Amplify Energy (AMPYW) 10-Q 4 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	Apr. 30, 2016
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
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 Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		82,899,509
General Partner [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		86,797

UNAUDITED CONDENSED CONSOLIDATE

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 836	$ 599
Accounts receivable	45,290	60,239
Short-term derivative instruments	259,854	272,320
Prepaid expenses and other current assets	4,839	7,028
Total current assets	310,819	340,186
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	3,639,835	3,616,325
Support equipment and facilities	206,147	205,876
Other	2,491	2,671
Accumulated depreciation, depletion and impairment	(1,931,091)	(1,878,549)
Property and equipment, net	1,917,382	1,946,323
Long-term derivative instruments	442,616	461,810
Restricted investments	154,766	152,631
Other long-term assets	4,519	5,053
Total assets	2,830,102	2,906,003
Current liabilities:
Accounts payable	6,863	8,792
Accounts payable - affiliates	5,137	3,339
Revenues payable	25,427	25,504
Accrued liabilities (Note 2)	61,744	52,923
Short-term derivative instruments	2,098	2,850
Total current liabilities	101,269	93,408
Long-term debt (Note 7)	1,957,984	2,000,579
Asset retirement obligations	164,964	162,989
Long-term derivative instruments	2,161	1,441
Deferred tax liabilities	2,158	2,094
Total liabilities	$ 2,228,536	$ 2,260,511
Commitments and contingencies (Note 12)
Partners' equity:
General partner (86,797 units outstanding at March 31, 2016 and December 31, 2015)	$ 799	$ 848
Total partners' equity	601,566	645,492
Total liabilities and equity	2,830,102	2,906,003
Limited Partners Common Units [Member]
Partners' equity:
Limited partners units	$ 600,767	$ 644,644

UNAUDITED CONDENSED CONSOLIDAT3

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Mar. 31, 2016	Dec. 31, 2015
General partner, units outstanding	86,797	86,797
Limited Partners Common Units [Member]
Limited partners, units outstanding	82,925,302	82,906,400

UNAUDITED CONDENSED STATEMENTS

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Revenues:
Oil & natural gas sales	$ 60,623	$ 91,949
Other revenues	243	869
Total revenues	60,866	92,818
Costs and expenses:
Lease operating	35,696	40,478
Gathering, processing and transportation	9,209	8,666
Exploration	122	90
Taxes other than income	4,008	6,655
Depreciation, depletion, and amortization	44,429	51,266
Impairment of proved oil and natural gas properties	8,342	251,347
General and administrative	13,524	14,511
Accretion of asset retirement obligations	2,707	1,634
(Gain) loss on commodity derivative instruments	(51,745)	(145,459)
(Gain) loss on sale of properties	(96)	0
Other, net	119	0
Total costs and expenses	66,315	229,188
Operating income (loss)	(5,449)	(136,370)
Other income (expense):
Interest expense, net	(32,552)	(28,818)
Other income (expense)	0	160
Total other income (expense)	(32,552)	(28,658)
Income (loss) before income taxes	(38,001)	(165,028)
Income tax benefit (expense)	(96)	2,370
Net income (loss)	(38,097)	(162,658)
Net income (loss) attributable to noncontrolling interest	0	159
Net income (loss) attributable to Memorial Production Partners LP	(38,097)	(162,817)
Limited partners' interest in net income (loss):
Net income (loss) attributable to Memorial Production Partners LP	(38,097)	(162,817)
Net (income) loss allocated to previous owners	0	2,268
Net (income) loss allocated to general partner	40	138
Net (income) loss allocated to NGP IDRs	0	(28)
Limited partners' interest in net income (loss)	$ (38,057)	$ (160,439)
Earnings per unit: (Note 9)
Basic and diluted earnings per unit	$ (0.46)	$ (1.90)
Weighted average limited partner units outstanding:
Basic and diluted	82,935	84,339

UNAUDITED CONDENSED STATEMENTS5

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash flows from operating activities:
Net income (loss)	$ (38,097)	$ (162,658)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	44,429	51,266
Impairment of proved oil and natural gas properties	8,342	251,347
(Gain) loss on derivative instruments	(48,063)	(143,018)
Cash settlements (paid) received on expired derivative instruments	79,691	59,236
Cash settlements on terminated commodity derivatives	0	27,063
Premiums paid for commodity derivatives	0	(27,063)
Deferred income tax expense (benefit)	65	(2,370)
Amortization of deferred financing costs	1,202	1,860
Accretion of senior notes net discount	605	599
Accretion of asset retirement obligations	2,707	1,634
Unit-based compensation (see Note 10)	2,568	2,341
Settlement of asset retirement obligations	(615)	0
Gain on sale of properties	(96)	0
Changes in operating assets and liabilities:
Accounts receivable	14,977	13,000
Prepaid expenses and other assets	2,190	(5,684)
Payables and accrued liabilities	7,058	4,410
Other	43	0
Net cash provided by operating activities	77,006	71,963
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	0	(3,305)
Additions to oil and gas properties	(22,537)	(74,375)
Additions to other property and equipment	(95)	0
Additions to restricted investments	(2,136)	(1,426)
Proceeds from the sale of oil and natural gas properties	325	0
Net cash used in investing activities	(24,443)	(79,106)
Cash flows from financing activities:
Advances on revolving credit facilities	28,000	166,000
Payments on revolving credit facilities	(72,000)	(5,000)
Deferred financing costs	(18)	(10)
Repurchase of senior notes	0	(2,914)
Capital contributions from previous owners	0	1,912
Contributions related to sale of assets to NGP affiliate	26	0
Distributions to partners	(8,304)	(46,315)
Distribution to Memorial Resource (see Note 1)	0	(78,000)
Restricted units returned to plan	(30)	(7)
Repurchases under unit repurchase program	0	(28,420)
Net cash (used in) provided by financing activities	(52,326)	7,246
Net change in cash and cash equivalents	237	103
Cash and cash equivalents, beginning of period	599	970
Cash and cash equivalents, end of period	$ 836	$ 1,073

UNAUDITED CONDENSED STATEMENTS6

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY - 3 months ended Mar. 31, 2016 - USD ($) $ in Thousands	Total	Limited Partners Common Units [Member]	General Partner [Member]
Balance at Dec. 31, 2015	$ 645,492	$ 644,644	$ 848
Net income (loss)	(38,097)	(38,057)	(40)
Distributions	(8,304)	(8,295)	(9)
Amortization of equity-based awards	2,492	2,492	0
Restricted units repurchased and other	(17)	(17)	0
Balance at Mar. 31, 2016	$ 601,566	$ 600,767	$ 799

