			561,713
	Production		(3,092	)		(41,494	)		(2,143	)		(72,902	)
	Sales of minerals in place		—			—			—			—
	Revision of previous estimates		(6,431	)		(31,777	)		(287	)		(72,090	)
	End of year		99,570			559,627			49,478			1,453,911

Proved developed reserves:
	Beginning of year		22,265			387,548			15,959			616,893
	End of year		54,526			380,397			35,539			920,783

Proved undeveloped reserves:
	Beginning of year		16,884			219,591			12,887			398,212
	End of year		45,044			179,230			13,939			533,128

		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

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:

·	We acquired 561.7 Bcfe in multiple acquisitions during the year ended December 31, 2014, the largest being the Wyoming Acquisition of 497.2 Bcfe. We also acquired 45.0 Bcfe from the Eagle Ford Acquisition. Downward revision of natural gas for the year ended December 31, 2014 was primarily due to updated well performance data in certain East Texas fields. Proved undeveloped reserves increased during the year ended December 31, 2014 primarily due to the Wyoming Acquisition.
·	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.
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,
		2014			2013			2012
		(In thousands)
Future cash inflows		$	13,191,866		$	6,892,150		$	6,511,776
Future production costs			(4,516,077	)		(2,719,024	)		(2,258,554	)
Future development costs			(1,222,221	)		(685,858	)		(620,944	)
Future net cash flows for estimated timing of cash flows			7,453,568			3,487,268			3,632,278
10% annual discount for estimated timing of cash flows			(4,693,960	)		(1,879,156	)		(2,042,362	)
Standardized measure of discounted future net cash flows		$	2,759,608		$	1,608,112		$	1,589,916


(1)We are subject to the Texas margin 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, 2014, 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, 2014:

		Years Ended December 31,
		2014			2013			2012
		(In thousands)
Beginning of year		$	1,608,112		$	1,589,916		$	1,499,414
Sale of oil and natural gas produced, net of production costs			(323,994	)		(234,520	)		(160,023	)
Purchase of minerals in place			1,489,477			23,160			375,953
Sale of minerals in place			—			—			(154,963	)
Extensions and discoveries			44,745			136,423			265,108
Changes in income taxes, net			—			—			1,947
Changes in prices and costs			(168,500	)		(74,395	)		(331,760	)
Previously estimated development costs incurred			223,861			174,490			66,360
Net changes in future development costs			(74,579	)		(74,867	)		(1,140	)
Revisions of previous quantities			(163,207	)		(141,122	)		(90,587	)
Accretion of discount			160,811			158,991			150,136
Change in production rates and other			(37,118	)		50,036			(30,529	)
End of year		$	2,759,608		$	1,608,112		$	1,589,916

Subsequent_Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	Note 17. Subsequent Events

	2015 Acquisition

	On February 23, 2015, we and Memorial Resource completed a transaction in which we exchanged our oil and gas properties in North Louisiana and approximately $78 million in cash for Memorial Resource’s East Texas and non-core Louisiana oil and gas properties. Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors. This transaction has an effective date of January 1, 2015.

	Conversion of Subordinated Units

	The subordination period for the 5,360,912 subordinated units ended on February 13, 2015. All of the subordinated units, which were owned by MRD Holdco, converted to common units on a one-to-one basis at the end of the subordination period.

	2015 Repurchases of Common Units

	We repurchased an additional $28.5 million in common units, which represents a repurchase and retirement of 1,909,583 common units under the MEMP Repurchase Program through February 1, 2015.

Organization_and_Basis_of_Pres1

Organization and Basis of Presentation (Policies)

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

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.

The Partnership was formed in April 2011 by Memorial Resource Development LLC (“MRD LLC”) to own, acquire and exploit oil and natural gas properties in North America. Memorial Resource Development Corp. (“MRD”) was formed by MRD LLC in January 2014 to exploit, develop and acquire natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed in April 2011 by Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P. (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. In June 2014, (i) the Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”), after which MRD Holdco owned 100% of MRD LLC, and (ii) MRD LLC distributed certain assets, including all of our subordinated units, to MRD Holdco. On June 18, 2014, MRD LLC contributed substantially all of its assets, including its interest in our general partner, to MRD in connection with MRD’s initial public offering. On June 27, 2014, MRD LLC merged into MRD Operating LLC, a subsidiary of MRD. 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”). The remaining IDRs are owned by our general partner.

Unless the context requires otherwise, references to “Memorial Resource” refer collectively to MRD and its subsidiaries other than the Partnership. 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. Our general partner is responsible for managing all of the Partnership’s operations and activities.

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).

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.

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 MRD LLC 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 was 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 owned by WHT Energy Partners (“WHT”) (the “WHT Properties”) 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 MRD LLC 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 are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements were derived from the historical accounting records of the previous owners and reflect the historical financial position, results of operations and cash flows for all periods presented.

The previous owners combined financial statements reflect: (i) certain oil and gas properties acquired from MRD LLC 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) MRD LLC.

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 current presentation.

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 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 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 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, 2014 and 2013, 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. Support equipment and facilities are depreciated using the straight-line method generally based on estimated useful lives of fifteen to forty years.

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, 2014, 2013 and 2012.

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. We engaged Netherland, Sewell & Associates, Inc. (“NSAI”) and Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2014.

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 cost 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 may 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 and generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2014, 2013 and 2012 was approximately $4.2 million, $5.8 million, and $2.0 million, respectively.

Impairments

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to 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, 2014, 2013 and 2012 was approximately $407.5 million, $54.4 million, and $10.5 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 in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.

Book Overdrafts

Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.

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, 2014 or 2013.

The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:

Years Ending December 31,

2014

2013

2012

Major customers:

Phillips 66 (1)

13%

15%

13%

ConocoPhillips (1)

n/a

14%

Sinclair Oil & Gas Company

12%

n/a

·Phillips 66 purchased production pursuant to existing marketing agreements with terms that are currently on “evergreen” status. Evergreen contracts automatically renew on a month-to-month basis until either party gives 30 or 60 days advance written notice of non-renewal. 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 a wholly-owned subsidiary of 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. Memorial Resource allocated indirect general and administrative costs based on time allocations for the year ended December 31, 2014, on production for the year ended December 31, 2013 and on a reserve basis methodology for the year ended December 31, 2012. 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 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.

Capitalized Interest

We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2014, we had $2.8 million in capitalized interest. We did not have any capitalized interest for the years ended December 31, 2013 and 2012.

Income Tax

We are organized as a pass-through entity for federal and most state income tax purposes. As a result, our partners are responsible for federal and state income taxes on their share of our taxable income. Certain of our consolidated subsidiaries are taxed as corporations for federal and state income tax purposes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. Deferred income 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 income tax liability of $3.1 million and $2.0 million at December 31, 2014 and 2013, respectively.

We must recognize the income 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 income 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, 2014 or 2013.

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.

Accrued Liabilities

Current accrued liabilities consisted of the following at the dates indicated (in thousands):

December 31,

2014

2013

Accrued capital expenditures

30,598

16,193

Accrued interest payable

24,673

8,931

Accrued lease operating expense

14,632

10,666

Accrued ad valorem taxes

8,231

1,531

Accrued general and administrative expenses

1,276

1,547

Environmental liability

2,092

437

Other

2,969

542

84,471

39,847

Supplemental Cash Flows

Supplemental cash flow for the periods presented (in thousands):

For the Year Ended

December 31,

2014

2013

2012

Supplemental cash flows:

Cash paid for interest, net of amounts capitalized

63,709

40,413

13,869

Cash paid for taxes

151

168

Noncash investing and financing activities:

Change in capital expenditures in payables and accrued liabilities

14,405

12,178

4,435

Repurchases under unit repurchase program

1,372

—

Accounts receivable related to Wyoming Acquisition

9,569

—

Accounts receivable related to Double A Acquisition

586

—

Assumptions of asset retirement obligations related to properties acquired

4,265

1,581

5,448

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

—

New Accounting Pronouncements

Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Partnership beginning on January 1, 2017. The Partnership is currently assessing the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures.

Reporting Discontinued Operations. In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures. The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition. We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Tables)	12 Months Ended
Summary of Significant Accounting Policies (Tables)	Dec. 31, 2014
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,
		2014		2013			2012
	Major customers:
	Phillips 66 (1)		13%		15%			13%
	ConocoPhillips (1)	n/a		n/a				14%
	Sinclair Oil & Gas Company		12%	n/a			n/a


	·Phillips 66 purchased production pursuant to existing marketing agreements with terms that are currently on “evergreen” status. Evergreen contracts automatically renew on a month-to-month basis until either party gives 30 or 60 days advance written notice of non-renewal. 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 Accounts Receivable from Joint Interest Owners and Other
	Accounts receivable from joint interest owners and other consisted of the following at the dates indicated (in thousands):

		December 31,			December 31,
		2014			2013
	Derivatives expired positions	$	13,754		$	—
	Wyoming Acquisition		9,569			—
	Joint interest owners		11,235			4,147
	Other		900			487
		$	35,458		$	4,634

Summary of Current Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands):

		December 31,			December 31,
		2014			2013
	Accrued capital expenditures	$	30,598		$	16,193
	Accrued interest payable		24,673			8,931
	Accrued lease operating expense		14,632			10,666
	Accrued ad valorem taxes		8,231			1,531
	Accrued general and administrative expenses		1,276			1,547
	Environmental liability		2,092			437
	Other		2,969			542
		$	84,471		$	39,847

Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands):

		For the Year Ended
		December 31,
		2014			2013				2012
	Supplemental cash flows:
	Cash paid for interest, net of amounts capitalized	$	63,709		$	40,413			$	13,869
	Cash paid for taxes		151			168				22
	Noncash investing and financing activities:
	Change in capital expenditures in payables and accrued liabilities		14,405			12,178				4,435
	Repurchases under unit repurchase program		1,372			—				—
	Accounts receivable related to Wyoming Acquisition		9,569			—				—
	Accounts receivable related to Double A Acquisition		586			—				—
	Assumptions of asset retirement obligations related to properties acquired		4,265			1,581				5,448
	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

Acquisitions_and_Divestitures_

Acquisitions and Divestitures (Tables)	12 Months Ended
Acquisitions and Divestitures (Tables)	Dec. 31, 2014
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,
	2014				2013				2012
	$	4,363			$	6,729			$	4,135

Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed	The following table summarizes the preliminary fair value of the third party assets acquired and liabilities assumed in the Wyoming Acquisition (in thousands):
		Wyoming
		Acquisition
	Oil and gas properties	$	930,168
	Asset retirement obligations		(3,980	)
	Revenues payable		(375	)
	Accrued liabilities		(19,693	)
	Total identifiable net assets	$	906,120

	The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):

		Eagle Ford
		Acquisition
	Oil and gas properties	$	168,606
	Asset retirement obligations		(285	)
	Accrued liabilities		(250	)
	Total identifiable net assets	$	168,071

	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 following table summarizes the fair value of the third party assets acquired and liabilities assumed as of each acquisition date (in thousands).

