Amplify Energy (AMPYW) 10-Q 4 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 31, 2015
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
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		82,935,577
General Partner [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		86,797

UNAUDITED CONDENSED CONSOLIDATE

UNAUDITED CONDENSED CONSOLIDATED AND COMBINED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 531	$ 970
Accounts receivable:
Oil and natural gas sales	22,361	46,413
Joint interest owners and other	32,808	36,937
Short-term derivative instruments	231,340	208,585
Prepaid expenses and other current assets	14,258	14,201
Total current assets	301,298	307,106
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	3,527,073	3,329,338
Support equipment and facilities	206,327	198,088
Other	2,984	3,020
Accumulated depreciation, depletion and impairment	(1,829,034)	(1,060,114)
Property and equipment, net	1,907,350	2,470,332
Long-term derivative instruments	439,070	311,802
Restricted investments	81,254	77,361
Other long-term assets	20,404	23,159
Total assets	2,749,376	3,189,760
Current liabilities:
Accounts payable	15,347	23,609
Accounts payable - affiliates	5,006	6,409
Revenues payable	32,700	30,110
Accrued liabilities (Note 2)	90,600	90,974
Short-term derivative instruments	3,515	3,289
Total current liabilities	147,168	154,391
Long-term debt (Note 8)	1,878,264	1,595,413
Asset retirement obligations	120,744	112,702
Long-term derivative instruments	3,183
Deferred tax liabilities	2,389	30,940
Total liabilities	$ 2,151,748	$ 1,893,446
Commitments and contingencies (Note 13)
Partners' equity (deficit):
General partner (86,797 units outstanding at September 30, 2015 and December 31, 2014)	$ 796	$ 1,251
Previous owners		220,657
Total partners' equity	591,740	1,290,754
Noncontrolling interests	5,888	5,560
Total equity	597,628	1,296,314
Total liabilities and equity	2,749,376	3,189,760
Limited Partners Common Units [Member]
Partners' equity (deficit):
Limited partners units	$ 590,944	1,085,265
Subordinated Units [Member]
Partners' equity (deficit):
Limited partners units		$ (16,419)

UNAUDITED CONDENSED CONSOLIDAT3

UNAUDITED CONDENSED CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical) - shares	Sep. 30, 2015	Dec. 31, 2014
General partner, units outstanding	86,797	86,797
Limited Partners Common Units [Member]
Limited partners, units outstanding	82,930,486	80,421,992
Subordinated Units [Member]
Limited partners, units outstanding	0	5,360,912

UNAUDITED CONDENSED STATEMENTS

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues:
Oil & natural gas sales	$ 87,519	$ 164,935	$ 276,689	$ 423,782
Pipeline tariff income and other	564	1,326	2,350	3,572
Total revenues	88,083	166,261	279,039	427,354
Costs and expenses:
Lease operating	45,416	41,878	130,782	99,526
Pipeline operating	461	431	1,407	1,596
Gathering, processing, and transportation	8,134	7,862	25,402	21,016
Exploration	2,141	42	2,263	252
Production and ad valorem taxes	6,896	11,053	19,609	24,482
Depreciation, depletion, and amortization	53,305	53,649	150,857	129,165
Impairment of proved oil and natural gas properties	361,836	67,181	613,183	67,181
General and administrative	13,910	12,069	42,798	34,181
Accretion of asset retirement obligations	1,716	1,421	5,036	4,212
(Gain) loss on commodity derivative instruments	(244,888)	(156,402)	(328,944)	28,710
Other, net			(943)	(12)
Total costs and expenses	248,927	39,184	661,450	410,309
Operating income (loss)	(160,844)	127,077	(382,411)	17,045
Other income (expense):
Interest expense, net	(31,255)	(26,458)	(87,983)	(60,573)
Other income (expense)	11		295
Total other income (expense)	(31,244)	(26,458)	(87,688)	(60,573)
Income (loss) before income taxes	(192,088)	100,619	(470,099)	(43,528)
Income tax benefit (expense)	107	688	1,601	303
Net income (loss)	(191,981)	101,307	(468,498)	(43,225)
Net income (loss) attributable to noncontrolling interest	104	150	328	193
Net income (loss) attributable to Memorial Production Partners LP	(192,085)	101,157	(468,826)	(43,418)
Limited partners' interest in net income (loss):
Net income (loss) attributable to Memorial Production Partners LP	(192,085)	101,157	(468,826)	(43,418)
Net (income) loss allocated to previous owners		1,919	2,268	(1,812)
Net (income) loss allocated to general partner	174	(127)	402	(19)
Net (income) loss allocated to NGP IDRs	(27)	(24)	(83)	(64)
Limited partners' interest in net income (loss)	$ (191,938)	$ 102,925	$ (466,239)	$ (45,313)
Earnings per unit: (Note 10)
Basic and diluted earnings per unit	$ (2.31)	$ 1.39	$ (5.57)	$ (0.69)
Weighted average limited partner units outstanding:
Basic and diluted	82,973	73,815	83,732	65,556

UNAUDITED CONDENSED STATEMENTS5

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash flows from operating activities:
Net income (loss)	$ (468,498)	$ (43,225)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	150,857	129,165
Impairment of proved oil and natural gas properties	613,183	67,181
(Gain) loss on derivative instruments	(322,316)	29,570
Cash settlements (paid) received on expired derivative instruments	175,703	(16,206)
Cash settlements on terminated commodity derivatives	27,063
Premiums paid for commodity derivatives	(27,063)
Deferred income tax expense (benefit)	(1,789)	(378)
Amortization of deferred financing costs	4,375	2,935
Accretion of senior notes net discount	1,818	1,308
Accretion of asset retirement obligations	5,036	4,212
Amortization of equity awards	7,899	5,387
Settlement of asset retirement obligations	(780)
Exploration costs	2,078
Changes in operating assets and liabilities:
Accounts receivable	17,629	(31,094)
Prepaid expenses and other assets	(162)	(642)
Payables and accrued liabilities	323	59,874
Other	216	1,859
Net cash provided by operating activities	185,572	209,946
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(6,095)	(1,083,167)
Acquisition post-closing adjustment receipts	9,570
Additions to oil and gas properties	(196,055)	(217,634)
Additions to other property and equipment		(14)
Additions to restricted investments	(3,893)	(2,883)
Net cash used in investing activities	(196,473)	(1,303,698)
Cash flows from financing activities:
Advances on revolving credit facilities	345,000	1,325,000
Payments on revolving credit facilities	(61,000)	(1,127,000)
Proceeds from senior notes		492,425
Deferred financing costs	(319)	(11,409)
Repurchase of senior notes	(2,914)
Capital contributions from previous owners	1,912	2,817
Proceeds from general partner contributions		570
Proceeds from the issuance of common units		553,288
Costs incurred in conjunction with issuance of common units		(12,222)
Distributions to partners	(138,349)	(107,070)
Distribution to Memorial Resource (see Note 1)	(78,396)	(33,880)
Restricted units returned to plan	(1,288)
Repurchases under unit repurchase program	(54,184)
Distributions made by previous owners		(9,887)
Net cash provided by financing activities	10,462	1,072,632
Net change in cash and cash equivalents	(439)	(21,120)
Cash and cash equivalents, beginning of period	970	21,698
Cash and cash equivalents, end of period	$ 531	$ 578

UNAUDITED CONDENSED STATEMENTS6

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY - 9 months ended Sep. 30, 2015 - USD ($) $ in Thousands		Total	Limited Partners Common Units [Member]	Limited Partners Subordinated [Member]	General Partner [Member]	Previous Owners [Member]	NGP IDR [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2014	[1]	$ 1,296,314	$ 1,085,265	$ (16,419)	$ 1,251	$ 220,657		$ 5,560
Net income (loss)		(468,498)	(466,269)	30	(402)	(2,268)	$ 83	328
Contributions		1,912				1,912
Distributions		(138,349)	(135,091)	(2,949)	(226)		$ (83)
Distribution attributable to net assets transferred (Note 1)		(78,396)	(78,318)		(78)
Net book value of net assets exchanged (Note 1)		2,721	250,791		251	(248,321)
Amortization of equity awards		7,899	7,899
Conversion of subordinated units to common units			(19,338)	$ 19,338
Common units repurchased under repurchase program (Note 9)		(52,813)	(52,813)
Restricted units repurchased and other		(1,182)	(1,182)
Deferred tax liability retained by previous owner (Note 2)		28,020				$ 28,020
Balance at Sep. 30, 2015		$ 597,628	$ 590,944		$ 796			$ 5,888
[1]	See Note 1 for information regarding recast amounts and basis of financial statement presentation.