Organization and Basis of Prese

Organization and Basis of Presentation	3 Months Ended
	Mar. 31, 2016
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 the economic environments are not different 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) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (iv) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (v) “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; (vi) “MRD Holdco” refer to MRD Holdco LLC, which together with a group, controls Memorial Resource; and (vii) “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 11). 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. Subsequent Event. On April 27, 2016, we entered into an agreement to acquire MEMP GP from Memorial Resource (“MEMP GP Acquisition”). In addition, on April 27, 2016, we entered into an agreement to acquire the 50% ownership of the IDRs of the Partnership owned by NGP (“NGP Acquisition”). See Note 13, for additional information regarding both acquisitions. Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer to certain oil and gas properties primarily located in East Texas and West Louisiana that the Partnership acquired on February 23, 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana for periods after common control commenced through the date of acquisition. We refer to this transaction as the “Property Swap.” The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”). The Property Swap was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information were retrospectively revised to give effect to the Property Swap as if the Partnership owned the assets for periods after common control commenced through the acquisition date. Basis of Presentation Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements of the previous owners were derived from their historical accounting records and reflect their historical financial position, results of operations and cash flows. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Our results of operations for the three months ended March 31, 2016 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Use of Estimates The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies A discussion of our significant accounting policies and estimates is included in our 2015 Form 10-K. Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): March 31, December 31, 2016 2015 Accrued capital expenditures $ 9,985 $ 8,110 Accrued interest payable 27,992 23,192 Accrued lease operating expense 16,919 16,843 Accrued ad valorem taxes 2,597 1,426 Accrued general and administrative expenses 2,882 1,961 Environmental liability 88 216 Asset retirement obligation 1,175 1,175 Other 106 — $ 61,744 $ 52,923 Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Three Months Ended March 31, 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized 22,793 21,298 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities 1,875 (1,450 ) Asset retirement obligation removal related to divestitures (451 ) — Assumptions of asset retirement obligations related to properties acquired — 2,266 New Accounting Pronouncements Improvements to Employee Share-Based Payment Accounting . In March 2016, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to reduce complexity involving several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, entities will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required. The new guidance is effective for reporting periods beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted, but all of the guidance must be adopted in the same period. For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. Entities should apply the new guidance retrospectively for all periods presented related to the classification of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirements. Entities may apply the presentation changes for excess tax benefits in the statement of cash flows either prospectively or retrospectively. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Leases. In February 2016, FASB issued a revision to lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The revised guidance must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Partnership is currently evaluating the standard and the impact on the consolidated financial statements and related footnote disclosures. 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 are also required. The guidance was effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. We adopted this guidance on January 1, 2016. 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 impact of adopting this guidance was not material to the Partnership’s financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Acquisitions and Divestitures

Acquisitions and Divestitures	3 Months Ended
	Mar. 31, 2016
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Related Party Acquisitions See Note 11 for further information regarding related party acquisitions that have been accounted for as transactions between entities under common control that impact the basis of presentation for the periods presented. Acquisition-related Costs Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Three Months Ended March 31, 2016 2015 $ 86 $ 1,299 2015 Acquisitions 2015 Beta Acquisition. Pro forma Information. The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2015 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical consolidated and 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 Three Months Ended March 31, 2015 (In thousands, except per unit amounts) Revenues $ 99,081 Net income (loss) (162,306 ) Basic and diluted earnings per unit (1.90 ) Divestitures There were no material divestitures during the three months ended March 31, 2016 and 2015, respectively.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. The carrying values of accounts receivables, accounts payables (including accrued liabilities), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at March 31, 2016 and December 31, 2015. 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 7 for the estimated fair value of our outstanding fixed-rate debt. Assets and Liabilities Measured at Fair Value on a Recurring Basis The fair market values of the derivative financial instruments reflected on the balance sheets as of March 31, 2016 and December 31, 2015 were based on estimated forward commodity prices and forward interest rate yield curves. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2016 and December 31, 2015 for each of the fair value hierarchy levels: Fair Value Measurements at March 31, 2016 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 $ — $ 776,805 $ — $ 776,805 Interest rate derivatives — 28 — 28 Total assets $ — $ 776,833 $ — $ 776,833 Liabilities: Commodity derivatives $ — $ 72,788 $ — $ 72,788 Interest rate derivatives — 5,834 — 5,834 Total liabilities $ — $ 78,622 $ — $ 78,622 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 See Note 5 for additional information regarding our derivative instruments. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: · The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs. · If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. · Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, estimates of probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. · During the three months ended March 31 2016, we recognized $8.3 million of impairments related to certain properties located in East Texas. 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 $11.0 million. We recorded approximately $251.3 million of impairments during the three months ended March 31, 2015 primarily related to certain properties located in East Texas, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable in part due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs.

Risk Management and Derivative

Risk Management and Derivative Instruments	3 Months Ended
	Mar. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments	Note 5. Risk Management and Derivative Instruments Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease. Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $332.2 million against amounts outstanding under our revolving credit facility at March 31, 2016, reducing our maximum credit exposure to approximately $369.1 million, of which approximately $213.5 million was with two counterparties. See Note 7 for additional information regarding our revolving credit facility. Commodity Derivatives We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, costless collars and basis swaps) to manage exposure to commodity price volatility. Historically, the Partnership has not paid or received premiums for put options. In February 2015, we restructured a portion of our commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor. Cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives. We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, CIG and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX-CL, ICE Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At March 31, 2016, we had the following open commodity positions: Remaining 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,586,331 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) 3,572,778 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) 304,313 301,600 312,000 160,000 Weighted-average fixed price $ 85.47 $ 85.00 $ 83.74 $ 85.52 Basis swaps: Average Monthly Volume (Bbls) 139,667 67,500 — — Spread $ (10.01 ) $ (7.82 ) $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 210,433 43,300 — — Weighted-average fixed price $ 35.79 $ 37.55 $ — $ — Our basis swaps included in the table above are presented on a disaggregated basis below: Remaining 2016 2017 2018 2019 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 2,997,778 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) 99,667 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, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At March 31, 2016, we had the following interest rate swap open positions: Remaining 2016 2017 2018 Average Monthly Notional (in thousands) $ 400,000 $ 400,000 $ 300,000 Weighted-average fixed rate 0.943 % 1.612 % 1.427 % 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 March 31, 2016 and December 31, 2015. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives March 31, December 31, March 31, December 31, Type Balance Sheet Location 2016 2015 2016 2015 (In thousands) Commodity contracts Short-term derivative instruments $ 308,480 $ 324,265 $ 48,530 $ 53,581 Interest rate swaps Short-term derivative instruments — — 2,194 1,214 Gross fair value 308,480 324,265 50,724 54,795 Netting arrangements Short-term derivative instruments (48,626 ) (51,945 ) (48,626 ) (51,945 ) Net recorded fair value Short-term derivative instruments $ 259,854 $ 272,320 $ 2,098 $ 2,850 Commodity contracts Long-term derivative instruments $ 468,325 $ 492,730 $ 24,258 $ 30,920 Interest rate swaps Long-term derivative instruments 28 — 3,640 1,441 Gross fair value 468,353 492,730 27,898 32,361 Netting arrangements Long-term derivative instruments (25,737 ) (30,920 ) (25,737 ) (30,920 ) Net recorded fair value Long-term derivative instruments $ 442,616 $ 461,810 $ 2,161 $ 1,441 (Gains) Losses on Derivatives We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands): For the Three Months Ended Statements of March 31, Operations Location 2016 2015 Commodity derivative contracts (Gain) loss on commodity derivatives $ (51,745 ) $ (145,459 ) Interest rate derivatives Interest expense, net 3,682 2,441

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. Asset Retirement Obligations The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2016 (in thousands): Asset retirement obligations at beginning of period $ 164,164 Liabilities added from acquisitions or drilling 10 Liabilities removed upon sale of wells (451 ) Liabilities settled (615 ) Accretion expense 2,707 Revision of estimates 324 Asset retirement obligations at end of period 166,139 Less: Current portion 1,175 Asset retirement obligations - long-term portion $ 164,964