		Undisclosed Seller				Goodrich				Menemsha			Other
		Acquisition				Acquisition				Acquisition			Acquisitions
	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

Supplemental Pro Forma Information	The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2014 and 2013 as though the Eagle Ford Acquisition and Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

		For the Year Ended December 31,
		2014 (1)				2013
		(In thousands, except per unit amounts)
	Revenues	$	594,570			$	583,823
	Net income (loss)		156,308				153,355
	Basic and diluted earnings per unit		2.2				3.08



	·Amounts represent historical revenues and expenses from January 1, 2014 through the respective dates of acquisition.


	The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2012 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 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
		(In thousands,
		except per unit amounts)
	Revenues	$	286,004
	Net income		58,472
	Basic and diluted earnings per unit		0.53

Fair_Value_Measurements_of_Fin1

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
Fair Value Measurements of Financial Instruments (Tables)	Dec. 31, 2014
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, 2014 and December 31, 2013 for each of the fair value hierarchy levels:


		Fair Value Measurements at December 31, 2014 Using
		Quoted Prices in		Significant Other		Significant
		Active Market		Observable Inputs		Unobservable Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	564,913	$	—	$	564,913
	Interest rate derivatives		—		1,305		—		1,305
	Total assets	$	—	$	566,218	$	—	$	566,218

	Liabilities:
	Commodity derivatives	$	—	$	45,831	$	—	$	45,831
	Interest rate derivatives		—		3,289		—		3,289
	Total liabilities	$	—	$	49,120	$	—	$	49,120


		Fair Value Measurements at December 31, 2013 Using
		Quoted Prices in		Significant Other		Significant
		Active Market		Observable Inputs		Unobservable Inputs
		(Level 1)		(Level 2)		(Level 3)		Fair Value
		(In thousands)
	Assets:
	Commodity derivatives	$	—	$	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

Risk_Management_and_Derivative1

Risk Management and Derivative Instruments (Tables)	12 Months Ended
Risk Management and Derivative Instruments (Tables)	Dec. 31, 2014
Open Commodity Positions	At December 31, 2014, the Partnership had the following open commodity positions:

		2015				2016				2017				2018			2019
	Natural Gas Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (MMBtu)		2,605,278				2,692,442				2,450,067				2,160,000			1,914,583
	Weighted-average fixed price	$	4.28			$	4.4			$	4.31			$	4.51		$	4.75

	Collar contracts:
	Average Monthly Volume (MMBtu)		350,000				—				—				—			—
	Weighted-average floor price	$	4.62			$	—			$	—			$	—		$	—
	Weighted-average ceiling price	$	5.8			$	—			$	—			$	—		$	—

	Call spreads (1):
	Average Monthly Volume (MMBtu)		80,000				—				—				—			—
	Weighted-average sold strike price	$	5.25			$	—			$	—			$	—		$	—
	Weighted-average bought strike price	$	6.75			$	—			$	—			$	—		$	—

	Basis swaps:
	Average Monthly Volume (MMBtu)		2,940,000				2,508,333				415,000				115,000			—
	Spread	$	(0.12	)		$	(0.04	)		$	0			$	0.15		$	—

	Crude Oil Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		314,281				332,813				326,600				312,000			160,000
	Weighted-average fixed price	$	90.96			$	85.83			$	84.38			$	83.74		$	85.52

	Collar contracts:
	Average Monthly Volume (Bbls)		5,000				—				—				—			—
	Weighted-average floor price	$	80			$	—			$	—			$	—		$	—
	Weighted-average ceiling price	$	94			$	—			$	—			$	—		$	—

	Basis swaps:
	Average Monthly Volume (Bbls)		97,500				95,000				—				—			—
	Spread	$	(7.07	)		$	(9.56	)		$	—			$	—		$	—

	NGL Derivative Contracts:
	Fixed price swap contracts:
	Average Monthly Volume (Bbls)		149,200				84,600				—				—			—
	Weighted-average fixed price	$	43.02			$	41.49			$	—			$	—		$	—



	(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, 2014, we had the following interest rate swap open positions:


			2015				2016				2017
	Average Monthly Notional (in thousands)		$	314,167			$	250,000			$	250,000
	Weighted-average fixed rate			1.349	%			1.029	%			1.62	%
	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, 2014 and 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.

					Asset Derivatives								Liability Derivatives
					December 31,				December 31,				December 31,			December 31,
	Type		Balance Sheet Location		2014				2013				2014			2013
					(In thousands)
	Commodity contracts		Short-term derivative instruments		$	225,882			$	18,578			$	17,297		$	17,120
	Interest rate swaps		Short-term derivative instruments			—				845				3,289			2,699
	Gross fair value					225,882				19,423				20,586			19,819
	Netting arrangements		Short-term derivative instruments			(17,297	)			(11,823	)			(17,297	)		(11,823	)
	Net recorded fair value		Short-term derivative instruments		$	208,585			$	7,600			$	3,289		$	7,996

	Commodity contracts		Long-term derivative instruments		$	339,031			$	77,348			$	28,534		$	38,456
	Interest rate swaps		Long-term derivative instruments			1,305				27				—			2,137
	Gross fair value					340,336				77,375				28,534			40,593
	Netting arrangements		Long-term derivative instruments			(28,534	)			(34,718	)			(28,534	)		(34,718	)
	Net recorded fair value		Long-term derivative instruments		$	311,802			$	42,657			$	—		$	5,875

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, 2014, 2013, and 2012:

			Statements of		For the Year Ended December 31,
			Operations Location		2014				2013				2012
	Commodity derivative contracts		(Gain) loss on commodity derivatives		$	(492,254	)		$	(26,281	)		$	(21,417	)
	Interest rate derivatives		Interest expense, net			(151	)			(548	)			4,839

Disaggregated Basis Swap [Member]
Open Commodity Positions	Our basis swaps included in the table above are presented on a disaggregated basis below:


		2015				2016				2017				2018
	Natural Gas Derivative Contracts:
	NGPL TexOk basis swaps:
	Average Monthly Volume (MMBtu)		2,280,000				2,103,333				300,000				—
	Spread	$	(0.11	)		$	(0.06	)		$	(0.05	)		$	—

	HSC basis swaps:
	Average Monthly Volume (MMBtu)		150,000				135,000				115,000				115,000
	Spread	$	(0.08	)		$	0.07			$	0.14			$	0.15

	CIG basis swaps:
	Average Monthly Volume (MMBtu)		210,000				—				—				—
	Spread	$	(0.25	)		$	—			$	—			$	—

	TETCO STX basis swaps:
	Average Monthly Volume (MMBtu)		300,000				270,000				—				—
	Spread	$	(0.09	)		$	0.06			$	—			$	—

	Crude Oil Derivative Contracts:
	Midway-Sunset basis swaps:
	Average Monthly Volume (Bbls)		57,500				55,000				—				—
	Spread - Brent	$	(9.73	)		$	(13.35	)		$	—			$	—

	Midland basis swaps:
	Average Monthly Volume (Bbls)		40,000				40,000				—				—
	Spread - WTI	$	(3.25	)		$	(4.34	)		$	—			$	—

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2014
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, 2014, 2013, and 2012:

		2014			2013			2012
		(in thousands)
	Asset retirement obligations at beginning of period	$	99,619		$	91,349		$	82,722
	Liabilities added from acquisitions or drilling		5,815			2,116			5,958
	Liabilities removed upon sale of wells		—			—			(1,795	)
	Liabilities settled		(651	)		(20	)		(91	)
	Accretion expense		5,618			4,853			4,377
	Revision of estimates		(29	)		1,321			178
	Asset retirement obligations at end of period	$	110,372		$	99,619		$	91,349

Restricted_Investments_Tables

Restricted Investments (Tables)	12 Months Ended
Restricted Investments (Tables)	Dec. 31, 2014
Investments Debt And Equity Securities [Abstract]
Restricted Investment Balance	The components of the restricted investment balance are as follows

		December 31,		December 31,
		2014		2013
		(In thousands)
	BOEM platform abandonment (See Note 13)	$	69,954	$	66,373
	BOEM lease bonds		794		794

	SPBPC Collateral:
	Contractual pipeline and surface facilities abandonment		2,701		2,306
	California State Lands Commission pipeline right-of-way bond		3,005		3,005
	City of Long Beach pipeline facility permit		500		500
	Federal pipeline right-of-way bond		307		307
	Port of Long Beach pipeline license		100		100
	Restricted investments	$	77,361	$	73,385

Long_Term_Debt_Tables

Long Term Debt (Tables)	12 Months Ended
Long Term Debt (Tables)	Dec. 31, 2014
Debt Disclosure [Abstract]
Consolidated Debt Obligations
	Our consolidated debt obligations consisted of the following at the dates indicated:

		December 31,			December 31,
		2014			2013
		(In thousands)
	OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	412,000		$	103,000
	2021 Senior Notes, fixed-rate, due May 2021 (1)		700,000			700,000
	2022 Senior Notes, fixed-rate, due August 2022 (2)		500,000			—
	Unamortized discounts		(16,587	)		(10,933	)
	Total long-term debt	$	1,595,413		$	792,067


	(1) The estimated fair value of our 2021 Senior Notes was $563.5 million and $721.0 million at December 31, 2014 and 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
	(2) The estimated fair value of our 2022 Senior Notes was $380.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Borrowing Base Credit Facility	Credit facilities tied to a borrowing base 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,
		2014
		(In thousands)
	OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	1,440,000

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,
		2014			2013			2012
	OLLC revolving credit facility		2.67	%		3.25	%		2.74	%
	WHT revolving credit facility	n/a				2.29	%		2.6	%
	REO revolving credit facility	n/a			n/a				3.4	%
	Stanolind revolving credit facility	n/a				3.52	%		3.76	%
	Boaz revolving credit facility	n/a				2.97	%		3.12	%
	Crown revolving credit facility	n/a				3.38	%		4.2	%
	Tanos revolving credit facility	n/a				3.1	%		2.31	%
	Propel Energy revolving credit facility	n/a				3.08	%		3.28	%

Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:

		December 31,			December 31,
		2014			2013
		(In thousands)
	OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1)	$	6,468		$	5,413
	2021 Senior Notes (2)		13,308			15,053
	2022 Senior Notes (2)		7,958			—
	Total	$	27,734		$	20,466


	(1) Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.
	(2) Unamortized deferred financing costs are amortized using the straight line method which generally approximates the effective interest method.