Organization and Basis of Prese

Organization and Basis of Presentation	9 Months Ended
	Sep. 30, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation General Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries. We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Colorado, Wyoming, New Mexico and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. Unless the context requires otherwise, references to: (i) “our general partner” or “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner; (ii) “Memorial Resource” refer collectively to Memorial Resource Development Corp. and its subsidiaries other than the Partnership; (iii) “MRD LLC” refer to Memorial Resource Development LLC, which is the predecessor of Memorial Resource; (iv) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (v) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refer to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; (vii) “MRD Holdco” refer to MRD Holdco LLC, which together with a group, controls Memorial Resource; and (viii) “NGP” refer to Natural Gas Partners. The Partnership is owned 99.9% by its limited partners and 0.1% by MEMP GP, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities. Memorial Resource provides management, administrative and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco. The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are owned by our general partner. Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer to certain oil and gas properties primarily located in East Texas and West Louisiana that the Partnership acquired on February 23, 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana for periods after common control commenced through the date of acquisition. We refer to this transaction as the “Property Swap.” The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”). The Property Swap was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information have been retrospectively revised to give effect to the Property Swap as if the Partnership owned the assets for periods after common control commenced through the acquisition date. Basis of Presentation Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements of the previous owners were derived from their historical accounting records and reflect their historical financial position, results of operations and cash flows. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of the Partnership, is presented as a noncontrolling interest in the financial statements. Our results of operations for the three and nine months ended September 30, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). These unaudited condensed consolidated and combined financial statements and the notes thereto should be read in conjunction with the audited supplemental consolidated and combined financial statements and notes thereto included in our Current Report on Form 8-K filed on April 21, 2015 (our “Recast Form 8-K”), which retrospectively revised certain of our financial and other information to give effect to the Property Swap. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Use of Estimates The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies A discussion of our significant accounting policies and estimates is included in our Recast Form 8-K. Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): September 30, December 31, 2015 2014 Accrued capital expenditures $ 29,105 $ 36,042 Accrued interest payable 27,983 24,673 Accrued lease operating expense 17,600 15,594 Accrued ad valorem taxes 12,996 8,281 Accrued general and administrative expenses 1,348 1,276 Environmental liability 588 2,092 Other 980 3,016 $ 90,600 $ 90,974 Income Tax In connection with MRD’s IPO in June 2014, an increase in equity was recorded by the previous owners related to a deferred tax liability established in connection with Memorial Resource’s initial public offering and restructuring transactions as it represented a transaction among shareholders. Subsequent to Memorial Resource’s initial public offering in June 2014, income tax related to the Property Swap was calculated on a separate return basis through February 2015. The deferred tax liability of approximately $28.0 million associated with the previous owners was retained by them in connection with the closing of the Property Swap transaction and reflected in the equity statement. Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Nine Months Ended September 30, 2015 2014 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 75,378 $ 31,978 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (6,937 ) 23,329 (Increase) decrease in accounts receivable related to acquisitions 9,570 (4,004 ) Restricted units returned to plan 3 932 New Accounting Pronouncements Simplifying the Accounting for Measurement-Period Adjustments . In September 2015, the Financial Accounting Standards Board ("FASB") issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Partnership does not expect the impact of adopting this guidance to be material to the Partnership’s financial statements and related disclosures. Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Partnership beginning on January 1, 2018. The Partnership has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures. Presentation of Debt Issuance Cost. In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Partnership does not expect the impact of adopting this guidance to be material to the Partnership’s financial statements and related disclosures. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. In April 2015, the FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. Since the Partnership has historically allocated the earnings (losses) of transferred businesses that occurred in periods before the date of the dropdown transaction entirely to affiliates of the general partner (i.e., the previous owners) and did not adjust previously reported earnings per unit of the limited partners, the Partnership does not expect the impact of adopting this guidance will be material to the Partnership’s financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Acquisitions and Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Related Party Acquisitions See Note 12 for further information regarding related party acquisitions that have been accounted for as transactions between entities under common control that impact the basis of presentation for the periods presented. 2014 Acquisitions Eagle Ford Acquisition. On March 25, 2014, we closed a transaction to acquire certain oil and natural gas producing properties in the Eagle Ford from a third party (the “Eagle Ford Acquisition”). In addition, we acquired a 30% interest in the seller’s Eagle Ford leasehold. Wyoming Acquisition. On July 1, 2014, we consummated a transaction to acquire certain oil and natural gas liquids properties in Wyoming from a third party for an aggregate purchase price of approximately $906.1 million, including customary post-closing adjustments (the “Wyoming Acquisition”). 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 For the Nine Months Ended September 30, September 30, 2015 2014 2015 2014 $ 16 $ 925 $ 1,612 $ 3,912 Pro forma Information. In March and July 2014, we closed two third-party acquisitions, as discussed above. The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2014 as though these third-party acquisitions had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Nine Months Ended September 30, 2014 (In thousands, except per unit amounts) Revenues $ 527,819 Net income (loss) (4,996 ) Basic and diluted earnings per unit (0.11 )

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. The carrying values of accounts receivables, accounts payables (including accrued liabilities), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at September 30, 2015 and December 31, 2014. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt. Assets and Liabilities Measured at Fair Value on a Recurring Basis The fair market values of the derivative financial instruments reflected on the balance sheets as of September 30, 2015 and December 31, 2014 were based on estimated forward commodity prices and forward interest rate yield curves. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at September 30, 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 $ — $ 744,761 $ — $ 744,761 Interest rate derivatives — — — — Total assets $ — $ 744,761 $ — $ 744,761 Liabilities: Commodity derivatives $ — $ 75,689 $ — $ 75,689 Interest rate derivatives — 5,360 — 5,360 Total liabilities $ — $ 81,049 $ — $ 81,049 Fair Value Measurements at December 31, 2014 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 564,913 $ — $ 564,913 Interest rate derivatives — 1,305 — 1,305 Total assets — $ 566,218 — $ 566,218 Liabilities: Commodity derivatives $ — $ 45,831 $ — $ 45,831 Interest rate derivatives — 3,289 — 3,289 Total liabilities $ — $ 49,120 $ — $ 49,120 See Note 5 for additional information regarding our derivative instruments. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: · The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs. · If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. · Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. During the three and nine months ended September 30, 2015, we recognized $361.8 million and $613.2 million, respectively, of impairments related to certain properties located in East Texas, South Texas, the Permian, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. As a result of the impairments, the carrying value of these properties at the respective impairment dates was approximately $407.7 million. We recorded approximately $67.2 million of impairments during the three and nine months ended September 30, 2014 primarily related to certain properties located in South Texas. 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	9 Months Ended
	Sep. 30, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments	Note 5. Risk Management and Derivative Instruments Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease. Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $320.3 million against amounts outstanding under our revolving credit facility at September 30, 2015, reducing our maximum credit exposure to approximately $345.9 million, of which approximately $115.3 million was with a single counterparty. See Note 8 for additional information regarding our revolving credit facility. Commodity Derivatives We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, costless collars, call spreads and basis swaps) to manage exposure to commodity price volatility. Historically, the Partnership has not paid or received premiums for put options. In February 2015, we restructured a portion of our commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor. Cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives. We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At September 30, 2015, we had the following open commodity positions: Remaining 2015 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,359,237 3,592,442 3,350,067 3,060,000 2,814,583 Weighted-average fixed price $ 4.08 $ 4.14 $ 4.06 $ 4.18 $ 4.31 Collar contracts: Average Monthly Volume (MMBtu) 350,000 — — — — Weighted-average floor price $ 4.62 $ — $ — $ — $ — Weighted-average ceiling price $ 5.80 $ — $ — $ — $ — Call spreads (1): Average Monthly Volume (MMBtu) 80,000 — — — — Weighted-average sold strike price $ 5.25 $ — $ — $ — $ — Weighted-average bought strike price $ 6.75 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (MMBtu) 3,690,000 3,578,333 2,210,000 1,315,000 900,000 Spread $ (0.12 ) $ (0.07 ) $ (0.04 ) $ (0.02 ) $ 0.01 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 272,531 279,813 301,600 312,000 160,000 Weighted-average fixed price $ 91.34 $ 86.87 $ 84.70 $ 83.74 $ 85.52 Collar contracts: Average Monthly Volume (Bbls) 5,000 — — — — Weighted-average floor price $ 80.00 $ — $ — $ — $ — Weighted-average ceiling price $ 94.00 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (Bbls) 97,000 95,000 30,000 — — Spread $ (7.06 ) $ (9.56 ) $ (2.35 ) $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 209,200 213,100 43,300 — — Weighted-average fixed price $ 42.38 $ 35.64 $ 37.55 $ — $ — (1) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. Our basis swaps included in the table above are presented on a disaggregated basis below: Remaining 2015 2016 2017 2018 2019 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 3,030,000 3,003,333 1,800,000 1,200,000 900,000 Spread-Henry Hub $ (0.11 ) $ (0.07 ) $ (0.07 ) $ (0.03 ) $ 0.01 HSC basis swaps: Average Monthly Volume (MMBtu) 150,000 135,000 115,000 115,000 — Spread-Henry Hub $ (0.08 ) $ 0.07 $ 0.14 $ 0.15 $ — CIG basis swaps: Average Monthly Volume (MMBtu) 210,000 170,000 — — — Spread-Henry Hub $ (0.25 ) $ (0.30 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 300,000 270,000 295,000 — — Spread-Henry Hub $ (0.09 ) $ 0.06 $ 0.03 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 57,000 55,000 — — — Spread - Brent $ (9.73 ) $ (13.35 ) $ — $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 40,000 30,000 — — Spread - WTI $ (3.25 ) $ (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 September 30, 2015, we had the following interest rate swap open positions: Remaining 2015 2016 2017 2018 Average Monthly Notional (in thousands) $ 400,000 $ 400,000 $ 400,000 $ 100,000 Weighted-average fixed rate 0.943 % 0.943 % 1.612 % 1.946 % Floating rate 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR Balance Sheet Presentation The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives September 30, December 31, September 30, December 31, Type Balance Sheet Location 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 269,724 $ 225,882 $ 39,670 $ 17,297 Interest rate swaps Short-term derivative instruments — — 2,229 3,289 Gross fair value 269,724 225,882 41,899 20,586 Netting arrangements Short-term derivative instruments (38,384 ) (17,297 ) (38,384 ) (17,297 ) Net recorded fair value Short-term derivative instruments $ 231,340 $ 208,585 $ 3,515 $ 3,289 Commodity contracts Long-term derivative instruments $ 475,037 $ 339,031 $ 36,019 $ 28,534 Interest rate swaps Long-term derivative instruments — 1,305 3,131 — Gross fair value 475,037 340,336 39,150 28,534 Netting arrangements Long-term derivative instruments (35,967 ) (28,534 ) (35,967 ) (28,534 ) Net recorded fair value Long-term derivative instruments $ 439,070 $ 311,802 $ 3,183 $ — (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 For the Nine Months Ended Statements of September 30, September 30, Operations Location 2015 2014 2015 2014 Commodity derivative contracts (Gain) loss on commodity derivatives $ (244,888 ) $ (156,402 ) $ (328,944 ) $ 28,710 Interest rate derivatives Interest expense, net 3,543 (231 ) 6,628 860

