Amplify Energy (AMPYW) 10-K 24 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Jan. 31, 2016	Jun. 30, 2015
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	MEMP
Entity Registrant Name	MEMORIAL PRODUCTION PARTNERS LP
Entity Central Index Key	1,521,847
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		82,943,323
Entity Public Float			$ 1,210
General Partner [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		86,797

CONSOLIDATED AND COMBINED BALAN

CONSOLIDATED AND COMBINED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 599	$ 970
Accounts receivable:
Oil and natural gas sales	21,988	46,413
Joint interest owners and other	38,251	36,937
Short-term derivative instruments	272,320	208,585
Prepaid expenses and other current assets	7,028	11,032
Total current assets	340,186	303,937
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	3,616,325	3,329,338
Support equipment and facilities	205,876	198,088
Other	2,671	3,020
Accumulated depreciation, depletion and impairment	(1,878,549)	(1,060,114)
Property and equipment, net	1,946,323	2,470,332
Long-term derivative instruments	461,810	311,802
Restricted investments	152,631	77,361
Other long-term assets	5,053	5,062
Total assets	2,906,003	3,168,494
Current liabilities:
Accounts payable	8,792	23,609
Accounts payable - affiliates	3,339	6,409
Revenues payable	25,504	30,110
Accrued liabilities (Note 2)	52,923	89,567
Short-term derivative instruments	2,850	3,289
Total current liabilities	93,408	152,984
Long-term debt (Note 8)	2,000,579	1,574,147
Asset retirement obligations	162,989	112,702
Long-term derivative instruments	1,441	0
Deferred tax liabilities	2,094	32,347
Total liabilities	2,260,511	1,872,180
Commitments and contingencies (Note 13)	0	0
Partners' equity (deficit):
General partner (86,797 units outstanding at December 31, 2015 and December 31, 2014)	848	1,251
Previous owners	0	220,657
Total partners' equity	645,492	1,290,754
Noncontrolling interests	0	5,560
Total equity	645,492	1,296,314
Total liabilities and equity	2,906,003	3,168,494
Limited Partners Common Units [Member]
Partners' equity (deficit):
Limited partners units	644,644	1,085,265
Subordinated Units [Member]
Partners' equity (deficit):
Limited partners units	$ 0	$ (16,419)

CONSOLIDATED AND COMBINED BALA3

CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
General partner, units outstanding	86,797	86,797	61,300	34,317
Limited Partners Common Units [Member]
Limited partners, units outstanding	82,906,400	80,421,992	55,877,831	28,921,903
Subordinated Units [Member]
Limited partners, units outstanding	0	5,360,912	5,360,912	5,360,912

STATEMENTS OF CONSOLIDATED AND

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Oil & natural gas sales	$ 355,422	$ 561,677	$ 391,440
Pipeline tariff income and other	2,725	4,366	3,075
Total revenues	358,147	566,043	394,515
Costs and expenses:
Lease operating	168,199	143,733	94,591
Gathering, processing and transportation	34,939	31,892	25,055
Exploration	2,317	2,750	1,322
Taxes other than income	25,828	33,141	18,447
Depreciation, depletion, and amortization	195,814	185,955	113,814
Impairment of proved oil and natural gas properties	616,784	407,540	4,072
General and administrative	56,671	49,124	54,947
Accretion of asset retirement obligations	7,125	5,773	4,988
(Gain) loss on commodity derivative instruments	(462,890)	(492,254)	(26,133)
(Gain) loss on sale of properties	(2,998)		(2,848)
Other, net	(665)	(11)	647
Total costs and expenses	641,124	367,643	288,902
Operating income (loss)	(282,977)	198,400	105,613
Other income (expense):
Interest expense, net	(114,732)	(83,550)	(44,302)
Other income (expense)	43	(657)	2
Total other income (expense)	(114,689)	(84,207)	(44,300)
Income (loss) before income taxes	(397,666)	114,193	61,313
Income tax benefit (expense)	2,175	1,421	(308)
Net income (loss)	(395,491)	115,614	61,005
Net income (loss) attributable to noncontrolling interest	386	32	267
Net income (loss) attributable to Memorial Production Partners LP	(395,877)	115,582	60,738
Limited partners' interest in net income (loss):
Net income (loss) attributable to Memorial Production Partners LP	(395,877)	115,582	60,738
Net (income) loss allocated to previous owners	2,268	2,465	(52,012)
Net (income) loss allocated to general partner	327	(206)	(49)
Net (income) loss allocated to NGP IDRs	(83)	(88)
Limited partners' interest in net income (loss)	$ (393,365)	$ 117,753	$ 8,677
Earnings per unit: (Note 10)
Basic and diluted earnings per unit	$ (4.71)	$ 1.66	$ 0.19
Weighted average limited partner units outstanding:
Basic and diluted	83,528	70,859	46,017

STATEMENTS OF CONSOLIDATED AND5

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (395,491)	$ 115,614	$ 61,005
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	195,814	185,955	113,814
Impairment of proved oil and natural gas properties	616,784	407,540	4,072
(Gain) loss on derivative instruments	(458,216)	(492,405)	(26,681)
Cash settlements (paid) received on expired derivative instruments	250,043	11,693	22,678
Cash settlements on terminated commodity derivatives	47,930
Premiums paid for commodity derivatives	(47,930)
Deferred income tax expense (benefit)	(2,234)	(1,548)	0
Amortization of deferred financing costs	6,058	4,227	6,013
Accretion of senior notes net discount	2,430	1,921	504
Accretion of asset retirement obligations	7,125	5,773	4,988
Amortization of equity awards	10,809	7,874	3,558
Settlement of asset retirement obligations	(1,430)
(Gain) loss on sale of properties	(2,998)		(2,848)
Exploration costs	2,078	1,960	95
Non-cash compensation expense	0		1,057
Changes in operating assets and liabilities:
Accounts receivable	15,528	(18,022)	1,269
Prepaid expenses and other assets	2,275	(2,695)	(1,052)
Payables and accrued liabilities	(32,068)	27,037	12,999
Other	244	(651)	232
Net cash provided by operating activities	216,751	254,273	201,703
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(100,730)	(1,083,761)	(38,664)
Acquisition post-closing adjustment receipts	9,570
Additions to oil and gas properties	(241,299)	(298,274)	(174,821)
Additions to other property and equipment	0	(98)	(238)
Additions to restricted investments	(5,690)	(3,976)	(5,361)
Proceeds from the sale of oil and natural gas properties	580		4,525
Net cash used in investing activities	(337,569)	(1,386,109)	(214,559)
Cash flows from financing activities:
Advances on revolving credit facilities	562,000	1,446,000	958,355
Payments on revolving credit facilities	(138,000)	(1,137,000)	(1,565,537)
Proceeds from senior notes	0	492,425	688,563
Deferred financing costs	(341)	(11,494)	(20,924)
Repurchase of senior notes	(2,914)
Capital contributions from previous owners	1,912	5,990	96,803
Contributions related to sale of assets to NGP affiliate	860		2,013
Proceeds from general partner contributions	0	570	521
Proceeds from the issuance of common units	0	553,288	511,204
Costs incurred in conjunction with issuance of common units	0	(12,510)	(21,066)
Purchase of noncontrolling interest	(5,946)
Distributions to partners	(163,259)	(154,852)	(96,643)
Distribution to Memorial Resource (see Note 1)	(78,396)	(48,880)	(151,714)
Distribution to NGP affiliates (see Note 1)	0		(355,495)
Restricted units returned to plan	(1,285)	(1,012)
Repurchases under unit repurchase program	(54,184)	(11,531)
Distributions made by previous owners	0	(9,886)	(31,098)
Cash retained by previous owners	0		(9,013)
Net cash provided by financing activities	120,447	1,111,108	5,969
Net change in cash and cash equivalents	(371)	(20,728)	(6,887)
Cash and cash equivalents, beginning of period	970	21,698	28,585
Cash and cash equivalents, end of period	$ 599	$ 970	$ 21,698

STATEMENTS OF CONSOLIDATED AND6

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY - USD ($) $ 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, 2012	[1]	$ 864,863	$ 301,204	$ 20,156	$ 450	$ 537,792		$ 5,261
Net income (loss)		61,005	7,880	797	49	52,012		267
Net proceeds from the issuance of common units		490,138	490,138
Contributions		97,324			521	96,803
Distribution attributable to net assets acquired		(502,920)	(490,400)	(67,242)	(559)	55,281
Net book value of net assets acquired/exchanged			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	[1]	863,021	582,075	(8,715)	728	283,405		5,528
Net income (loss)		115,614	113,573	4,180	206	(2,465)	$ 88	32
Net proceeds from the issuance of common units		540,698	540,698
Contributions		6,560			570	5,990
Distribution attributable to net assets acquired		(2,413)	(2,321)	(90)	(2)
Distribution of net asset to MRD Holdco		(26,131)				(26,131)
Amortization of equity awards		7,874	7,874
Tax related effects attributable to Memorial Resource restructuring and initial public offering		(30,483)				(30,483)
Common units repurchased under repurchase program (Note 9)		(12,903)	(12,903)
Restricted units repurchased (See Note 9)		(1,012)	(1,012)
Distributions		(164,738)	(142,719)	(11,794)	(251)	(9,886)	(88)
Other		227				227
Balance at Dec. 31, 2014	[1]	1,296,314	1,085,265	(16,419)	1,251	220,657		5,560
Net income (loss)		(395,491)	(393,395)	30	(327)	(2,268)	83	386
Contributions		4,877	2,962	0	3	1,912	0	0
Distribution attributable to net assets transferred (Note 1)		(78,396)	(78,318)	0	(78)	0	0	0
Net book value of net assets acquired/exchanged		2,721	250,791	0	251	(248,321)	0	0
Purchase of noncontrolling interest		(5,946)	0	0	0	0	0	(5,946)
Amortization of equity awards		10,809	10,809	0	0	0	0	0
Conversion of subordinated units to common units		0	(19,338)	19,338	0	0	0	0
Common units repurchased under repurchase program (Note 9)		(52,813)	(52,813)	0	0	0	0	0
Deferred tax liability retained by previous owner (Note 2)		28,020	0	0	0	28,020	0	0
Distributions		(163,259)	(159,975)	(2,949)	(252)	0	(83)	0
Balance at Dec. 31, 2015		645,492	644,644	0	848	0	0	0
Restricted units repurchased and other		$ (1,344)	$ (1,344)	$ 0	$ 0	$ 0	$ 0	$ 0
[1]	See Note 1 for information regarding recast amounts and basis of financial statement presentation.

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation General Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries. We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Colorado, Wyoming 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. Unless the context requires otherwise, references to: (i) “our general partner” or “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner; (ii) “Memorial Resource” refer collectively to Memorial Resource Development Corp. and its subsidiaries other than the Partnership; (iii) “MRD LLC” refer to Memorial Resource Development LLC, which is the predecessor of Memorial Resource; (iv) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (v) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refer to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; (vii) “MRD Holdco” refer to MRD Holdco LLC, which together with a group, controls Memorial Resource; and (viii) “NGP” refer to Natural Gas Partners. The Partnership is owned 99.9% by its limited partners and 0.1% by MEMP GP, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities. Memorial Resource provides management, administrative and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco. The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are owned by our general partner. Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer collectively to: · Certain oil and natural gas properties and related assets in East Texas and North Louisiana that the Partnership acquired in March 2013 from WHT Energy Partners (“WHT”) (the “WHT Properties”). · 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.” · Certain oil and natural gas properties primarily located in East Texas and assets in Louisiana that the Partnership acquired in February 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana. We refer to this transaction as the “Property Swap.” The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”). 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) the WHT Properties, (ii) 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, was presented as noncontrolling interest in the financial statements for the periods prior to November 3, 2015. On November 3, 2015, we purchased the noncontrolling interest in SPBPC for approximately $6.0 million and completed an acquisition of the remaining interests in our oil and gas properties offshore Southern California (the “Beta properties”) from a third party for approximately $94.6 million (the “2015 Beta Acquisition”). See Note 3 for additional information regarding the 2015 Beta Acquisition. 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. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. We have elected to early adopt new accounting pronouncements related to the presentation of deferred taxes and debt issuance costs as of December 31, 2015. See Note 2 for more information. A retrospective change to the December 31, 2014 balance sheet as previously presented was required due to the adoption. The retrospective adjustment to the December 31, 2014 balance sheet is shown below: Previously December 31, 2014 Adjustment Effect As Adjusted December 31, 2014 (In thousands) Prepaid expenses and other current assets 14,201 (3,169 ) 11,032 Other long-term assets 23,159 (18,097 ) 5,062 Accrued liabilities 90,974 (1,407 ) 89,567 Long-term debt 1,595,413 (21,266 ) 1,574,147 Deferred tax liabilities 30,940 1,407 32,347

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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, and commercial paper, 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, 2015 and 2014, 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, which are primarily related to our Wyoming and California assets, 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, 2015, 2014 and 2013. 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 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, 2015. 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. 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, 2015, 2014 and 2013 was approximately $6.1 million, $4.2 million, and $6.0 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, 2015, 2014 and 2013 was approximately $616.8 million, $407.5 million, and $4.1 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, 2015 or 2014. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Years Ending December 31, 2015 2014 2013 Major customers: Phillips 66 12% 12% 14% Royal Dutch Shell plc and subsidiaries 14% n/a n/a Sinclair Oil & Gas Company 18% 11% n/a 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 years ended December 31, 2015 and 2014 and on production for the year ended December 31, 2013. 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 years ended December 31, 2015 and 2014, we had $2.1 million and $2.8 million in capitalized interest, respectively. We did not have any capitalized interest for the year ended December 31, 2013. 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 for partnership activity in the state of Texas. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our consolidated statement of operations. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority. 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 (e.g., phantom units 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 would 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, December 31, 2015 2014 Accrued capital expenditures $ 8,110 $ 36,042 Accrued interest payable 23,192 24,673 Accrued lease operating expense 16,843 15,594 Accrued ad valorem taxes 1,426 8,281 Accrued general and administrative expenses 1,961 1,276 Environmental liability 216 2,092 Asset retirement obligation - current 1,175 — Other — 1,609 $ 52,923 $ 89,567 Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 107,272 $ 63,709 $ 42,599 Cash paid for taxes 472 151 168 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (27,932 ) 13,759 18,779 (Increase) decrease in accounts receivable related to acquisitions 9,698 (5,854 ) (4,301 ) Repurchases under unit repurchase program — 1,372 — Assumptions of asset retirement obligations related to properties acquired 23,754 4,265 1,581 New Accounting Pronouncements Balance Sheet Classification of Deferred Taxes. In November 2015, the FASB issued an accounting standards update that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendments. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We adopted this guidance and applied the disclosure requirements retrospectively to the consolidated financial statements and footnote disclosure. Simplifying the Accounting for Measurement-Period Adjustments . In September 2015, the Board FASB issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Partnership does not expect the impact of adopting this guidance to be material to the Partnership’s financial statements and related disclosures. 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. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. 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, 2018. The Partnership has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures. Presentation of Debt Issuance Cost. In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Partnership has chosen to adopt this standard and have applied this guidance in its consolidated financial statements and footnote disclosures. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Partnership has elected this presentation in its consolidated financial statements and footnote disclosure. Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. In April 2015, the FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. Since the Partnership has historically allocated the earnings (losses) of transferred businesses that occurred in periods before the date of the dropdown transaction entirely to affiliates of the general partner (i.e., the previous owners) and did not adjust previously reported earnings per unit of the limited partners, the Partnership does not expect the impact of adopting this guidance will be material to the Partnership’s financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 $ 1,928 $ 4,363 $ 6,729 2015 Acquisitions 2015 Beta Acquisition. As previously disclosed in Note 1, we closed the 2015 Beta Acquisition on November 3, 2015. During the year ended December 31, 2015, we recorded revenues of $3.6 million in the statement of operations and generated losses of approximately $1.0 million related to the 2015 Beta Acquisition subsequent to the closing date. The following table summarizes the fair value of the third party assets acquired and liabilities assumed in the 2015 Beta Acquisition (in thousands): Beta Acquisition Oil and gas properties $ 40,029 Prepaid expenses and other current assets 840 Restricted investments 69,579 Derivative instruments 4,568 Accounts receivable - affiliates and other 4,499 Asset retirement obligations (22,871 ) Accrued liabilities (2,010 ) Total identifiable net assets $ 94,634 The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2015 and 2014 as though the 2015 Beta Acquisition had been completed on January 1, 2014. 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 (iii) accretion expense associated with asset retirement obligations recorded and (iv) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Year Ended December 31, 2015 2014 (In thousands, except per unit amounts) Revenues $ 381,495 $ 613,563 Net income (loss) (394,756 ) 132,630 Basic and diluted earnings per unit (4.73 ) 1.87 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 a final aggregate purchase price of approximately $906.1 million, after customary post-closing adjustments (the “Wyoming Acquisition”). During the year ended December 31, 2014, we recorded revenues of $72.8 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 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 $36.6 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 years 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 2013 (In thousands, except per unit amounts) Revenues $ 666,508 $ 634,722 Net income (loss) 153,843 194,092 Basic and diluted earnings per unit 2.20 3.08 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. 2015 Divestitures During the year ended December 31, 2015, we conducted an auction process administered by a third-party and sold interests in certain oil and gas properties located in the Permian Basin in various Texas and New Mexico counties to two third parties of approximately $0.6 million in the aggregate. In addition as part of that auction process, we also sold interests in certain oil and gas properties located in the Permian Basin to a related party for approximately $0.9 million. See Note 12 for additional information regarding this related party divestiture. 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 to an NGP controlled entity and the remaining proceeds of approximately $2.0 million were released from escrow in April 2013.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). 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, 2015 and 2014, 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, 2015 and December 31, 2014. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt. The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2015 and December 31, 2014 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, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2015 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 816,995 $ — $ 816,995 Interest rate derivatives — — — — Total assets $ — $ 816,995 $ — $ 816,995 Liabilities: Commodity derivatives $ — $ 84,501 $ — $ 84,501 Interest rate derivatives — 2,655 — 2,655 Total liabilities $ — $ 87,156 $ — $ 87,156 Fair Value Measurements at December 31, 2014 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 564,913 $ — $ 564,913 Interest rate derivatives — 1,305 — 1,305 Total assets — $ 566,218 — $ 566,218 Liabilities: Commodity derivatives $ — $ 45,831 $ — $ 45,831 Interest rate derivatives — 3,289 — 3,289 Total liabilities $ — $ 49,120 $ — $ 49,120 See Note 5 for additional information regarding our derivative instruments. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: · The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding 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, 2015, we recognized $616.8 million of impairments. These impairments primarily related to certain properties located in East Texas, South Texas, the Permian Basin, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. As a result of the impairments, the carrying value of these properties was reduced to approximately $408.6 million. · 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 $4.1 million of impairments. The impairments related to certain properties located in South Texas. 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.