Advances and Repayments	The following table presents borrowings and repayments under our consolidated and combined revolving credit facilities for the periods presented (in thousands):

					Previous Owner
		OLLC Revolving			Revolving
		Credit Facility			Credit Facility			Total
	For the Twelve Months Ended December 31, 2014:
	Advances on revolving credit facility	$	1,446,000		$	—		$	1,446,000
	Payments on revolving credit facility		(1,137,000	)		—			(1,137,000	)

	For the Twelve Months 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 Twelve Months 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	)

Equity_and_Distributions_Table

Equity and Distributions (Tables)	12 Months Ended
Equity and Distributions (Tables)	Dec. 31, 2014
Limited Partners Capital Account [Line Items]
Summary of Changes in Number of Outstanding Units	The following table summarizes changes in the number of outstanding units since December 31, 2011:

										General
		Common				Subordinated				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
	Common units issued		24,840,000				—				—
	Restricted common units issued		684,954				—				—
	Restricted common units forfeited		(38,294	)			—				—
	Restricted common units repurchased (1)		(42,587	)			—				—
	Common units repurchased under repurchase program		(899,912	)			—				—
	General partner units issued		—				—				25,497
	Balance, December 31, 2014		80,421,992				5,360,912				86,797


	·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 $1.0 million and $0.1 million for the years ended December 31, 2014 and 2013, respectively. 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:

			Target Quarterly Distributions				Marginal Percentage Interest in Distributions
			Target Amount				Unitholders				General Partner				IDR (1)
	Minimum Quarterly Distribution		$	0.475				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	%


	·The Funds collectively indirectly own 50% of our incentive distribution rights. The remaining IDRs are owned by our general partner.

Summary of Quarterly Cash Distribution Rates	The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts):

																	Distribution
									Amount				Aggregate				Received by
	Quarter		Declaration Date		Record Date		Payable Date		Per Unit				Distribution				Affiliates
	4th Quarter 2014		26-Jan-15		5-Feb-15		12-Feb-15		$	0.55			$	46.3			$	3.1
	3rd Quarter 2014		23-Oct-14		5-Nov-14		12-Nov-14		$	0.55			$	47.8			$	3.1
	2nd Quarter 2014		24-Jul-14		5-Aug-14		12-Aug-14		$	0.55			$	39.5			$	3
	1st Quarter 2014		24-Apr-14		6-May-14		13-May-14		$	0.55			$	33.8			$	3
	4th Quarter 2013		27-Jan-14		6-Feb-14		13-Feb-14		$	0.55			$	33.8			$	3
	3rd Quarter 2013		22-Oct-13		1-Nov-13		12-Nov-13		$	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

Previous Owners [Member]
Limited Partners Capital Account [Line Items]
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 Properties				REO				WHT Properties				Cinco Group				Total Previous Owners
	Balance, December 31, 2011		$	50,853			$	72,755			$	99,524			$	211,444			$	434,576
	Net income			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 previous owners			—				—				—				(20,782	)			(20,782	)
	Balance, December 31, 2013		$	—			$	—			$	—			$	—			$	—

Earnings_per_Unit_Tables

Earnings per Unit (Tables)	12 Months Ended
Earnings per Unit (Tables)	Dec. 31, 2014
Earnings Per Share [Line Items]
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,
		2014		2013		2012
	Net income (loss) attributable to Memorial Production Partners LP	$	118,047	$	20,001	$	46,414
	Less: Previous owners interest in net income (loss)		—		11,275		46,293
	Less: General partner's 0.1% interest in net income (loss)		118		9		—
	Less: IDRs attributable to corresponding period		202		81		—
	Net income (loss) available to limited partners	$	117,727	$	8,636	$	121

	Weighted average limited partner units outstanding:
	Common units		65,498		40,656		17,519
	Subordinated units		5,361		5,361		5,361
	Total		70,859		46,017		22,880
	Basic and diluted EPU	$	1.66	$	0.19	$	0.01

Supplemental EPU [Member]
Earnings Per Share [Line Items]
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,
		2014		2013		2012
	Net income (loss) attributable to Memorial Production Partners LP	$	118,047	$	20,001	$	46,414
	Less: General partner's 0.1% interest in net income (loss)		118		20		46
	Less: IDRs attributable to corresponding period		202		81		—
	Net income (loss) available to limited partners	$	117,727	$	19,900	$	46,368

	Weighted average limited partner units outstanding:
	Common units		65,498		40,656		17,519
	Subordinated units		5,361		5,361		5,361
	Total		70,859		46,017		22,880
	Supplemental basic and diluted EPU	$	1.66	$	0.43	$	2.03

Equitybased_Awards_Tables

Equity-based Awards (Tables)	12 Months Ended
Equity-based Awards (Tables)	Dec. 31, 2014
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:

						Weighted-
						Average Grant
						Date Fair Value
		Number of Units				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
	Granted (4)		684,954			$	22.39
	Forfeited		(38,294	)		$	20.54
	Vested		(260,067	)		$	18.56
	Restricted common units outstanding at December 31, 2014		1,093,520			$	20.93


	·Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
	·The aggregate grant date fair value of restricted common unit awards issued in 2012 was $5.2 million based on grant date market prices ranging from of $17.14 to $18.58 per unit.
	·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 aggregate grant date fair value of restricted common unit awards issued in 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 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,
	2014				2013			2012
	$	7,874			$	3,558		$	1,423

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
Related Party Transactions (Tables)	Dec. 31, 2014
Related Party Transaction [Line Items]
Schedule of Net Assets Recorded by Partnership	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

	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

	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

Schedule of Acquisition of Net Assets	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

	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

Net Book Value of Assets Contributed to Memorial Resource	The net book value of the assets contributed to MRD LLC 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

Double A and Wattenberg Acquisition [Member]
Related Party Transaction [Line Items]
Schedule of Net Assets Recorded by Partnership	The Partnership recorded the following net assets (in thousands):

		Double A				Wattenberg
		Acquisition				Acquisition
	Oil and gas properties, net	$	37,838			$	9,822
	Asset retirement obligations		(908	)			(149	)
	Other current liabilities		(722	)			—
	Total identifiable net assets	$	36,208			$	9,673

Omnibus Agreement [Member]
Related Party Transaction [Line Items]
Schedule of Amount of General and Administrative Costs and Expenses Recognized	The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands):

	For the Year Ended December 31,
	2014				2013				2012
	$	24,372			$	9,440			$	1,771

REO [Member]
Related Party Transaction [Line Items]
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 Twelve Months Ended December 31,
	2012
	$	1,552

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Environmental Reserves	The following table presents the activity of our environmental reserves for the periods presented:

		2014				2013			2012
		(In thousands)
	Balance at beginning of period	$	437			$	1,051		$	1,747
	Charged to costs and expenses		2,852				—			(225	)
	Payments		(1,197	)			(614	)		(471	)
	Balance at end of period	$	2,092			$	437		$	1,051

Minimum Balances Attributable to Net Working Interest	The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):

	30-Jun-15	$	72,450
	30-Jun-16	$	76,590
	31-Dec-16	$	78,660

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, 2014 (in thousands):

			Amortized
	Investment		Cost
	U.S. Bank Money Market Cash Equivalent		$	135,176
	Less: Outside working interest owners share			(65,222	)
			$	69,954

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 (in thousands):

							Payment or Settlement Due by Period
	Purchase commitment		Total				2015			2016		2017		2018		2019		Thereafter
	Operating leases		$	3,665			$	788		$	416	$	205	$	205	$	205	$	1,846

CO2 Minimum Purchase Commitment	At December 31, 2014, we had a CO2 purchase commitment with a third party that was assumed in our Wyoming Acquisition. The table below outlines our purchase commitment under the contract (in thousands):

							Payment or Settlement Due by Period
	Purchase commitment		Total				2015			2016		2017		2018		2019		Thereafter
	CO2 minimum purchase commitment:		$	50,495			$	9,608		$	10,179	$	10,151	$	6,995	$	7,060	$	6,502

Quarterly_Financial_Informatio1

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
Quarterly Financial Information (Unaudited) (Tables)	Dec. 31, 2014
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
		(In thousands, except per unit amounts)
	For the Year Ended December 31, 2014:
	Revenues	$	100,977		$	123,310		$	147,243		$	122,575
	Operating income (loss)		(17,904	)		(96,170	)		129,685			187,466
	Net income (loss)		(34,057	)		(114,206	)		103,226			163,116
	Net income (loss) attributable to Memorial Production Partners LP		(34,112	)		(114,194	)		103,076			163,277
	Net income (loss) noncontrolling interest		55			(12	)		150			(161	)
	Limited partners’ interest in net income (loss)		(34,118	)		(114,120	)		102,925			163,066
	Basic and diluted earnings per unit		(0.56	)		(1.86	)		1.39			1.88

		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
		(In thousands, except per unit amounts)
	For the Year Ended December 31, 2013:
	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 (loss) 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 (loss)		(5,017	)		46,133			(43,290	)		10,811
	Basic and diluted earnings per unit		(0.14	)		1.04			(0.97	)		0.18

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
Supplemental Oil and Gas Information (Unaudited) (Tables)	Dec. 31, 2014
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,
			2014			2013			2012
			(In thousands)
	Evaluated oil and natural gas properties (1)		$	3,007,214		$	1,748,438		$	1,539,642
	Support equipment and facilities			185,997			5,910			5,760
	Unevaluated oil and natural gas properties			—			—			5,004
	Accumulated depletion, depreciation, and amortization (1)			(989,103	)		(416,617	)		(265,710	)
	Total		$	2,204,108		$	1,337,731		$	1,284,696

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,
			2014			2013			2012
			(In thousands)
	Property acquisition costs, proved		$	983,076		$	37,786		$	278,246
	Exploration			—			—			42,430
	Development (1)			279,318			145,830			62,472
	Total		$	1,262,394		$	183,616		$	383,148


	(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:

			2014			2013			2012
	Oil ($/Bbl):
	WTI (1)		$	91.48		$	93.42		$	91.22

	NGL ($/Bbl):
	WTI (1)		$	91.48		$	93.42		$	91.27

	Natural Gas ($/MMbtu):
	Henry Hub (2)		$	4.35		$	3.67		$	2.76


	(1)The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential.
	(2)The weighted average Henry Hub 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, 2014, 2013 and 2012, respectively:

			Year Ended December 31, 2014
			Oil			Gas			NGLs			Equivalent
			(MBbls)			(MMcf)			(MBbls)			(MMcfe)
	Proved developed and undeveloped reserves:
		Beginning of year		39,149			607,139			28,846			1,015,105
		Extensions and discoveries		849			12,723			711			22,085
		Purchase of minerals in place		69,095			13,036			22,351			561,713
		Production		(3,092	)		(41,494	)		(2,143	)		(72,902	)
		Sales of minerals in place		—			—			—			—
		Revision of previous estimates		(6,431	)		(31,777	)		(287	)		(72,090	)
		End of year		99,570			559,627			49,478			1,453,911