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. Asset Retirement Obligations The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2015 (in thousands): Asset retirement obligations at beginning of period $ 112,702 Liabilities added from acquisitions or drilling 3,275 Liabilities removed upon sale of wells (62 ) Liabilities settled (780 ) Accretion expense 5,036 Revision of estimates 573 Asset retirement obligations at end of period $ 120,744

Restricted Investments

Restricted Investments	9 Months Ended
	Sep. 30, 2015
Investments Debt And Equity Securities [Abstract]
Restricted Investments	Note 7. Restricted Investments Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and gas properties. The components of the restricted investment balance consisted of the following at the dates indicated: September 30, December 31, 2015 2014 (In thousands) BOEM platform abandonment (See Note 13) $ 73,488 $ 69,954 BOEM lease bonds 794 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 3,060 2,701 California State Lands Commission pipeline right-of-way bond 3,005 3,005 City of Long Beach pipeline facility permit 500 500 Federal pipeline right-of-way bond 307 307 Port of Long Beach pipeline license 100 100 Restricted investments $ 81,254 $ 77,361

Long Term Debt

Long Term Debt	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Long Term Debt	Note 8. Long Term Debt The following table presents our consolidated debt obligations at the dates indicated: September 30, December 31, 2015 2014 (In thousands) MEMP: OLLC $2.0 billion revolving credit facility, variable-rate, $ 696,000 $ 412,000 2021 Senior Notes, fixed-rate, due May 2021 (1) (3) 700,000 700,000 2022 Senior Notes, fixed-rate, due August 2022 (2) (3) 496,990 500,000 Unamortized discounts (14,726 ) (16,587 ) Total long-term debt $ 1,878,264 $ 1,595,413 (1) The estimated fair value of our 2021 Senior Notes was $469.0 million and $563.5 million at September 30, 2015 and December 31, 2014, respectively. (2) The estimated fair value of our 2022 Senior Notes was $303.2 million and $380.0 million at September 30, 2015 and December 31, 2014, respectively. (3) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. Subsidiary Guarantors We are a “Well-Known Seasoned Issuer” under SEC rules and have filed a universal shelf registration statement with the SEC that allows us to issue debt and equity securities. Any debt securities issued will be governed by an indenture. Our outstanding debt securities are, and any debt securities issued in the future will likely be, jointly and severally, fully and unconditionally guaranteed (subject to customary release provisions) by certain of the Partnership’s subsidiaries (collectively, the “Guarantor Subsidiaries”). The Guarantor Subsidiaries are 100% owned by the Partnership. The Partnership has no material assets or operations independent of the Guarantor Subsidiaries and there are no significant restrictions upon the ability of the Guarantor Subsidiaries to distribute funds to the Partnership. Borrowing Base Credit facilities tied to borrowing bases are common throughout the oil and gas industry. The borrowing base for our revolving credit facility was the following at the date indicated: September 30, 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 1,300,000 Subsequent Event . Effective November 4, 2015 the borrowing base under our revolving credit facility was reduced to approximately $1.18 billion in connection with the semi-annual borrowing base redetermination by the lenders. OLLC Revolving Credit Facility OLLC is a party to a $2.0 billion revolving credit facility, which is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries). Weighted-Average Interest Rates The following table presents the weighted-average interest rates paid, excluding commitment fees, on our consolidated variable-rate debt obligations for the periods presented: For the Three Months Ended For the Nine Months Ended September 30, September 30, 2015 2014 2015 2014 OLLC revolving credit facility 2.14 % 2.16 % 2.06 % 2.08 % Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: September 30, December 31, 2015 2014 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due $ 4,534 $ 6,468 2021 Senior Notes (2) 11,722 13,308 2022 Senior Notes (2) 7,375 7,958 Total $ 23,631 $ 27,734 (1) Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility. (2) Unamortized deferred financing costs are amortized using the straight line method, which generally approximates the effective interest method. Letters of Credit At September 30, 2015, we had $2.1 million of letters of credit outstanding, all related to operations at our Wyoming properties.

Equity and Distributions

Equity and Distributions	9 Months Ended
	Sep. 30, 2015
Equity [Abstract]
Equity and Distributions	Note 9. Equity & Distributions 2014 Public Equity Offerings On September 9, 2014, we issued 14,950,000 common units representing limited partner interests in the Partnership (including 1,950,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $22.29 per unit generating total net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility. On July 15, 2014, we issued 9,890,000 common units representing limited partner interests in the Partnership (including 1,290,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the underwriters at a negotiated price of $22.25 per unit generating total net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility. Equity Outstanding The following table summarizes changes in the number of outstanding units since December 31, 2014: General Common Subordinated Partner Balance, December 31, 2014 80,421,992 5,360,912 86,797 Restricted common units issued 815,607 — — Restricted common units forfeited (32,876 ) — — Restricted common units repurchased (1) (87,228 ) — — Common units repurchased under repurchase program (3,547,921 ) — — Subordinated units converted to common units 5,360,912 (5,360,912 ) — Balance, September 30, 2015 82,930,486 — 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 $1.3 million for the nine months ended September 30, 2015. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership. Restricted common units are a component of common units as presented on our unaudited condensed consolidated balance sheets. See Note 11 for additional information regarding restricted common units that were granted during the nine months ended September 30, 2015. On February 13, 2015, all of the 5,360,912 outstanding subordinated units owned by MRD Holdco were converted into common units. The subordinated units converted on a one-for-one basis into common units upon the payment of MEMP's fourth quarter 2014 distribution. MRD Holdco sold all of the common units during the three months ended June 30, 2015 and no longer owns any of our outstanding common units. 2015 Repurchases of Common Units In December 2014, the board of directors of our general partner authorized the repurchase of up to $150.0 million of our common units (“MEMP Repurchase Program”). Under the MEMP Repurchase Program, units may be repurchased and retired from time to time at our discretion on the open market. The MEMP Repurchase Program does not obligate us to repurchase any dollar amount or specific number of common units and may be discontinued at any time. During the nine months ended September 30, 2015, we repurchased $52.8 million in common units, which represents a repurchase and retirement of 3,547,921 common units under the MEMP Repurchase Program. At September 30, 2015, we have up to approximately $81.7 million of authorized repurchases remaining under the MEMP Repurchase Program. Allocations of Net Income (Loss) Net income (loss) attributable to the Partnership is allocated between our general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner and the Funds. Net income (loss) attributable to acquisitions accounted for as a transaction between entities under common control in a manner similar to the pooling of interest method prior to their acquisition date is allocated to the previous owners since they are affiliates of our general partner. Cash Distributions to Unitholders The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts): Distribution Amount Aggregate Received by Quarter Declaration Date Record Date Payable Date Per Unit Distribution Affiliates 3 rd October 26, 2015 November 5, 2015 November 12, 2015 $ 0.3000 $ 24.9 $ < 0.1 2 nd July 24, 2015 August 5, 2015 August 12, 2015 $ 0.5500 $ 45.7 $ 0.1 1 st April 24, 2015 May 6, 2015 May 13, 2015 $ 0.5500 $ 46.3 $ 0.2 4 th January 26, 2015 February 5, 2015 February 12, 2015 $ 0.5500 $ 46.3 $ 3.1 3 rd October 23, 2014 November 5, 2014 November 12, 2014 $ 0.5500 $ 47.8 $ 3.1 2 nd July 24, 2014 August 5, 2014 August 12, 2014 $ 0.5500 $ 39.5 $ 3.0 1 st April 24, 2014 May 6, 2014 May 13, 2014 $ 0.5500 $ 33.8 $ 3.0