Risk Management and Derivative

Risk Management and Derivative Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments	Note 5. Risk Management and Derivative Instruments Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These 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 $350.0 million against amounts outstanding under our revolving credit facility at December 31, 2015, reducing our maximum credit exposure to approximately $380.9 million, of which approximately $123.4 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. In February 2015, we restructured a portion of our commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor. In February 2015, cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives. In November 2015, we had cash settlement receipts of $16.4 million from the termination of certain WTI crude oil derivatives that were applied as premiums for new Brent crude oil derivatives. As a part of the 2015 Beta Acquisition, we acquired $4.6 million of commodity derivatives. These derivatives were subsequently restructured by terminating “in-the-money” crude oil derivatives settling in 2015 through 2016 and entering into new crude oil derivatives. Cash settlement receipts of approximately $4.4 million from the termination of the crude oil derivatives were applied as premiums for the new crude oil swaps. 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, 2015, the Partnership had the following open commodity positions: 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,592,442 3,350,067 3,060,000 2,814,583 Weighted-average fixed price $ 4.14 $ 4.06 $ 4.18 $ 4.31 Basis swaps: Average Monthly Volume (MMBtu) 3,578,333 2,210,000 1,315,000 900,000 Spread $ (0.07 ) $ (0.04 ) $ (0.02 ) $ 0.01 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 304,813 301,600 312,000 160,000 Weighted-average fixed price $ 85.48 $ 85.00 $ 83.74 $ 85.52 Basis swaps: Average Monthly Volume (Bbls) 140,000 67,500 — — Spread $ (10.02 ) $ (7.82 ) $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 213,100 43,300 — — Weighted-average fixed price $ 35.64 $ 37.55 $ — $ — Our basis swaps included in the table above are presented on a disaggregated basis below: 2016 2017 2018 2019 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 3,003,333 1,800,000 1,200,000 900,000 Spread-Henry Hub $ (0.07 ) $ (0.07 ) $ (0.03 ) $ 0.01 HSC basis swaps: Average Monthly Volume (MMBtu) 135,000 115,000 115,000 — Spread-Henry Hub $ 0.07 $ 0.14 $ 0.15 $ — CIG basis swaps: Average Monthly Volume (MMBtu) 170,000 — — — Spread-Henry Hub $ (0.30 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 270,000 295,000 — — Spread-Henry Hub $ 0.06 $ 0.03 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 100,000 37,500 — — Spread - Brent $ (12.29 ) $ (12.20 ) $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 30,000 — — Spread - WTI $ (4.34 ) $ (2.35 ) $ — $ — 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, 2015, we had the following interest rate swap open positions: 2016 2017 2018 Average Monthly Notional (in thousands) $ 400,000 $ 400,000 $ 100,000 Weighted-average fixed rate 0.943 % 1.612 % 1.946 % 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, 2015 and 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives December 31, December 31, December 31, December 31, Type Balance Sheet Location 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 324,265 $ 225,882 $ 53,581 $ 17,297 Interest rate swaps Short-term derivative instruments — — 1,214 3,289 Gross fair value 324,265 225,882 54,795 20,586 Netting arrangements Short-term derivative instruments (51,945 ) (17,297 ) (51,945 ) (17,297 ) Net recorded fair value Short-term derivative instruments $ 272,320 $ 208,585 $ 2,850 $ 3,289 Commodity contracts Long-term derivative instruments $ 492,730 $ 339,031 $ 30,920 $ 28,534 Interest rate swaps Long-term derivative instruments — 1,305 1,441 — Gross fair value 492,730 340,336 32,361 28,534 Netting arrangements Long-term derivative instruments (30,920 ) (28,534 ) (30,920 ) (28,534 ) Net recorded fair value Long-term derivative instruments $ 461,810 $ 311,802 $ 1,441 $ — (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, 2015, 2014, and 2013: For the Year Ended Statements of December 31, Operations Location 2015 2014 2013 Commodity derivative contracts (Gain) loss on commodity derivatives $ (462,890 ) $ (492,254 ) $ (26,133 ) Interest rate derivatives Interest expense, net 4,674 (151 ) (548 )

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. Asset Retirement Obligations The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the years ended December 31, 2015, 2014, and 2013: 2015 2014 2013 (in thousands) Asset retirement obligations at beginning of period $ 112,702 $ 101,436 $ 93,031 Liabilities added from acquisitions or drilling 26,876 5,815 2,116 Liabilities removed upon sale of wells (3,412 ) — — Liabilities settled (1,430 ) (651 ) (20 ) Accretion expense 7,125 5,773 4,988 Revision of estimates 22,303 329 1,321 Asset retirement obligations at end of period 164,164 112,702 101,436 Less: Current portion 1,175 — — Asset retirement obligations - long-term portion $ 162,989 $ 112,702 $ 101,436

Restricted Investments

Restricted Investments	12 Months Ended
	Dec. 31, 2015
Investments Debt And Equity Securities [Abstract]
Restricted Investments	Note 7. Restricted Investments Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. The components of the restricted investment balance are as follows: December 31, December 31, 2015 2014 (In thousands) BOEM platform abandonment (See Note 13) $ 144,008 $ 69,954 BOEM lease bonds 1,533 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 3,178 2,701 California State Lands Commission pipeline right-of-way bond 3,005 3,005 City of Long Beach pipeline facility permit 500 500 Federal pipeline right-of-way bond 307 307 Port of Long Beach pipeline license 100 100 Restricted investments $ 152,631 $ 77,361 The restricted investments balance at December 31, 2015 represents 100% ownership of these properties compared to a 51.75% ownership at December 31, 2014. See Note 3 for additional information regarding the 2015 Beta Acquisition.

Long Term Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 (In thousands) MEMP: OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 836,000 $ 412,000 2021 Senior Notes, fixed-rate, due May 2021 (1) (3) 700,000 700,000 2022 Senior Notes, fixed-rate, due August 2022 (2) (3) 496,990 500,000 Senior notes debt issuance costs, net (18,297 ) (21,266 ) Unamortized discounts (14,114 ) (16,587 ) Total long-term debt $ 2,000,579 $ 1,574,147 (1) The estimated fair value of our 2021 Senior Notes was $210.0 million and $563.5 million at December 31, 2015 and 2014, respectively. (2) The estimated fair value of our 2022 Senior Notes was $149.1 million and $380.0 million at December 31, 2015 and 2014, respectively. (3) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. Subsidiary Guarantors 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, 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 1,175,000 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 the revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in OLLC and any future guarantor subsidiaries and all of our other assets including personal property. Additionally, 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, 2015, the revolving credit facility was primarily used to fund the acquisitions of oil and gas properties and working capital needs. 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 2022 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 2022 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 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 WHT, Stanolind, Boaz, Crown, Tanos and Propel and 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 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. All of the indebtedness outstanding under the MRD LLC revolving credit facility was attributable to Classic. On November 22, 2013, the borrowing base under this revolving credit facility was automatically reduced and triggered a mandatory principal repayment of $20.0 million. This principal repayment is reflected in previous owner equity as a contribution. On December 18, 2013, indebtedness then outstanding under the MRD LLC revolving credit facility of $59.7 million and all accrued interest was paid off in full and the revolving credit facility was terminated. This principal repayment is also reflected in previous owner equity as a contribution. 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, 2015 2014 2013 OLLC revolving credit facility 2.12% 2.67% 3.25% MRD LLC revolving credit facility n/a n/a 3.17% WHT revolving credit facility n/a n/a 2.29% Stanolind revolving credit facility n/a n/a 3.52% Boaz revolving credit facility n/a n/a 2.97% Crown revolving credit facility n/a n/a 3.38% Tanos revolving credit facility n/a n/a 3.10% Propel Energy revolving credit facility n/a n/a 3.08% 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, 2015 2014 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 3,672 $ 6,468 2021 Senior Notes (2) 11,194 13,308 2022 Senior Notes (2) 7,103 7,958 Total $ 21,969 $ 27,734 (1) Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility. (2) Unamortized deferred financing costs are amortized using the straight line method which generally approximates the effective interest method. 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 Credit Facility Credit Total For the Twelve Months Ended December 31, 2015: Advances on revolving credit facility $ 562,000 $ — $ 562,000 Payments on revolving credit facility $ (138,000 ) $ — $ (138,000 ) 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 ) $ (356,537 ) $ (1,565,537 ) For accounting and financial reporting purposes, any amounts that were repaid concurrent with the closing of 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, 2015, we had $2.1 million of letters of credit outstanding related to our operations in Wyoming.

Equity and Distributions

Equity and Distributions	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Equity and Distributions	Note 9. Equity and Distributions 2015 Purchase of Noncontrolling Interest In connection with the 2015 Beta Acquisition, we purchased the noncontrolling interests in SPBPC. See Note 3 for further information. 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 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 proportionate capital contribution, were used to repay a portion of outstanding borrowings under our revolving credit facility. 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. Equity Outstanding The following table summarizes changes in the number of outstanding units since December 31, 2012: General Common Subordinated Partner 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 issued 827,704 — — Restricted common units forfeited (69,059 ) — — Restricted common units repurchased (1) (87,228 ) — — Common units repurchased under repurchase program (3,547,921 ) — — Subordinated units converted to common units 5,360,912 (5,360,912 ) — Balance, December 31, 2015 82,906,400 — 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 $1.3 million, $1.0 million and $0.1 million for the years ended December 31, 2015, 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, 2015, 2014 and 2013. 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 Units. The common units are a separate class 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. On February 13, 2015, all of the 5,360,912 outstanding subordinated units owned by MRD Holdco were converted into common units. The subordinated units converted on a one-for-one basis into common units upon the payment of MEMP's fourth quarter 2014 distribution. MRD Holdco sold all of the common units during the three months ended June 30, 2015 and no longer owns any of our outstanding common units. 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. 2015 Repurchases of Common Units In December 2014, the board of directors of our general partner authorized the repurchase of up to $150.0 million of our common units (“MEMP Repurchase Program”). Under the MEMP Repurchase Program, units could be repurchased and retired from time to time at our discretion on the open market. The MEMP Repurchase Program did not obligate us to repurchase any dollar amount or specific number of common units and could have been discontinued at any time. During the year ended December 31, 2015, we repurchased $52.8 million in common units, which represents a repurchase and retirement of 3,547,921 common units under the MEMP Repurchase Program. During the year ended December 31, 2014, we repurchased $12.9 million in common units, which represented a repurchase and retirement of 899,912 common units. At December 31, 2015, we had no authorized repurchases remaining under the MEMP Repurchase Program. Allocations of Net Income (Loss) Net income (loss) attributable to the Partnership is allocated between our general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner and 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 could 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 % 0.1 % 14.9 % Thereafter above $0.59375 75.0 % 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. 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 4 th January 26, 2016 February 5, 2016 February 12, 2016 $ 0.1000 $ 8.3 $ < 0.1 3 rd October 26, 2015 November 5, 2015 November 12, 2015 $ 0.3000 $ 24.9 $ < 0.1 2 nd July 24, 2015 August 5, 2015 August 12, 2015 $ 0.5500 $ 45.7 $ 0.1 1 st April 24, 2015 May 6, 2015 May 13, 2015 $ 0.5500 $ 46.3 $ 0.2 4 th January 26, 2015 February 5, 2015 February 12, 2015 $ 0.5500 $ 46.3 $ 3.1 3 rd October 23, 2014 November 5, 2014 November 12, 2014 $ 0.5500 $ 47.8 $ 3.1 2 nd July 24, 2014 August 5, 2014 August 12, 2014 $ 0.5500 $ 39.5 $ 3.0 1 st April 24, 2014 May 6, 2014 May 13, 2014 $ 0.5500 $ 33.8 $ 3.0 4 th January 24, 2014 February 6, 2014 February 13, 2014 $ 0.5500 $ 33.8 $ 3.0 3 rd October 22, 2013 November 1, 2013 November 12, 2013 $ 0.5500 $ 33.8 $ 6.9 2 nd July 18, 2013 August 1, 2013 August 12, 2013 $ 0.5125 $ 22.9 $ 6.4 1 st April 18, 2013 May 1, 2013 May 13, 2013 $ 0.5125 $ 22.6 $ 6.4 Previous Owners Capital The following table summarizes our previous owners’ equity transactions with respect to the period indicated (dollars in thousands): WHT Properties Cinco Group Property Swap Total Previous Owners Balance, December 31, 2012 107,893 276,801 153,098 537,792 Net income (loss) (1,219 ) 12,494 40,737 52,012 Contributions — 7,233 89,570 96,803 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 $ — $ — $ 283,405 $ 283,405 Net income (loss) — — (2,465 ) (2,465 ) Contributions — — 5,990 5,990 Distributions — — (9,886 ) (9,886 ) Distribution of net asset to MRD Holdco — — (26,131 ) (26,131 ) Tax related effects attributable to Memorial Resource restructuring transactions and initial public offering — — (30,483 ) (30,483 ) Other — — 227 227 Balance, December 31, 2014 $ — $ — $ 220,657 $ 220,657 Net income (loss) — — (2,268 ) (2,268 ) Contributions — — 1,912 1,912 Net book value of net assets exchanged — — (248,321 ) (248,321 ) Deferred tax liability retained by previous owner — — 28,020 28,020 Balance, December 31, 2015 $ — $ — $ — $ —

Earnings per Unit

Earnings per Unit	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings per Unit	Note 10. Earnings per Unit The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts): For the Year Ended December 31, 2015 2014 2013 Net income (loss) attributable to Memorial Production Partners LP $ (395,877 ) $ 115,582 $ 60,738 Less: Previous owners interest in net income (loss) (2,268 ) (2,465 ) 52,012 Less: General partner's 0.1% interest in net income (loss) (1) (412 ) 118 9 Less: IDRs attributable to corresponding period 112 202 81 Net income (loss) available to limited partners $ (393,309 ) $ 117,727 $ 8,636 Weighted average limited partner units outstanding: Common units 82,897 65,498 40,656 Subordinated units 631 5,361 5,361 Total 83,528 70,859 46,017 Basic and diluted EPU $ (4.71 ) $ 1.66 $ 0.19 (1) As a result of repurchases under the MEMP Repurchase Program, our general partner had an approximate average 0.105% interest in us for the year ended December 31, 2015.