	Proved developed reserves:
		Beginning of year		22,265			387,548			15,959			616,893
		End of year		54,526			380,397			35,539			920,783

	Proved undeveloped reserves:
		Beginning of year		16,884			219,591			12,887			398,212
		End of year		45,044			179,230			13,939			533,128

			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

Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows is as follows:

			Years Ended December 31,
			2014			2013			2012
			(In thousands)
	Future cash inflows		$	13,191,866		$	6,892,150		$	6,511,776
	Future production costs			(4,516,077	)		(2,719,024	)		(2,258,554	)
	Future development costs			(1,222,221	)		(685,858	)		(620,944	)
	Future net cash flows for estimated timing of cash flows			7,453,568			3,487,268			3,632,278
	10% annual discount for estimated timing of cash flows			(4,693,960	)		(1,879,156	)		(2,042,362	)
	Standardized measure of discounted future net cash flows		$	2,759,608		$	1,608,112		$	1,589,916


	(1)We are subject to the Texas margin 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, 2014, 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, 2014:

			Years Ended December 31,
			2014			2013			2012
			(In thousands)
	Beginning of year		$	1,608,112		$	1,589,916		$	1,499,414
	Sale of oil and natural gas produced, net of production costs			(323,994	)		(234,520	)		(160,023	)
	Purchase of minerals in place			1,489,477			23,160			375,953
	Sale of minerals in place			—			—			(154,963	)
	Extensions and discoveries			44,745			136,423			265,108
	Changes in income taxes, net			—			—			1,947
	Changes in prices and costs			(168,500	)		(74,395	)		(331,760	)
	Previously estimated development costs incurred			223,861			174,490			66,360
	Net changes in future development costs			(74,579	)		(74,867	)		(1,140	)
	Revisions of previous quantities			(163,207	)		(141,122	)		(90,587	)
	Accretion of discount			160,811			158,991			150,136
	Change in production rates and other			(37,118	)		50,036			(30,529	)
	End of year		$	2,759,608		$	1,608,112		$	1,589,916

Organization_and_Basis_of_Pres2

Organization and Basis of Presentation - Additional Information (Detail)	Dec. 31, 2014
MRD Holdco [Member]
Organization And Basis Of Presentation (Textual) [Abstract]
Affiliate's ownership percentage in our former parent	100.00%
General Partner [Member]
Organization And Basis Of Presentation (Textual) [Abstract]
Partnership ownership percentage	0.10%
General Partner [Member] \| The Funds [Member]
Organization And Basis Of Presentation (Textual) [Abstract]
Percentage of economic interest in incentive distribution rights	50.00%
Limited Partners Common Units [Member]
Organization And Basis Of Presentation (Textual) [Abstract]
Partnership ownership percentage	99.90%

Summary_of_Significant_Account2

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Significant Accounting Policies [Line Items]
Capitalized exploratory drilling costs pending evaluation	$0	$0	$0
Amortization expense including write-off of debt issuance costs	4,200,000	5,800,000	2,000,000
Impairment expense	407,540,000	54,362,000	10,532,000
Capitalized interest	2,800,000	0	0
Deferred income tax liabilities, net	3,100,000	2,000,000
Chance of tax effect being realized	More than a 50%
Uncertain tax positions that required recognition	$0	$0
Customer Concentration Risk [Member] \| Revenues [Member]
Significant Accounting Policies [Line Items]
Percentage of total revenue	10.00%
Minimum [Member]
Significant Accounting Policies [Line Items]
Estimated useful lives	3 years
Maximum [Member]
Significant Accounting Policies [Line Items]
Estimated useful lives	5 years
Support Equipment and Facilities [Member] \| Minimum [Member]
Significant Accounting Policies [Line Items]
Estimated useful lives	15 years
Support Equipment and Facilities [Member] \| Maximum [Member]
Significant Accounting Policies [Line Items]
Estimated useful lives	40 years

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Major Customers (Detail) (Customer Concentration Risk [Member], Revenues [Member])	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Significant Accounting Policies [Line Items]
Total Reported Revenues	10.00%
Phillips 66 [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	13.00%	[1]	15.00%	[1]	13.00%	[1]
Conoco Phillips [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues					14.00%	[1]
Sinclair Oil & Gas Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	12.00%

[1]	(1) Phillips 66 purchased production pursuant to existing marketing agreements with terms that are currently on bevergreenb status. Evergreen contracts automatically renew on a month-to-month basis until either party gives 30 or 60 days advance written notice of non-renewal. 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_Significant_Account4

Summary of Significant Accounting Policies - Major Customers (Parantheticals) (Detail)	12 Months Ended
	Dec. 31, 2014
Minimum [Member]
Significant Accounting Policies [Line Items]
Notice Period for Contract Non-Renewal	30 days
Maximum [Member]
Significant Accounting Policies [Line Items]
Notice Period for Contract Non-Renewal	60 days

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Summary of Accounts Receivable from Joint Interest Owners and Other (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Derivatives expired positions	$13,754
Joint interest owners	11,235	4,147
Other	900	487
Accounts receivable from joint interest owners and other	35,458	4,634
Wyoming Acquisition [Member]
Related Party Transaction [Line Items]
Wyoming Acquisition	$9,569

Summary_of_Significant_Account6

Summary of Significant Accounting Policies - Summary of Current Accrued Liabilities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Accrued Liabilities Current [Abstract]
Accrued capital expenditures	$30,598	$16,193
Accrued interest payable	24,673	8,931
Accrued lease operating expense	14,632	10,666
Accrued ad valorem taxes	8,231	1,531
Accrued general and administrative expenses	1,276	1,547
Environmental liability	2,092	437
Other	2,969	542
Accrued liabilities, Total	$84,471	$39,847

Summary_of_Significant_Account7

Summary of Significant Accounting Policies - Summary of Supplemental Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$63,709	$40,413	$13,869
Cash paid for taxes	151	168	22
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities	14,405	12,178	4,435
Repurchases under unit repurchase program	1,372
Assumptions of asset retirement obligations related to properties acquired	4,265	1,581	5,448
Contribution related to sale of assets to NGP affiliate - restricted cash			2,013
Accrued equity offering costs			170
Distributions to partners			48
Wyoming Acquisition [Member]
Noncash investing and financing activities:
Accounts receivable	9,569
Double A Acquisition [Member]
Noncash investing and financing activities:
Accounts receivable	586
Cinco Group acquisition [Member]
Noncash investing and financing activities:
Accounts receivable		$4,352

Acquisitions_and_Divestitures_1

Acquisitions and Divestitures - Acquisition-Related Costs (Detail) (General and Administrative Expense, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
General and Administrative Expense
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	$4,363	$6,729	$4,135

Acquisitions_and_Divestitures_2

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

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

Oct. 11, 2012

Dec. 31, 2013

Dec. 31, 2012

Jan. 01, 2013

Sep. 18, 2012

Jul. 11, 2012

Jul. 01, 2014

Mar. 25, 2014

Dec. 31, 2014

1-May-12

Sep. 28, 2012

Jul. 31, 2012

Business Acquisition And Divestiture [Line Items]

Oil and gas properties

$9,300,000

Interest Sold In Oil And Gas Properties

4,525,000

34,521,000

Proceeds in excess of book value of properties sold

6,300,000

Louisiana [Member]

Business Acquisition And Divestiture [Line Items]

Cash proceeds related to sale of assets to NGP affiliate

38,100,000

Interest Sold In Oil And Gas Properties

40,100,000

Tanos [Member]

Business Acquisition And Divestiture [Line Items]

Maximum allowable additional proceeds

2,000,000

Aggregate gain of acquisition

1,400,000

Contingent consideration

400,000

Tanos [Member] | Minimum [Member]

Business Acquisition And Divestiture [Line Items]

Assets sold

1,500,000

Garza County [Member] | Cinco Group acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Net gain (loss) on disposition of previous owner's assets

2,200,000

7,600,000

Ector County [Member] | Cinco Group acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Interest Sold In Oil And Gas Properties

4,700,000

26,100,000

Non Operated Oil And Gas Properties [Member] | Tanos [Member]

Business Acquisition And Divestiture [Line Items]

Net gain (loss) on disposition of previous owner's assets

1,400,000

Asset sold

2,900,000

Wyoming Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Purchase price

906,100,000

Revenue recorded in statement of operations

72,000,000

Earnings recorded in statement of operations

22,900,000

Eagle Ford [Member]

Business Acquisition And Divestiture [Line Items]

Purchase price

168,100,000

Revenue recorded in statement of operations

36,500,000

Earnings recorded in statement of operations

16,300,000

Eagle Ford [Member] | Leasehold [Member]

Business Acquisition And Divestiture [Line Items]

Percentage of leasehold interest acquired

30.00%

East Texas And Rockies [Member]

Business Acquisition And Divestiture [Line Items]

Purchase price

29,400,000

Undisclosed Seller Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Purchase price

36,500,000

Revenue recorded in statement of operations

4,800,000

Earnings recorded in statement of operations

1,200,000

Date of acquisition

1-May-12

2012 Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Date of acquisition

1-Jan-12

Goodrich Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Purchase price

90,400,000

Revenue recorded in statement of operations

4,600,000

Earnings recorded in statement of operations

2,000,000

Date of acquisition

1-Jul-12

Texas And New Mexico [Member]

Business Acquisition And Divestiture [Line Items]

Purchase price

150,700,000

Menemsha Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Purchase price

74,700,000

Revenue recorded in statement of operations

4,900,000

Earnings recorded in statement of operations

$900,000

Acquisitions_and_Divestitures_3

Acquisitions and Divestitures - Summary of Fair Value of Assets Acquired and Liabilities Assumed (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Revenues payable	($25,073)	($16,291)
Undisclosed Seller Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties			36,865
Asset retirement obligations			-321
Accrued liabilities			-83
Total identifiable net assets			36,461
Goodrich Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties			91,187
Prepaid expenses and other current assets			425
Asset retirement obligations			-161
Revenues payable			-875
Accrued liabilities			-153
Total identifiable net assets			90,423
Menemsha Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties			75,114
Asset retirement obligations			-408
Total identifiable net assets			74,706
Other Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties			80,591
Asset retirement obligations			-4,558
Total identifiable net assets			76,033
Wyoming Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties	930,168
Asset retirement obligations	-3,980
Revenues payable	-375
Accrued liabilities	-19,693
Total identifiable net assets	906,120
Eagle Ford Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties	168,606
Asset retirement obligations	-285
Accrued liabilities	-250
Total identifiable net assets	168,071
East Texas Properties [Member]
Business Acquisition [Line Items]
Oil and gas properties		9,974
Asset retirement obligations		-78
Total identifiable net assets		9,896
Rockies [Member]
Business Acquisition [Line Items]
Oil and gas properties		20,744
Asset retirement obligations		-1,163
Accrued liabilities		-118
Total identifiable net assets		$19,463