Earnings per Unit

Earnings per Unit	9 Months Ended
	Sep. 30, 2015
Earnings Per Share [Abstract]
Earnings per Unit	Note 10. Earnings per Unit The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Net income (loss) attributable to Memorial Production Partners LP $ (192,085 ) $ 101,157 $ (468,826 ) $ (43,418 ) Less: Previous owners interest in net income (loss) — (1,919 ) (2,268 ) 1,812 Less: General partner's 0.1% interest in net income (loss) (1) (198 ) 103 (483 ) (45 ) Less: IDRs attributable to corresponding period — 56 112 144 Net income (loss) available to limited partners $ (191,887 ) $ 102,917 $ (466,187 ) $ (45,329 ) Weighted average limited partner units outstanding: Common units 82,973 68,454 82,888 60,195 Subordinated units — 5,361 844 5,361 Total 82,973 73,815 83,732 65,556 Basic and diluted EPU $ (2.31 ) $ 1.39 $ (5.57 ) $ (0.69 ) (1) As a result of repurchases under the MEMP Repurchase Program, our general partner had an approximate average 0.105% and 0.104% interest in us for the three and nine months ended September 30, 2015, respectively.

Equity-based Awards

Equity-based Awards	9 Months Ended
	Sep. 30, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Equity-based Awards	Note 11. Equity-Based Awards The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for the periods presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted common units outstanding at December 31, 2014 1,093,520 $ 20.93 Granted (2) 815,607 $ 15.04 Forfeited (32,876 ) $ 19.61 Vested (483,627 ) $ 20.37 Restricted common units outstanding at September 30, 2015 1,392,624 $ 17.70 (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 nine months ended September 30, 2015 was $12.3 million based on a grant date market price from $14.70 to $15.45 per unit. The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2015 2014 2015 2014 $ 2,993 $ 2,427 $ 7,899 $ 5,387 The unrecognized compensation cost associated with restricted common unit awards was $20.0 million at September 30, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.03 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to partners as presented on our unaudited condensed statements of consolidated and combined cash flows.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Note 12. Related Party Transactions Amounts due to (due from) Memorial Resource and certain affiliates of NGP at September 30, 2015 and December 31, 2014 are presented as “Accounts receivable – – NGP Affiliated Companies During the three and nine months ended September 30, 2015, we paid less than $0.1 million and $0.3 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, we consummated a common control transaction whereby Memorial Resource exchanged its East Texas and West Louisiana properties for all of our interest in the Terryville Field in North Louisiana and cash consideration of approximately $78.4 million, including estimated customary purchase price adjustments. The transaction had an effective date of January 1, 2015. The properties MEMP received are primarily located in the Joaquin Field in Shelby and Panola counties in East Texas. This acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to such acquisition as if the Partnership owned the assets for the period after common control commenced through the acquisition date. The Partnership recorded the following net assets (in thousands): Accounts receivable $ 2,372 Other receivables 5,478 Prepaid expenses and other current assets 1,874 Property and equipment, net 263,210 Accounts payable (3,586 ) Accounts payable - affiliate (1,290 ) Revenues payable (1,110 ) Accrued liabilities (11,347 ) Asset retirement obligations (4,559 ) Net assets $ 251,042 April 2014 Acquisition. On April 1, 2014, we acquired certain oil and natural gas properties in East Texas from a subsidiary of MRD LLC, for approximately $33.3 million, including estimated customary post-closing adjustments. The acquired properties primarily represented additional working interests in wells that were already owned by us and located in Polk and Tyler Counties in the Double A Field of East Texas as well as the Sunflower, Segno and Sugar Creek Fields. This acquisition was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date. The Partnership recorded the following net assets (in thousands): Property and equipment, net $ 37,838 Asset retirement obligations (908 ) Other current liabilities (722 ) Net assets $ 36,208 Due to common control considerations, the difference between the purchase price and the total net assets was recorded as an equity contribution. 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 For the Nine Months Ended September 30, September 30, 2015 2014 2015 2014 $ 8,439 $ 6,528 $ 25,448 $ 16,787 Beta Management Agreement Memorial Resource through its wholly-owned subsidiary Beta Operating Company, LLC provides management and administrative oversight related to our offshore Southern California oil and gas properties in exchange for an annual management fee. Memorial Resource will receive approximately $0.4 million from us annually. Classic Agreements In November 2011, Classic Hydrocarbons Operating, LLC, a subsidiary of Memorial Resource (“Classic Operating”), and Classic Pipeline & Gathering, LLC (“Classic Pipeline”), a subsidiary of MRD Holdco, entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. Effective July 1, 2015, the fee was reduced to $0.40 per barrel. In February 2015, in connection with and as part of the Property Swap, Classic Hydrocarbons Holdings, L.P. sold all of the equity interests owned by it in Classic Operating as well as Craton Energy GP III, LLC (“Craton GP”) and Craton Energy Holdings III, LP (“Craton LP”), two subsidiaries of Memorial Resource, to OLLC, and Classic Operating, Craton GP and Craton LP were merged into OLLC. OLLC is therefore the successor to Classic Operating under the amended gas gathering agreement and water disposal agreement.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 13. Commitments and Contingencies Litigation & Environmental As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows. At September 30, 2015 and December 31, 2014, we had $0.6 million and $2.1 million of environmental reserves recorded on our balance sheets, respectively. Supplemental Bond for Decommissioning Liabilities Trust Agreement In connection with its 2009 acquisition of the Beta properties, Rise Energy Operating, LLC (“REO”), our wholly-owned subsidiary, assumed an obligation with the BOEM for the decommissioning of the offshore production facilities. The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of September 30, 2015 (in thousands): Amortized Investment Cost U.S. Bank Money Market Cash Equivalent $ 142,005 Less: Outside working interest owners share (68,517 ) $ 73,488 The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): June 30, 2016 $ 76,590 December 31, 2016 $ 78,660 As of September 30, 2015, the maximum remaining obligation net to REO’s interest was approximately $5.2 million.

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	Note 14. Subsequent Events MEMP Borrowing Base Redetermination For additional information, see Note 8. November 2015 Beta Acquisition On November 3, 2015, we completed an acquisition of the remaining interests in our oil and gas properties offshore Southern California (the “Beta properties”) from a third party for approximately $101.0 million, subject to customary post-closing adjustments. We first acquired our interests in the Beta properties in December 2012. The acquired interests primarily consist of the 48.25% remaining working interests in three Pacific Outer Continental Shelf blocks in the Beta Field, which includes 58 gross wells, that are located in federal waters approximately eleven miles offshore the Port of Long Beach, California. The acquired interests also include the 48.25% remaining interest in associated facilities including (i) two combined production and drilling platforms (ii) one production processing platform, (iii) a 17.5 mile long 16-inch diameter oil pipeline and (iv) an onshore pump station, tankage and metering facility.