Long Term Debt

Long Term Debt	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Long Term Debt	Note 7. Long Term Debt The following table presents our consolidated debt obligations at the dates indicated: March 31, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 792,000 $ 836,000 2021 Senior Notes, fixed-rate, due May 2021 (1) (3) 700,000 700,000 2022 Senior Notes, fixed-rate, due August 2022 (2) (3) 496,990 496,990 Senior notes debt issuance costs, net (17,497 ) (18,297 ) Unamortized discounts (13,509 ) (14,114 ) Total long-term debt $ 1,957,984 $ 2,000,579 (1) The estimated fair value of our 2021 Senior Notes was $203.0 million and $210.0 million at March 31, 2016 and December 31, 2015, respectively. (2) The estimated fair value of our 2022 Senior Notes was $135.4 million and $149.1 million at March 31, 2016 and December 31, 2015, 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. OLLC Revolving Credit Facility OLLC is a party to a $2.0 billion revolving credit facility, which is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries). Borrowing Base Credit facilities tied to borrowing bases are common throughout the oil and gas industry. The borrowing base for our revolving credit facility was the following at the date indicated: March 31, 2016 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 1,175,000 Subsequent Event On April 14, 2016, we entered into a tenth amendment to our credit agreement, dated as of December 14, 2011 (as previously amended, the “Credit Agreement”), by and among the Partnership, OLLC, the administrative agent and the other agents and lenders party thereto (the “Tenth Amendment”). The Tenth Amendment, among other things, amended the Credit Agreement to: · establish a new Applicable Margin (as defined in the Credit Agreement) that ranges from 1.25% to 2.25% per annum (based on borrowing base usage) on alternate base rate loans and from 2.25% to 3.25% per annum (based on borrowing base usage) on Eurodollar or LIBOR loans and sets the committee fee for the unused portion of the borrowing base to 0.50% per annum regardless of the borrowing base usage; · reduce the borrowing base thereunder from $1,175 million to $925 million; · require the Partnership to maintain a ratio of Consolidated First Lien Net Secured Debt (as defined in the Credit Agreement) to Consolidated EBITDAX (as defined in the Credit Agreement) of not greater than 3.25 to 1.00 as of the end of each fiscal quarter; · permit the issuance by the Partnership of secured second lien notes solely in exchange for the Partnership’s outstanding senior unsecured notes pursuant to one or more senior debt exchanges; provided that, among other things: (i) such debt shall be (A) in an aggregate principal amount not to exceed $600 million (plus any principal representing payment of interest in kind) and (B) such debt is subject to an intercreditor agreement at all times; and (ii) such debt shall not (A) have any scheduled principal amortization or have a scheduled maturity date or a date of mandatory redemption in full prior to 180 days after March 19, 2018, or (B) not contain any covenants or events of default that are more onerous or restrictive than those set forth in the Credit Agreement other than covenants or events of default that are contained in the Partnership’s existing senior unsecured notes and (C) the Consolidated Net Interest Expense (as defined in the Credit Agreement) for the 12-month period following the exchange, after giving pro forma effect to the exchange, shall be no greater than the Consolidated Net Interest Expense for such period had the exchange not occurred; · permit the payment by the Partnership of cash distributions to its equity holders out of available cash in accordance with its partnership agreement so long as, among other things, the pro forma Availability (as defined in the Credit Agreement) shall be not less than the greater of $75 million or (x) 10% of the borrowing base then in effect with respect to any such distributions made prior to June 1, 2016 or (y) 15% of the borrowing base then in effect with respect to any such distributions made on or after June 1, 2016; provided that the aggregate amount of all such payments made in any fiscal quarter for which the ratio of the Partnership’s total debt at the time of such payment to its Consolidated EBITDAX for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available is greater than or equal to 4.00 to 1.00 will not exceed $4.15 million during such fiscal quarter; · permit the repurchase of the Partnership’s (i) outstanding senior unsecured notes, or if any, second lien debt with proceeds from Swap Liquidations (as defined in the Credit Agreement) or the sale or other disposition of oil and gas properties and (ii) outstanding senior unsecured notes with the proceeds from the release of cash securing certain governmental obligations located in the Beta Field offshore Southern California, provided that, among other things, (A) the pro forma Availability is not less than the greater of $75 million or (x) 10% of the borrowing base then in effect through May 31, 2016 or (y) 15% of the borrowing base then in effect on or after June 1, 2016, (B) the Partnership’s pro forma ratio of Consolidated First Lien Net Secured Debt to Consolidated EBITDAX is not greater than 3.00 to 1.00, and (C) the amount of proceeds from all Swap Liquidations and sales or other dispositions of oil and gas properties used to repurchase outstanding senior unsecured notes or secured second lien notes does not exceed $40 million in the aggregate, or in the case of the release of cash securing such obligations, the amount of proceeds used to repurchase outstanding senior unsecured notes does not exceed $60 million in the aggregate; · require that the oil and gas properties of the Partnership mortgaged as collateral security for the loans under the Credit Agreement represent not less than 90% of the total value of the oil and gas properties of the Partnership evaluated in the most recently completed reserve report; and · require the Partnership, in the event that at the close of any business day the aggregate amount of any unrestricted cash or cash equivalents exceeds $25 million in the aggregate, to prepay the loans under the Credit Agreement and cash collateralize any letter of credit exposure with such excess. Weighted-Average Interest Rates The following table presents the weighted-average interest rates paid, excluding commitment fees, on our consolidated variable-rate debt obligations for the periods presented: For the Three Months Ended March 31, 2016 2015 OLLC revolving credit facility 2.43 % 1.90 % Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: March 31, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 3,289 $ 3,672 2021 Senior Notes (2) 10,665 11,194 2022 Senior Notes (2) 6,832 7,103 Total $ 20,786 $ 21,969 (1) Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility. (2) Unamortized deferred financing costs are amortized using the straight line method, which generally approximates the effective interest method. Letters of Credit At March 31, 2016, we had $2.1 million of letters of credit outstanding, all related to operations at our Wyoming properties.

Equity and Distributions

Equity and Distributions	3 Months Ended
	Mar. 31, 2016
Equity [Abstract]
Equity and Distributions	Note 8. Equity & Distributions Equity Outstanding The following table summarizes changes in the number of outstanding units since December 31, 2015: General Common Partner Balance, December 31, 2015 82,906,400 86,797 Restricted common units issued 50,000 — Restricted common units forfeited (9,669 ) — Restricted common units repurchased (1) (21,429 ) — Balance, March 31, 2016 82,925,302 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 approximately $0.1 million for the three months ended March 31, 2016. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership. Restricted common units are a component of common units as presented on our unaudited condensed consolidated balance sheets. See Note 10 for additional information regarding restricted common units that were granted during the three months ended March 31, 2016. 2015 Repurchases of Common Units During the three months ended March 31, 2015, we repurchased $28.4 million in common units, which represented a repurchase and retirement of 1,909,583 common units under the December 2014 repurchase program. The December 2014 repurchase program expired in December 2015. Allocations of Net Income (Loss) Net income (loss) attributable to the Partnership is allocated between our general partner and the common unitholders in proportion to their pro rata ownership after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner and the Funds. Net income (loss) attributable to acquisitions accounted for as a transaction between entities under common control in a manner similar to the pooling of interest method prior to their acquisition date is allocated to the previous owners since they are affiliates of our general partner. Cash Distributions to Unitholders The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts): Distribution Amount Aggregate Received by Quarter Declaration Date Record Date Payable Date Per Unit Distribution Affiliates 1 st April 26, 2016 May 6, 2016 May 13, 2016 $ 0.0300 $ 2.5 $ < 0.1 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