Acquisitions_and_Divestitures_4

Acquisitions and Divestitures - Supplemental Pro Forma Information (Detail) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Business Acquisition Pro Forma Information [Abstract]
Revenues	$594,570	[1]	$583,823	$286,004
Net income (loss)	$156,308	[1]	$153,355	$58,472
Basic and diluted earnings per unit	$2.20	[1]	$3.08	$0.53

[1]	Amounts represent historical revenues and expenses from January 1, 2014 through the respective dates of acquisition

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, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	$566,218	$96,798
Interest rate derivatives, Assets	1,305	872
Liabilities	49,120	60,412
Interest rate derivatives, Liabilities	3,289	4,836
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	566,218	96,798
Interest rate derivatives, Assets	1,305	872
Liabilities	49,120	60,412
Interest rate derivatives, Liabilities	3,289	4,836
Commodity derivatives [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	564,913	95,926
Liabilities	45,831	55,576
Commodity derivatives [Member] \| Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	564,913	95,926
Liabilities	$45,831	$55,576

Fair_Value_Measurements_of_Fin3

Fair Value Measurements of Financial Instruments - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	$407,540	$54,362	$10,532
Carrying value of properties after impairment charges	2,216,489	1,348,680
Permian Basin
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	234,200		8,000
Carrying value of properties after impairment charges	88,700
East Texas Properties [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	107,600	50,300
Carrying value of properties after impairment charges	88,800	31,500
South Texas [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	65,600	4,100
Carrying value of properties after impairment charges	$71,200	$7,300

Risk_Management_and_Derivative2

Risk Management and Derivative Instruments - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
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	$207.30
Maximum amount of loss due to credit risk	309.8
Single Counterparty [Member]
Concentration Risks, Types, No Concentration Percentage [Abstract]
Maximum amount of loss due to credit risk	$109.70

Risk_Management_and_Derivative3

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	12 Months Ended
	Dec. 31, 2014
	MMBTU
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)	2,605,278
Weighted-average fixed price	4.28
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)	2,940,000
Spread	-0.12
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)	314,281
Weighted-average fixed price	90.96
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)	97,500
Spread	-7.07
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)	149,200
Weighted-average fixed price	43.02
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)	2,692,442
Weighted-average fixed price	4.4
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)	2,508,333
Spread	-0.04
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)	332,813
Weighted-average fixed price	85.83
2016 [Member] \| Crude Oil Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	95,000
Spread	-9.56
2016 [Member] \| NGL Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	84,600
Weighted-average fixed price	41.49
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)	2,450,067
Weighted-average fixed price	4.31
2017 [Member] \| Natural Gas Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	415,000
Spread	0
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)	326,600
Weighted-average fixed price	84.38
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)	2,160,000
Weighted-average fixed price	4.51
2018 [Member] \| Natural Gas Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	115,000
Spread	0.15
2018 [Member] \| Crude Oil Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	312,000
Weighted-average fixed price	83.74
2019 [Member] \| Natural Gas Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	1,914,583
Weighted-average fixed price	4.75
2019 [Member] \| Crude Oil Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	160,000
Weighted-average fixed price	85.52

Risk_Management_and_Derivative4

Risk Management and Derivative Instruments - Open Commodity Positions Disaggregated Basis (Detail) (Disaggregated Basis Swap [Member])	12 Months Ended
	Dec. 31, 2014
	MMBTU
2015 [Member] \| Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	2,280,000
Spread	-0.11
2015 [Member] \| Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	150,000
Spread	-0.08
2015 [Member] \| Natural Gas Derivative Contracts CIG Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	210,000
Spread	-0.25
2015 [Member] \| Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	300,000
Spread	-0.09
2015 [Member] \| Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	57,500
2015 [Member] \| Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	40,000
2015 [Member] \| Brent \| Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-9.73
2015 [Member] \| WTI \| Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-3.25
2016 [Member] \| Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	2,103,333
Spread	-0.06
2016 [Member] \| Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	135,000
Spread	0.07
2016 [Member] \| Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	270,000
Spread	0.06
2016 [Member] \| Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	55,000
2016 [Member] \| Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls)	40,000
2016 [Member] \| Brent \| Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-13.35
2016 [Member] \| WTI \| Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	-4.34
2017 [Member] \| Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	300,000
Spread	-0.05
2017 [Member] \| Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	115,000
Spread	0.14
2018 [Member] \| Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu)	115,000
Spread	0.15

Risk_Management_and_Derivative5

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, 2014
2015 [Member]
Derivative [Line Items]
Average Monthly Notional	$314,167
Weighted-average fixed rate	1.35%
Floating rate	1 Month LIBOR
2016 [Member]
Derivative [Line Items]
Average Monthly Notional	250,000
Weighted-average fixed rate	1.03%
Floating rate	1 Month LIBOR
2017 [Member]
Derivative [Line Items]
Average Monthly Notional	$250,000
Weighted-average fixed rate	1.62%
Floating rate	1 Month LIBOR

Risk_Management_and_Derivative6

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$208,585	$7,600
Asset Derivatives, Net recorded fair value	311,802	42,657
Liability Derivatives, Net recorded fair value	3,289	7,996
Liability Derivatives, Net recorded fair value		5,875
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	225,882	19,423
Asset Derivatives, Netting arrangements	-17,297	-11,823
Asset Derivatives, Net recorded fair value	208,585	7,600
Liability Derivatives, Gross fair value	20,586	19,819
Liability Derivatives, Netting arrangements	-17,297	-11,823
Liability Derivatives, Net recorded fair value	3,289	7,996
Short-Term Derivative Instruments [Member] \| Commodity derivative contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	225,882	18,578
Liability Derivatives, Gross fair value	17,297	17,120
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	3,289	2,699
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	340,336	77,375
Asset Derivatives, Netting arrangements	-28,534	-34,718
Asset Derivatives, Net recorded fair value	311,802	42,657
Liability Derivatives, Gross fair value	28,534	40,593
Liability Derivatives, Netting arrangements	-28,534	-34,718
Liability Derivatives, Net recorded fair value		5,875
Long-Term Derivative Instruments [Member] \| Commodity derivative contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	339,031	77,348
Liability Derivatives, Gross fair value	28,534	38,456
Long-Term Derivative Instruments [Member] \| Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	1,305	27
Liability Derivatives, Gross fair value		$2,137

Risk_Management_and_Derivative7

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	($492,254)	($26,281)	($21,417)
Interest expense, net	83,550	41,901	20,436
Commodity derivative contracts [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	-492,254	-26,281	-21,417
Interest rate derivatives [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
Interest expense, net	($151)	($548)	$4,839

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Roll Forward Analysis Roll Forward
Asset retirement obligations at beginning of period	$99,619	$91,349	$82,722
Liabilities added from acquisitions or drilling	5,815	2,116	5,958
Liabilities removed upon sale of wells			-1,795
Liabilities settled	-651	-20	-91
Accretion expense	5,618	4,853	4,377
Revision of estimates	-29	1,321	178
Asset retirement obligations at end of period	$110,372	$99,619	$91,349

Restricted_Investments_Restric

Restricted Investments - Restricted Investment Balance (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Restricted Cash and Investments [Abstract]
Restricted investments	$77,361	$73,385
BOEM platform abandonment [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	69,954	66,373
BOEM lease bonds [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	794	794
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	2,701	2,306
SPBPC Collateral California State Lands Commission pipeline right-of-way bond [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	3,005	3,005
SPBPC Collateral City of Long Beach pipeline facility permit [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	500	500
SPBPC Collateral Federal pipeline right-of-way bond [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	307	307
SPBPC Collateral Port of Long Beach pipeline license [Member]
Restricted Cash and Investments [Abstract]
Restricted investments	$100	$100

Long_Term_Debt_Consolidated_De

Long Term Debt - Consolidated Debt Obligations (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Debt Obligations [Abstract]
Unamortized discounts	($16,587)		($10,933)
Long-term debt (Note 8)	1,595,413		792,067
OLLC $2.0 billion revolving credit facility [Member]
Debt Obligations [Abstract]
Revolving credit facility	412,000		103,000
Senior Secured Notes [Member] \| Notes Due 2021 [Member]
Debt Obligations [Abstract]
Senior Notes, fixed-rate	700,000	[1]	700,000	[1]
Senior Secured Notes [Member] \| Notes Due 2022 [Member]
Debt Obligations [Abstract]
Senior Notes, fixed-rate	$500,000	[2]

[1]	The estimated fair value of our 2021 Senior Notes was $563.5 million and $721.0 million at December 31, 2014 and 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[2]	The estimated fair value of our 2022 Senior Notes was $380.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Long_Term_Debt_Consolidated_De1

Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
OLLC $2.0 billion revolving credit facility [Member]
Debt Obligations [Abstract]
Senior Notes maturity date	Mar-18
Revolving credit facility	$2,000,000,000
Senior Secured Notes [Member] \| Notes Due 2021 [Member]
Debt Obligations [Abstract]
Senior Notes maturity date	May-21
Estimated fair value of fixed rate debt	563,500,000	721,000,000
Senior Secured Notes [Member] \| Notes Due 2022 [Member]
Debt Obligations [Abstract]
Senior Notes maturity date	Aug-22
Estimated fair value of fixed rate debt	$380,000,000