Organization and Basis of Pre21

Organization and Basis of Presentation (Policies)	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
General	General Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries. We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Colorado, Wyoming, New Mexico and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. Unless the context requires otherwise, references to: (i) “our general partner” or “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner; (ii) “Memorial Resource” refer collectively to Memorial Resource Development Corp. and its subsidiaries other than the Partnership; (iii) “MRD LLC” refer to Memorial Resource Development LLC, which is the predecessor of Memorial Resource; (iv) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (v) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refer to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; (vii) “MRD Holdco” refer to MRD Holdco LLC, which together with a group, controls Memorial Resource; and (viii) “NGP” refer to Natural Gas Partners. The Partnership is owned 99.9% by its limited partners and 0.1% by MEMP GP, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities. Memorial Resource provides management, administrative and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco. The Funds collectively indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are owned by our general partner.
Previous Owners	Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer to certain oil and gas properties primarily located in East Texas and West Louisiana that the Partnership acquired on February 23, 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana for periods after common control commenced through the date of acquisition. We refer to this transaction as the “Property Swap.” The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”). The Property Swap was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information have been retrospectively revised to give effect to the Property Swap as if the Partnership owned the assets for periods after common control commenced through the acquisition date.
Basis of Presentation	Basis of Presentation Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements of the previous owners were derived from their historical accounting records and reflect their historical financial position, results of operations and cash flows. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of the Partnership, is presented as a noncontrolling interest in the financial statements. Our results of operations for the three and nine months ended September 30, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). These unaudited condensed consolidated and combined financial statements and the notes thereto should be read in conjunction with the audited supplemental consolidated and combined financial statements and notes thereto included in our Current Report on Form 8-K filed on April 21, 2015 (our “Recast Form 8-K”), which retrospectively revised certain of our financial and other information to give effect to the Property Swap. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements.
Use of Estimates	Use of Estimates The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.
Accrued Liabilities	Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): September 30, December 31, 2015 2014 Accrued capital expenditures $ 29,105 $ 36,042 Accrued interest payable 27,983 24,673 Accrued lease operating expense 17,600 15,594 Accrued ad valorem taxes 12,996 8,281 Accrued general and administrative expenses 1,348 1,276 Environmental liability 588 2,092 Other 980 3,016 $ 90,600 $ 90,974
Income Tax	Income Tax In connection with MRD’s IPO in June 2014, an increase in equity was recorded by the previous owners related to a deferred tax liability established in connection with Memorial Resource’s initial public offering and restructuring transactions as it represented a transaction among shareholders. Subsequent to Memorial Resource’s initial public offering in June 2014, income tax related to the Property Swap was calculated on a separate return basis through February 2015. The deferred tax liability of approximately $28.0 million associated with the previous owners was retained by them in connection with the closing of the Property Swap transaction and reflected in the equity statement.
Supplemental Cash Flows	Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Nine Months Ended September 30, 2015 2014 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 75,378 $ 31,978 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (6,937 ) 23,329 (Increase) decrease in accounts receivable related to acquisitions 9,570 (4,004 ) Restricted units returned to plan 3 932
New Accounting Pronouncements	New Accounting Pronouncements Simplifying the Accounting for Measurement-Period Adjustments . In September 2015, the Financial Accounting Standards Board ("FASB") issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Partnership does not expect the impact of adopting this guidance to be material to the Partnership’s financial statements and related disclosures. Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Partnership beginning on January 1, 2018. The Partnership has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures. Presentation of Debt Issuance Cost. In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Partnership does not expect the impact of adopting this guidance to be material to the Partnership’s financial statements and related disclosures. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. In April 2015, the FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted. Since the Partnership has historically allocated the earnings (losses) of transferred businesses that occurred in periods before the date of the dropdown transaction entirely to affiliates of the general partner (i.e., the previous owners) and did not adjust previously reported earnings per unit of the limited partners, the Partnership does not expect the impact of adopting this guidance will be material to the Partnership’s financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Summary of Current Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands): September 30, December 31, 2015 2014 Accrued capital expenditures $ 29,105 $ 36,042 Accrued interest payable 27,983 24,673 Accrued lease operating expense 17,600 15,594 Accrued ad valorem taxes 12,996 8,281 Accrued general and administrative expenses 1,348 1,276 Environmental liability 588 2,092 Other 980 3,016 $ 90,600 $ 90,974
Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands): For the Nine Months Ended September 30, 2015 2014 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 75,378 $ 31,978 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (6,937 ) 23,329 (Increase) decrease in accounts receivable related to acquisitions 9,570 (4,004 ) Restricted units returned to plan 3 932

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	9 Months Ended
	Sep. 30, 2015
Business Combinations [Abstract]
Acquisition-Related Costs	Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2015 2014 2015 2014 $ 16 $ 925 $ 1,612 $ 3,912
Supplemental Pro Forma Information	The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2014 as though these third-party acquisitions had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Nine Months Ended September 30, 2014 (In thousands, except per unit amounts) Revenues $ 527,819 Net income (loss) (4,996 ) Basic and diluted earnings per unit (0.11 )

Fair Value Measurements of Fi24

Fair Value Measurements of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at September 30, 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 $ — $ 744,761 $ — $ 744,761 Interest rate derivatives — — — — Total assets $ — $ 744,761 $ — $ 744,761 Liabilities: Commodity derivatives $ — $ 75,689 $ — $ 75,689 Interest rate derivatives — 5,360 — 5,360 Total liabilities $ — $ 81,049 $ — $ 81,049 Fair Value Measurements at December 31, 2014 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 564,913 $ — $ 564,913 Interest rate derivatives — 1,305 — 1,305 Total assets — $ 566,218 — $ 566,218 Liabilities: Commodity derivatives $ — $ 45,831 $ — $ 45,831 Interest rate derivatives — 3,289 — 3,289 Total liabilities $ — $ 49,120 $ — $ 49,120

Risk Management and Derivativ25

Risk Management and Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Open Commodity Positions	At September 30, 2015, we had the following open commodity positions: Remaining 2015 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,359,237 3,592,442 3,350,067 3,060,000 2,814,583 Weighted-average fixed price $ 4.08 $ 4.14 $ 4.06 $ 4.18 $ 4.31 Collar contracts: Average Monthly Volume (MMBtu) 350,000 — — — — Weighted-average floor price $ 4.62 $ — $ — $ — $ — Weighted-average ceiling price $ 5.80 $ — $ — $ — $ — Call spreads (1): Average Monthly Volume (MMBtu) 80,000 — — — — Weighted-average sold strike price $ 5.25 $ — $ — $ — $ — Weighted-average bought strike price $ 6.75 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (MMBtu) 3,690,000 3,578,333 2,210,000 1,315,000 900,000 Spread $ (0.12 ) $ (0.07 ) $ (0.04 ) $ (0.02 ) $ 0.01 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 272,531 279,813 301,600 312,000 160,000 Weighted-average fixed price $ 91.34 $ 86.87 $ 84.70 $ 83.74 $ 85.52 Collar contracts: Average Monthly Volume (Bbls) 5,000 — — — — Weighted-average floor price $ 80.00 $ — $ — $ — $ — Weighted-average ceiling price $ 94.00 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (Bbls) 97,000 95,000 30,000 — — Spread $ (7.06 ) $ (9.56 ) $ (2.35 ) $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 209,200 213,100 43,300 — — Weighted-average fixed price $ 42.38 $ 35.64 $ 37.55 $ — $ — (1) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.
Interest Rate Swap Open Positions	At September 30, 2015, we had the following interest rate swap open positions: Remaining 2015 2016 2017 2018 Average Monthly Notional (in thousands) $ 400,000 $ 400,000 $ 400,000 $ 100,000 Weighted-average fixed rate 0.943 % 0.943 % 1.612 % 1.946 % Floating rate 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR
Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet	The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives September 30, December 31, September 30, December 31, Type Balance Sheet Location 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 269,724 $ 225,882 $ 39,670 $ 17,297 Interest rate swaps Short-term derivative instruments — — 2,229 3,289 Gross fair value 269,724 225,882 41,899 20,586 Netting arrangements Short-term derivative instruments (38,384 ) (17,297 ) (38,384 ) (17,297 ) Net recorded fair value Short-term derivative instruments $ 231,340 $ 208,585 $ 3,515 $ 3,289 Commodity contracts Long-term derivative instruments $ 475,037 $ 339,031 $ 36,019 $ 28,534 Interest rate swaps Long-term derivative instruments — 1,305 3,131 — Gross fair value 475,037 340,336 39,150 28,534 Netting arrangements Long-term derivative instruments (35,967 ) (28,534 ) (35,967 ) (28,534 ) Net recorded fair value Long-term derivative instruments $ 439,070 $ 311,802 $ 3,183 $ —
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 For the Nine Months Ended Statements of September 30, September 30, Operations Location 2015 2014 2015 2014 Commodity derivative contracts (Gain) loss on commodity derivatives $ (244,888 ) $ (156,402 ) $ (328,944 ) $ 28,710 Interest rate derivatives Interest expense, net 3,543 (231 ) 6,628 860
Disaggregated Basis Swap [Member]
Open Commodity Positions	Our basis swaps included in the table above are presented on a disaggregated basis below: Remaining 2015 2016 2017 2018 2019 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 3,030,000 3,003,333 1,800,000 1,200,000 900,000 Spread-Henry Hub $ (0.11 ) $ (0.07 ) $ (0.07 ) $ (0.03 ) $ 0.01 HSC basis swaps: Average Monthly Volume (MMBtu) 150,000 135,000 115,000 115,000 — Spread-Henry Hub $ (0.08 ) $ 0.07 $ 0.14 $ 0.15 $ — CIG basis swaps: Average Monthly Volume (MMBtu) 210,000 170,000 — — — Spread-Henry Hub $ (0.25 ) $ (0.30 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 300,000 270,000 295,000 — — Spread-Henry Hub $ (0.09 ) $ 0.06 $ 0.03 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 57,000 55,000 — — — Spread - Brent $ (9.73 ) $ (13.35 ) $ — $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 40,000 30,000 — — Spread - WTI $ (3.25 ) $ (4.34 ) $ (2.35 ) $ — $ —