Earnings per Unit

Earnings per Unit	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Earnings per Unit	Note 9. Earnings per Unit The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts): For the Three Months Ended March 31, 2016 2015 Net income (loss) attributable to Memorial Production Partners LP $ (38,097 ) $ (162,817 ) Less: Previous owners interest in net income (loss) — (2,268 ) Less: General partner's 0.1% interest in net income (loss) (1) (40 ) (166 ) Less: IDRs attributable to corresponding period — 56 Less: Phantom unit distribution equivalents attributable to corresponding period (see Note 11) (5 ) — Net income (loss) available to limited partners $ (38,052 ) $ (160,439 ) Weighted average limited partner units outstanding: Common units 82,935 81,778 Subordinated units — 2,561 Total 82,935 84,339 Basic and diluted EPU $ (0.46 ) $ (1.90 ) (1) As a result of repurchases under the December 2014 repurchase program, our general partner had an approximate average 0.1046% and 0.1023% interest in us for the three months ended March 31, 2016 and 2015, respectively.

Unit-based Awards

Unit-based Awards	3 Months Ended
	Mar. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Unit-based Awards	Note 10. Unit-Based Awards Restricted Common Units The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for the periods presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted common units outstanding at December 31, 2015 1,368,538 $ 17.61 Granted (2) 50,000 $ 2.41 Forfeited (9,669 ) $ 18.50 Vested (102,600 ) $ 15.96 Restricted common units outstanding at March 31, 2016 1,306,269 $ 17.15 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in the three months ended March 31, 2016 was $0.1 million based on a grant date market price of $2.41 per unit. The unrecognized compensation cost associated with restricted common unit awards was $12.9 million at March 31, 2016. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.66 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to partners as presented on our unaudited condensed statements of consolidated and combined cash flows. LTIP Modification. On March 9, 2016, certain employees were impacted by an involuntary termination which, upon the approval of the board of directors of our general partner, accelerated the vesting schedule of unvested awards under the LTIP that otherwise would have been forfeited upon a voluntary termination. The acceleration of the LTIP vesting schedule represents an improbable-to-probable modification. The grant-date fair value compensation cost of approximately $0.5 million was reversed and the modified-date grant fair value compensation cost of approximately $0.3 million was recognized. Phantom Units The Partnership issued a total of 155,601 phantom units to the non-employee directors in January 2016 which will vest in January 2017. The awards included distribution equivalent rights (“DERs”) pursuant to which the recipient will receive a cash payment with respect to each phantom unit equal to any cash distribution that we pay to a holder of a common unit. Upon vesting, the phantom unit shall be settled through an amount of cash in a single lump sum payment equal to the product of (y) the closing price of our common units on the vesting date and (z) the number of such vested phantom units. In lieu of a cash payment, the board of directors of our general partner, in its discretion, may elect for the recipient to receive either a number of common units equal to the number of such vested phantom units or a combination of cash and common units. The following table summarizes the amount of recognized compensation expense associated with the LTIP awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended March 31, 2016 2015 Equity classified awards Restricted common units $ 2,492 $ 2,341 Liability classified awards Phantom units 76 — $ 2,568 $ 2,341

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Note 11. Related Party Transactions Amounts due to Memorial Resource and certain affiliates of NGP at March 31, 2016 and December 31, 2015 are presented within “Accounts payable – NGP Affiliated Companies During the three months ended March 31, 2016 and 2015, we paid less than $0.1 million and $0.2 million, respectively to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities. Common Control Acquisitions February 2015 Acquisition. On February 23, 2015, as discussed in Note 1, we consummated the Property Swap. The Partnership recorded the following net assets (in thousands): Accounts receivable $ 2,372 Other receivables 5,478 Prepaid expenses and other current assets 1,874 Property and equipment, net 263,210 Accounts payable (3,586 ) Accounts payable - affiliate (1,290 ) Revenues payable (1,110 ) Accrued liabilities (11,347 ) Asset retirement obligations (4,559 ) Net assets $ 251,042 Related Party Agreements We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations. Omnibus Agreement Memorial Resource provides management, administrative and operating services for us and our general partner pursuant to our omnibus agreement. The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended March 31, 2016 2015 $ 7,449 $ 8,553 Subsequent Event. Upon completion of the announced MEMP GP Acquisition, the omnibus agreement will be terminated. We will subsequently enter into a transition services agreement with Memorial Resource to manage post-closing separation costs and activities. See Note 13 for additional information. Beta Management Agreement Memorial Resource through its wholly-owned subsidiary Beta Operating Company, LLC provided management and administrative oversight related to our offshore Southern California oil and gas properties in exchange for an annual management fee. 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. Classic Gas Gathering and Water Disposal Agreements A discussion of these agreements is included in our 2015 Form 10-K. The amended gas gathering agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline and Gathering LLC’s (“Classic Pipeline”) Joaquin gathering system. Additionally, Classic Pipeline assigned its salt water system to OLLC in November 2015. For the three months ended March 31, 2015, we incurred gathering and saltwater disposal fees of approximately $0.9 million under these agreements.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 12. Commitments and Contingencies Litigation & Environmental As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows. At March 31, 2016 and December 31, 2015, we had $0.1 million and $0.2 million of environmental reserves recorded on our balance sheets, respectively. Supplemental Bond for Decommissioning Liabilities Trust Agreement 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, we 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 us. As of March 31, 2016, the remaining obligation was approximately $6.0 million. In 2015, the BOEM issued a preliminary report that indicated the estimated costs 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 March 31, 2016 for the U.S. Bank money market cash equivalent was $146.0 million.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Note 13. Subsequent Events MEMP GP Acquisition On April 27, 2016, the Partnership entered into an agreement to acquire, among other things, all of the equity interests in MEMP GP from Memorial Resource for cash consideration of approximately $0.8 million. We expect to close this transaction by the end of the second quarter of 2016, subject to customary closing conditions. In connection with the closing of the transaction, our partnership agreement with be amended and restated to, among other things, (i) to convert MEMP GP’s 0.1% general partnership interest into a non-economic general partner interest, (ii) cancel the incentive distribution rights of the Partnership, and (iii) provide the limited partners of the Partnership the ability to elect the members of MEMP GP’s board of directors beginning with an annual meeting in 2017. MEMP and Memorial Resource will enter into a transition services agreement to manage post-closing separation costs and activities. Acquisition of NGP owned IDRs On April 27, 2016, the Partnership entered into an agreement to acquire the 50% ownership of the IDRs of the Partnership owned by NGP. This acquisition is expected to close immediately prior to the MEMP GP Acquisition. Amendment to Credit Facility and Borrowing Base Redetermination Effective April 14, 2016 the borrowing base under our revolving credit facility was reduced to approximately $925 million in connection with the semi-annual borrowing redetermination by the lenders. In addition, we and our lenders reached an agreement on amending certain terms of our revolving credit facility. For additional information, see Note 7.