Long_Term_Debt_Additional_Info

Long Term Debt - Additional Information (Detail) (USD $)	12 Months Ended	0 Months Ended
Long Term Debt - Additional Information (Detail) (USD $)	Dec. 31, 2014	Jul. 17, 2014	Dec. 12, 2012	Mar. 28, 2013	Apr. 01, 2013	Oct. 10, 2013	23-May-13	Apr. 17, 2013
Line of Credit Facility [Line Items]
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%
Interest coverage ratio on EBITDAX to net interest expenses	2.50%
Interest coverage ratio consolidated current assets to consolidated current liabilities	1.00%
Letters of credit outstanding	$6,700,000
Senior Secured Notes [Member] \| Notes Due 2022 [Member]
Line of Credit Facility [Line Items]
Senior unsecured notes maturity period	1-Aug-22
Senior Secured Notes [Member] \| Notes Due 2021 [Member]
Line of Credit Facility [Line Items]
Senior unsecured notes maturity period	1-May-21
Senior notes	7.63%
Other events of default minimum note holder percentage to accelerate	25.00%
Six Point Eight Seven Five Percent Senior Notes [Member]
Line of Credit Facility [Line Items]
Other events of default minimum note holder percentage to accelerate		25.00%
REO revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility			28,500,000
Termination date of revolving credit facility	12-Dec-12
WHT revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility				89,300,000
Termination date of revolving credit facility	28-Mar-13
Tanos revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility					27,000,000
Termination date of revolving credit facility	1-Apr-13
Boaz And Crown [Member]
Line of Credit Facility [Line Items]
Termination date of revolving credit facility	1-Oct-13
Stanolind And Propel Energy [Member]
Line of Credit Facility [Line Items]
Termination date of revolving credit facility	1-Oct-13
Private Placement of Debt [Member] \| Senior Secured Notes [Member] \| Notes Due 2022 [Member]
Line of Credit Facility [Line Items]
Face amount of senior notes at time of issuance		500,000,000
Senior notes		6.88%
Senior notes issued at par		98.49%
Private Placement of Debt [Member] \| Senior Secured Notes [Member] \| Notes Due 2021 [Member]
Line of Credit Facility [Line Items]
Face amount of senior notes at time of issuance						$300,000,000	$100,000,000	$300,000,000
Minimum [Member]
Line of Credit Facility [Line Items]
Variable LIBOR Market index plus margin, Maximum	1.50%
Variable commitment fee	0.38%
Maximum [Member]
Line of Credit Facility [Line Items]
Variable LIBOR Market index plus margin, Maximum	2.50%
Variable commitment fee	0.50%
Universal Shelf Registration Statement [Member]
Line of Credit Facility [Line Items]
Universal shelf guarantor subsidiaries ownership percentage	100.00%

Long_Term_Debt_Borrowing_Base_

Long Term Debt - Borrowing Base Credit Facility (Detail) (OLLC $2.0 billion revolving credit facility [Member], USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
OLLC $2.0 billion revolving credit facility [Member]
Line of Credit Facility [Line Items]
Borrowing Base	$1,440,000

Long_Term_Debt_Borrowing_Base_1

Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail) (OLLC $2.0 billion revolving credit facility [Member], USD $)	Dec. 31, 2014
OLLC $2.0 billion revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility	$2,000,000,000

Long_Term_Debt_Summary_of_Weig

Long Term Debt - Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OLLC Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	2.67%	3.25%	2.74%
WHT revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		2.29%	2.60%
REO revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates			3.40%
Stanolind revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.52%	3.76%
Boaz revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		2.97%	3.12%
Crown revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.38%	4.20%
Tanos revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.10%	2.31%
Propel Energy revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.08%	3.28%

Long_Term_Debt_Summary_of_Unam

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Credit Facilities [Line Items]
Unamortized deferred financing costs	$27,734		$20,466
OLLC $2.0 billion revolving credit facility [Member]
Credit Facilities [Line Items]
Unamortized deferred financing costs	6,468	[1]	5,413	[1]
2021 [Member] \| Senior Notes [Member]
Credit Facilities [Line Items]
Unamortized deferred financing costs	13,308	[2]	15,053	[2]
2022 [Member] \| Senior Notes [Member]
Credit Facilities [Line Items]
Unamortized deferred financing costs	$7,958	[2]

[1]	Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.
[2]	Unamortized deferred financing costs are amortized using the straight line method which generally approximates the effective interest method.

Long_Term_Debt_Summary_of_Unam1

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Parenthetical) (Detail) (OLLC $2.0 billion revolving credit facility [Member], USD $)	Dec. 31, 2014
OLLC $2.0 billion revolving credit facility [Member]
Credit Facilities [Line Items]
Revolving credit facility	$2,000,000,000

Long_Term_Debt_Advances_and_Re

Long Term Debt - Advances and Repayments (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Credit Facilities [Line Items]
Advances on revolving credit facility	$1,446,000	$958,355	$391,000
Payments on revolving credit facilities	-1,137,000	-1,485,537	-121,819
OLLC Revolving Credit Facility [Member]
Credit Facilities [Line Items]
Advances on revolving credit facility	1,446,000	941,000	293,000
Payments on revolving credit facilities	-1,137,000	-1,209,000	-42,000
Previous Owners Revolving Credit Facility [Member]
Credit Facilities [Line Items]
Advances on revolving credit facility		17,355	98,000
Payments on revolving credit facilities		($276,537)	($79,819)

Equity_and_Distributions_Addit

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

3 Months Ended

12 Months Ended

0 Months Ended

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Feb. 13, 2015

Sep. 09, 2014

Jul. 15, 2014

Oct. 08, 2013

Mar. 25, 2013

Dec. 21, 2012

Dec. 12, 2012

Distribution Made To Limited Partner [Line Items]

Net proceeds from the issuance of common units

$540,698,000

$490,138,000

$194,134,000

Subordination period

13-Feb-15

Partner percentage on common units

0.10%

Maximum IDR distribution percentage

24.90%

Second Target Quarterly Distribution Minimum, per unit

0.54625

Percentage of general partner interest incentive distribution

0.10%

Minimum Quarterly Distribution amount per common unit

0.475

Common unitholders, pro rata percentage

99.90%

Cash Distribution Percentage For General Partners

0.10%

Percentage of General Partner incentive when no subordinated units outstanding

25.00%

Subsequent Event

Distribution Made To Limited Partner [Line Items]

Conversion ratio

100.00%

Maximum [Member]

Distribution Made To Limited Partner [Line Items]

Second Target Quarterly Distribution Minimum, per unit

0.59375

Maximum [Member] | General Partner and Affiliates [Member]

Distribution Made To Limited Partner [Line Items]

Partner percentage on common units

80.00%

The Funds [Member] | IDR [Member]

Distribution Made To Limited Partner [Line Items]

Partnership ownership percentage

50.00%

Memorial Resource [Member]

Distribution Made To Limited Partner [Line Items]

Percentage of economic interest in incentive distribution rights

50.00%

General Partner [Member]

Distribution Made To Limited Partner [Line Items]

Partnership ownership percentage

0.10%

Percentage of General Partner incentive when no subordinated units outstanding

0.10%

General Partner [Member] | IDR [Member]

Distribution Made To Limited Partner [Line Items]

Partnership ownership percentage

50.00%

General Partner [Member] | The Funds [Member]

Distribution Made To Limited Partner [Line Items]

Percentage of economic interest in incentive distribution rights

50.00%

General Partner [Member] | Memorial Resource [Member]

Distribution Made To Limited Partner [Line Items]

Partnership ownership percentage

100.00%

Subordinated Units [Member] | MRD Holdco [Member]

Distribution Made To Limited Partner [Line Items]

Partnership ownership percentage

100.00%

2014 Public Equity Offerings [Member]

Distribution Made To Limited Partner [Line Items]

Number of common units issued in public offering

14,950,000

9,890,000

Number of over-allotment common units issued by Partnership

1,950,000

1,290,000

Public offering price per common unit

$22.29

$22.25

Net proceeds from the issuance of common units

321,300,000

220,000,000

2013 Public Equity Offerings [Member]

Distribution Made To Limited Partner [Line Items]

Number of common units issued in public offering

16,675,000

9,775,000

Number of over-allotment common units issued by Partnership

2,175,000

1,275,000

Public offering price per common unit

$19.90

$18.35

Net proceeds from the issuance of common units

318,300,000

171,800,000

2012 Public Equity Offerings [Member]

Distribution Made To Limited Partner [Line Items]

Number of common units issued in public offering

10,500,000

Public offering price per common unit

$17

Net proceeds from the issuance of common units

170,000,000

Additional common units granted to underwriters

1,475,000

Addition of net proceeds

$24,100,000

Equity_and_Distributions_Summa

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	61,300	34,317	22,044
General partner units issued	25,497	26,983	12,273
Ending balance	86,797	61,300	34,317
Limited Partners Common Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	55,877,831	28,921,903	16,661,294
Common units issued	24,840,000	26,450,000	11,975,000
Restricted common units issued	684,954	524,717	287,943
Restricted common units forfeited	-38,294	-11,734	-2,334
Restricted common units repurchased	-42,587	-7,055
Common units repurchased under repurchase program	-899,912
Ending balance	80,421,992	55,877,831	28,921,903
Subordinated Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance				5,360,912
Ending balance	5,360,912	5,360,912	5,360,912	5,360,912

Equity_and_Distributions_Summa1

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Parenthetical) (Detail) (Maximum [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Maximum [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Withholding tax withheld and paid related to vesting of restricted common units	$1	$0.10

Equity_and_Distributions_Summa2

Equity and Distributions - Summary of Incentive Distributions (Detail)	12 Months Ended
	Dec. 31, 2014
Distributions To Unitholders General Partner or IDR Holders [Line Items]
Minimum total quarterly distribution, per unit	0.475
Second Target Quarterly Distribution Minimum, per unit	0.54625
IDR [Member]
Distributions To Unitholders General Partner or IDR Holders [Line Items]
Marginal Percentage Interest In Second Target Distributions	14.90%
Marginal Percentage Interest In Distributions Thereafter	24.90%
Unitholders [Member]
Distributions To Unitholders General Partner or IDR Holders [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]
Distributions To Unitholders General Partner or IDR Holders [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]
Distributions To Unitholders General Partner or IDR Holders [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]
Distributions To Unitholders General Partner or IDR Holders [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) (The Funds [Member], IDR [Member])	Dec. 31, 2014
The Funds [Member] \| IDR [Member]
Distributions To Unitholders General Partner or IDR Holders [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, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Equity [Abstract]