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2015 (in thousands): Asset retirement obligations at beginning of period $ 112,702 Liabilities added from acquisitions or drilling 3,275 Liabilities removed upon sale of wells (62 ) Liabilities settled (780 ) Accretion expense 5,036 Revision of estimates 573 Asset retirement obligations at end of period $ 120,744

Restricted Investments (Tables)

Restricted Investments (Tables)	9 Months Ended
	Sep. 30, 2015
Investments Debt And Equity Securities [Abstract]
Restricted Investment Balance	The components of the restricted investment balance consisted of the following at the dates indicated: September 30, December 31, 2015 2014 (In thousands) BOEM platform abandonment (See Note 13) $ 73,488 $ 69,954 BOEM lease bonds 794 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 3,060 2,701 California State Lands Commission pipeline right-of-way bond 3,005 3,005 City of Long Beach pipeline facility permit 500 500 Federal pipeline right-of-way bond 307 307 Port of Long Beach pipeline license 100 100 Restricted investments $ 81,254 $ 77,361

Long Term Debt (Tables)

Long Term Debt (Tables)	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations at the dates indicated: September 30, December 31, 2015 2014 (In thousands) MEMP: OLLC $2.0 billion revolving credit facility, variable-rate, $ 696,000 $ 412,000 2021 Senior Notes, fixed-rate, due May 2021 (1) (3) 700,000 700,000 2022 Senior Notes, fixed-rate, due August 2022 (2) (3) 496,990 500,000 Unamortized discounts (14,726 ) (16,587 ) Total long-term debt $ 1,878,264 $ 1,595,413 (1) The estimated fair value of our 2021 Senior Notes was $469.0 million and $563.5 million at September 30, 2015 and December 31, 2014, respectively. (2) The estimated fair value of our 2022 Senior Notes was $303.2 million and $380.0 million at September 30, 2015 and December 31, 2014, respectively. (3) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
Borrowing Base Credit Facility	Credit facilities tied to 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: September 30, 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 1,300,000
Summary of Weighted-Average Interest Rates Paid 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 For the Nine Months Ended September 30, September 30, 2015 2014 2015 2014 OLLC revolving credit facility 2.14 % 2.16 % 2.06 % 2.08 %
Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: September 30, December 31, 2015 2014 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due $ 4,534 $ 6,468 2021 Senior Notes (2) 11,722 13,308 2022 Senior Notes (2) 7,375 7,958 Total $ 23,631 $ 27,734 (1) Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility. (2) Unamortized deferred financing costs are amortized using the straight line method, which generally approximates the effective interest method.

Equity and Distributions (Table

Equity and Distributions (Tables)	9 Months Ended
	Sep. 30, 2015
Equity [Abstract]
Summary of Changes in Number of Outstanding Units	The following table summarizes changes in the number of outstanding units since December 31, 2014: General Common Subordinated Partner Balance, December 31, 2014 80,421,992 5,360,912 86,797 Restricted common units issued 815,607 — — Restricted common units forfeited (32,876 ) — — Restricted common units repurchased (1) (87,228 ) — — Common units repurchased under repurchase program (3,547,921 ) — — Subordinated units converted to common units 5,360,912 (5,360,912 ) — Balance, September 30, 2015 82,930,486 — 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 $1.3 million for the nine months ended September 30, 2015. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership.
Summary of Quarterly Cash Distribution Rates	The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts): Distribution Amount Aggregate Received by Quarter Declaration Date Record Date Payable Date Per Unit Distribution Affiliates 3 rd October 26, 2015 November 5, 2015 November 12, 2015 $ 0.3000 $ 24.9 $ < 0.1 2 nd July 24, 2015 August 5, 2015 August 12, 2015 $ 0.5500 $ 45.7 $ 0.1 1 st April 24, 2015 May 6, 2015 May 13, 2015 $ 0.5500 $ 46.3 $ 0.2 4 th January 26, 2015 February 5, 2015 February 12, 2015 $ 0.5500 $ 46.3 $ 3.1 3 rd October 23, 2014 November 5, 2014 November 12, 2014 $ 0.5500 $ 47.8 $ 3.1 2 nd July 24, 2014 August 5, 2014 August 12, 2014 $ 0.5500 $ 39.5 $ 3.0 1 st April 24, 2014 May 6, 2014 May 13, 2014 $ 0.5500 $ 33.8 $ 3.0

Earnings per Unit (Tables)

Earnings per Unit (Tables)	9 Months Ended
	Sep. 30, 2015
Earnings Per Share [Abstract]
Calculation of Earnings (Loss) Per Unit	The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Net income (loss) attributable to Memorial Production Partners LP $ (192,085 ) $ 101,157 $ (468,826 ) $ (43,418 ) Less: Previous owners interest in net income (loss) — (1,919 ) (2,268 ) 1,812 Less: General partner's 0.1% interest in net income (loss) (1) (198 ) 103 (483 ) (45 ) Less: IDRs attributable to corresponding period — 56 112 144 Net income (loss) available to limited partners $ (191,887 ) $ 102,917 $ (466,187 ) $ (45,329 ) Weighted average limited partner units outstanding: Common units 82,973 68,454 82,888 60,195 Subordinated units — 5,361 844 5,361 Total 82,973 73,815 83,732 65,556 Basic and diluted EPU $ (2.31 ) $ 1.39 $ (5.57 ) $ (0.69 ) (1) As a result of repurchases under the MEMP Repurchase Program, our general partner had an approximate average 0.105% and 0.104% interest in us for the three and nine months ended September 30, 2015, respectively.

Equity-based Awards (Tables)

Equity-based Awards (Tables)	9 Months Ended
	Sep. 30, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Information Regarding Restricted Common Unit Awards	The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for the periods presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted common units outstanding at December 31, 2014 1,093,520 $ 20.93 Granted (2) 815,607 $ 15.04 Forfeited (32,876 ) $ 19.61 Vested (483,627 ) $ 20.37 Restricted common units outstanding at September 30, 2015 1,392,624 $ 17.70 (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 nine months ended September 30, 2015 was $12.3 million based on a grant date market price from $14.70 to $15.45 per unit.
Summary of Amount of Compensation Expense Recognized	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2015 2014 2015 2014 $ 2,993 $ 2,427 $ 7,899 $ 5,387

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2015
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 For the Nine Months Ended September 30, September 30, 2015 2014 2015 2014 $ 8,439 $ 6,528 $ 25,448 $ 16,787
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
April 2014 Acquisition [Member]
Related Party Transaction [Line Items]
Schedule of Net Assets Recorded by Partnership	The Partnership recorded the following net assets (in thousands): Property and equipment, net $ 37,838 Asset retirement obligations (908 ) Other current liabilities (722 ) Net assets $ 36,208

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2015
Commitments And Contingencies Disclosure [Abstract]
Gross Held-to-Maturity Investments	The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of September 30, 2015 (in thousands): Amortized Investment Cost U.S. Bank Money Market Cash Equivalent $ 142,005 Less: Outside working interest owners share (68,517 ) $ 73,488
Minimum Balances Attributable to Net Working Interest	The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): June 30, 2016 $ 76,590 December 31, 2016 $ 78,660

Organization and Basis of Pre34

Organization and Basis of Presentation - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2015Segment
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments	1
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 Accoun35

Summary of Significant Accounting Policies - Summary of Current Accrued Liabilities (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Accrued Liabilities Current [Abstract]
Accrued capital expenditures	$ 29,105	$ 36,042
Accrued interest payable	27,983	24,673
Accrued lease operating expense	17,600	15,594
Accrued ad valorem taxes	12,996	8,281
Accrued general and administrative expenses	1,348	1,276
Environmental liability	588	2,092
Other	980	3,016
Accrued liabilities, Total	$ 90,600	$ 90,974

Summary of Significant Accoun36

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

Summary of Significant Accoun37

Summary of Significant Accounting Policies - Summary of Supplemental Cash Flows (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$ 75,378	$ 31,978
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	(6,937)	23,329
(Increase) decrease in accounts receivable related to acquisitions	9,570	(4,004)
Restricted units returned to plan	$ 3	$ 932