Equity-based Awards

Equity-based Awards	12 Months Ended
	Dec. 31, 2015
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 (“DERs”), 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, 2015, 2014 and 2013 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, 2015, 2014 and 2013 was $12.3 million, $15.0 million and $9.7 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 Number of Date Fair Value Units per Unit (1) Restricted common units outstanding at December 31, 2012 285,609 $ 18.08 Granted (2) 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 (3) 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 Granted (4) 827,704 $ 14.90 Forfeited (69,059 ) $ 18.35 Vested (483,627 ) $ 20.37 Restricted common units outstanding at December 31, 2015 1,368,538 $ 17.61 (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 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 per unit. (3) 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. (4) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.3 million based on grant date market prices ranging from of $6.20 to $15.45 per unit. The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 $ 10,809 $ 7,874 $ 3,558 The unrecognized compensation cost associated with restricted common unit awards was an aggregate $16.5 million at December 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.8 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, 2015, 2014 and 2013, the restricted common unitholders received a distribution of approximately $2.8 million, $1.9 million and $1.0 million, respectively. Subsequent event . On January 8, 2016, the Partnership issued a total of 155,601 phantom units to the independent directors of our general partner, which vest 100% after a one year period. Upon vesting, the phantom units will settle (i) in cash, (ii) in a number of common units equal to the number of vested units or (iii) a combination of cash and common units. The phantom unit awards also include DERs which stipulate that if there is a distribution paid on the common units, the independent directors are entitled to receive a cash payment with respect to each phantom unit equal to the cash distribution paid per unit to common unit holders.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Note 12. Related Party Transactions Amounts payable to Memorial Resource and certain affiliates of NGP at December 31, 2015 and 2014 are presented as “Accounts payable – NGP Affiliated Companies During the year ended December 31, 2015, we paid $0.3 million to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities. Common Control Acquisitions 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 $78.4 million in cash for Memorial Resource’s East Texas and Louisiana oil and gas properties. The transaction had an effective date of January 1, 2015. The properties MEMP received are primarily located in the Joaquin Field in Shelby and Panola counties in East Texas. This acquisition 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 acquisition as if the Partnership owned the assets for the period after common control commenced through the acquisition date. The Partnership recorded the following net assets (in thousands): Accounts receivable $ 2,372 Other receivables 5,478 Prepaid expenses and other current assets 1,874 Property and equipment, net 263,210 Accounts payable (3,586 ) Accounts payable - affiliate (1,290 ) Revenues payable (1,110 ) Accrued liabilities (11,347 ) Asset retirement obligations (4,559 ) Net assets $ 251,042 2014 Acquisitions On April 1, 2014, we acquired certain oil and natural gas properties in East Texas from a subsidiary of MRD LLC, for approximately $33.3 million, including customary post-closing adjustments (the “Double A Acquisition”). The acquired properties primarily represent additional working interests in wells currently owned by us and located in Polk and Tyler Counties in the Double A Field of East Texas as well as the Sunflower, Segno and Sugar Creek Fields. 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 acquisition was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date. On October 1, 2014, we acquired certain oil and natural gas properties in Weld County, Colorado from Memorial Resource for approximately $15.0 million in cash consideration. The acquired properties represent working interests in wells located in the Wattenberg field (the “Wattenberg Acquisition”). Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee. This acquisition has an effective date of October 1, 2014 and was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date. The Partnership recorded the following net assets (in thousands): Double A Wattenberg Acquisition Acquisition Property and equipment, net $ 37,838 $ 9,822 Asset retirement obligations (908 ) (149 ) Other current liabilities (722 ) — Net assets $ 36,208 $ 9,673 Due to common control considerations, the difference between the purchase price and the total identifiable assets has been recorded as a contribution on our Statements of Consolidated and Combined Equity. 2013 Acquisitions On March 28, 2013, we acquired all of the outstanding equity interests in WHT from operating subsidiaries of MRD LLC for a purchase price of $200.0 million, which included $4.0 million of working capital and other customary adjustments. This acquisition was funded with borrowings under our revolving credit facility and the net proceeds from our March 25, 2013 public offering of common units (including our general partner’s proportionate capital contribution). Terms of the transaction were approved by our general partner’s Board and by its conflicts committee. The WHT Properties consist of additional working interests in properties that we originally acquired in December 2011 in conjunction with our initial public offering. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands): Cash and cash equivalents $ 1,354 Accounts receivable 3,866 Short-term derivative instruments, net 1,206 Prepaid expenses and other current assets 98 Oil and natural gas properties, net 192,280 Long-term derivative instruments, net 3,528 Accrued liabilities (3,494 ) Asset retirement obligations (2,753 ) Credit facilities (89,300 ) Other long-term liabilities (111 ) Net assets $ 106,674 Acquisition of Cinco Group Properties from Memorial Resource & NGP On October 1, 2013, we acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from MRD LLC and certain affiliates of NGP for an aggregate purchase price of approximately $603 million, subject to customary post-closing adjustments. The Cinco Group acquisition was funded with borrowings under our revolving credit facility. Terms of the transaction were approved by the Board and by its conflicts committee. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands): Cash and cash equivalents $ 3,265 Accounts receivable 10,615 Prepaid expenses and other current assets 1,824 Oil and natural gas properties, net 457,439 Long-term derivative instruments, net 3,056 Other long-term assets 356 Accounts payable (4,063 ) Revenue payable (4,519 ) Accrued liabilities (3,311 ) Short-term derivative instruments, net (1,505 ) Asset retirement obligations (13,575 ) Credit facilities (151,690 ) Other long-term liabilities (265 ) Net assets $ 297,627 2015 Divestiture On November 2, 2015, in connection with an auction process administered by a third-party, we divested certain oil and natural gas properties in the Permian Basin to an affiliate of NGP for a purchase price of approximately $0.9 million. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties sold by $0.7 million and is recognized in the equity statement. Related Party Agreements We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations. Omnibus Agreement Memorial Resource continues to provide management, administrative and operating services for us and our general partner pursuant to our omnibus agreement. The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 $ 32,281 $ 24,372 $ 9,440 Beta Management Agreement In connection with the December 2012 Beta acquisition, Memorial Resource entered into a management agreement with its wholly-owned subsidiary, Beta Operating Company, LLC, pursuant to which Memorial Resource agreed to provide management and administrative oversight with respect to the services provided by such subsidiary under certain operating agreements with our subsidiary, Rise Energy Beta, LLC, related to the Beta properties in exchange for an annual management fee. Pursuant to such management agreement and in connection with such operating agreements, Memorial Resource had the right to receive approximately $0.4 million from Rise Energy Beta, LLC annually. This agreement was terminated in November 2015 in connection with the 2015 Beta Acquisition. Cinco Group Transition Service Agreements The Partnership entered into transition service agreements with Propel Energy, Stanolind, and Boaz Energy Partners to ensure that ownership, operation, and maintenance of acquired properties could be smoothly transitioned. The term of these agreements were from October 1, 2013 through February 28, 2014. The Partnership paid transition service fees of approximately $0.8 million in the aggregate under these agreements. Classic Agreements In November 2011, Classic Hydrocarbons Operating, LLC, a subsidiary of Memorial Resource (“Classic Operating”), and Classic Pipeline & Gathering, LLC (“Classic Pipeline”), a subsidiary of MRD Holdco, entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline’s Joaquin gathering system. In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement had a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. Effective July 1, 2015, the fee was reduced to $0.40 per barrel. In February 2015, in connection with and as part of the Property Swap, Classic Hydrocarbons Holdings, L.P. sold all of the equity interests owned by it in Classic Operating as well as Craton Energy GP III, LLC (“Craton GP”) and Craton Energy Holdings III, LP (“Craton LP”), two subsidiaries of Memorial Resource, to OLLC, and Classic Operating, Craton GP and Craton LP were merged into OLLC. OLLC was therefore the successor to Classic Operating under the terminated amended gas gathering agreement and water disposal agreement. Classic Pipeline assigned its saltwater disposal system to OLLC in November 2015. Due to common control considerations, we recorded the receipt of this asset at historical cost and recognized approximately $2.1 million in the equity statement. For the years ended December 31, 2015, 2014 and 2013, the Partnership incurred gathering and salt water disposal fees of approximately $3.2 million, $1.8 million and $0.6 million, respectively, from Classic Pipeline, an affiliate. Other Related Party Transactions Director & Advisory Fees Certain of the Cinco Group entities entered into an advisory service, reimbursement, and indemnification agreements with NGP. These agreements generally required that an annual advisory fee be paid to NGP. Fees paid under these agreements for the year ended December 31, 2013 were approximately $0.3 million. Classic Management Team Equity Interest On November 1, 2013, Classic’s management team sold its membership interest in Classic to MRD LLC and all incentive units held were forfeited. The governing documents of Classic provided for the issuance of incentive units. Classic granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions when declared, but only after cumulative distribution thresholds had been achieved (i.e., recovery of specified members’ capital contributions plus a rate of return). These incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. No compensation cost was recorded related to incentive units prior to the incentive units being forfeited on November 1, 2013. Compensation expense of approximately $8.3 million was recorded by Classic and recognized as general and administrative expense during November 2013. Tanos Management Team Equity Interest On April 1, 2013, Tanos’ management team sold its 1.066% membership interest in Tanos to MRD LLC and all incentive units held were forfeited. In connection with this sale, all of Tanos’ employees resigned and became employees of Tanos Exploration II, LLC (“Tanos II”), a Texas limited liability company controlled by the former management team of Tanos. Effective April 1, 2013, Tanos II entered into a Transition Services Agreement with Tanos, whereby Tanos II would manage the operations of Tanos for up to a 6-month period of time. Tanos II is an unrelated entity. The governing documents of Tanos provided for the issuance of incentive units. Tanos granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions when declared, but only after cumulative distribution thresholds had been achieved (i.e., recovery of specified members’ capital contributions plus a rate of return). These incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. No compensation cost was recorded related to incentive units prior to the incentive units being forfeited on April 1, 2013. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as general and administrative expense during April 2013.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 13. Commitments and Contingencies Litigation & Environmental As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows. 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, 2015, 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: 2015 2014 2013 (In thousands) Balance at beginning of period $ 2,092 $ 437 $ 1,051 Charged to costs and expenses — 2,852 — Payments (1,876 ) (1,197 ) (614 ) Balance at end of period $ 216 $ 2,092 $ 437 At December 31, 2015 and 2014, $0.2 million and $2.1 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, 2015, the gross account balance included in restricted investments was approximately $3.2 million. 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 of $1.25 million. The trust account must maintain minimum balances as follows (in thousands): June 30, 2016 $ 148,000 December 31, 2016 $ 152,000 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, 2015, the remaining obligation was approximately $8.0 million. In 2015, the BOEM issued a preliminary report that indicated the estimated cost of decommissioning may further increase, and we expect the amount to be finalized during 2016 after negotiations are completed. The gross held-to-maturity investments held in the trust account as of December 31, 2015 for the U.S. Bank money market cash equivalent was $144.0 million. 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, compressors 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, 2015, 2014 and 2013, we recognized $16.9 million, $6.4 million and $2.4 million of rent expense, respectively. The previous owners recorded rent expense of approximately $0.5 million and $2.9 million for the years ended December 31, 2014 and 2013, 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 2016 2017 2018 2019 2020 Thereafter Operating leases $ 6,107 $ 1,007 $ 317 $ 294 $ 294 $ 295 $ 3,900 Purchase Commitments At December 31, 2015, we had a CO 2 Payment or Settlement Due by Period Purchase commitment Total 2016 2017 2018 2019 2020 Thereafter CO 2 $ 30,307 $ 7,393 $ 7,505 $ 5,075 $ 5,366 $ 4,968 $ — Offshore ship services & other 4,662 4,662 — — — — — Minimum Volume Commitment At December 31, 2015, we had a seven year minimum volume commitment with a third party associated with a certain portion of our properties located in East Texas. The table below outlines the payment commitments associated with this minimum volume commitment (in thousands): Payment or Settlement Due by Period Purchase commitment Total 2016 2017 2018 2019 2020 Thereafter Midstream services $ 35,788 $ 5,121 $ 5,121 $ 5,106 $ 5,107 $ 5,106 $ 10,227

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Tax	Note 14. Income Tax The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Current taxes: Federal $ (11 ) $ — $ — State (48 ) (127 ) (308 ) Total current income tax benefit (expense) (59 ) (127 ) (308 ) Deferred taxes: Federal 1,193 2,057 — State 1,041 (509 ) — Total deferred income tax benefit (expense) 2,234 1,548 — Total income tax benefit (expense) $ 2,175 $ 1,421 $ (308 ) The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows: For the Year Ended December 31, 2015 2014 2013 Expected tax benefit (expense) at federal statutory rate $ 139,183 $ (39,966 ) $ (21,459 ) State income tax benefit (expense), net of federal benefit 645 (1,907 ) (308 ) Pass-through entities (1) (137,704 ) 42,000 21,459 Other 51 1,294 — Total income tax benefit (expense) $ 2,175 $ 1,421 $ (308 ) (1) MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes. The components of net deferred income tax liabilities recognized were as follows: December 31, 2015 2014 (In thousands) Deferred income tax assets: Net operating loss carryforward $ 56 $ 3,959 Asset retirement obligation 694 1,855 Other 38 15 Total deferred income tax assets: 788 5,829 Valuation allowance — (2,633 ) Net deferred income tax assets 788 3,196 Deferred income tax liabilities: Property, plant and equipment $ 1,324 $ 32,094 Derivatives 1,514 3,388 Other 44 61 Total deferred income tax liabilities 2,882 35,543 Net deferred income tax liabilities $ 2,094 $ 32,347 A deferred tax liability was recorded in equity by the previous owners and related to Memorial Resource’s initial public offering and restructuring transactions as it represented a transaction among shareholders. Subsequent to the Memorial Resource’s initial public offering, income tax related to the Property Swap was calculated on a separate return basis. Uncertain Income Tax Position. We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. We had no unrecognized tax benefits as of December 31, 2015 or 2014. Tax Audits and Settlements. Generally, our income tax years 2011 through 2015 remain open and subject to examination by the Internal Revenue Service or state tax jurisdictions where we conduct operations. In certain jurisdictions we operate through more than one legal entity, each of which may have different open years subject to examination. Tax Attribute carryforwards and Valuation Allowance. As of December 31, 2015, we had federal net operating loss carryforwards of approximately $0.2 million, which would expire in 2034. No valuation allowance was established based upon management’s evaluation that loss carryforwards will be fully realized.

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2015
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, 2015: Revenues $ 92,818 $ 98,138 $ 88,083 $ 79,108 Operating income (loss) (136,370 ) (85,197 ) (160,844 ) 99,434 Net income (loss) (162,658 ) (113,859 ) (191,981 ) 73,007 Net income (loss) attributable to Memorial Production Partners LP (162,817 ) (113,924 ) (192,085 ) 72,949 Net income (loss) allocated to previous owners (2,268 ) — — — Net income (loss) noncontrolling interest 159 65 104 58 Limited partners’ interest in net income (loss) (160,439 ) (113,862 ) (191,938 ) 72,874 Basic and diluted earnings per unit (1.90 ) (1.36 ) (2.31 ) 0.88 First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per unit amounts) For the Year Ended December 31, 2014: Revenues $ 116,885 $ 144,208 $ 166,261 $ 138,689 Operating income (loss) (16,739 ) (93,294 ) 127,078 181,355 Net income (loss) (32,892 ) (111,640 ) 101,307 158,839 Net income (loss) attributable to Memorial Production Partners LP (32,947 ) (111,628 ) 101,157 159,000 Net income (loss) allocated to previous owners 1,165 2,566 (1,919 ) (4,277 ) 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 The Partnership has consummated several common control acquisitions, as further discussed in Note 12, directly or indirectly from Memorial Resource and certain affiliates of NGP. The quarterly financial information for the years ended December 31, 2015 and 2014 presented above has been retrospectively revised for the Property Swap. See Notes 2 and 10 for additional information regarding earnings per unit.

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Supplemental Oil and Gas Information (Unaudited)	N ote 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, 2015 2014 2013 (In thousands) Evaluated oil and natural gas properties $ 3,616,325 $ 3,329,338 $ 2,077,344 Support equipment and facilities 205,876 198,088 16,030 Unevaluated oil and natural gas properties — — 1,960 Accumulated depletion, depreciation, and amortization (1,878,549 ) (1,060,114 ) (464,812 ) Total $ 1,943,652 $ 2,467,312 $ 1,630,522 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, 2015 2014 2013 (In thousands) Property acquisition costs, proved $ 77,834 $ 983,076 $ 37,786 Property acquisition costs, unproved 1,887 720 — Exploration 2,078 — — Development 233,241 308,724 166,090 Total $ 315,040 $ 1,292,520 $ 203,876 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 Ryder Scott to audit our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2015. 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: 2015 2014 2013 Oil ($/Bbl): WTI (1) $ 46.79 $ 91.48 $ 93.42 NGL ($/Bbl): WTI (1) $ 46.79 $ 91.48 $ 93.42 Natural Gas ($/MMbtu): Henry Hub (2) $ 2.58 $ 4.35 $ 3.67 (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, 2015, 2014 and 2013, respectively: Year Ended December 31, 2015 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 100,258 727,216 59,034 1,682,960 Extensions and discoveries 2,319 8,686 558 25,950 Purchase of minerals in place 10,132 34,128 367 97,122 Production (4,087 ) (50,875 ) (2,820 ) (92,315 ) Sale of minerals in place (380 ) (13,731 ) (758 ) (20,559 ) Revision of previous estimates (17,297 ) (243,898 ) (12,986 ) (425,587 ) End of year 90,945 461,526 43,395 1,267,571 Proved developed reserves: Beginning of year 54,723 417,247 37,260 969,141 End of year 50,817 311,147 30,315 797,936 Proved undeveloped reserves: Beginning of year 45,535 309,969 21,774 713,819 End of year 40,128 150,379 13,080 469,635 Year Ended December 31, 2014 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 39,635 737,908 35,794 1,190,484 Extensions and discoveries 849 12,783 711 22,145 Purchase of minerals in place 69,095 13,036 22,351 561,713 Production (3,135 ) (48,721 ) (2,498 ) (82,520 ) Revision of previous estimates (6,186 ) 12,210 2,676 (8,862 ) End of year 100,258 727,216 59,034 1,682,960 Proved developed reserves: Beginning of year 22,429 427,983 17,637 668,381 End of year 54,723 417,247 37,260 969,141 Proved undeveloped reserves: Beginning of year 17,206 309,925 18,157 522,103 End of year 45,535 309,969 21,774 713,819 Year Ended December 31, 2013 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 40,822 794,369 39,554 1,276,625 Extensions and discoveries 5,814 85,455 4,353 146,463 Purchase of minerals in place 119 16,294 258 18,554 Production (1,797 ) (41,287 ) (1,806 ) (62,907 ) Revision of previous estimates (5,323 ) (116,923 ) (6,565 ) (188,251 ) End of year 39,635 737,908 35,794 1,190,484 Proved developed reserves: Beginning of year 24,784 441,858 18,060 698,922 End of year 22,429 427,983 17,637 668,381 Proved undeveloped reserves: Beginning of year 16,038 352,511 21,494 577,703 End of year 17,206 309,925 18,157 522,103 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. An upward revision of natural gas for the year ended December 31, 2014 was due to increased natural gas prices on certain East Texas properties. The upward revision was partially offset by a downward revision of natural gas for the year ended December 31, 2014, which was primarily due to updated well performance data in certain other East Texas fields. Proved undeveloped reserves increased during the year ended December 31, 2014 primarily due to the Wyoming Acquisition. · The 415.4 Bcfe reduction in reserves for the year ended December 31, 2015 is primarily due to a 413 Bcfe downward pricing revision and a 13 Bcfe downward revision due to updated well performance data. We acquired 97.1 Bcfe during the year ended December 31, 2015, the largest being the 2015 Beta Acquisition of 58.5 Bcfe. Proved undeveloped reserves decreased primarily due to downward pricing during the year ended December 31, 2015. 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, 2015 2014 2013 (In thousands) Future cash inflows $ 5,952,935 $ 14,190,450 $ 7,672,312 Future production costs (3,194,577 ) (4,821,051 ) (2,963,146 ) Future development costs (808,512 ) (1,455,926 ) (901,374 ) Future income tax expense (1) — (119,675 ) — Future net cash flows for estimated timing of cash flows 1,949,846 7,793,798 3,807,792 10% annual discount for estimated timing of cash flows (1,360,292 ) (4,881,811 ) (2,089,588 ) Standardized measure of discounted future net cash flows $ 589,554 $ 2,911,987 $ 1,718,204 (1) We are subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality we have excluded the impact of this tax for the years ended December 31, 2015, 2014 and 2013. The 2014 amount was related to Classic since its reserves were a part of a taxable entity for federal income tax purposes for the year ended December 31, 2014. 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, 2015: Years Ended December 31, 2015 2014 2013 (In thousands) Beginning of year $ 2,911,987 $ 1,718,204 $ 1,772,240 Sale of oil and natural gas produced, net of production costs (128,382 ) (354,932 ) (255,031 ) Purchase of minerals in place 75,998 1,489,477 23,160 Sale of minerals in place (45,100 ) — — Extensions and discoveries 18,582 44,843 150,631 Changes in income taxes, net 63,180 (63,180 ) — Changes in prices and costs (2,764,481 ) (170,682 ) (26,648 ) Previously estimated development costs incurred 322,446 275,078 199,775 Net changes in future development costs 448,089 (133,098 ) (16,219 ) Revisions of previous quantities (344,775 ) (48,087 ) (373,109 ) Accretion of discount 297,517 171,820 177,223 Change in production rates and other (265,507 ) (17,456 ) 66,182 End of year $ 589,554 $ 2,911,987 $ 1,718,204