Distribution made to member or limited partner, date of declaration

26-Jan-15

23-Oct-14

24-Jul-14

24-Apr-14

27-Jan-14

22-Oct-13

18-Jul-13

18-Apr-13

15-Jan-13

19-Oct-12

19-Jul-12

19-Apr-12

Distribution made to member or limited partner, date of record

5-Feb-15

5-Nov-14

5-Aug-14

6-May-14

6-Feb-14

1-Nov-13

1-Aug-13

1-May-13

1-Feb-13

1-Nov-12

1-Aug-12

1-May-12

Distribution made to member or limited partner, date of distribution

12-Feb-15

12-Nov-14

12-Aug-14

13-May-14

13-Feb-14

12-Nov-13

12-Aug-13

13-May-13

13-Feb-13

12-Nov-12

13-Aug-12

14-May-12

Distribution per unit

$0.55

$0.51

$0.50

$0.48

Aggregate Distribution

$46.30

$47.80

$39.50

$33.80

$22.90

$22.60

$17.40

$11.10

$10.70

Distribution Received by Affiliates

$3.10

$6.90

$6.40

$6.30

$6.20

Equity_and_Distributions_Summa5

Equity and Distributions - Summary of Previous Owners' Equity Transactions (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity Structure And Transactions [Line Items]
Balance				$579,616				$711,765	$579,616	$711,765	$742,901
Net income (loss)	163,116	103,226	-114,206	-34,057	10,909	-39,039	52,695	-4,297	118,079	20,268	46,518
Contributions									570	7,754	64,803
Contribution of oil and gas properties											6,893
Distribution attributable to net assets acquired									-2,413	-502,920	-287,663
Contribution related to sale of assets to NGP affiliate											40,138
Net book value of net assets acquired by NGP affiliate											-33,859
Distributions									-154,852	-127,741	-64,001
Other										2,424	-32
Net assets retained by previous owners										-20,782
Balance	1,075,657				579,616				1,075,657	579,616	711,765
Tanos/Classic Properties [Member]
Equity Structure And Transactions [Line Items]
Balance											50,853
Net income (loss)											1,000
Net book value of net assets acquired by Partnership											-50,639
Distributions											-1,214
REO [Member]
Equity Structure And Transactions [Line Items]
Balance											72,755
Net income (loss)											28,691
Net book value of net assets acquired by Partnership											-93,696
Distributions											-7,750
WHT Properties [Member]
Equity Structure And Transactions [Line Items]
Balance								107,893		107,893	99,524
Net income (loss)										-1,219	8,369
Net book value of net assets acquired by Partnership										-106,674
Balance											107,893
Cinco Group [Member]
Equity Structure And Transactions [Line Items]
Balance								276,801		276,801	211,444
Net income (loss)										12,494	8,233
Contributions										7,233	64,597
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
Other										-2,302	-92
Net assets retained by previous owners										-20,782
Balance											276,801
Previous Owners [Member]
Equity Structure And Transactions [Line Items]
Balance								384,694		384,694	434,576
Net income (loss)										11,275	46,293
Contributions										7,233	64,597
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
Other										-2,302	-92
Net assets retained by previous owners										-20,782
Balance											$384,694

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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Unit [Line Items]
Net income (loss) attributable to Memorial Production Partners LP	$163,277	$103,076	($114,194)	($34,112)	$10,862	($39,165)	$52,597	($4,293)	$118,047	$20,001	$46,414
Less: Previous owners interest in net income (loss)						4,128	6,418	729		11,275	46,293
Less: General partner's 0.1% interest in net income (loss)									118	9
Less: IDRs attributable to corresponding period									202	81
Net income (loss) available to limited partners									117,727	8,636	121
Weighted average limited partner units outstanding:
Basic and diluted									70,859	46,017	22,880
Basic and diluted EPU	$1.88	$1.39	($1.86)	($0.56)	$0.18	($0.97)	$1.04	($0.14)	$1.66	$0.19	$0.01
Supplemental EPU [Member]
Earnings Per Unit [Line Items]
Net income (loss) attributable to Memorial Production Partners LP									118,047	20,001	46,414
Less: General partner's 0.1% interest in net income (loss)									118	20	46
Less: IDRs attributable to corresponding period									202	81
Net income (loss) available to limited partners									$117,727	$19,900	$46,368
Weighted average limited partner units outstanding:
Basic and diluted									70,859	46,017	22,880
Basic and diluted EPU									$1.66	$0.43	$2.03
Common Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding									65,498	40,656	17,519
Common Units [Member] \| Supplemental EPU [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding									65,498	40,656	17,519
Subordinated Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding									5,361	5,361	5,361
Subordinated Units [Member] \| Supplemental EPU [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding									5,361	5,361	5,361

Earnings_Per_Unit_Calculation_1

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Unit [Line Items]
General partner's interest in net income, percentage	0.10%	0.10%	0.10%
Supplemental EPU [Member]
Earnings Per Unit [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, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$16.50
Weighted-average period of unrecognized compensation cost	2 years 1 month 6 days
Cash distributions paid	1.9	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	$15	$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, 2014	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	706,927	285,609
Granted, Number of Units	684,954	524,718	287,943
Restricted common units forfeited	-38,294	-11,734	-2,334
Vested, Number of Units	-260,067	-91,666
Restricted common units outstanding, Ending Balance	1,093,520	706,927	285,609
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance	$18.62	$18.08
Granted, Weighted-Average Grant Date Fair Value per Unit	$22.39	$18.83	$18.07
Forfeited, Weighted-Average Grant Date Fair Value per Unit	$20.54	$17.24	$17.14
Vested, Weighted-Average Grant Date Fair Value per Unit	$18.56	$18.31
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance	$20.93	$18.62	$18.08

Equitybased_Awards_Summary_of_1

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted common unit awards issued	$15.30	$9.90	$5.20
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Range of grant date market price	$21.99	$18.33	$17.14
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Range of grant date market price	$23.40	$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, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Compensation expense	$7,874	$3,558	$1,423

Related_Party_Transactions_Add

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

0 Months Ended

12 Months Ended

4 Months Ended

1 Months Ended

Mar. 28, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Jul. 31, 2013

Apr. 30, 2013

Apr. 01, 2014

Oct. 01, 2014

Oct. 01, 2013

14-May-12

Apr. 02, 2012

Dec. 12, 2012

Apr. 01, 2013

Related Party Transaction [Line Items]

Date of acquisition common control

14-May-12

Management fee per month

$200,000

Annual Advisory fee paid

300,000

400,000

Other Management fee paid under agreement

400,000

Compensation expense

45,619,000

43,495,000

30,342,000

Double A Acquisition [Member]

Related Party Transaction [Line Items]

Date of acquisition common control

1-Apr-14

Common Control Acquisition Purchase Price

33,300,000

Wattenberg Acquisition [Member]

Related Party Transaction [Line Items]

Date of acquisition common control

1-Oct-14

Common Control Acquisition Purchase Price

15,000,000

WHT Acquisition [Member]

Related Party Transaction [Line Items]

Date of acquisition common control

28-Mar-13

Common Control Acquisition Purchase Price

200,000,000

Working capital and other customary adjustments

4,000,000

Management fee per month

600,000

Cinco Group acquisition [Member]

Related Party Transaction [Line Items]

Date of acquisition common control

1-Oct-13

Acquisition cost of Assets

603,000,000

Amount in exchange for partnership contribution to memorial resources

6,900,000

Management fee per month

800,000

Tanos/Classic Acquisition [Member]

Related Party Transaction [Line Items]

Date of acquisition common control

2-Apr-12

Common Control Acquisition Purchase Price

27,000,000

18,500,000

Beta [Member]

Related Party Transaction [Line Items]

Date of acquisition common control

12-Dec-12

Working capital and other customary adjustments

3,000,000

Acquisition cost of Assets

270,600,000

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

Memorial Resource [Member]

Related Party Transaction [Line Items]

Amount in exchange for partnership contribution to memorial resources

3,000,000

Amount receivable under management agreement

400,000

Percentage interest in Tanos sold

1.07%

Salt water disposal fee

700,000

600,000

800,000

Tanos [Member]

Related Party Transaction [Line Items]

Compensation expense

5,800,000

Boaz revolving credit facility [Member]

Related Party Transaction [Line Items]

Agreement related expense

$300,000

Related_Party_Transactions_Sch

Related Party Transactions - Schedule of Net Assets Recorded by Partnership (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Apr. 01, 2014	Oct. 01, 2014	Mar. 28, 2013	Oct. 01, 2013	Apr. 02, 2012	14-May-12	Dec. 12, 2012
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Apr. 01, 2014	Oct. 01, 2014	Mar. 28, 2013	Oct. 01, 2013	Apr. 02, 2012	14-May-12	Dec. 12, 2012
Related Party Transaction [Line Items]
Noncontrolling interest	($5,560)	($5,528)
Double A Acquisition [Member]
Related Party Transaction [Line Items]
Oil and natural gas properties, net			37,838
Asset retirement obligations			-908
Other current liabilities			-722
Total identifiable net assets			36,208
Wattenberg Acquisition [Member]
Related Party Transaction [Line Items]
Oil and natural gas properties, net				9,822
Asset retirement obligations				-149
Total identifiable net assets				9,673
WHT Acquisition [Member]
Related Party Transaction [Line Items]
Oil and natural gas properties, net					192,280
Asset retirement obligations					-2,753
Total identifiable net assets					106,674
Cash and cash equivalents					1,354
Accounts receivable					3,866
Short-term derivative instruments, net					1,206
Prepaid expenses and other current assets					98
Long-term derivative instruments, net					3,528
Accrued liabilities					-3,494
Credit facilities					-89,300
Other long-term liabilities					-111
Cinco Group acquisition [Member]
Related Party Transaction [Line Items]
Oil and natural gas properties, net						457,439
Asset retirement obligations						-13,575
Total identifiable net assets						297,627
Cash and cash equivalents						3,265
Accounts receivable						10,615
Short-term derivative instruments, net						-1,505
Prepaid expenses and other current assets						1,824
Long-term derivative instruments, net						3,056
Accrued liabilities						-3,311
Credit facilities						-151,690
Other long-term liabilities						-265
Other long-term assets						356
Accounts payable						-4,063
Revenue payable						-4,519
Tanos/Classic Properties [Member]
Related Party Transaction [Line Items]
Oil and natural gas properties, net							15,164
Asset retirement obligations							-466
Total identifiable net assets							16,070
Short-term derivative instruments, net							715
Long-term derivative instruments, net							674
Accrued liabilities							-17
East Texas Properties [Member]
Related Party Transaction [Line Items]
Oil and natural gas properties, net								31,716
Asset retirement obligations								-43
Total identifiable net assets								34,569
Accounts receivable								612
Short-term derivative instruments, net								1,017
Long-term derivative instruments, net								1,337
Accrued liabilities								-70
Beta [Member]
Related Party Transaction [Line Items]
Oil and natural gas properties, net									108,342
Asset retirement obligations									-58,746
Total identifiable net assets									93,696
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
Accrued liabilities									-9,140
Credit facilities									-28,500
Accounts payable									-9,092
Restricted investments									68,009
Deferred tax liability									-1,674
Noncontrolling interest									($5,255)

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	Dec. 12, 2012
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_Sch1

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, 2014	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	$24,372	$9,440	$1,771

Related_Party_Transactions_Sch2

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
REO [Member]
Related Party Transaction [Line Items]
Management fees	$1,552

Commitments_and_Contingencies_1

Commitments and Contingencies - Environmental Reserves (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments And Contingencies Disclosure [Abstract]
Balance at beginning of period	$437	$1,051	$1,747
Charged to costs and expenses	2,852		-225
Payments	-1,197	-614	-471
Balance at end of period	$2,092	$437	$1,051