Organization and Basis of Pre20

Organization and Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2016
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 the economic environments are not different 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) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (iv) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (v) “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; (vi) “MRD Holdco” refer to MRD Holdco LLC, which together with a group, controls Memorial Resource; and (vii) “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 11). 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. Subsequent Event. On April 27, 2016, we entered into an agreement to acquire MEMP GP from Memorial Resource (“MEMP GP Acquisition”). In addition, on April 27, 2016, we entered into an agreement to acquire the 50% ownership of the IDRs of the Partnership owned by NGP (“NGP Acquisition”). See Note 13, for additional information regarding both acquisitions.
Previous Owners	Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer to certain oil and gas properties primarily located in East Texas and West Louisiana that the Partnership acquired on February 23, 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana for periods after common control commenced through the date of acquisition. We refer to this transaction as the “Property Swap.” The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”). The Property Swap was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information were retrospectively revised to give effect to the Property Swap as if the Partnership owned the assets for periods after common control commenced through the acquisition date.
Basis of Presentation	Basis of Presentation Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements of the previous owners were derived from their historical accounting records and reflect their historical financial position, results of operations and cash flows. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Our results of operations for the three months ended March 31, 2016 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements.
Use of Estimates	Use of Estimates The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.
Accrued Liabilities	Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): March 31, December 31, 2016 2015 Accrued capital expenditures $ 9,985 $ 8,110 Accrued interest payable 27,992 23,192 Accrued lease operating expense 16,919 16,843 Accrued ad valorem taxes 2,597 1,426 Accrued general and administrative expenses 2,882 1,961 Environmental liability 88 216 Asset retirement obligation 1,175 1,175 Other 106 — $ 61,744 $ 52,923
Supplemental Cash Flows	Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Three Months Ended March 31, 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized 22,793 21,298 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities 1,875 (1,450 ) Asset retirement obligation removal related to divestitures (451 ) — Assumptions of asset retirement obligations related to properties acquired — 2,266
New Accounting Pronouncements	New Accounting Pronouncements Improvements to Employee Share-Based Payment Accounting . In March 2016, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to reduce complexity involving several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, entities will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required. The new guidance is effective for reporting periods beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted, but all of the guidance must be adopted in the same period. For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. Entities should apply the new guidance retrospectively for all periods presented related to the classification of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirements. Entities may apply the presentation changes for excess tax benefits in the statement of cash flows either prospectively or retrospectively. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Leases. In February 2016, FASB issued a revision to lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The revised guidance must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Partnership is currently evaluating the standard and the impact on the consolidated financial statements and related footnote disclosures. 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 are also required. The guidance was effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. We adopted this guidance on January 1, 2016. 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 impact of adopting this guidance was not material to the Partnership’s financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Summary of Significant Accoun21

Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Summary of Current Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands): March 31, December 31, 2016 2015 Accrued capital expenditures $ 9,985 $ 8,110 Accrued interest payable 27,992 23,192 Accrued lease operating expense 16,919 16,843 Accrued ad valorem taxes 2,597 1,426 Accrued general and administrative expenses 2,882 1,961 Environmental liability 88 216 Asset retirement obligation 1,175 1,175 Other 106 — $ 61,744 $ 52,923
Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands): For the Three Months Ended March 31, 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized 22,793 21,298 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities 1,875 (1,450 ) Asset retirement obligation removal related to divestitures (451 ) — Assumptions of asset retirement obligations related to properties acquired — 2,266

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	3 Months Ended
	Mar. 31, 2016
Business Combinations [Abstract]
Acquisition-Related Costs	Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Three Months Ended March 31, 2016 2015 $ 86 $ 1,299
Supplemental Pro Forma Information	The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2015 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical consolidated and 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 Three Months Ended March 31, 2015 (In thousands, except per unit amounts) Revenues $ 99,081 Net income (loss) (162,306 ) Basic and diluted earnings per unit (1.90 )

Fair Value Measurements of Fi23

Fair Value Measurements of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2016 and December 31, 2015 for each of the fair value hierarchy levels: Fair Value Measurements at March 31, 2016 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 $ — $ 776,805 $ — $ 776,805 Interest rate derivatives — 28 — 28 Total assets $ — $ 776,833 $ — $ 776,833 Liabilities: Commodity derivatives $ — $ 72,788 $ — $ 72,788 Interest rate derivatives — 5,834 — 5,834 Total liabilities $ — $ 78,622 $ — $ 78,622 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

Risk Management and Derivativ24

Risk Management and Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2016
Open Commodity Positions	At March 31, 2016, we had the following open commodity positions: Remaining 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,586,331 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) 3,572,778 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) 304,313 301,600 312,000 160,000 Weighted-average fixed price $ 85.47 $ 85.00 $ 83.74 $ 85.52 Basis swaps: Average Monthly Volume (Bbls) 139,667 67,500 — — Spread $ (10.01 ) $ (7.82 ) $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 210,433 43,300 — — Weighted-average fixed price $ 35.79 $ 37.55 $ — $ —
Interest Rate Swap Open Positions	At March 31, 2016, we had the following interest rate swap open positions: Remaining 2016 2017 2018 Average Monthly Notional (in thousands) $ 400,000 $ 400,000 $ 300,000 Weighted-average fixed rate 0.943 % 1.612 % 1.427 % 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 March 31, 2016 and December 31, 2015. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives March 31, December 31, March 31, December 31, Type Balance Sheet Location 2016 2015 2016 2015 (In thousands) Commodity contracts Short-term derivative instruments $ 308,480 $ 324,265 $ 48,530 $ 53,581 Interest rate swaps Short-term derivative instruments — — 2,194 1,214 Gross fair value 308,480 324,265 50,724 54,795 Netting arrangements Short-term derivative instruments (48,626 ) (51,945 ) (48,626 ) (51,945 ) Net recorded fair value Short-term derivative instruments $ 259,854 $ 272,320 $ 2,098 $ 2,850 Commodity contracts Long-term derivative instruments $ 468,325 $ 492,730 $ 24,258 $ 30,920 Interest rate swaps Long-term derivative instruments 28 — 3,640 1,441 Gross fair value 468,353 492,730 27,898 32,361 Netting arrangements Long-term derivative instruments (25,737 ) (30,920 ) (25,737 ) (30,920 ) Net recorded fair value Long-term derivative instruments $ 442,616 $ 461,810 $ 2,161 $ 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 periods indicated (in thousands): For the Three Months Ended Statements of March 31, Operations Location 2016 2015 Commodity derivative contracts (Gain) loss on commodity derivatives $ (51,745 ) $ (145,459 ) Interest rate derivatives Interest expense, net 3,682 2,441
Disaggregated Basis Swap [Member]
Open Commodity Positions	Our basis swaps included in the table above are presented on a disaggregated basis below: Remaining 2016 2017 2018 2019 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 2,997,778 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) 99,667 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)	3 Months Ended
	Mar. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2016 (in thousands): Asset retirement obligations at beginning of period $ 164,164 Liabilities added from acquisitions or drilling 10 Liabilities removed upon sale of wells (451 ) Liabilities settled (615 ) Accretion expense 2,707 Revision of estimates 324 Asset retirement obligations at end of period 166,139 Less: Current portion 1,175 Asset retirement obligations - long-term portion $ 164,964

Long Term Debt (Tables)