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events

Organization and Basis of Pre24

Organization and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
General	General Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries. We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Colorado, Wyoming 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. Unless the context requires otherwise, references to: (i) “our general partner” or “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner; (ii) “Memorial Resource” refer collectively to Memorial Resource Development Corp. and its subsidiaries other than the Partnership; (iii) “MRD LLC” refer to Memorial Resource Development LLC, which is the predecessor of Memorial Resource; (iv) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (v) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refer to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; (vii) “MRD Holdco” refer to MRD Holdco LLC, which together with a group, controls Memorial Resource; and (viii) “NGP” refer to Natural Gas Partners. The Partnership is owned 99.9% by its limited partners and 0.1% by MEMP GP, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities. Memorial Resource provides management, administrative and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco. The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are owned by our general partner.
Previous Owners	Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer collectively to: · Certain oil and natural gas properties and related assets in East Texas and North Louisiana that the Partnership acquired in March 2013 from WHT Energy Partners (“WHT”) (the “WHT Properties”). · 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.” · Certain oil and natural gas properties primarily located in East Texas and assets in Louisiana that the Partnership acquired in February 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana. We refer to this transaction as the “Property Swap.” The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”). Each of these aforementioned acquisitions was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to such acquisitions as if the Partnership owned the assets for periods after common control commenced through their respective acquisition dates. See Note 12 for additional information.
Basis of Presentation	Basis of Presentation Our consolidated results of operations 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) the WHT Properties, (ii) 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, was presented as noncontrolling interest in the financial statements for the periods prior to November 3, 2015. On November 3, 2015, we purchased the noncontrolling interest in SPBPC for approximately $6.0 million and completed an acquisition of the remaining interests in our oil and gas properties offshore Southern California (the “Beta properties”) from a third party for approximately $94.6 million (the “2015 Beta Acquisition”). See Note 3 for additional information regarding the 2015 Beta Acquisition. 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. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. We have elected to early adopt new accounting pronouncements related to the presentation of deferred taxes and debt issuance costs as of December 31, 2015. See Note 2 for more information. A retrospective change to the December 31, 2014 balance sheet as previously presented was required due to the adoption. The retrospective adjustment to the December 31, 2014 balance sheet is shown below: Previously December 31, 2014 Adjustment Effect As Adjusted December 31, 2014 (In thousands) Prepaid expenses and other current assets 14,201 (3,169 ) 11,032 Other long-term assets 23,159 (18,097 ) 5,062 Accrued liabilities 90,974 (1,407 ) 89,567 Long-term debt 1,595,413 (21,266 ) 1,574,147 Deferred tax liabilities 30,940 1,407 32,347
Use of Estimates	Use of Estimates The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.
Principles of Consolidation and Combination	Principles of Consolidation and Combination Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of the previous owners as discussed above. All material intercompany balances and transactions have been eliminated.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.
Concentrations of Credit Risk	Concentrations of Credit Risk Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts, money market mutual funds, and commercial paper, 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, 2015 and 2014, respectively. If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.
Oil and Natural Gas Properties	Oil and Natural Gas Properties Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred. As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Support equipment and facilities, which are primarily related to our Wyoming and California assets, 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, 2015, 2014 and 2013.
Oil And Gas Reserves	Oil and Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We engaged 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, 2015. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
Other Property & Equipment	Other Property & Equipment Other property and equipment is stated at historical 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	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. 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	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, 2015, 2014 and 2013 was approximately $6.1 million, $4.2 million, and $6.0 million, respectively.
Impairments	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, 2015, 2014 and 2013 was approximately $616.8 million, $407.5 million, and $4.1 million, respectively.
Asset Retirement Obligations	Asset Retirement Obligations An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized 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 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 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, 2015 or 2014. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Years Ending December 31, 2015 2014 2013 Major customers: Phillips 66 12% 12% 14% Royal Dutch Shell plc and subsidiaries 14% n/a n/a Sinclair Oil & Gas Company 18% 11% n/a
General and Administrative Expense	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 years ended December 31, 2015 and 2014 and on production for the year ended December 31, 2013. 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	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	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 years ended December 31, 2015 and 2014, we had $2.1 million and $2.8 million in capitalized interest, respectively. We did not have any capitalized interest for the year ended December 31, 2013.
Income Tax	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 for partnership activity in the state of Texas. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax bases of assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our consolidated statement of operations. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority.
Earnings Per Unit	Earnings Per Unit Basic and diluted earnings per unit (“EPU”) is determined by dividing net income or loss available to the limited partners by the weighted average number of outstanding limited partner units during the period. Net income or loss available to the limited partners is determined by applying the two-class method. The two-class method of computing EPU is an earnings allocation formula that determines EPU based on distributions declared. The amount of net income or loss used in the determination of EPU is reduced (or increased) by the amount of available cash that has been or will be distributed to the limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the limited partners in accordance with the contractual terms of the partnership agreement. The total earnings allocated to the limited partners is determined by adding together the amount allocated for distributions declared and the amount allocated for the undistributed earnings or excess distributions over earnings. Basic and diluted EPU are equivalent, as all restricted common units and subordinated units participate in distributions. See Note 10 for additional information.
Equity Compensation	Equity Compensation The fair value of equity-classified awards (e.g., restricted common unit awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., phantom units 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 would vest when it is probable that the performance criteria will be met and the requisite service period has been met. Generally, no compensation expense is recognized for equity instruments that do not vest. See Note 11 for further information.
Incentive Units	Incentive Units The governing documents of certain entities within the Cinco Group provided for the issuance of incentive units. The incentive units were accounted for as liability awards with compensation expense based on period-end fair value. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. Tanos recognized compensation expense related to the forfeiture of incentive units during April 2013 as further discussed in Note 12.
Accrued Liabilities	Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, December 31, 2015 2014 Accrued capital expenditures $ 8,110 $ 36,042 Accrued interest payable 23,192 24,673 Accrued lease operating expense 16,843 15,594 Accrued ad valorem taxes 1,426 8,281 Accrued general and administrative expenses 1,961 1,276 Environmental liability 216 2,092 Asset retirement obligation - current 1,175 — Other — 1,609 $ 52,923 $ 89,567
Supplemental Cash Flows	Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 107,272 $ 63,709 $ 42,599 Cash paid for taxes 472 151 168 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (27,932 ) 13,759 18,779 (Increase) decrease in accounts receivable related to acquisitions 9,698 (5,854 ) (4,301 ) Repurchases under unit repurchase program — 1,372 — Assumptions of asset retirement obligations related to properties acquired 23,754 4,265 1,581
New Accounting Pronouncements	New Accounting Pronouncements Balance Sheet Classification of Deferred Taxes. In November 2015, the FASB issued an accounting standards update that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendments. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We adopted this guidance and applied the disclosure requirements retrospectively to the consolidated financial statements and footnote disclosure. Simplifying the Accounting for Measurement-Period Adjustments . In September 2015, the Board FASB issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Partnership does not expect the impact of adopting this guidance to be material to the Partnership’s financial statements and related disclosures. 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. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. 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, 2018. The Partnership has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures. Presentation of Debt Issuance Cost. In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Partnership has chosen to adopt this standard and have applied this guidance in its consolidated financial statements and footnote disclosures. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Partnership has elected this presentation in its consolidated financial statements and footnote disclosure. Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. In April 2015, the FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. Since the Partnership has historically allocated the earnings (losses) of transferred businesses that occurred in periods before the date of the dropdown transaction entirely to affiliates of the general partner (i.e., the previous owners) and did not adjust previously reported earnings per unit of the limited partners, the Partnership does not expect the impact of adopting this guidance will be material to the Partnership’s financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Organization and Basis of Pre25

Organization and Basis of Presentation (Tables)	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Schedule of Retrospective Balance Sheet Adjustments	The retrospective adjustment to the December 31, 2014 balance sheet is shown below: Previously December 31, 2014 Adjustment Effect As Adjusted December 31, 2014 (In thousands) Prepaid expenses and other current assets 14,201 (3,169 ) 11,032 Other long-term assets 23,159 (18,097 ) 5,062 Accrued liabilities 90,974 (1,407 ) 89,567 Long-term debt 1,595,413 (21,266 ) 1,574,147 Deferred tax liabilities 30,940 1,407 32,347

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Major customers: Phillips 66 12% 12% 14% Royal Dutch Shell plc and subsidiaries 14% n/a n/a Sinclair Oil & Gas Company 18% 11% n/a
Summary of Current Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, December 31, 2015 2014 Accrued capital expenditures $ 8,110 $ 36,042 Accrued interest payable 23,192 24,673 Accrued lease operating expense 16,843 15,594 Accrued ad valorem taxes 1,426 8,281 Accrued general and administrative expenses 1,961 1,276 Environmental liability 216 2,092 Asset retirement obligation - current 1,175 — Other — 1,609 $ 52,923 $ 89,567
Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 107,272 $ 63,709 $ 42,599 Cash paid for taxes 472 151 168 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (27,932 ) 13,759 18,779 (Increase) decrease in accounts receivable related to acquisitions 9,698 (5,854 ) (4,301 ) Repurchases under unit repurchase program — 1,372 — Assumptions of asset retirement obligations related to properties acquired 23,754 4,265 1,581

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisition-Related Costs	Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Year Ended December 31, 2015 2014 2013 $ 1,928 $ 4,363 $ 6,729
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed	The following table summarizes the fair value of the third party assets acquired and liabilities assumed in the 2015 Beta Acquisition (in thousands): Beta Acquisition Oil and gas properties $ 40,029 Prepaid expenses and other current assets 840 Restricted investments 69,579 Derivative instruments 4,568 Accounts receivable - affiliates and other 4,499 Asset retirement obligations (22,871 ) Accrued liabilities (2,010 ) Total identifiable net assets $ 94,634 The following table summarizes the 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
Supplemental Pro Forma Information	The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2015 and 2014 as though the 2015 Beta Acquisition had been completed on January 1, 2014. 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 (iii) accretion expense associated with asset retirement obligations recorded and (iv) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Year Ended December 31, 2015 2014 (In thousands, except per unit amounts) Revenues $ 381,495 $ 613,563 Net income (loss) (394,756 ) 132,630 Basic and diluted earnings per unit (4.73 ) 1.87 The following unaudited pro forma combined results of operations are provided for the years 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 2013 (In thousands, except per unit amounts) Revenues $ 666,508 $ 634,722 Net income (loss) 153,843 194,092 Basic and diluted earnings per unit 2.20 3.08

Fair Value Measurements of Fi28

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2015 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 816,995 $ — $ 816,995 Interest rate derivatives — — — — Total assets $ — $ 816,995 $ — $ 816,995 Liabilities: Commodity derivatives $ — $ 84,501 $ — $ 84,501 Interest rate derivatives — 2,655 — 2,655 Total liabilities $ — $ 87,156 $ — $ 87,156 Fair Value Measurements at December 31, 2014 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 564,913 $ — $ 564,913 Interest rate derivatives — 1,305 — 1,305 Total assets — $ 566,218 — $ 566,218 Liabilities: Commodity derivatives $ — $ 45,831 $ — $ 45,831 Interest rate derivatives — 3,289 — 3,289 Total liabilities $ — $ 49,120 $ — $ 49,120

Risk Management and Derivativ29

Risk Management and Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Open Commodity Positions	At December 31, 2015, the Partnership had the following open commodity positions: 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,592,442 3,350,067 3,060,000 2,814,583 Weighted-average fixed price $ 4.14 $ 4.06 $ 4.18 $ 4.31 Basis swaps: Average Monthly Volume (MMBtu) 3,578,333 2,210,000 1,315,000 900,000 Spread $ (0.07 ) $ (0.04 ) $ (0.02 ) $ 0.01 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 304,813 301,600 312,000 160,000 Weighted-average fixed price $ 85.48 $ 85.00 $ 83.74 $ 85.52 Basis swaps: Average Monthly Volume (Bbls) 140,000 67,500 — — Spread $ (10.02 ) $ (7.82 ) $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 213,100 43,300 — — Weighted-average fixed price $ 35.64 $ 37.55 $ — $ —
Interest Rate Swap Open Positions	At December 31, 2015, we had the following interest rate swap open positions: 2016 2017 2018 Average Monthly Notional (in thousands) $ 400,000 $ 400,000 $ 100,000 Weighted-average fixed rate 0.943 % 1.612 % 1.946 % 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, 2015 and 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives December 31, December 31, December 31, December 31, Type Balance Sheet Location 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 324,265 $ 225,882 $ 53,581 $ 17,297 Interest rate swaps Short-term derivative instruments — — 1,214 3,289 Gross fair value 324,265 225,882 54,795 20,586 Netting arrangements Short-term derivative instruments (51,945 ) (17,297 ) (51,945 ) (17,297 ) Net recorded fair value Short-term derivative instruments $ 272,320 $ 208,585 $ 2,850 $ 3,289 Commodity contracts Long-term derivative instruments $ 492,730 $ 339,031 $ 30,920 $ 28,534 Interest rate swaps Long-term derivative instruments — 1,305 1,441 — Gross fair value 492,730 340,336 32,361 28,534 Netting arrangements Long-term derivative instruments (30,920 ) (28,534 ) (30,920 ) (28,534 ) Net recorded fair value Long-term derivative instruments $ 461,810 $ 311,802 $ 1,441 $ —
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, 2015, 2014, and 2013: For the Year Ended Statements of December 31, Operations Location 2015 2014 2013 Commodity derivative contracts (Gain) loss on commodity derivatives $ (462,890 ) $ (492,254 ) $ (26,133 ) Interest rate derivatives Interest expense, net 4,674 (151 ) (548 )
Disaggregated Basis Swap [Member]
Open Commodity Positions	Our basis swaps included in the table above are presented on a disaggregated basis below: 2016 2017 2018 2019 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 3,003,333 1,800,000 1,200,000 900,000 Spread-Henry Hub $ (0.07 ) $ (0.07 ) $ (0.03 ) $ 0.01 HSC basis swaps: Average Monthly Volume (MMBtu) 135,000 115,000 115,000 — Spread-Henry Hub $ 0.07 $ 0.14 $ 0.15 $ — CIG basis swaps: Average Monthly Volume (MMBtu) 170,000 — — — Spread-Henry Hub $ (0.30 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 270,000 295,000 — — Spread-Henry Hub $ 0.06 $ 0.03 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 100,000 37,500 — — Spread - Brent $ (12.29 ) $ (12.20 ) $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 30,000 — — Spread - WTI $ (4.34 ) $ (2.35 ) $ — $ —

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the years ended December 31, 2015, 2014, and 2013: 2015 2014 2013 (in thousands) Asset retirement obligations at beginning of period $ 112,702 $ 101,436 $ 93,031 Liabilities added from acquisitions or drilling 26,876 5,815 2,116 Liabilities removed upon sale of wells (3,412 ) — — Liabilities settled (1,430 ) (651 ) (20 ) Accretion expense 7,125 5,773 4,988 Revision of estimates 22,303 329 1,321 Asset retirement obligations at end of period 164,164 112,702 101,436 Less: Current portion 1,175 — — Asset retirement obligations - long-term portion $ 162,989 $ 112,702 $ 101,436

Restricted Investments (Tables)