Acquisitions and Divestitures -

Acquisitions and Divestitures - Additional Information (Detail) - USD ($) $ in Millions	Jul. 01, 2014	Mar. 25, 2014
Eagle Ford [Member] | Leasehold [Member]
Business Acquisition And Divestiture [Line Items]
Percentage of leasehold interest acquired		30.00%
Wyoming Acquisition [Member]
Business Acquisition And Divestiture [Line Items]
Purchase price	$ 906.1

Acquisitions and Divestitures39

Acquisitions and Divestitures - Acquisition-Related Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
General and Administrative Expense
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	$ 16	$ 925	$ 1,612	$ 3,912

Acquisitions and Divestitures40

Acquisitions and Divestitures - Supplemental Pro Forma Information (Detail) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2015USD ($)$ / shares
Business Acquisition Pro Forma Information [Abstract]
Revenues	$ 527,819
Net income (loss)	$ (4,996)
Basic and diluted earnings per unit | $ / shares	$ (0.11)

Fair Value Measurements of Fi41

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value [Member] - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	$ 744,761	$ 566,218
Interest rate derivatives, Assets		1,305
Liabilities	81,049	49,120
Interest rate derivatives, Liabilities	5,360	3,289
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	744,761	566,218
Interest rate derivatives, Assets		1,305
Liabilities	81,049	49,120
Interest rate derivatives, Liabilities	5,360	3,289
Commodity derivatives [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	744,761	564,913
Liabilities	75,689	45,831
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	744,761	564,913
Liabilities	$ 75,689	$ 45,831

Fair Value Measurements of Fi42

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	$ 361,836	$ 67,181	$ 613,183	$ 67,181
Carrying value of properties after impairment charges	1,907,350		1,907,350		$ 2,470,332
East Texas, Wyoming and Colorado [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	361,800	$ 67,200	613,200	$ 67,200
Carrying value of properties after impairment charges	$ 407,700		$ 407,700

Risk Management and Derivativ43

Risk Management and Derivative Instruments - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Feb. 28, 2015	Sep. 30, 2015
Derivative Instruments Gain Loss [Line Items]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk		$ 320.3
Maximum amount of loss due to credit risk		345.9
Cash settlement receipt	$ 27.1
Single Counterparty [Member]
Derivative Instruments Gain Loss [Line Items]
Maximum amount of loss due to credit risk		$ 115.3

Risk Management and Derivativ44

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	9 Months Ended
	Sep. 30, 2015MMBTU$ / MMBTU$ / bblbbl
Remaining 2015 [Member] | Natural Gas Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,359,237
Weighted-average fixed price	4.08
Remaining 2015 [Member] | Natural Gas Derivative Contracts Collar Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	350,000
Weighted-average floor price	4.62
Weighted-average ceiling price	5.80
Remaining 2015 [Member] | Natural Gas Derivative Contracts Call Spreads [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	80,000	[1]
Weighted-average sold strike price	5.25	[1]
Weighted-average bought strike price	6.75	[1]
Remaining 2015 [Member] | Natural Gas Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,690,000
Spread	(0.12)
Remaining 2015 [Member] | Crude Oil Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	272,531
Weighted-average fixed price | $ / bbl	91.34
Remaining 2015 [Member] | Crude Oil Derivative Contracts Collar Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	5,000
Weighted-average floor price | $ / bbl	80
Weighted-average ceiling price | $ / bbl	94
Remaining 2015 [Member] | Crude Oil Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	97,000
Spread | $ / bbl	(7.06)
Remaining 2015 [Member] | NGL Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	209,200
Weighted-average fixed price | $ / bbl	42.38
2016 [Member] | Natural Gas Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,592,442
Weighted-average fixed price	4.14
2016 [Member] | Natural Gas Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,578,333
Spread	(0.07)
2016 [Member] | Crude Oil Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	279,813
Weighted-average fixed price | $ / bbl	86.87
2016 [Member] | Crude Oil Derivative Contracts Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	95,000
Spread | $ / bbl	(9.56)
2016 [Member] | NGL Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	213,100
Weighted-average fixed price | $ / bbl	35.64
2017 [Member] | Natural Gas Derivative Contracts Fixed Price Swap Contracts [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,350,067
Weighted-average fixed price	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	(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	84.70
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	30,000
Spread | $ / bbl	(2.35)
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	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	(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
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	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	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
[1]	These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps

Risk Management and Derivativ45

Risk Management and Derivative Instruments - Open Commodity Positions Disaggregated Basis (Detail) - Disaggregated Basis Swap [Member]	9 Months Ended
	Sep. 30, 2015MMBTU$ / MMBTU$ / bblbbl
Remaining 2015 [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,030,000
Remaining 2015 [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	150,000
Remaining 2015 [Member] | Natural Gas Derivative Contracts CIG Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	210,000
Remaining 2015 [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	300,000
Remaining 2015 [Member] | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	57,000
Remaining 2015 [Member] | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	40,000
Remaining 2015 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	(0.11)
Remaining 2015 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	(0.08)
Remaining 2015 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts CIG Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	(0.25)
Remaining 2015 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	(0.09)
Remaining 2015 [Member] | Brent | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / bbl	(9.73)
Remaining 2015 [Member] | WTI | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / bbl	(3.25)
2016 [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,003,333
2016 [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	135,000
2016 [Member] | Natural Gas Derivative Contracts CIG Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	170,000
2016 [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	270,000
2016 [Member] | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	55,000
2016 [Member] | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	40,000
2016 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	(0.07)
2016 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts HSC Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	0.07
2016 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts CIG Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	(0.30)
2016 [Member] | Henry Hub [Member] | Natural Gas Derivative Contracts TETCO STX Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	0.06
2016 [Member] | Brent | Crude Oil Derivative Contracts Midway-Sunset Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / bbl	(13.35)
2016 [Member] | WTI | Crude Oil Derivative Contracts Midland Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread | $ / 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 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 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	(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	0.14
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	0.03
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] | Henry Hub [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	(0.03)
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	0.15
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] | Henry Hub [Member] | Natural Gas Derivative Contracts NGPL TexOk Basis Swaps [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Spread	0.01

Risk Management and Derivativ46

Risk Management and Derivative Instruments - Interest Rate Swap Open Positions (Detail) - Interest rate swaps [Member] $ in Thousands	9 Months Ended
	Sep. 30, 2015USD ($)
Remaining 2015 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	0.943%
Floating rate	1 Month LIBOR
2016 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	0.943%
Floating rate	1 Month LIBOR
2017 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	1.612%
Floating rate	1 Month LIBOR
2018 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 100,000
Weighted-average fixed rate	1.946%
Floating rate	1 Month LIBOR

Risk Management and Derivativ47

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 231,340	$ 208,585
Asset Derivatives, Net recorded fair value	439,070	311,802
Liability Derivatives, Net recorded fair value	3,515	3,289
Liability Derivatives, Net recorded fair value	3,183
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	269,724	225,882
Asset Derivatives, Netting arrangements	(38,384)	(17,297)
Asset Derivatives, Net recorded fair value	231,340	208,585
Liability Derivatives, Gross fair value	41,899	20,586
Liability Derivatives, Netting arrangements	(38,384)	(17,297)
Liability Derivatives, Net recorded fair value	3,515	3,289
Short-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	269,724	225,882
Liability Derivatives, Gross fair value	39,670	17,297
Short-Term Derivative Instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Liability Derivatives, Gross fair value	2,229	3,289
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	475,037	340,336
Asset Derivatives, Netting arrangements	(35,967)	(28,534)
Asset Derivatives, Net recorded fair value	439,070	311,802
Liability Derivatives, Gross fair value	39,150	28,534
Liability Derivatives, Netting arrangements	(35,967)	(28,534)
Liability Derivatives, Net recorded fair value	3,183
Long-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	475,037	339,031
Liability Derivatives, Gross fair value	36,019	28,534
Long-Term Derivative Instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value		$ 1,305
Liability Derivatives, Gross fair value	$ 3,131

Risk Management and Derivativ48

Risk Management and Derivative Instruments - Unrealized and Realized Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	$ (244,888)	$ (156,402)	$ (328,944)	$ 28,710
Interest expense, net	(31,255)	(26,458)	(87,983)	(60,573)
Commodity derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	(244,888)	(156,402)	(328,944)	28,710
Interest rate derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net	$ 3,543	$ (231)	$ 6,628	$ 860

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period			$ 112,702
Liabilities added from acquisitions or drilling			3,275
Liabilities removed upon sale of wells			(62)
Liabilities settled			(780)
Accretion expense	$ 1,716	$ 1,421	5,036	$ 4,212
Revision of estimates			573
Asset retirement obligations at end of period	$ 120,744		$ 120,744

Restricted Investments - Restri

Restricted Investments - Restricted Investment Balance (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Schedule Of Investments [Line Items]
Restricted investments	$ 81,254	$ 77,361
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	73,488	69,954
BOEM lease bonds [Member]
Schedule Of Investments [Line Items]
Restricted investments	794	794
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	3,060	2,701
SPBPC Collateral Lands Commission pipeline right-of-way bond [Member] | California State
Schedule Of Investments [Line Items]
Restricted investments	3,005	3,005
SPBPC Collateral City of Long Beach pipeline facility permit [Member]
Schedule Of Investments [Line Items]
Restricted investments	500	500
SPBPC Collateral Federal pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	307	307
SPBPC Collateral Port of Long Beach pipeline license [Member]
Schedule Of Investments [Line Items]
Restricted investments	$ 100	$ 100

Long Term Debt - Consolidated D

Long Term Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Unamortized discounts		$ (14,726)	$ (16,587)
Total long-term debt		1,878,264	1,595,413
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Revolving credit facility		696,000	412,000
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Senior Notes, fixed-rate	[1],[2]	700,000	700,000
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Senior Notes, fixed-rate	[1],[3]	$ 496,990	$ 500,000
[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 $469.0 million and $563.5 million at September 30, 2015 and December 31, 2014, respectively.
[3]	The estimated fair value of our 2022 Senior Notes was $303.2 million and $380.0 million at September 30, 2015 and December 31, 2014, respectively.