Long Term Debt (Tables)	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations at the dates indicated: March 31, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 792,000 $ 836,000 2021 Senior Notes, fixed-rate, due May 2021 (1) (3) 700,000 700,000 2022 Senior Notes, fixed-rate, due August 2022 (2) (3) 496,990 496,990 Senior notes debt issuance costs, net (17,497 ) (18,297 ) Unamortized discounts (13,509 ) (14,114 ) Total long-term debt $ 1,957,984 $ 2,000,579 (1) The estimated fair value of our 2021 Senior Notes was $203.0 million and $210.0 million at March 31, 2016 and December 31, 2015, respectively. (2) The estimated fair value of our 2022 Senior Notes was $135.4 million and $149.1 million at March 31, 2016 and December 31, 2015, 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 borrowing bases are common throughout the oil and gas industry. The borrowing base for our revolving credit facility was the following at the date indicated: March 31, 2016 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 1,175,000
Summary of Weighted-Average Interest Rates Paid Excluding Commitment Fees on Variable-Rate Debt Obligations	The following table presents the weighted-average interest rates paid, excluding commitment fees, on our consolidated variable-rate debt obligations for the periods presented: For the Three Months Ended March 31, 2016 2015 OLLC revolving credit facility 2.43 % 1.90 %
Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: March 31, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 3,289 $ 3,672 2021 Senior Notes (2) 10,665 11,194 2022 Senior Notes (2) 6,832 7,103 Total $ 20,786 $ 21,969 (1) Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility. (2) Unamortized deferred financing costs are amortized using the straight line method, which generally approximates the effective interest method.

Equity and Distributions (Table

Equity and Distributions (Tables)	3 Months Ended
	Mar. 31, 2016
Equity [Abstract]
Summary of Changes in Number of Outstanding Units	The following table summarizes changes in the number of outstanding units since December 31, 2015: General Common Partner Balance, December 31, 2015 82,906,400 86,797 Restricted common units issued 50,000 — Restricted common units forfeited (9,669 ) — Restricted common units repurchased (1) (21,429 ) — Balance, March 31, 2016 82,925,302 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 approximately $0.1 million for the three months ended March 31, 2016. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership.
Summary of Quarterly Cash Distribution Rates	The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts): Distribution Amount Aggregate Received by Quarter Declaration Date Record Date Payable Date Per Unit Distribution Affiliates 1 st April 26, 2016 May 6, 2016 May 13, 2016 $ 0.0300 $ 2.5 $ < 0.1 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

Earnings per Unit (Tables)

Earnings per Unit (Tables)	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Calculation of Earnings (Loss) Per Unit	The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts): For the Three Months Ended March 31, 2016 2015 Net income (loss) attributable to Memorial Production Partners LP $ (38,097 ) $ (162,817 ) Less: Previous owners interest in net income (loss) — (2,268 ) Less: General partner's 0.1% interest in net income (loss) (1) (40 ) (166 ) Less: IDRs attributable to corresponding period — 56 Less: Phantom unit distribution equivalents attributable to corresponding period (see Note 11) (5 ) — Net income (loss) available to limited partners $ (38,052 ) $ (160,439 ) Weighted average limited partner units outstanding: Common units 82,935 81,778 Subordinated units — 2,561 Total 82,935 84,339 Basic and diluted EPU $ (0.46 ) $ (1.90 ) (1) As a result of repurchases under the December 2014 repurchase program, our general partner had an approximate average 0.1046% and 0.1023% interest in us for the three months ended March 31, 2016 and 2015, respectively.

Unit-based Awards (Tables)

Unit-based Awards (Tables)	3 Months Ended
	Mar. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Information Regarding Restricted Common Unit Awards	Restricted Common Units The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for the periods presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted common units outstanding at December 31, 2015 1,368,538 $ 17.61 Granted (2) 50,000 $ 2.41 Forfeited (9,669 ) $ 18.50 Vested (102,600 ) $ 15.96 Restricted common units outstanding at March 31, 2016 1,306,269 $ 17.15 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in the three months ended March 31, 2016 was $0.1 million based on a grant date market price of $2.41 per unit.
Summary of Amount of Compensation Expense Recognized	The following table summarizes the amount of recognized compensation expense associated with the LTIP awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended March 31, 2016 2015 Equity classified awards Restricted common units $ 2,492 $ 2,341 Liability classified awards Phantom units 76 — $ 2,568 $ 2,341

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2016
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
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
Schedule of Amount of General and Administrative Costs and Expenses Recognized	The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended March 31, 2016 2015 $ 7,449 $ 8,553

Commitments and Contingencies (

Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
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

Organization and Basis of Pre32

Organization and Basis of Presentation - Additional Information (Detail) - Segment	Apr. 27, 2016	Mar. 31, 2016
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments		1
Subsequent Event [Member] | MEMP GP [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage	0.10%
Related party, transaction date	Apr. 27, 2016
IDRs [Member] | Natural Gas Partners [Member] | Subsequent Event [Member]
Consolidation And Basis Of Presentation [Line Items]
Related party, transaction date	Apr. 27, 2016
Agreed ownership interest percentage to acquire	50.00%
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%

Summary of Significant Accoun33

Summary of Significant Accounting Policies - Summary of Current Accrued Liabilities (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Accrued Liabilities Current [Abstract]
Accrued capital expenditures	$ 9,985	$ 8,110
Accrued interest payable	27,992	23,192
Accrued lease operating expense	16,919	16,843
Accrued ad valorem taxes	2,597	1,426
Accrued general and administrative expenses	2,882	1,961
Environmental liability	88	216
Asset retirement obligation	1,175	1,175
Other	106
Accrued liabilities, Total	$ 61,744	$ 52,923

Summary of Significant Accoun34

Summary of Significant Accounting Policies - Summary of Supplemental Cash Flows (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$ 22,793	$ 21,298
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	1,875	(1,450)
Asset retirement obligation removal related to divestitures	(451)
Assumptions of asset retirement obligations related to properties acquired	$ 0	$ 2,266

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisition-Related Costs (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
General and Administrative Expense
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	$ 86	$ 1,299

Acquisitions and Divestitures36

Acquisitions and Divestitures - Supplemental Pro Forma Information (Detail) - 2015 Beta Acquisition [Member] $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2015USD ($)$ / shares
Business Acquisition [Line Items]
Revenues	$ 99,081
Net income (loss)	$ (162,306)
Basic and diluted earnings per unit | $ / shares	$ (1.90)

Fair Value Measurements of Fi37

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value [Member] - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	$ 776,833	$ 816,995
Interest rate derivatives, Assets	28	0
Liabilities	78,622	87,156
Interest rate derivatives, Liabilities	5,834	2,655
Quoted Prices in Active Market (Level 1) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0	0
Interest rate derivatives, Assets	0	0
Liabilities	0	0
Interest rate derivatives, Liabilities	0	0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	776,833	816,995
Interest rate derivatives, Assets	28	0
Liabilities	78,622	87,156
Interest rate derivatives, Liabilities	5,834	2,655
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0	0
Interest rate derivatives, Assets	0	0
Liabilities	0	0
Interest rate derivatives, Liabilities	0	0
Commodity derivatives [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	776,805	816,995
Liabilities	72,788	84,501
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	0
Liabilities	0	0
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	776,805	816,995
Liabilities	72,788	84,501
Commodity derivatives [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0	0
Liabilities	$ 0	$ 0

Fair Value Measurements of Fi38

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	$ 8,342	$ 251,347
Carrying value of properties after impairment charges	1,917,382		$ 1,946,323
East Texas, Wyoming and Colorado [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	8,300	$ 251,300
Carrying value of properties after impairment charges	$ 11,000