Restricted Investments (Tables)	12 Months Ended
	Dec. 31, 2015
Investments Debt And Equity Securities [Abstract]
Restricted Investment Balance	The components of the restricted investment balance are as follows December 31, December 31, 2015 2014 (In thousands) BOEM platform abandonment (See Note 13) $ 144,008 $ 69,954 BOEM lease bonds 1,533 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 3,178 2,701 California State Lands Commission pipeline right-of-way bond 3,005 3,005 City of Long Beach pipeline facility permit 500 500 Federal pipeline right-of-way bond 307 307 Port of Long Beach pipeline license 100 100 Restricted investments $ 152,631 $ 77,361

Long Term Debt (Tables)

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Consolidated Debt Obligations	Our consolidated debt obligations consisted of the following at the dates indicated: December 31, December 31, 2015 2014 (In thousands) MEMP: OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 836,000 $ 412,000 2021 Senior Notes, fixed-rate, due May 2021 (1) (3) 700,000 700,000 2022 Senior Notes, fixed-rate, due August 2022 (2) (3) 496,990 500,000 Senior notes debt issuance costs, net (18,297 ) (21,266 ) Unamortized discounts (14,114 ) (16,587 ) Total long-term debt $ 2,000,579 $ 1,574,147 (1) The estimated fair value of our 2021 Senior Notes was $210.0 million and $563.5 million at December 31, 2015 and 2014, respectively. (2) The estimated fair value of our 2022 Senior Notes was $149.1 million and $380.0 million at December 31, 2015 and 2014, respectively. (3) 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, 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 1,175,000
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, 2015 2014 2013 OLLC revolving credit facility 2.12% 2.67% 3.25% MRD LLC revolving credit facility n/a n/a 3.17% WHT revolving credit facility n/a n/a 2.29% Stanolind revolving credit facility n/a n/a 3.52% Boaz revolving credit facility n/a n/a 2.97% Crown revolving credit facility n/a n/a 3.38% Tanos revolving credit facility n/a n/a 3.10% Propel Energy revolving credit facility n/a n/a 3.08%
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, 2015 2014 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 3,672 $ 6,468 2021 Senior Notes (2) 11,194 13,308 2022 Senior Notes (2) 7,103 7,958 Total $ 21,969 $ 27,734 (1) Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility. (2) Unamortized deferred financing costs are amortized using the straight line method which generally approximates the effective interest method.
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 Credit Facility Credit Total For the Twelve Months Ended December 31, 2015: Advances on revolving credit facility $ 562,000 $ — $ 562,000 Payments on revolving credit facility $ (138,000 ) $ — $ (138,000 ) 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 ) $ (356,537 ) $ (1,565,537 )

Equity and Distributions (Table

Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2012: General Common Subordinated Partner 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 issued 827,704 — — Restricted common units forfeited (69,059 ) — — Restricted common units repurchased (1) (87,228 ) — — Common units repurchased under repurchase program (3,547,921 ) — — Subordinated units converted to common units 5,360,912 (5,360,912 ) — Balance, December 31, 2015 82,906,400 — 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 $1.3 million, $1.0 million and $0.1 million for the years ended December 31, 2015, 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 % 0.1 % 14.9 % Thereafter above $0.59375 75.0 % 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.
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 4 th January 26, 2016 February 5, 2016 February 12, 2016 $ 0.1000 $ 8.3 $ < 0.1 3 rd October 26, 2015 November 5, 2015 November 12, 2015 $ 0.3000 $ 24.9 $ < 0.1 2 nd July 24, 2015 August 5, 2015 August 12, 2015 $ 0.5500 $ 45.7 $ 0.1 1 st April 24, 2015 May 6, 2015 May 13, 2015 $ 0.5500 $ 46.3 $ 0.2 4 th January 26, 2015 February 5, 2015 February 12, 2015 $ 0.5500 $ 46.3 $ 3.1 3 rd October 23, 2014 November 5, 2014 November 12, 2014 $ 0.5500 $ 47.8 $ 3.1 2 nd July 24, 2014 August 5, 2014 August 12, 2014 $ 0.5500 $ 39.5 $ 3.0 1 st April 24, 2014 May 6, 2014 May 13, 2014 $ 0.5500 $ 33.8 $ 3.0 4 th January 24, 2014 February 6, 2014 February 13, 2014 $ 0.5500 $ 33.8 $ 3.0 3 rd October 22, 2013 November 1, 2013 November 12, 2013 $ 0.5500 $ 33.8 $ 6.9 2 nd July 18, 2013 August 1, 2013 August 12, 2013 $ 0.5125 $ 22.9 $ 6.4 1 st April 18, 2013 May 1, 2013 May 13, 2013 $ 0.5125 $ 22.6 $ 6.4
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): WHT Properties Cinco Group Property Swap Total Previous Owners Balance, December 31, 2012 107,893 276,801 153,098 537,792 Net income (loss) (1,219 ) 12,494 40,737 52,012 Contributions — 7,233 89,570 96,803 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 $ — $ — $ 283,405 $ 283,405 Net income (loss) — — (2,465 ) (2,465 ) Contributions — — 5,990 5,990 Distributions — — (9,886 ) (9,886 ) Distribution of net asset to MRD Holdco — — (26,131 ) (26,131 ) Tax related effects attributable to Memorial Resource restructuring transactions and initial public offering — — (30,483 ) (30,483 ) Other — — 227 227 Balance, December 31, 2014 $ — $ — $ 220,657 $ 220,657 Net income (loss) — — (2,268 ) (2,268 ) Contributions — — 1,912 1,912 Net book value of net assets exchanged — — (248,321 ) (248,321 ) Deferred tax liability retained by previous owner — — 28,020 28,020 Balance, December 31, 2015 $ — $ — $ — $ —

Earnings per Unit (Tables)

Earnings per Unit (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Calculation of Earnings (Loss) Per Unit	The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts): For the Year Ended December 31, 2015 2014 2013 Net income (loss) attributable to Memorial Production Partners LP $ (395,877 ) $ 115,582 $ 60,738 Less: Previous owners interest in net income (loss) (2,268 ) (2,465 ) 52,012 Less: General partner's 0.1% interest in net income (loss) (1) (412 ) 118 9 Less: IDRs attributable to corresponding period 112 202 81 Net income (loss) available to limited partners $ (393,309 ) $ 117,727 $ 8,636 Weighted average limited partner units outstanding: Common units 82,897 65,498 40,656 Subordinated units 631 5,361 5,361 Total 83,528 70,859 46,017 Basic and diluted EPU $ (4.71 ) $ 1.66 $ 0.19 (1) As a result of repurchases under the MEMP Repurchase Program, our general partner had an approximate average 0.105% interest in us for the year ended December 31, 2015.

Equity-based Awards (Tables)

Equity-based Awards (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Information Regarding Restricted Common Unit Awards	The following table summarizes information regarding restricted common unit awards for the periods presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted common units outstanding at December 31, 2012 285,609 $ 18.08 Granted (2) 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 (3) 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 Granted (4) 827,704 $ 14.90 Forfeited (69,059 ) $ 18.35 Vested (483,627 ) $ 20.37 Restricted common units outstanding at December 31, 2015 1,368,538 $ 17.61 (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 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 per unit. (3) 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. (4) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.3 million based on grant date market prices ranging from of $6.20 to $15.45 per unit.
Summary of Amount of Compensation Expense Recognized	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 $ 10,809 $ 7,874 $ 3,558

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
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
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, 2015 2014 2013 $ 32,281 $ 24,372 $ 9,440
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 Property and equipment, net $ 37,838 $ 9,822 Asset retirement obligations (908 ) (149 ) Other current liabilities (722 ) — Net assets $ 36,208 $ 9,673
February 2015 Acquisition [Member]
Related Party Transaction [Line Items]
Schedule of Net Assets Recorded by Partnership	The Partnership recorded the following net assets (in thousands): Accounts receivable $ 2,372 Other receivables 5,478 Prepaid expenses and other current assets 1,874 Property and equipment, net 263,210 Accounts payable (3,586 ) Accounts payable - affiliate (1,290 ) Revenues payable (1,110 ) Accrued liabilities (11,347 ) Asset retirement obligations (4,559 ) Net assets $ 251,042

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Environmental Reserves	The following table presents the activity of our environmental reserves for the periods presented: 2015 2014 2013 (In thousands) Balance at beginning of period $ 2,092 $ 437 $ 1,051 Charged to costs and expenses — 2,852 — Payments (1,876 ) (1,197 ) (614 ) Balance at end of period $ 216 $ 2,092 $ 437
Minimum Balances Attributable to Net Working Interest	The trust account must maintain minimum balances as follows (in thousands): June 30, 2016 $ 148,000 December 31, 2016 $ 152,000
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 2016 2017 2018 2019 2020 Thereafter Operating leases $ 6,107 $ 1,007 $ 317 $ 294 $ 294 $ 295 $ 3,900
Purchase Commitments Under the Contracts	At December 31, 2015, we had a CO 2 Payment or Settlement Due by Period Purchase commitment Total 2016 2017 2018 2019 2020 Thereafter CO 2 $ 30,307 $ 7,393 $ 7,505 $ 5,075 $ 5,366 $ 4,968 $ — Offshore ship services & other 4,662 4,662 — — — — — At December 31, 2015, we had a seven year minimum volume commitment with a third party associated with a certain portion of our properties located in East Texas. The table below outlines the payment commitments associated with this minimum volume commitment (in thousands): Payment or Settlement Due by Period Purchase commitment Total 2016 2017 2018 2019 2020 Thereafter Midstream services $ 35,788 $ 5,121 $ 5,121 $ 5,106 $ 5,107 $ 5,106 $ 10,227

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Components of Income Tax Expense (Benefit)	The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Current taxes: Federal $ (11 ) $ — $ — State (48 ) (127 ) (308 ) Total current income tax benefit (expense) (59 ) (127 ) (308 ) Deferred taxes: Federal 1,193 2,057 — State 1,041 (509 ) — Total deferred income tax benefit (expense) 2,234 1,548 — Total income tax benefit (expense) $ 2,175 $ 1,421 $ (308 )
Reconciliation of Income Tax Benefit (Provision)	The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows: For the Year Ended December 31, 2015 2014 2013 Expected tax benefit (expense) at federal statutory rate $ 139,183 $ (39,966 ) $ (21,459 ) State income tax benefit (expense), net of federal benefit 645 (1,907 ) (308 ) Pass-through entities (1) (137,704 ) 42,000 21,459 Other 51 1,294 — Total income tax benefit (expense) $ 2,175 $ 1,421 $ (308 ) (1) MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes.
Components of Net Deferred Income Tax Liabilities	The components of net deferred income tax liabilities recognized were as follows: December 31, 2015 2014 (In thousands) Deferred income tax assets: Net operating loss carryforward $ 56 $ 3,959 Asset retirement obligation 694 1,855 Other 38 15 Total deferred income tax assets: 788 5,829 Valuation allowance — (2,633 ) Net deferred income tax assets 788 3,196 Deferred income tax liabilities: Property, plant and equipment $ 1,324 $ 32,094 Derivatives 1,514 3,388 Other 44 61 Total deferred income tax liabilities 2,882 35,543 Net deferred income tax liabilities $ 2,094 $ 32,347

Quarterly Financial Informati39

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015: Revenues $ 92,818 $ 98,138 $ 88,083 $ 79,108 Operating income (loss) (136,370 ) (85,197 ) (160,844 ) 99,434 Net income (loss) (162,658 ) (113,859 ) (191,981 ) 73,007 Net income (loss) attributable to Memorial Production Partners LP (162,817 ) (113,924 ) (192,085 ) 72,949 Net income (loss) allocated to previous owners (2,268 ) — — — Net income (loss) noncontrolling interest 159 65 104 58 Limited partners’ interest in net income (loss) (160,439 ) (113,862 ) (191,938 ) 72,874 Basic and diluted earnings per unit (1.90 ) (1.36 ) (2.31 ) 0.88 First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per unit amounts) For the Year Ended December 31, 2014: Revenues $ 116,885 $ 144,208 $ 166,261 $ 138,689 Operating income (loss) (16,739 ) (93,294 ) 127,078 181,355 Net income (loss) (32,892 ) (111,640 ) 101,307 158,839 Net income (loss) attributable to Memorial Production Partners LP (32,947 ) (111,628 ) 101,157 159,000 Net income (loss) allocated to previous owners 1,165 2,566 (1,919 ) (4,277 ) 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

Supplemental Oil and Gas Info40

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 (In thousands) Evaluated oil and natural gas properties $ 3,616,325 $ 3,329,338 $ 2,077,344 Support equipment and facilities 205,876 198,088 16,030 Unevaluated oil and natural gas properties — — 1,960 Accumulated depletion, depreciation, and amortization (1,878,549 ) (1,060,114 ) (464,812 ) Total $ 1,943,652 $ 2,467,312 $ 1,630,522
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, 2015 2014 2013 (In thousands) Property acquisition costs, proved $ 77,834 $ 983,076 $ 37,786 Property acquisition costs, unproved 1,887 720 — Exploration 2,078 — — Development 233,241 308,724 166,090 Total $ 315,040 $ 1,292,520 $ 203,876
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: 2015 2014 2013 Oil ($/Bbl): WTI (1) $ 46.79 $ 91.48 $ 93.42 NGL ($/Bbl): WTI (1) $ 46.79 $ 91.48 $ 93.42 Natural Gas ($/MMbtu): Henry Hub (2) $ 2.58 $ 4.35 $ 3.67 (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, 2015, 2014 and 2013, respectively: Year Ended December 31, 2015 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 100,258 727,216 59,034 1,682,960 Extensions and discoveries 2,319 8,686 558 25,950 Purchase of minerals in place 10,132 34,128 367 97,122 Production (4,087 ) (50,875 ) (2,820 ) (92,315 ) Sale of minerals in place (380 ) (13,731 ) (758 ) (20,559 ) Revision of previous estimates (17,297 ) (243,898 ) (12,986 ) (425,587 ) End of year 90,945 461,526 43,395 1,267,571 Proved developed reserves: Beginning of year 54,723 417,247 37,260 969,141 End of year 50,817 311,147 30,315 797,936 Proved undeveloped reserves: Beginning of year 45,535 309,969 21,774 713,819 End of year 40,128 150,379 13,080 469,635 Year Ended December 31, 2014 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 39,635 737,908 35,794 1,190,484 Extensions and discoveries 849 12,783 711 22,145 Purchase of minerals in place 69,095 13,036 22,351 561,713 Production (3,135 ) (48,721 ) (2,498 ) (82,520 ) Revision of previous estimates (6,186 ) 12,210 2,676 (8,862 ) End of year 100,258 727,216 59,034 1,682,960 Proved developed reserves: Beginning of year 22,429 427,983 17,637 668,381 End of year 54,723 417,247 37,260 969,141 Proved undeveloped reserves: Beginning of year 17,206 309,925 18,157 522,103 End of year 45,535 309,969 21,774 713,819 Year Ended December 31, 2013 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 40,822 794,369 39,554 1,276,625 Extensions and discoveries 5,814 85,455 4,353 146,463 Purchase of minerals in place 119 16,294 258 18,554 Production (1,797 ) (41,287 ) (1,806 ) (62,907 ) Revision of previous estimates (5,323 ) (116,923 ) (6,565 ) (188,251 ) End of year 39,635 737,908 35,794 1,190,484 Proved developed reserves: Beginning of year 24,784 441,858 18,060 698,922 End of year 22,429 427,983 17,637 668,381 Proved undeveloped reserves: Beginning of year 16,038 352,511 21,494 577,703 End of year 17,206 309,925 18,157 522,103
Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows is as follows: Years Ended December 31, 2015 2014 2013 (In thousands) Future cash inflows $ 5,952,935 $ 14,190,450 $ 7,672,312 Future production costs (3,194,577 ) (4,821,051 ) (2,963,146 ) Future development costs (808,512 ) (1,455,926 ) (901,374 ) Future income tax expense (1) — (119,675 ) — Future net cash flows for estimated timing of cash flows 1,949,846 7,793,798 3,807,792 10% annual discount for estimated timing of cash flows (1,360,292 ) (4,881,811 ) (2,089,588 ) Standardized measure of discounted future net cash flows $ 589,554 $ 2,911,987 $ 1,718,204 (1) We are subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality we have excluded the impact of this tax for the years ended December 31, 2015, 2014 and 2013. The 2014 amount was related to Classic since its reserves were a part of a taxable entity for federal income tax purposes for the year ended December 31, 2014.
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, 2015: Years Ended December 31, 2015 2014 2013 (In thousands) Beginning of year $ 2,911,987 $ 1,718,204 $ 1,772,240 Sale of oil and natural gas produced, net of production costs (128,382 ) (354,932 ) (255,031 ) Purchase of minerals in place 75,998 1,489,477 23,160 Sale of minerals in place (45,100 ) — — Extensions and discoveries 18,582 44,843 150,631 Changes in income taxes, net 63,180 (63,180 ) — Changes in prices and costs (2,764,481 ) (170,682 ) (26,648 ) Previously estimated development costs incurred 322,446 275,078 199,775 Net changes in future development costs 448,089 (133,098 ) (16,219 ) Revisions of previous quantities (344,775 ) (48,087 ) (373,109 ) Accretion of discount 297,517 171,820 177,223 Change in production rates and other (265,507 ) (17,456 ) 66,182 End of year $ 589,554 $ 2,911,987 $ 1,718,204