Commitments_and_Contingencies_2

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 10, 2010	Mar. 01, 2007
Commitments And Contingencies Additional Textual [Abstract]
Remaining environmental accrued liability recorded	$2,092,000	$437,000
Amount per barrel of oil	0.25
Aggregate value to ceases fund	4,300,000
Restricted Investment - decommissioning of offshore production facilities	77,361,000	73,385,000
Percentage of working interest under sinking fund trust agreement	51.75%
Maximum remaining obligation	800,000
Additional quarterly payments				600,000
Minimum balances attributable to net working interest	78,700,000
Maximum remaining obligation	8,700,000
Rent expense	6,400,000	2,400,000	1,000,000
Predecessor [Member]
Commitments And Contingencies Additional Textual [Abstract]
Rent expense		2,300,000	2,100,000
REO revolving credit facility [Member]
Commitments And Contingencies Additional Textual [Abstract]
Restricted Investment - decommissioning of offshore production facilities					90,000,000
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Commitments And Contingencies Additional Textual [Abstract]
Restricted Investment - decommissioning of offshore production facilities	$2,700,000

Commitments_and_Contingencies_3

Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Asset retirement obligations
Minimum balances attributable to REO's net working interest	$78,700
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 $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Held-to-maturity Securities [Abstract]
Amortized Cost	$69,954
Less: Outside working interest owners share	-65,222
U.S. Bank Money Market Cash Equivalent [Member]
Held-to-maturity Securities [Abstract]
Amortized Cost	$135,176

Commitments_and_Contingencies_5

Commitments and Contingencies - Lease Obligations (Detail) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Total	$3,665
2015	788
2016	416
2017	205
2018	205
2019	205
Thereafter	$1,846

Commitments_and_Contingencies_6

Commitments and Contingencies - CO2 Minimum Purchase Commitment (Detail) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Total	$50,495
2015	9,608
2016	10,179
2017	10,151
2018	6,995
2019	7,060
Thereafter	$6,502

Defined_Contribution_Plans_Add

Defined Contribution Plans - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Contribution Plan [Line Items]
Tax-deferred contributions	100.00%
Matching contributions	100.00%
Percentage of compensation	6.00%
Employer contributions to the plan	$1.40	$0.90	$0.40
Cinco Group [Member]
Defined Contribution Plan [Line Items]
Employer contributions to the plan		0.1	0.2
REO revolving credit facility [Member]
Defined Contribution Plan [Line Items]
Tax-deferred contributions	100.00%
Matching contributions	100.00%
Percentage of compensation	6.00%
Employer contributions to the plan		0.6	0.5
Cost and expenses to the plan		$0.30	$0.30
Vesting Schedule Period	3 years

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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Revenues	$122,575	$147,243	$123,310	$100,977	$92,100	$93,240	$90,174	$68,102	$494,105	$343,616	$258,423
Operating income (loss)	187,466	129,685	-96,170	-17,904	26,786	-27,368	60,814	2,245	203,077	62,477	67,433
Net income (loss)	163,116	103,226	-114,206	-34,057	10,909	-39,039	52,695	-4,297	118,079	20,268	46,518
Net income (loss) attributable to Memorial Production Partners LP	163,277	103,076	-114,194	-34,112	10,862	-39,165	52,597	-4,293	118,047	20,001	46,414
Net income allocated to previous owners						4,128	6,418	729		11,275	46,293
Net income (loss) noncontrolling interest	-161	150	-12	55	47	126	98	-4	32	267	104
Limited partnersb interest in net income (loss)	$163,066	$102,925	($114,120)	($34,118)	$10,811	($43,290)	$46,133	($5,017)	$117,753	$8,677	$121
Basic and diluted earnings per unit	$1.88	$1.39	($1.86)	($0.56)	$0.18	($0.97)	$1.04	($0.14)	$1.66	$0.19	$0.01

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, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Evaluated oil and natural gas properties	$3,007,214	$1,748,438	$1,539,642
Support equipment and facilities	185,997	5,910	5,760
Unevaluated oil and natural gas properties			5,004
Accumulated depletion, depreciation, and amortization	-989,103	-416,617	-265,710
Total	$2,204,108	$1,337,731	$1,284,696

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Property acquisition costs, proved	$983,076	$37,786	$278,246
Exploration			42,430
Development	279,318	145,830	62,472
Total	$1,262,394	$183,616	$383,148

Supplemental_Oil_and_Gas_Infor4

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012
	Bcfe	Bcfe
Supplemental Oil And Gas Reserve Information [Line Items]
Percent of discount factor to proved reserves	10.00%
Multiple acquisitions	561.7	224.2
Wyoming Acquisition [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Multiple acquisitions, Largest acquisition	497.2
Eagle Ford Acquisition [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Multiple acquisitions	45
Goodrich [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Multiple acquisitions, Largest acquisition		148.9
Stanolind revolving credit facility [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Multiple acquisitions		43.6
Menemsha [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Multiple acquisitions, Largest acquisition		23.9
Propel [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Divestiture of Oil and Gas Properties		19

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	91.48	93.42	91.22
NGL [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	91.48	93.42	91.27
Natural Gas [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	4.35	3.67	2.76

Supplemental_Oil_and_Gas_Infor6

Supplemental Oil and Gas Information (Unaudited) - Schedule of Net Reserves (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	bbl	bbl	bbl
Oil [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	39,149,000	39,089,000	27,150,000
Extensions and discoveries	849,000	5,655,000	7,501,000
Purchase of minerals in place	69,095,000	119,000	11,336,000
Production	-3,092,000	-1,764,000	-1,519,000
Sales of minerals in place			-4,214,000
Revision of previous estimates	-6,431,000	-3,950,000	-1,165,000
Proved developed and undeveloped reserves, End of year	99,570,000	39,149,000	39,089,000
Proved developed reserves, Beginning of year	22,265,000	24,515,000	19,332,000
Proved developed reserves, End of year	54,526,000	22,265,000	24,515,000
Proved undeveloped reserves, Beginning of year	16,884,000	14,574,000	7,818,000
Proved undeveloped reserves, End of year	45,044,000	16,884,000	14,574,000
Natural Gas [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	607,139	604,440	579,751
Extensions and discoveries	12,723	40,770	19,869
Purchase of minerals in place	13,036	16,294	113,617
Production	-41,494	-35,924	-29,744
Sales of minerals in place			-4,214
Revision of previous estimates	-31,777	-18,441	-74,839
Proved developed and undeveloped reserves, End of year	559,627	607,139	604,440
Proved developed reserves, Beginning of year	387,548	376,932	413,431
Proved developed reserves, End of year	380,397	387,548	376,932
Proved undeveloped reserves, Beginning of year	219,591	227,508	166,320
Proved undeveloped reserves, End of year	179,230	219,591	227,508
NGL [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	28,846,000	29,352,000	15,045,000
Extensions and discoveries	711,000	1,747,000	1,053,000
Purchase of minerals in place	22,351,000	258,000	7,095,000
Production	-2,143,000	-1,632,000	-745,000
Revision of previous estimates	-287,000	-879,000	6,904,000
Proved developed and undeveloped reserves, End of year	49,478,000	28,846,000	29,352,000
Proved developed reserves, Beginning of year	15,959,000	15,947,000	10,015,000
Proved developed reserves, End of year	35,539,000	15,959,000	15,947,000
Proved undeveloped reserves, Beginning of year	12,887,000	13,405,000	5,030,000
Proved undeveloped reserves, End of year	13,939,000	12,887,000	13,405,000
Equivalent [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	1,015,105	1,015,095	832,913
Extensions and discoveries	22,085	85,180	71,192
Purchase of minerals in place	561,713	18,554	224,202
Production	-72,902	-56,303	-43,329
Sales of minerals in place			-29,499
Revision of previous estimates	-72,090	-47,421	-40,384
Proved developed and undeveloped reserves, End of year	1,453,911	1,015,105	1,015,095
Proved developed reserves, Beginning of year	616,893	619,704	589,504
Proved developed reserves, End of year	920,783	616,893	619,704
Proved undeveloped reserves, Beginning of year	398,212	395,391	243,409
Proved undeveloped reserves, End of year	533,128	398,212	395,391

Supplemental_Oil_and_Gas_Infor7

Supplemental Oil and Gas Information (Unaudited) -Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]
Future cash inflows	$13,191,866	$6,892,150	$6,511,776
Future production costs	-4,516,077	-2,719,024	-2,258,554
Future development costs	-1,222,221	-685,858	-620,944
Future net cash flows for estimated timing of cash flows	7,453,568	3,487,268	3,632,278
10% annual discount for estimated timing of cash flows	-4,693,960	-1,879,156	-2,042,362
Standardized measure of discounted future net cash flows	$2,759,608	$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, 2014
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, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Beginning of year	$1,608,112	$1,589,916	$1,499,414
Sale of oil and natural gas produced, net of production costs	-323,994	-234,520	-160,023
Purchase of minerals in place	1,489,477	23,160	375,953
Sale of minerals in place			-154,963
Extensions and discoveries	44,745	136,423	265,108
Changes in income taxes, net			1,947
Changes in prices and costs	-168,500	-74,395	-331,760
Previously estimated development costs incurred	223,861	174,490	66,360
Net changes in future development costs	-74,579	-74,867	-1,140
Revisions of previous quantities	-163,207	-141,122	-90,587
Accretion of discount	160,811	158,991	150,136
Change in production rates and other	-37,118	50,036	-30,529
End of year	$2,759,608	$1,608,112	$1,589,916

Subsequent_Events_Additional_I

Subsequent Events - Additional Information (Detail) (USD $)	12 Months Ended	0 Months Ended
Subsequent Events - Additional Information (Detail) (USD $)	Dec. 31, 2014	Feb. 23, 2015	Feb. 01, 2015	Feb. 13, 2015
Subsequent Event [Line Items]
Common units amount repurchased under repurchase program	$12,903,000
Limited Partners Common Units [Member]
Subsequent Event [Line Items]
Common units amount repurchased under repurchase program	12,903,000
Common units repurchased under repurchase program	899,912
MRD Holdco [Member] \| Subordinated Units [Member]
Subsequent Event [Line Items]
Conversion of subordinated units, Description	All of the subordinated units, which were owned by MRD Holdco, converted to common units on a one-to-one basis at the end of the subordination period.
Subsequent Event
Subsequent Event [Line Items]
Net payment made to affiliate for acquisition of oil and natural gas properties		78,000,000
Effective date of acquisition common control		1-Jan-15
Subsequent Event \| Limited Partners Common Units [Member]
Subsequent Event [Line Items]
Common units amount repurchased under repurchase program			$28,500,000
Common units repurchased under repurchase program			1,909,583
Subsequent Event \| MRD Holdco [Member] \| Subordinated Units [Member]
Subsequent Event [Line Items]
Subordinated units converted into common units				5,360,912