Risk Management and Derivativ39

Risk Management and Derivative Instruments - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
	Feb. 28, 2015	Mar. 31, 2016
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		$ 332.2
Maximum amount of loss due to credit risk		369.1
Cash settlement receipt	$ 27.1
Two Counterparties [Member]
Derivative Instruments Gain Loss [Line Items]
Maximum amount of loss due to credit risk		$ 213.5

Risk Management and Derivativ40

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	3 Months Ended
	Mar. 31, 2016MMBTU$ / MMBTU$ / bblbbl
Remaining 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	3,586,331
Weighted-average fixed price | $ / MMBTU	4.14
Remaining 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	3,572,778
Spread | $ / MMBTU	(0.07)
Remaining 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	304,313
Weighted-average fixed price | $ / bbl	85.47
Remaining 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	139,667
Spread | $ / bbl	(10.01)
Remaining 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	210,433
Weighted-average fixed price | $ / bbl	35.79
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 Derivativ41

Risk Management and Derivative Instruments - Open Commodity Positions Disaggregated Basis (Detail) - Disaggregated Basis Swap [Member]	3 Months Ended
	Mar. 31, 2016MMBTU$ / MMBTU$ / bblbbl
Remaining 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	2,997,778
Remaining 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
Remaining 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
Remaining 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
Remaining 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	99,667
Remaining 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
Remaining 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)
Remaining 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
Remaining 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)
Remaining 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
Remaining 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)
Remaining 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 Derivativ42

Risk Management and Derivative Instruments - Interest Rate Swap Open Positions (Detail) - Interest rate swaps [Member] $ in Thousands	3 Months Ended
	Mar. 31, 2016USD ($)
Remaining 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	$ 300,000
Weighted-average fixed rate	1.427%
Floating rate	1 Month LIBOR

Risk Management and Derivativ43

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 259,854	$ 272,320
Asset Derivatives, Net recorded fair value	442,616	461,810
Liability Derivatives, Net recorded fair value	2,098	2,850
Liability Derivatives, Net recorded fair value	2,161	1,441
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	308,480	324,265
Asset Derivatives, Netting arrangements	(48,626)	(51,945)
Asset Derivatives, Net recorded fair value	259,854	272,320
Liability Derivatives, Gross fair value	50,724	54,795
Liability Derivatives, Netting arrangements	(48,626)	(51,945)
Liability Derivatives, Net recorded fair value	2,098	2,850
Short-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	308,480	324,265
Liability Derivatives, Gross fair value	48,530	53,581
Short-Term Derivative Instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	0	0
Liability Derivatives, Gross fair value	2,194	1,214
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	468,353	492,730
Asset Derivatives, Netting arrangements	(25,737)	(30,920)
Asset Derivatives, Net recorded fair value	442,616	461,810
Liability Derivatives, Gross fair value	27,898	32,361
Liability Derivatives, Netting arrangements	(25,737)	(30,920)
Liability Derivatives, Net recorded fair value	2,161	1,441
Long-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	468,325	492,730
Liability Derivatives, Gross fair value	24,258	30,920
Long-Term Derivative Instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	28	0
Liability Derivatives, Gross fair value	$ 3,640	$ 1,441

Risk Management and Derivativ44

Risk Management and Derivative Instruments - Unrealized and Realized Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	$ (51,745)	$ (145,459)
Interest expense, net	(32,552)	(28,818)
Commodity derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	(51,745)	(145,459)
Interest rate derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net	$ 3,682	$ 2,441

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 164,164
Liabilities added from acquisitions or drilling	10
Liabilities removed upon sale of wells	(451)
Liabilities settled	(615)
Accretion expense	2,707	$ 1,634
Revision of estimates	324
Asset retirement obligations at end of period	166,139
Less: Current portion	1,175		$ 1,175
Asset retirement obligations - long-term portion	$ 164,964		$ 162,989

Long Term Debt - Consolidated D

Long Term Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized discounts		$ (13,509)	$ (14,114)
Total long-term debt		1,957,984	2,000,579
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Revolving credit facility		792,000	836,000
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	496,990
Senior Notes [Member]
Debt Instrument [Line Items]
Debt issuance costs, net		$ (17,497)	$ (18,297)
[1]	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 $203.0 million and $210.0 million at March 31, 2016 and December 31, 2015, respectively.
[3]	The estimated fair value of our 2022 Senior Notes was $135.4 million and $149.1 million at March 31, 2016 and December 31, 2015, respectively.

Long Term Debt - Consolidated47

Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
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	$ 203,000,000	$ 210,000,000
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	$ 135,400,000	$ 149,100,000

Long Term Debt - Additional Inf

Long Term Debt - Additional Information (Detail) - USD ($)	Apr. 14, 2016	Mar. 31, 2016
Line of Credit Facility [Line Items]
Letters of credit outstanding		$ 2,100,000
Subsequent Event [Member]
Line of Credit Facility [Line Items]
Debt covenant, cash distributions to equity holders, pro forma availability minimum	$ 75,000,000
Debt covenant, cash distributions to equity holders, borrowing base amount percentage prior threshold date	10.00%
Debt covenant, cash distributions to equity holders, borrowing base amount percentage after threshold date	15.00%
Debt covenant, cash distributions to equity holders, total debt to EBITDAX ratio minimum	400.00%
Debt covenant, maximum payment of cash distributions to equity holders amount	$ 4,150,000
Debt covenant, repurchase, pro forma availability minimum	$ 75,000,000
Debt covenant, repurchase, borrowing base amount percentage prior threshold date minimum	10.00%
Debt covenant, repurchase, borrowing base amount percentage after threshold date minimum	15.00%
Debt covenant, outstanding senior unsecured notes repurchase, total debt to EBITDAX ratio maximum	300.00%
Maximum amount of proceeds from swap liquidations, sale or other disposition of oil and gas properties to repurchase outstanding senior unsecured notes or second lien debt	$ 40,000,000
Maximum amount of sale and cash proceeds to repurchase outstanding senior unsecured notes aggregate	$ 60,000,000
Minimum Percentage of Oil and Gas Properties mortgaged as collateral security for the loans under the Credit Agreement	90.00%
Debt covenant, minimum aggregate amount of unrestricted cash or cash equivalents to prepay loans and cash collateralize letter of credit exposure	$ 25,000,000
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
Borrowing base		$ 1,175,000,000
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Percentage of revolving unused commitment fee	0.50%
Borrowing base	$ 925,000,000
Consolidated First Lien Net Secured Debt to Consolidated EBITDAX ratio Maximum	325.00%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Subsequent Event [Member] | Minimum [Member] | Alternative Base Rate [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage	1.25%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Subsequent Event [Member] | Minimum [Member] | Eurodollar or LIBOR [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage	2.25%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Subsequent Event [Member] | Maximum [Member] | Alternative Base Rate [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage	2.25%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Subsequent Event [Member] | Maximum [Member] | Eurodollar or LIBOR [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage	3.25%
Issuance Of Secured Second Lien Notes Solely In Exchange Of Outstanding Senior Unsecured Notes | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Debt instrument, redemption period	180 days
Issuance Of Secured Second Lien Notes Solely In Exchange Of Outstanding Senior Unsecured Notes | Subsequent Event [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Aggregate principal amount	$ 600,000,000
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)	Mar. 31, 2016USD ($)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line of Credit Facility [Line Items]
Borrowing base	$ 1,175,000,000