Organization and Basis of Pre41

Organization and Basis of Presentation - Additional Information (Detail) $ in Thousands	Nov. 03, 2015USD ($)	Dec. 31, 2015USD ($)Segment	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments | Segment		1
Acquisitions of oil and natural gas properties		$ 100,730	$ 1,083,761	$ 38,664
Purchase of noncontrolling interest in SPBPC	$ 6,000
2015 Beta Acquisition [Member]
Consolidation And Basis Of Presentation [Line Items]
Acquisitions of oil and natural gas properties	$ 94,600
Limited Partners Common Units [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage		99.90%
General Partner [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage		0.10%
General Partner [Member] | The Funds [Member]
Consolidation And Basis Of Presentation [Line Items]
Percentage of economic interest in incentive distribution rights		50.00%

Organization and Basis of Pre42

Organization and Basis of Presentation - Retrospective Balance Sheet Adjustments (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Consolidation And Basis Of Presentation [Line Items]
Prepaid expenses and other current assets	$ 7,028	$ 11,032
Other long-term assets	5,053	5,062
Accrued liabilities	52,923	89,567
Long-term debt	2,000,579	1,574,147
Deferred tax liabilities	$ 2,094	32,347
Previously Reported [Member]
Consolidation And Basis Of Presentation [Line Items]
Prepaid expenses and other current assets		14,201
Other long-term assets		23,159
Accrued liabilities		90,974
Long-term debt		1,595,413
Deferred tax liabilities		30,940
Adjustment Effect [Member]
Consolidation And Basis Of Presentation [Line Items]
Prepaid expenses and other current assets		(3,169)
Other long-term assets		(18,097)
Accrued liabilities		(1,407)
Long-term debt		(21,266)
Deferred tax liabilities		$ 1,407

Summary of Significant Accoun43

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
Capitalized exploratory drilling costs pending evaluation	$ 0	$ 0	$ 0
Amortization expense including write-off of debt issuance costs	6,100,000	4,200,000	6,000,000
Impairment expense	616,784,000	407,540,000	4,072,000
Capitalized interest	$ 2,100,000	$ 2,800,000	$ 0
Chance of tax benefit likely to be realized	greater than 50%
Customer Concentration Risk [Member] | Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of total revenue	10.00%
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	3 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	5 years
Support Equipment and Facilities [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	15 years
Support Equipment and Facilities [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	40 years

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Major Customers (Detail) - Customer Concentration Risk [Member] - Revenues [Member]	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Significant Accounting Policies [Line Items]
Total Reported Revenues	10.00%
Phillips 66 [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	12.00%	12.00%	14.00%
Royal Dutch Shell plc and subsidiaries [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	14.00%
Sinclair Oil & Gas Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	18.00%	11.00%

Summary of Significant Accoun45

Summary of Significant Accounting Policies - Summary of Current Accrued Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accrued Liabilities Current [Abstract]
Accrued capital expenditures	$ 8,110	$ 36,042
Accrued interest payable	23,192	24,673
Accrued lease operating expense	16,843	15,594
Accrued ad valorem taxes	1,426	8,281
Accrued general and administrative expenses	1,961	1,276
Environmental liability	216	2,092
Asset retirement obligation - current	1,175	0
Other	0	1,609
Accrued liabilities, Total	$ 52,923	$ 89,567

Summary of Significant Accoun46

Summary of Significant Accounting Policies - Summary of Supplemental Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$ 107,272	$ 63,709	$ 42,599
Cash paid for taxes	472	151	168
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	(27,932)	13,759	18,779
(Increase) decrease in accounts receivable related to acquisitions	9,698	(5,854)	(4,301)
Repurchases under unit repurchase program	0	1,372	0
Assumptions of asset retirement obligations related to properties acquired	$ 23,754	$ 4,265	$ 1,581

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisition-Related Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
General and Administrative Expense
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	$ 1,928	$ 4,363	$ 6,729

Acquisitions and Divestitures48

Acquisitions and Divestitures - Additional Information (Detail) - USD ($)	Jul. 01, 2014	Mar. 25, 2014	Jan. 01, 2013	Oct. 11, 2012	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition And Divestiture [Line Items]
Oil and gas properties							$ 9,300,000
Proceeds from the sale of oil and natural gas properties				$ 2,000,000	$ 580,000		4,525,000
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
Permian Basin
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures					900,000
Permian Basin | Texas And New Mexico
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures					600,000
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
2015 Beta Acquisition [Member]
Business Acquisition And Divestiture [Line Items]
Revenue recorded in statement of operations					3,600,000
Earnings (Losses) recorded in statement of operations					$ (1,000,000)
Wyoming Acquisition [Member]
Business Acquisition And Divestiture [Line Items]
Revenue recorded in statement of operations	$ 72,800,000
Earnings (Losses) recorded in statement of operations	22,900,000
Purchase price	$ 906,100,000
Eagle Ford [Member]
Business Acquisition And Divestiture [Line Items]
Revenue recorded in statement of operations						$ 36,600,000
Earnings (Losses) recorded in statement of operations						$ 16,300,000
Purchase price		$ 168,100,000
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

Acquisitions and Divestitures49

Acquisitions and Divestitures - Summary of Fair Value of Assets Acquired and Liabilities Assumed (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Nov. 03, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Revenues payable	$ (25,504)		$ (30,110)
Wyoming Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties			930,168
Revenues payable			(375)
Asset retirement obligations			(3,980)
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
2015 Beta Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties		$ 40,029
Prepaid expenses and other current assets		840
Restricted investments		69,579
Derivative instruments		4,568
Accounts receivable - affiliates and other		4,499
Asset retirement obligations		(22,871)
Accrued liabilities		(2,010)
Total identifiable net assets		$ 94,634

Acquisitions and Divestitures50

Acquisitions and Divestitures - Supplemental Pro Forma Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Revenues		$ 666,508	$ 634,722
Net income (loss)		$ 153,843	$ 194,092
Basic and diluted earnings per unit		$ 2.20	$ 3.08
2015 Beta Acquisition [Member]
Business Acquisition [Line Items]
Revenues	$ 381,495	$ 613,563
Net income (loss)	$ (394,756)	$ 132,630
Basic and diluted earnings per unit	$ (4.73)	$ 1.87

Fair Value Measurements of Fi51

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value [Member] - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	$ 816,995	$ 566,218
Interest rate derivatives, Assets	0	1,305
Liabilities	87,156	49,120
Interest rate derivatives, Liabilities	2,655	3,289
Quoted Prices in Active Market (Level 1) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0
Interest rate derivatives, Assets	0
Liabilities	0
Interest rate derivatives, Liabilities	0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	816,995	566,218
Interest rate derivatives, Assets	0	1,305
Liabilities	87,156	49,120
Interest rate derivatives, Liabilities	2,655	3,289
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0
Interest rate derivatives, Assets	0
Liabilities	0
Interest rate derivatives, Liabilities	0
Commodity derivatives [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	816,995	564,913
Liabilities	84,501	45,831
Commodity derivatives [Member] | Quoted Prices in Active Market (Level 1) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0
Liabilities	0
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	816,995	564,913
Liabilities	84,501	$ 45,831
Commodity derivatives [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0
Liabilities	$ 0

Fair Value Measurements of Fi52

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	$ 616,784	$ 407,540	$ 4,072
Carrying value of properties after impairment charges	1,946,323	2,470,332
Permian Basin
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties		234,200
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
Carrying value of properties after impairment charges		88,800
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
East Texas, Wyoming and Colorado [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	616,800
Carrying value of properties after impairment charges	$ 408,600

Risk Management and Derivativ53

Risk Management and Derivative Instruments - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Nov. 30, 2015	Feb. 28, 2015	Dec. 31, 2015	Nov. 03, 2015
Derivative Instruments Gain Loss [Line Items]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk			$ 350
Maximum amount of loss due to credit risk			380.9
Cash settlement receipt	$ 16.4	$ 27.1
Beta Acquisition [Member]
Derivative Instruments Gain Loss [Line Items]
Cash settlement receipt			4.4
Acquired hedges				$ 4.6
Single Counterparty [Member]
Derivative Instruments Gain Loss [Line Items]
Maximum amount of loss due to credit risk			$ 123.4

Risk Management and Derivativ54

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	12 Months Ended
	Dec. 31, 2015MMBTU$ / MMBTU$ / bblbbl
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) | MMBTU	3,592,442
Weighted-average fixed price | $ / MMBTU	4.14
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) | MMBTU	3,578,333
Spread | $ / MMBTU	(0.07)
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) | bbl	304,813
Weighted-average fixed price | $ / bbl	85.48
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) | bbl	140,000
Spread | $ / bbl	(10.02)
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) | bbl	213,100
Weighted-average fixed price | $ / bbl	35.64
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) | MMBTU	3,350,067
Weighted-average fixed price | $ / MMBTU	4.06
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) | MMBTU	2,210,000
Spread | $ / MMBTU	(0.04)
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) | bbl	301,600
Weighted-average fixed price | $ / bbl	85
2017 [Member] | Crude Oil Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	67,500
Spread | $ / bbl	(7.82)
2017 [Member] | NGL Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	43,300
Weighted-average fixed price | $ / bbl	37.55
2018 [Member] | Natural Gas Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,060,000
Weighted-average fixed price | $ / MMBTU	4.18
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) | MMBTU	1,315,000
Spread | $ / MMBTU	(0.02)
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) | bbl	312,000
Weighted-average fixed price | $ / bbl	83.74
2018 [Member] | Crude Oil Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	0
Spread | $ / bbl	0
2018 [Member] | NGL Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	0
Weighted-average fixed price | $ / bbl	0
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) | MMBTU	2,814,583
Weighted-average fixed price | $ / MMBTU	4.31
2019 [Member] | Natural Gas Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	900,000
Spread | $ / MMBTU	0.01
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) | bbl	160,000
Weighted-average fixed price | $ / bbl	85.52
2019 [Member] | Crude Oil Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	0
Spread | $ / bbl	0
2019 [Member] | NGL Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	0
Weighted-average fixed price | $ / bbl	0

Risk Management and Derivativ55

Risk Management and Derivative Instruments - Open Commodity Positions Disaggregated Basis (Detail) - Disaggregated Basis Swap [Member]	12 Months Ended
	Dec. 31, 2015MMBTU$ / MMBTU$ / bblbbl
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) | MMBTU	3,003,333
2016 [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	135,000
2016 [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) | MMBTU	170,000
2016 [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	270,000
2016 [Member] | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	100,000
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) | bbl	40,000
2016 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	(0.07)
2016 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0.07
2016 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts CIG Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	(0.30)
2016 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0.06
2016 [Member] | Brent | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / bbl	(12.29)
2016 [Member] | WTI | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / bbl	(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) | MMBTU	1,800,000
2017 [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	115,000
2017 [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) | MMBTU	0
2017 [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) | MMBTU	295,000
2017 [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) | bbl	37,500
2017 [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) | bbl	30,000
2017 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	(0.07)
2017 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0.14
2017 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts CIG Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0
2017 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0.03
2017 [Member] | Brent | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / bbl	(12.20)
2017 [Member] | WTI | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / bbl	(2.35)
2018 [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) | MMBTU	1,200,000
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) | MMBTU	115,000
2018 [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) | MMBTU	0
2018 [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) | MMBTU	0
2018 [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) | bbl	0
2018 [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) | bbl	0
2018 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	(0.03)
2018 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0.15
2018 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts CIG Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0
2018 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0
2018 [Member] | Brent | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / bbl	0
2018 [Member] | WTI | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / bbl	0
2019 [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) | MMBTU	900,000
2019 [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) | MMBTU	0
2019 [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) | MMBTU	0
2019 [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) | MMBTU	0
2019 [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) | bbl	0
2019 [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) | bbl	0
2019 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0.01
2019 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0
2019 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts CIG Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0
2019 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / MMBTU	0
2019 [Member] | Brent | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / bbl	0
2019 [Member] | WTI | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / bbl	0

Risk Management and Derivativ56

Risk Management and Derivative Instruments - Interest Rate Swap Open Positions (Detail) - Interest rate swaps [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
2016 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	0.943%
Floating rate	1 Month LIBOR
2017 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	1.612%
Floating rate	1 Month LIBOR
2018 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 100,000
Weighted-average fixed rate	1.946%
Floating rate	1 Month LIBOR

Risk Management and Derivativ57

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 272,320	$ 208,585
Asset Derivatives, Net recorded fair value	461,810	311,802
Liability Derivatives, Net recorded fair value	2,850	3,289
Liability Derivatives, Net recorded fair value	1,441	0
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	324,265	225,882
Asset Derivatives, Netting arrangements	(51,945)	(17,297)
Asset Derivatives, Net recorded fair value	272,320	208,585
Liability Derivatives, Gross fair value	54,795	20,586
Liability Derivatives, Netting arrangements	(51,945)	(17,297)
Liability Derivatives, Net recorded fair value	2,850	3,289
Short-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	324,265	225,882
Liability Derivatives, Gross fair value	53,581	17,297
Short-Term Derivative Instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	0
Liability Derivatives, Gross fair value	1,214	3,289
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	492,730	340,336
Asset Derivatives, Netting arrangements	(30,920)	(28,534)
Asset Derivatives, Net recorded fair value	461,810	311,802
Liability Derivatives, Gross fair value	32,361	28,534
Liability Derivatives, Netting arrangements	(30,920)	(28,534)
Liability Derivatives, Net recorded fair value	1,441
Long-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	492,730	339,031
Liability Derivatives, Gross fair value	30,920	28,534
Long-Term Derivative Instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	0	$ 1,305
Liability Derivatives, Gross fair value	$ 1,441

Risk Management and Derivativ58

Risk Management and Derivative Instruments - Unrealized and Realized Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	$ (462,890)	$ (492,254)	$ (26,133)
Interest expense, net	(114,732)	(83,550)	(44,302)
Commodity derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	(462,890)	(492,254)	(26,133)
Interest rate derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net	$ 4,674	$ (151)	$ (548)

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 112,702	$ 101,436	$ 93,031
Liabilities added from acquisitions or drilling	26,876	5,815	2,116
Liabilities removed upon sale of wells	(3,412)
Liabilities settled	(1,430)	(651)	(20)
Accretion expense	7,125	5,773	4,988
Revision of estimates	22,303	329	1,321
Asset retirement obligations at end of period	164,164	112,702	101,436
Less: Current portion	1,175	0
Asset retirement obligations - long-term portion	$ 162,989	$ 112,702	$ 101,436

Restricted Investments - Restri

Restricted Investments - Restricted Investment Balance (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Schedule Of Investments [Line Items]
Restricted investments	$ 152,631	$ 77,361
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	144,008	69,954
BOEM lease bonds [Member]
Schedule Of Investments [Line Items]
Restricted investments	1,533	794
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	3,178	2,701
SPBPC Collateral Lands Commission pipeline right-of-way bond [Member] | California State
Schedule Of Investments [Line Items]
Restricted investments	3,005	3,005
SPBPC Collateral City of Long Beach pipeline facility permit [Member]
Schedule Of Investments [Line Items]
Restricted investments	500	500
SPBPC Collateral Federal pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	307	307
SPBPC Collateral Port of Long Beach pipeline license [Member]
Schedule Of Investments [Line Items]
Restricted investments	$ 100	$ 100

Restricted Investments - Additi

Restricted Investments - Additional Information (Detail)	Dec. 31, 2015	Dec. 31, 2014
Beta Acquisition [Member]
Schedule Of Investments [Line Items]
Percentage of working interest owned	100.00%	51.75%

Long Term Debt - Consolidated D

Long Term Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Unamortized discounts		$ (14,114)	$ (16,587)
Total long-term debt		2,000,579	1,574,147
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Revolving credit facility		836,000	412,000
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Senior Notes, fixed-rate	[1],[2]	700,000	700,000
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Senior Notes, fixed-rate	[1],[3]	496,990	500,000
Senior Notes [Member]
Debt Instrument [Line Items]
Debt issuance costs, net		$ (18,297)	$ (21,266)
[1]	(3) 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 2021 Senior Notes was $210.0 million and $563.5 million at December 31, 2015 and 2014, respectively.
[3]	The estimated fair value of our 2022 Senior Notes was $149.1 million and $380.0 million at December 31, 2015 and 2014, respectively.

Long Term Debt - Consolidated63

Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Maturity date	Mar. 19, 2018
Revolving credit facility	$ 2,000,000,000
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Maturity date	May 1, 2021
Estimated fair value of fixed rate debt	$ 210,000,000	$ 563,500,000
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Maturity date	Aug. 1, 2022
Estimated fair value of fixed rate debt	$ 149,100,000	$ 380,000,000

Long Term Debt - Additional Inf

Long Term Debt - Additional Information (Detail) - USD ($)	Jul. 17, 2014	Nov. 22, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 18, 2013	Oct. 10, 2013	May. 23, 2013	Apr. 17, 2013	Apr. 01, 2013	Mar. 28, 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			$ 2,100,000
Minimum [Member]
Line of Credit Facility [Line Items]
Variable LIBOR Market index plus margin, Maximum			1.50%
Variable commitment fee			0.375%
Maximum [Member]
Line of Credit Facility [Line Items]
Variable LIBOR Market index plus margin, Maximum			2.50%
Variable commitment fee			0.50%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line of Credit Facility [Line Items]
Revolving credit facility, maximum borrowing capacity			$ 2,000,000,000
Maturity date			Mar. 19, 2018
Revolving credit facility			$ 836,000,000	$ 412,000,000
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Minimum [Member]
Line of Credit Facility [Line Items]
Lien percentage of assets for credit facility			80.00%
Senior Secured Notes [Member] | Notes Due 2022 [Member]
Line of Credit Facility [Line Items]
Maturity date			Aug. 1, 2022
Senior Secured Notes [Member] | Notes Due 2021 [Member]
Line of Credit Facility [Line Items]
Maturity date			May 1, 2021
Senior notes			7.625%
Other events of default minimum note holder percentage to accelerate			25.00%
Senior Secured Notes [Member] | Private Placement of Debt [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	6.875%
Senior notes issued at par	98.485%
Senior Secured Notes [Member] | Private Placement of Debt [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
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%
WHT revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility										$ 89,300,000
Termination date of revolving credit facility			Mar. 28, 2013
Tanos revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility									$ 27,000,000
Termination date of revolving credit facility			Apr. 1, 2013
REO revolving credit facility [Member]
Line of Credit Facility [Line Items]
Termination date of revolving credit facility			Dec. 12, 2012
Boaz And Crown [Member]
Line of Credit Facility [Line Items]
Termination date of revolving credit facility			Oct. 1, 2013
Stanolind And Propel Energy [Member]
Line of Credit Facility [Line Items]
Termination date of revolving credit facility			Oct. 1, 2013
MRD LLC revolving credit facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility					$ 59,700,000
Principal repayment		$ 20,000,000
Universal Shelf Registration Statement [Member]
Line of Credit Facility [Line Items]
Universal shelf guarantor subsidiaries ownership percentage			100.00%

Long Term Debt - Borrowing Base

Long Term Debt - Borrowing Base Credit Facility (Detail) $ in Thousands	Dec. 31, 2015USD ($)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line of Credit Facility [Line Items]
Borrowing base	$ 1,175,000

Long Term Debt - Borrowing Ba66

Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail)	Dec. 31, 2015USD ($)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line of Credit Facility [Line Items]
Revolving credit facility	$ 2,000,000,000

Long Term Debt - Summary of Wei

Long Term Debt - Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
OLLC revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates	2.12%	2.67%	3.25%
MRD LLC revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates			3.17%
WHT revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates			2.29%
Stanolind revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates			3.52%
Boaz revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates			2.97%
Crown revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates			3.38%
Tanos revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates			3.10%
Propel Energy revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates			3.08%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Unamortized deferred financing costs		$ 21,969	$ 27,734
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Unamortized deferred financing costs	[1]	3,672	6,468
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[2]	11,194	13,308
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[2]	$ 7,103	$ 7,958
[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 U69

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Parenthetical) (Detail)	Dec. 31, 2015USD ($)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Revolving credit facility	$ 2,000,000,000

Long Term Debt - Advances and R

Long Term Debt - Advances and Repayments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Credit Facilities [Line Items]
Advances on revolving credit facility	$ 562,000	$ 1,446,000	$ 958,355
Payments on revolving credit facilities	(138,000)	(1,137,000)	(1,565,537)
Revolving Credit Facilities [Member]
Credit Facilities [Line Items]
Advances on revolving credit facility			17,355
Payments on revolving credit facilities			(356,537)
OLLC revolving credit facility [Member]
Credit Facilities [Line Items]
Advances on revolving credit facility	562,000	1,446,000	941,000
Payments on revolving credit facilities	$ (138,000)	$ (1,137,000)	$ (1,209,000)

Equity and Distributions - Addi

Equity and Distributions - Additional Information (Detail)	Feb. 13, 2015shares	Sep. 09, 2014USD ($)$ / sharesshares	Jul. 15, 2014USD ($)$ / sharesshares	Oct. 08, 2013USD ($)$ / sharesshares	Mar. 25, 2013USD ($)$ / sharesshares	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2015USD ($)$ / Partnershipshares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)
Limited Partners Capital Account [Line Items]
Net proceeds from the issuance of common units | $										$ 540,698,000	$ 490,138,000
Subordination period									Feb. 13, 2015
Subordinated units converted to common units									0
Partner percentage on common units									0.10%
Common units amount repurchased under repurchase program | $									$ 52,813,000	12,903,000
Common units repurchased under repurchase program									0
Maximum IDR distribution percentage									24.90%
Second Target Quarterly Distribution Minimum, per unit | $ / Partnership									0.54625
Percentage of general partner interest incentive distribution									0.10%
Minimum Quarterly Distribution amount per common unit | $ / Partnership									0.475
Common unitholders, pro rata percentage						99.90%	99.90%	99.90%
Cash Distribution Percentage For General Partners						0.10%	0.10%	0.10%
Percentage of General Partner incentive when no subordinated units outstanding									25.00%
MEMP Repurchase Program [Member]
Limited Partners Capital Account [Line Items]
Stock repurchase program, authorized amount | $										150,000,000
Common units amount repurchased under repurchase program | $									$ 52,800,000	$ 12,900,000
Common units repurchased under repurchase program									3,547,921	899,912
Amount remaining under repurchase program | $									$ 0
Minimum [Member]
Limited Partners Capital Account [Line Items]
Second Target Quarterly Distribution Minimum, per unit | $ / Partnership									0.54625
Minimum [Member] | General Partner and Affiliates [Member]
Limited Partners Capital Account [Line Items]
Partner percentage on common units									80.00%
The Funds [Member] | IDR [Member]
Limited Partners Capital Account [Line Items]
Partnership ownership percentage									50.00%
Memorial Resource [Member]
Limited Partners Capital Account [Line Items]
Percentage of economic interest in incentive distribution rights									50.00%
General Partner [Member]
Limited Partners Capital Account [Line Items]
Partnership ownership percentage									0.10%
Common units amount repurchased under repurchase program | $									$ 0
Percentage of General Partner incentive when no subordinated units outstanding									0.10%
General Partner [Member] | IDR [Member]
Limited Partners Capital Account [Line Items]
Partnership ownership percentage									50.00%
General Partner [Member] | The Funds [Member]
Limited Partners Capital Account [Line Items]
Percentage of economic interest in incentive distribution rights									50.00%
General Partner [Member] | Memorial Resource [Member]
Limited Partners Capital Account [Line Items]
Partnership ownership percentage									100.00%
Subordinated Units [Member]
Limited Partners Capital Account [Line Items]
Subordinated units converted to common units									(5,360,912)
Common units repurchased under repurchase program									0
Subordinated Units [Member] | MRD Holdco [Member]
Limited Partners Capital Account [Line Items]
Subordinated units converted to common units	5,360,912
Conversion of stock description									The subordinated units converted on a one-for-one basis into common units upon the payment of MEMP's fourth quarter 2014 distribution. MRD Holdco sold all of the common units during the three months ended June 30, 2015 and no longer owns any of our outstanding common units.
2014 Public Equity Offerings [Member]
Limited Partners Capital Account [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 | $ / shares		$ 22.29	$ 22.25
Net proceeds from the issuance of common units | $		$ 321,300,000	$ 220,000,000
2013 Public Equity Offerings [Member]
Limited Partners Capital Account [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 | $ / shares				$ 19.90	$ 18.35
Net proceeds from the issuance of common units | $				$ 318,300,000	$ 171,800,000

Equity and Distributions - Summ

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Detail) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	86,797	61,300	34,317
Restricted common units issued	0
Restricted common units forfeited	0
Restricted common units repurchased	0
Common units repurchased under repurchase program	0
Subordinated units converted to common units	0
General partner units issued		25,497	26,983
Ending balance	86,797	86,797	61,300
Limited Partners Common Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	80,421,992	55,877,831	28,921,903
Common units issued		24,840,000	26,450,000
Restricted common units issued	827,704	684,954	524,717
Restricted common units forfeited	(69,059)	(38,294)	(11,734)
Restricted common units repurchased	(87,228)	(42,587)	(7,055)
Common units repurchased under repurchase program	(3,547,921)	(899,912)
Subordinated units converted to common units	5,360,912
Ending balance	82,906,400	80,421,992	55,877,831
Subordinated Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	5,360,912	5,360,912	5,360,912
Restricted common units issued	0
Restricted common units forfeited	0
Restricted common units repurchased	0
Common units repurchased under repurchase program	0
Subordinated units converted to common units	(5,360,912)
Ending balance	0	5,360,912	5,360,912

Equity and Distributions - Su73

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Parenthetical) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Changes In Number Of Outstanding Units [Abstract]
Withholding tax withheld and paid related to vesting of restricted common units	$ 1,285	$ 1,012	$ 100

Equity and Distributions - Su74

Equity and Distributions - Summary of Incentive Distributions (Detail)	12 Months Ended
	Dec. 31, 2015$ / Partnership
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]
Minimum Marginal Percentage Interest In Quarterly Distributions	0.00%
Marginal Percentage Interest In First Target Distributions	0.00%
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	0.4750
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 - Su75

Equity and Distributions - Summary of Incentive Distributions (Parenthetical) (Detail)	Dec. 31, 2015
The Funds [Member] | IDR [Member]
Distributions To Unitholders General Partner or IDR Holders [Line Items]
Percentage of IDRs owned	50.00%

Equity and Distributions - Su76

Equity and Distributions - Summary of Quarterly Cash Distribution Rates (Detail) - USD ($)

3 Months Ended

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Limited Partners Capital Account [Line Items]

Distribution made to member or limited partner, date of declaration

Jan. 26, 2016

Oct. 26, 2015

Jul. 24, 2015

Apr. 24, 2015

Jan. 26, 2015

Oct. 23, 2014

Jul. 24, 2014

Apr. 24, 2014

Jan. 24, 2014

Oct. 22, 2013

Jul. 18, 2013

Apr. 18, 2013

Distribution made to member or limited partner, date of record

Feb. 5, 2016

Nov. 5, 2015

Aug. 5, 2015

May 6, 2015

Feb. 5, 2015

Nov. 5, 2014

Aug. 5, 2014

May 6, 2014

Feb. 6, 2014

Nov. 1, 2013

Aug. 1, 2013

May 1, 2013

Distribution made to member or limited partner, date of distribution

Feb. 12, 2016

Nov. 12, 2015

Aug. 12, 2015

May 13, 2015

Feb. 12, 2015

Nov. 12, 2014

Aug. 12, 2014

May 13, 2014

Feb. 13, 2014

Nov. 12, 2013

Aug. 12, 2013

May 13, 2013

Distribution per unit

$ 0.1000

$ 0.3000

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5500

$ 0.5125

$ 0.5125

Aggregate Distribution

$ 8,300,000

$ 24,900,000

$ 45,700,000

$ 46,300,000

$ 46,300,000

$ 47,800,000

$ 39,500,000

$ 33,800,000

$ 33,800,000

$ 33,800,000

$ 22,900,000

$ 22,600,000

Distribution Received by Affiliates

$ 100,000

$ 200,000

$ 3,100,000

$ 3,100,000

$ 3,000,000

$ 3,000,000

$ 3,000,000

$ 6,900,000

$ 6,400,000

$ 6,400,000

Maximum [Member]

Limited Partners Capital Account [Line Items]

Distribution Received by Affiliates

$ 100,000

$ 100,000

Equity and Distributions - Su77

Equity and Distributions - Summary of Previous Owners' Equity Transactions (Detail) - USD ($) $ in Thousands		3 Months Ended									12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014		Dec. 31, 2013
Equity Structure And Transactions [Line Items]
Balance	[1]				$ 1,296,314					$ 863,021	$ 1,296,314	$ 863,021		$ 864,863
Net income (loss)		$ 73,007	$ (191,981)	$ (113,859)	(162,658)	$ 158,839		$ 101,307	$ (111,640)	(32,892)	(395,491)	115,614		61,005
Contributions											4,877	6,560		97,324
Distribution attributable to net assets acquired												(2,413)		(502,920)
Distributions											(163,259)	(164,738)		(127,741)
Distribution of net asset to MRD Holdco												(26,131)
Other												(227)		2,424
Net assets retained by previous owners														(20,782)
Deferred tax liability retained by previous owner											28,020
Balance		645,492				1,296,314	[1]				645,492	1,296,314	[1]	863,021	[1]
WHT Properties [Member]
Equity Structure And Transactions [Line Items]
Balance														107,893
Net income (loss)											0			(1,219)
Contributions											0
Net book value of net assets acquired by Partnership														(106,674)
Net book value of net assets exchanged											0
Deferred tax liability retained by previous owner											0
Balance		0									0
Cinco Group [Member]
Equity Structure And Transactions [Line Items]
Balance														276,801
Net income (loss)											0			12,494
Contributions											0			7,233
Distribution attributable to net assets acquired														55,281
Net book value of net assets acquired by Partnership														(297,627)
Distributions														(31,098)
Other														(2,302)
Net assets retained by previous owners														(20,782)
Net book value of net assets exchanged											0
Deferred tax liability retained by previous owner											0
Balance		0									0
Property Swap [Member]
Equity Structure And Transactions [Line Items]
Balance					220,657					283,405	220,657	283,405		153,098
Net income (loss)											(2,268)	(2,465)		40,737
Contributions											1,912	5,990		89,570
Distributions												(9,886)
Distribution of net asset to MRD Holdco												(26,131)
Tax related effects attributable to Memorial Resource restructuring transactions and initial public offering												(30,483)
Other												227
Net book value of net assets exchanged											(248,321)
Deferred tax liability retained by previous owner											28,020
Balance		0				220,657					0	220,657		283,405
Previous Owners [Member]
Equity Structure And Transactions [Line Items]
Balance					$ 220,657					$ 283,405	220,657	283,405		537,792
Net income (loss)											(2,268)	(2,465)		52,012
Contributions											1,912	5,990		96,803
Distribution attributable to net assets acquired														55,281
Net book value of net assets acquired by Partnership														(404,301)
Distributions												(9,886)		(31,098)
Distribution of net asset to MRD Holdco												(26,131)
Tax related effects attributable to Memorial Resource restructuring transactions and initial public offering												(30,483)
Other												227		(2,302)
Net assets retained by previous owners														(20,782)
Net book value of net assets exchanged											(248,321)
Deferred tax liability retained by previous owner											28,020
Balance		$ 0				$ 220,657					$ 0	$ 220,657		$ 283,405
[1]	See Note 1 for information regarding recast amounts and basis of financial statement presentation.

Earnings Per Unit - Calculation

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Unit [Line Items]
Net income (loss) attributable to Memorial Production Partners LP									$ (395,877)	$ 115,582	$ 60,738
Less: Previous owners interest in net income (loss)				$ (2,268)	$ (4,277)	$ (1,919)	$ 2,566	$ 1,165	(2,268)	(2,465)	52,012
Less: General partner's 0.1% interest in net income (loss)									(412)	118	9
Less: IDRs attributable to corresponding period									112	202	81
Net income (loss) available to limited partners									$ (393,309)	$ 117,727	$ 8,636
Weighted average limited partner units outstanding:
Basic and diluted									83,528	70,859	46,017
Basic and diluted EPU	$ 0.88	$ (2.31)	$ (1.36)	$ (1.90)	$ 1.88	$ 1.39	$ (1.86)	$ (0.56)	$ (4.71)	$ 1.66	$ 0.19
Common Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding									82,897	65,498	40,656
Subordinated Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding									631	5,361	5,361

Earnings Per Unit - Calculati79

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2015
Earnings Per Unit [Line Items]
General partner's interest in net income, percentage	0.10%
Average [Member]
Earnings Per Unit [Line Items]
General partner's interest in net income, percentage	0.105%

Equity-based Awards - Additiona

Equity-based Awards - Additional Information (Detail) - USD ($) $ in Millions	Jan. 08, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost		$ 16.5
Weighted-average period of unrecognized compensation cost		1 year 9 months 18 days
Cash distributions paid		$ 2.8	$ 1.9	$ 1
Independent Directors [Member] | Phantom units [Member] | Subsequent Event [Member] | General Partner [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Number of Units	155,601
Units vesting period	1 year
Independent Directors [Member] | Phantom units [Member] | Tranche One [Member] | Subsequent Event [Member] | General Partner [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units vesting percentage	100.00%
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		$ 12.3	$ 15	$ 9.7

Equity-based Awards - Summary o

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted common units forfeited	0
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted common units outstanding, Beginning Balance	1,093,520	706,927	285,609
Granted, Number of Units	827,704	684,954	524,718
Restricted common units forfeited	(69,059)	(38,294)	(11,734)
Vested, Number of Units	(483,627)	(260,067)	(91,666)
Restricted common units outstanding, Ending Balance	1,368,538	1,093,520	706,927
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance	$ 20.93	$ 18.62	$ 18.08
Granted, Weighted-Average Grant Date Fair Value per Unit	14.90	22.39	18.83
Forfeited, Weighted-Average Grant Date Fair Value per Unit	18.35	20.54	17.24
Vested, Weighted-Average Grant Date Fair Value per Unit	20.37	18.56	18.31
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance	$ 17.61	$ 20.93	$ 18.62

Equity-based Awards - Summary82

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Stock [Member] - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted common unit awards issued	$ 12.3	$ 15.3	$ 9.9
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	$ 6.20	$ 21.99	$ 18.33
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	$ 15.45	$ 23.40	$ 20.35

Equity-based Awards - Summary83

Equity-based Awards - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Compensation expense	$ 10,809	$ 7,874	$ 3,558

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) $ in Thousands

Nov. 02, 2015USD ($)

Jul. 01, 2015$ / bbl

Oct. 11, 2012USD ($)

Nov. 30, 2015USD ($)

May. 31, 2014$ / MMBTU$ / bbl

Nov. 30, 2013USD ($)

Apr. 30, 2013USD ($)

Nov. 30, 2011MMBTU

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Feb. 23, 2015USD ($)

Oct. 01, 2014USD ($)

Apr. 01, 2014USD ($)

Oct. 01, 2013USD ($)

Apr. 01, 2013

Mar. 28, 2013USD ($)

Related Party Transaction [Line Items]

Interest sold in oil and gas properties

$ 2,000

$ 580

$ 4,525

Compensation expense

$ 56,671

$ 49,124

54,947

Classic Operating And Classic Pipeline [Member] | Classic Pipeline Gas Gathering Agreement [Member]