Long Term Debt - Borrowing Ba50

Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail)	Mar. 31, 2016USD ($)
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 Excluding Commitment Fees on Variable-Rate Debt Obligations (Detail)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
OLLC revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates	2.43%	1.90%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized deferred financing costs		$ 20,786	$ 21,969
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Unamortized deferred financing costs	[1]	3,289	3,672
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[2]	10,665	11,194
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[2]	$ 6,832	$ 7,103
[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 U53

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Parenthetical) (Detail)	Mar. 31, 2016USD ($)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Revolving credit facility	$ 2,000,000,000

Equity and Distributions - Summ

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Detail)	3 Months Ended
	Mar. 31, 2016shares
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	86,797
Restricted common units issued	0
Restricted common units forfeited	0
Restricted common units repurchased	0
Ending balance	86,797
Limited Partners Common Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	82,906,400
Restricted common units issued	50,000
Restricted common units forfeited	(9,669)
Restricted common units repurchased	(21,429)
Ending balance	82,925,302

Equity and Distributions - Su55

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Parenthetical) (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)
Summary Of Changes In Number Of Outstanding Units [Abstract]
Withholding tax withheld and paid related to vesting of restricted common units	$ 0.1

Equity and Distributions - Addi

Equity and Distributions - Additional Information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2015USD ($)shares
Equity [Abstract]
Common units amount repurchased under repurchase program | $	$ 28.4
Common units repurchased under repurchase program | shares	1,909,583

Equity and Distributions - Su57

Equity and Distributions - Summary of Quarterly Cash Distribution Rates (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
Limited Partners Capital Account [Line Items]
Distribution made to member or limited partner, date of declaration	Apr. 26, 2016	Jan. 26, 2016	Oct. 26, 2015	Jul. 24, 2015	Apr. 24, 2015	Jan. 26, 2015
Distribution made to member or limited partner, date of record	May 6, 2016	Feb. 5, 2016	Nov. 5, 2015	Aug. 5, 2015	May 6, 2015	Feb. 5, 2015
Distribution made to member or limited partner, date of distribution	May 13, 2016	Feb. 12, 2016	Nov. 12, 2015	Aug. 12, 2015	May 13, 2015	Feb. 12, 2015
Distribution per unit	$ 0.0300	$ 0.1000	$ 0.3000	$ 0.5500	$ 0.5500	$ 0.5500
Aggregate Distribution	$ 2,500,000	$ 8,300,000	$ 24,900,000	$ 45,700,000	$ 46,300,000	$ 46,300,000
Distribution Received by Affiliates				$ 100,000	$ 200,000	$ 3,100,000
Maximum [Member]
Limited Partners Capital Account [Line Items]
Distribution Received by Affiliates	$ 100,000	$ 100,000	$ 100,000

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
	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Unit [Line Items]
Net income (loss) attributable to Memorial Production Partners LP	$ (38,097)	$ (162,817)
Less: Previous owners interest in net income (loss)	0	(2,268)
Less: General partner's 0.1% interest in net income (loss)	(40)	(166)
Less: IDRs attributable to corresponding period	0	56
Less: Phantom unit distribution equivalents attributable to corresponding period (see Note 11)	(5)
Net income (loss) available to limited partners	$ (38,052)	$ (160,439)
Weighted average limited partner units outstanding:
Basic and diluted	82,935	84,339
Basic and diluted EPU	$ (0.46)	$ (1.90)
Common Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding	82,935	81,778
Subordinated Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding	0	2,561

Earnings Per Unit - Calculati59

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Parenthetical) (Detail)	3 Months Ended
	Mar. 31, 2016	Mar. 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	0.1046%	0.1023%

Unit-based Awards - Summary of

Unit-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Detail)	3 Months Ended
	Mar. 31, 2016$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted common units forfeited	0
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted common units outstanding, Beginning Balance	1,368,538
Granted, Number of Units	50,000
Restricted common units forfeited	(9,669)
Vested, Number of Units	(102,600)
Restricted common units outstanding, Ending Balance	1,306,269
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance | $ / shares	$ 17.61
Granted, Weighted-Average Grant Date Fair Value per Unit | $ / shares	2.41
Forfeited, Weighted-Average Grant Date Fair Value per Unit | $ / shares	18.50
Vested, Weighted-Average Grant Date Fair Value per Unit | $ / shares	15.96
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance | $ / shares	$ 17.15

Unit-based Awards - Summary o61

Unit-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Common Units [Member] $ / shares in Units, $ in Millions	Mar. 31, 2016USD ($)$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted common unit awards issued | $	$ 0.1
Grant date market price | $ / shares	$ 2.41

Unit-based Awards - Additional

Unit-based Awards - Additional Information (Detail) - USD ($) $ in Millions	Mar. 09, 2016	Mar. 31, 2016	Mar. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Reversed share based compensation	$ 0.5
Fair value of compensation cost recognized on the date of plan modification	$ 0.3
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost		$ 12.9	$ 12.9
Weighted-average period of unrecognized compensation cost			1 year 7 months 28 days
Phantom units [Member] | Non-Employee Directors [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Number of Units		155,601
Vesting period date		2017-01

Unit-based Awards - Summary o63

Unit-based Awards - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	$ 2,568	$ 2,341
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	2,492	$ 2,341
Phantom units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	$ 76

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Multi-Shot, LLC [Member]
Related Party Transaction [Line Items]
Drilling and completion expenses	$ 0.1	$ 0.2
Memorial Resource [Member]
Related Party Transaction [Line Items]
Amount receivable under management agreement	$ 0.4
Classic Operating And Classic Pipeline [Member] | Water Disposal Agreement [Member]
Related Party Transaction [Line Items]
Salt water disposal fees		$ 0.9

Related Party Transactions - Sc

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

Related Party Transactions - 66

Related Party Transactions - Schedule of Amount of General and Administrative Costs and Expenses Recognized (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
General and administrative costs and expenses under omnibus agreement	$ 7,449	$ 8,553

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Commitments And Contingencies Additional Textual [Abstract]
Remaining environmental accrued liability recorded	$ 88	$ 216
Maximum remaining obligation	6,000
U S Bank Money Market [Member]
Commitments And Contingencies Additional Textual [Abstract]
Held-to-maturity investment, amortized cost	$ 146,000

Commitments and Contingencies68

Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) $ in Thousands	Mar. 31, 2016USD ($)
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

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($)	Apr. 27, 2016	Apr. 14, 2016	Mar. 31, 2016
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Subsequent Event [Line Items]
Borrowing base			$ 1,175,000,000
Subsequent Event [Member] | OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Subsequent Event [Line Items]
Borrowing base		$ 925,000,000
Subsequent Event [Member] | IDRs [Member] | Natural Gas Partners [Member]
Subsequent Event [Line Items]
Related party, transaction date	Apr. 27, 2016
Agreed ownership interest percentage to acquire	50.00%
MEMP GP [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Related party transaction, amounts of transaction	$ 800,000
Related party, transaction date	Apr. 27, 2016
Partnership ownership percentage	0.10%
Related party transaction, description of transaction	(i) to convert MEMP GP’s 0.1% general partnership interest into a non-economic general partner interest, (ii) cancel the incentive distribution rights of the Partnership, and (iii) provide the limited partners of the Partnership the ability to elect the members of MEMP GP’s board of directors beginning with an annual meeting in 2017.