Related Party Transaction [Line Items]

Maximum dedication of natural gas produced | MMBTU

50,000

Pipeline transportation agreement expiration year

2,020

Pipeline transportation agreement extension

1 year

Amended gas gathering agreement terms disclosure

Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel

Base gas gathering fee per MMBtu | $ / MMBTU

0.30

Base stage of compression fee per MMBtu | $ / MMBTU

0.07

Annual inflationary escalation, rate

3.50%

Classic Operating And Classic Pipeline [Member] | Water Disposal Agreement [Member]

Related Party Transaction [Line Items]

Pipeline water disposal agreement extension

1 year

Water disposal agreement period

3 years

Water disposal fee per barrel | $ / bbl

0.40

1.10

Gain recognized as contribution

$ 2,100

Salt water disposal fee

$ 3,200

$ 1,800

600

Multi-Shot, LLC [Member]

Related Party Transaction [Line Items]

Drilling and completion expenses

$ 300

Affiliated Entity [Member] | February 2015 Acquisition [Member]

Related Party Transaction [Line Items]

Effective date of acquisition common control

Jan. 1, 2015

Common Control Acquisition Purchase Price

$ 78,400

Double A Acquisition [Member]

Related Party Transaction [Line Items]

Effective date of acquisition common control

Apr. 1, 2014

Common Control Acquisition Purchase Price

$ 33,300

Wattenberg Acquisition [Member]

Related Party Transaction [Line Items]

Common Control Acquisition Purchase Price

$ 15,000

Date of acquisition common control

Oct. 1, 2014

WHT Acquisition [Member]

Related Party Transaction [Line Items]

Common Control Acquisition Purchase Price

$ 200,000

Date of acquisition common control

Mar. 28, 2013

Working capital and other customary adjustments

$ 4,000

Cinco Group Acquisition [Member]

Related Party Transaction [Line Items]

Date of acquisition common control

Oct. 1, 2013

Acquisition cost of Assets

$ 603,000

Management fee per month

$ 800

Annual Advisory fee paid

$ 300

Stanolind Oil and Gass LLC [Member] | 2015 Divestiture [Member]

Related Party Transaction [Line Items]

Interest sold in oil and gas properties

$ 900

Proceeds in excess of book value of properties sold

$ 700

Memorial Resource [Member]

Related Party Transaction [Line Items]

Amount receivable under management agreement

$ 400

Percentage interest in Tanos sold

1.066%

Classic revolving credit facility [Member]

Related Party Transaction [Line Items]

Compensation expense

$ 8,300

Tanos [Member]

Related Party Transaction [Line Items]

Compensation expense

$ 5,800

Related Party Transactions - Sc

Related Party Transactions - Schedule of Net Assets Recorded by Partnership (Detail) - USD ($) $ in Thousands	Feb. 23, 2015	Oct. 01, 2014	Oct. 01, 2013	Mar. 28, 2013
Property Swap [Member] | February 2015 Acquisition [Member]
Related Party Transaction [Line Items]
Accounts receivable	$ 2,372
Other receivables	5,478
Prepaid expenses and other current assets	1,874
Property and equipment, net	263,210
Accounts payable	(3,586)
Accounts payable - affiliate	(1,290)
Revenues payable	(1,110)
Accrued liabilities	(11,347)
Asset retirement obligations	(4,559)
Net assets	$ 251,042
Double A Acquisition [Member]
Related Party Transaction [Line Items]
Property and equipment, net		$ 37,838
Asset retirement obligations		(908)
Net assets		36,208
Other current liabilities		(722)
Wattenberg Acquisition [Member]
Related Party Transaction [Line Items]
Property and equipment, net		9,822
Asset retirement obligations		(149)
Net assets		9,673
Other current liabilities		$ 0
WHT Acquisition [Member]
Related Party Transaction [Line Items]
Prepaid expenses and other current assets				$ 98
Accrued liabilities				(3,494)
Asset retirement obligations				(2,753)
Net assets				106,674
Cash and cash equivalents				1,354
Accounts receivable				3,866
Short-term derivative instruments, net				1,206
Oil and natural gas properties, net				192,280
Long-term derivative instruments, net				3,528
Credit facilities				(89,300)
Other long-term liabilities				$ (111)
Cinco Group Acquisition [Member]
Related Party Transaction [Line Items]
Prepaid expenses and other current assets			$ 1,824
Accounts payable			(4,063)
Revenues payable			(4,519)
Accrued liabilities			(3,311)
Asset retirement obligations			(13,575)
Net assets			297,627
Cash and cash equivalents			3,265
Accounts receivable			10,615
Short-term derivative instruments, net			(1,505)
Oil and natural gas properties, net			457,439
Long-term derivative instruments, net			3,056
Credit facilities			(151,690)
Other long-term liabilities			(265)
Other long-term assets			$ 356

Related Party Transactions - 86

Related Party Transactions - Schedule of Amount of General and Administrative Costs and Expenses Recognized (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
General and administrative costs and expenses under omnibus agreement	$ 32,281	$ 24,372	$ 9,440

Commitments and Contingencies -

Commitments and Contingencies - Environmental Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]
Balance at beginning of period	$ 2,092	$ 437	$ 1,051
Charged to costs and expenses	0	2,852	0
Payments	(1,876)	(1,197)	(614)
Balance at end of period	$ 216	$ 2,092	$ 437

Commitments and Contingencies88

Commitments and Contingencies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / bbl	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Jun. 10, 2010USD ($)	Mar. 01, 2007USD ($)
Commitments And Contingencies Additional Textual [Abstract]
Remaining environmental accrued liability recorded	$ 216	$ 2,092
Amount per barrel of oil | $ / bbl	0.25
Aggregate value to ceases fund	$ 4,300
Additional quarterly payments				$ 1,250
Maximum remaining obligation	8,000
Rent expense	$ 16,900	6,400	$ 2,400
East Texas Properties [Member]
Commitments And Contingencies Additional Textual [Abstract]
Term of minimum volume commitment	7 years
Predecessor [Member]
Commitments And Contingencies Additional Textual [Abstract]
Rent expense		$ 500	$ 2,900
U S Bank Money Market [Member]
Commitments And Contingencies Additional Textual [Abstract]
Held-to-maturity investment, amortized cost	$ 144,000
REO revolving credit facility [Member]
Commitments And Contingencies Additional Textual [Abstract]
Restricted Investment - decommissioning of offshore production facilities					$ 90,000
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Commitments And Contingencies Additional Textual [Abstract]
Restricted Investment - decommissioning of offshore production facilities	$ 3,200

Commitments and Contingencies89

Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) $ in Thousands	Dec. 31, 2015USD ($)
June 30, 2016 [Member]
Asset retirement obligations
Minimum balances attributable to REO's net working interest	$ 148,000
December 31, 2016 [Member]
Asset retirement obligations
Minimum balances attributable to REO's net working interest	$ 152,000

Commitments and Contingencies90

Commitments and Contingencies - Lease Obligations (Detail) $ in Thousands	Dec. 31, 2015USD ($)
Commitments And Contingencies Disclosure [Abstract]
Total	$ 6,107
2,016	1,007
2,017	317
2,018	294
2,019	294
2,020	295
Thereafter	$ 3,900

Commitments and Contingencies91

Commitments and Contingencies - Purchase Commitments Under the Contracts (Detail) $ in Thousands	Dec. 31, 2015USD ($)
CO2 Minimum Purchase Commitment [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Total	$ 30,307
2,016	7,393
2,017	7,505
2,018	5,075
2,019	5,366
2,020	4,968
Thereafter	0
Offshore Ship Services & Other [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Total	4,662
2,016	4,662
2,017	0
2,018	0
2,019	0
2,020	0
Thereafter	0
Midstream services [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Total	35,788
2,016	5,121
2,017	5,121
2,018	5,106
2,019	5,107
2,020	5,106
Thereafter	$ 10,227

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current taxes:
Federal	$ (11)	$ 0	$ 0
State	(48)	(127)	(308)
Total current income tax benefit (expense)	(59)	(127)	(308)
Deferred taxes:
Federal	1,193	2,057	0
State	1,041	(509)	0
Total deferred income tax benefit (expense)	2,234	1,548	0
Total income tax benefit (expense)	$ 2,175	$ 1,421	$ (308)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Federal statutory corporate tax rate	35.00%
Unrecognized Tax Benefits	$ 0	$ 0
Valuation allowance	0	$ 2,633,000
United States [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 200,000
Operating loss carryforwards expiration year	2,034

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Income Tax Benefit (Provision) (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Expected tax benefit (expense) at federal statutory rate		$ 139,183	$ (39,966)	$ (21,459)
State income tax benefit (expense), net of federal benefit		645	(1,907)	(308)
Pass-through entities	[1]	(137,704)	42,000	21,459
Other		51	1,294	0
Total income tax benefit (expense)		$ 2,175	$ 1,421	$ (308)
[1]	(1) MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes.

Income Taxes - Components of Ne

Income Taxes - Components of Net Deferred Income Tax Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred income tax assets:
Net operating loss carryforward	$ 56	$ 3,959
Asset retirement obligation	694	1,855
Other	38	15
Total deferred income tax assets:	788	5,829
Valuation allowance	0	(2,633)
Net deferred income tax assets	788	3,196
Deferred income tax liabilities:
Property, plant and equipment	1,324	32,094
Derivatives	1,514	3,388
Other	44	61
Total deferred income tax liabilities	2,882	35,543
Net deferred income tax liabilities	$ 2,094	$ 32,347

Quarterly Financial Informati96

Quarterly Financial Information (Unaudited) - Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 79,108	$ 88,083	$ 98,138	$ 92,818	$ 138,689	$ 166,261	$ 144,208	$ 116,885	$ 358,147	$ 566,043	$ 394,515
Operating income (loss)	99,434	(160,844)	(85,197)	(136,370)	181,355	127,078	(93,294)	(16,739)	(282,977)	198,400	105,613
Net income (loss)	73,007	(191,981)	(113,859)	(162,658)	158,839	101,307	(111,640)	(32,892)	(395,491)	115,614	61,005
Net income (loss) attributable to Memorial Production Partners LP	72,949	(192,085)	(113,924)	(162,817)	159,000	101,157	(111,628)	(32,947)	(395,877)	115,582	60,738
Net income (loss) allocated to previous owners				(2,268)	(4,277)	(1,919)	2,566	1,165	(2,268)	(2,465)	52,012
Net income (loss) attributable to noncontrolling interest	58	104	65	159	(161)	150	(12)	55	386	32	267
Limited partners’ interest in net income (loss)	$ 72,874	$ (191,938)	$ (113,862)	$ (160,439)	$ 163,066	$ 102,925	$ (114,120)	$ (34,118)	$ (393,365)	$ 117,753	$ 8,677
Basic and diluted earnings per unit	$ 0.88	$ (2.31)	$ (1.36)	$ (1.90)	$ 1.88	$ 1.39	$ (1.86)	$ (0.56)	$ (4.71)	$ 1.66	$ 0.19

Supplemental Oil and Gas Info97

Supplemental Oil and Gas Information (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Evaluated oil and natural gas properties	$ 3,616,325	$ 3,329,338	$ 2,077,344
Support equipment and facilities	205,876	198,088	16,030
Unevaluated oil and natural gas properties	0	0	1,960
Accumulated depletion, depreciation, and amortization	(1,878,549)	(1,060,114)	(464,812)
Total	$ 1,943,652	$ 2,467,312	$ 1,630,522

Supplemental Oil and Gas Info98

Supplemental Oil and Gas Information (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Property acquisition costs, proved	$ 77,834	$ 983,076	$ 37,786
Property acquisition costs, unproved	1,887	720	0
Exploration	2,078	0	0
Development	233,241	308,724	166,090
Total	$ 315,040	$ 1,292,520	$ 203,876

Supplemental Oil and Gas Info99

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Detail) - Bcfe	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil And Gas Reserve Information [Line Items]
Percent of discount factor to proved reserves	10.00%
Multiple acquisitions	97.1	561.7
Reduction in reserves	415.4
Downward price revisions in proved reserve	413
Downward revisions due to updated well performance data	13
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
2015 Beta Acquisition [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Multiple acquisitions, Largest acquisition	58.5

Supplemental Oil and Gas Inf100

Supplemental Oil and Gas Information (Unaudited) - Schedule of Product Prices Used for Valuing the Reserves (Detail)	12 Months Ended
	Dec. 31, 2015$ / MMBTU$ / bbl	Dec. 31, 2014$ / MMBTU$ / bbl	Dec. 31, 2013$ / MMBTU$ / bbl
Oil [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	46.79	91.48	93.42
NGL [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	46.79	91.48	93.42
Natural Gas [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves | $ / MMBTU	2.58	4.35	3.67

Supplemental Oil and Gas Inf101

Supplemental Oil and Gas Information (Unaudited) - Schedule of Net Reserves (Detail)	12 Months Ended
	Dec. 31, 2015MMcfebblMMcf	Dec. 31, 2014MMcfebblMMcf	Dec. 31, 2013MMcfebblMMcf
Oil [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	100,258	39,635	40,822
Extensions and discoveries	2,319	849	5,814
Purchase of minerals in place	10,132	69,095	119
Production	(4,087)	(3,135)	(1,797)
Sale of minerals in place	(380)
Revision of previous estimates	(17,297)	(6,186)	(5,323)
Proved developed and undeveloped reserves, End of year	90,945	100,258	39,635
Proved developed reserves, Beginning of year	54,723	22,429	24,784
Proved developed reserves, End of year	50,817	54,723	22,429
Proved undeveloped reserves, Beginning of year	45,535	17,206	16,038
Proved undeveloped reserves, End of year	40,128	45,535	17,206
Natural Gas [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MMcf	727,216	737,908	794,369
Extensions and discoveries | MMcf	8,686	12,783	85,455
Purchase of minerals in place | MMcf	34,128	13,036	16,294
Production | MMcf	(50,875)	(48,721)	(41,287)
Sale of minerals in place | MMcf	(13,731)
Revision of previous estimates | MMcf	(243,898)	12,210	(116,923)
Proved developed and undeveloped reserves, End of year | MMcf	461,526	727,216	737,908
Proved developed reserves, Beginning of year | MMcf	417,247	427,983	441,858
Proved developed reserves, End of year | MMcf	311,147	417,247	427,983
Proved undeveloped reserves, Beginning of year | MMcf	309,969	309,925	352,511
Proved undeveloped reserves, End of year | MMcf	150,379	309,969	309,925
NGL [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	59,034	35,794	39,554
Extensions and discoveries	558	711	4,353
Purchase of minerals in place	367	22,351	258
Production	(2,820)	(2,498)	(1,806)
Sale of minerals in place	(758)
Revision of previous estimates	(12,986)	2,676	(6,565)
Proved developed and undeveloped reserves, End of year	43,395	59,034	35,794
Proved developed reserves, Beginning of year	37,260	17,637	18,060
Proved developed reserves, End of year	30,315	37,260	17,637
Proved undeveloped reserves, Beginning of year	21,774	18,157	21,494
Proved undeveloped reserves, End of year	13,080	21,774	18,157
Equivalent [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MMcfe	1,682,960	1,190,484	1,276,625
Extensions and discoveries | MMcfe	25,950	22,145	146,463
Purchase of minerals in place | MMcfe	97,122	561,713	18,554
Production | MMcfe	(92,315)	(82,520)	(62,907)
Sale of minerals in place | MMcfe	(20,559)
Revision of previous estimates | MMcfe	(425,587)	(8,862)	(188,251)
Proved developed and undeveloped reserves, End of year | MMcfe	1,267,571	1,682,960	1,190,484
Proved developed reserves, Beginning of year | MMcfe	969,141	668,381	698,922
Proved developed reserves, End of year | MMcfe	797,936	969,141	668,381
Proved undeveloped reserves, Beginning of year | MMcfe	713,819	522,103	577,703
Proved undeveloped reserves, End of year | MMcfe	469,635	713,819	522,103

Supplemental Oil and Gas Inf102

Supplemental Oil and Gas Information (Unaudited) -Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Future cash inflows	$ 5,952,935	$ 14,190,450	$ 7,672,312
Future production costs	(3,194,577)	(4,821,051)	(2,963,146)
Future development costs	(808,512)	(1,455,926)	(901,374)
Future income tax expense	0	(119,675)
Future net cash flows for estimated timing of cash flows	1,949,846	7,793,798	3,807,792
10% annual discount for estimated timing of cash flows	(1,360,292)	(4,881,811)	(2,089,588)
Standardized measure of discounted future net cash flows	$ 589,554	$ 2,911,987	$ 1,718,204	$ 1,772,240

Supplemental Oil and Gas Inf103

Supplemental Oil and Gas Information (Unaudited) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Beginning of year	$ 2,911,987	$ 1,718,204	$ 1,772,240
Sale of oil and natural gas produced, net of production costs	(128,382)	(354,932)	(255,031)
Purchase of minerals in place	75,998	1,489,477	23,160
Sale of minerals in place	(45,100)
Extensions and discoveries	18,582	44,843	150,631
Changes in income taxes, net	63,180	(63,180)
Changes in prices and costs	(2,764,481)	(170,682)	(26,648)
Previously estimated development costs incurred	322,446	275,078	199,775
Net changes in future development costs	448,089	(133,098)	(16,219)
Revisions of previous quantities	(344,775)	(48,087)	(373,109)
Accretion of discount	297,517	171,820	177,223
Change in production rates and other	(265,507)	(17,456)	66,182
End of year	$ 589,554	$ 2,911,987	$ 1,718,204