Long Term Debt - Consolidated52

Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Maturity date	Mar. 19, 2018
Revolving credit facility	$ 2,000,000,000
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Maturity date	May 1, 2021
Estimated fair value of fixed rate debt	$ 469,000,000	$ 563,500,000
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Maturity date	Aug. 1, 2022
Estimated fair value of fixed rate debt	$ 303,200,000	$ 380,000,000

Long Term Debt - Additional Inf

Long Term Debt - Additional Information (Detail) - USD ($)	Nov. 04, 2015	Sep. 30, 2015
Line Of Credit Facility [Line Items]
Letters of credit outstanding		$ 2,100,000
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line Of Credit Facility [Line Items]
Borrowing base		1,300,000,000
Revolving credit facility, maximum borrowing capacity		$ 2,000,000,000
Subsequent Event | OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line Of Credit Facility [Line Items]
Borrowing base	$ 1,180,000,000
Universal Shelf Registration Statement [Member]
Line Of Credit Facility [Line Items]
Universal shelf guarantor subsidiaries ownership percentage		100.00%

Long Term Debt - Borrowing Base

Long Term Debt - Borrowing Base Credit Facility (Detail) $ in Thousands	Sep. 30, 2015USD ($)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line Of Credit Facility [Line Items]
Borrowing base	$ 1,300,000

Long Term Debt - Borrowing Ba55

Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail)	Sep. 30, 2015USD ($)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line Of Credit Facility [Line Items]
Revolving credit facility	$ 2,000,000,000

Long Term Debt - Summary of Wei

Long Term Debt - Summary of Weighted-Average Interest Rates Paid Excluding Commitment Fees on Variable-Rate Debt Obligations (Detail)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	2.14%	2.16%	2.06%	2.08%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Unamortized deferred financing costs		$ 23,631	$ 27,734
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Unamortized deferred financing costs	[1]	4,534	6,468
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[2]	11,722	13,308
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[2]	$ 7,375	$ 7,958
[1]	Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.
[2]	Unamortized deferred financing costs are amortized using the straight line method, which generally approximates the effective interest method.

Long Term Debt - Summary of U58

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Parenthetical) (Detail)	Sep. 30, 2015USD ($)
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 - Addi

Equity and Distributions - Additional Information (Detail) - USD ($)	Feb. 13, 2015	Sep. 09, 2014	Jul. 15, 2014	Sep. 30, 2015	Dec. 31, 2014
Limited Partners Capital Account [Line Items]
Common units amount repurchased under repurchase program				$ 52,813,000
MEMP Repurchase Program [Member]
Limited Partners Capital Account [Line Items]
Stock repurchase program, authorized amount					$ 150,000,000
Common units amount repurchased under repurchase program				$ 52,800,000
Common units repurchased under repurchase program				3,547,921
Amount remaining under repurchase program				$ 81,700,000
Subordinated Units [Member]
Limited Partners Capital Account [Line Items]
Subordinated units converted to common units				(5,360,912)
Subordinated Units [Member] | MRD Holdco [Member]
Limited Partners Capital Account [Line Items]
Subordinated units converted to common units	5,360,912
Conversion of subordinated units, Description				The subordinated units converted on a one-for-one basis into common units upon the payment of MEMP's fourth quarter 2014 distribution.
2014 Public Equity Offerings [Member]
Limited Partners Capital Account [Line Items]
Number of common units issued in public offering		14,950,000	9,890,000
Number of over-allotment common units issued by Partnership		1,950,000	1,290,000
Public offering price per common unit		$ 22.29	$ 22.25
Net proceeds from the issuance of common units		$ 321,300,000	$ 220,000,000

Equity and Distributions - Summ

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Detail)	9 Months Ended
	Sep. 30, 2015shares
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	86,797
Ending balance	86,797
Limited Partners Common Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	80,421,992
Restricted common units issued	815,607
Restricted common units forfeited	(32,876)
Restricted common units repurchased	(87,228)
Common units repurchased under repurchase program	(3,547,921)
Subordinated units converted to common units	5,360,912
Ending balance	82,930,486
Subordinated Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	5,360,912
Subordinated units converted to common units	(5,360,912)
Ending balance	0

Equity and Distributions - Su61

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Parenthetical) (Detail) $ in Thousands	9 Months Ended
	Sep. 30, 2015USD ($)
Summary Of Changes In Number Of Outstanding Units [Abstract]
Withholding tax withheld and paid related to vesting of restricted common units	$ 1,288

Equity and Distributions - Su62

Equity and Distributions - Summary of Quarterly Cash Distribution Rates (Detail) - USD ($)	3 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014
Limited Partners Capital Account [Line Items]
Distribution made to member or limited partner, date of declaration	Oct. 26, 2015	Jul. 24, 2015	Apr. 24, 2015	Jan. 26, 2015	Oct. 23, 2014	Jul. 24, 2014	Apr. 24, 2014
Distribution made to member or limited partner, date of record	Nov. 5, 2015	Aug. 5, 2015	May 6, 2015	Feb. 5, 2015	Nov. 5, 2014	Aug. 5, 2014	May 6, 2014
Distribution made to member or limited partner, date of distribution	Nov. 12, 2015	Aug. 12, 2015	May 13, 2015	Feb. 12, 2015	Nov. 12, 2014	Aug. 12, 2014	May 13, 2014
Distribution per unit	$ 0.3000	$ 0.5500	$ 0.5500	$ 0.5500	$ 0.5500	$ 0.5500	$ 0.5500
Aggregate Distribution	$ 24,900,000	$ 45,700,000	$ 46,300,000	$ 46,300,000	$ 47,800,000	$ 39,500,000	$ 33,800,000
Distribution Received by Affiliates		$ 100,000	$ 200,000	$ 3,100,000	$ 3,100,000	$ 3,000,000	$ 3,000,000
Maximum [Member]
Limited Partners Capital Account [Line Items]
Distribution Received by Affiliates	$ 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		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Earnings Per Unit [Line Items]
Net income (loss) attributable to Memorial Production Partners LP	$ (192,085)	$ 101,157	$ (468,826)	$ (43,418)
Less: Previous owners interest in net income (loss)		(1,919)	(2,268)	1,812
Less: General partner's 0.1% interest in net income (loss)	(198)	103	(483)	(45)
Less: IDRs attributable to corresponding period		56	112	144
Net income (loss) available to limited partners	$ (191,887)	$ 102,917	$ (466,187)	$ (45,329)
Weighted average limited partner units outstanding:
Basic and diluted	82,973	73,815	83,732	65,556
Basic and diluted EPU	$ (2.31)	$ 1.39	$ (5.57)	$ (0.69)
Common Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding	82,973	68,454	82,888	60,195
Subordinated Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding		5,361	844	5,361

Earnings Per Unit - Calculati64

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Parenthetical) (Detail)	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Earnings Per Unit [Line Items]
General partner's interest in net income, percentage		0.10%
MEMP Repurchase Program [Member]
Earnings Per Unit [Line Items]
General partner's interest in net income, percentage	0.105%	0.104%

Equity-based Awards - Summary o

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Detail) - Restricted Stock [Member]	9 Months Ended
	Sep. 30, 2015$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted common units outstanding, Beginning Balance | shares	1,093,520
Granted, Number of Units | shares	815,607
Restricted common units forfeited | shares	(32,876)
Vested, Number of Units | shares	(483,627)
Restricted common units outstanding, Ending Balance | shares	1,392,624
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance	$ 20.93
Granted, Weighted-Average Grant Date Fair Value per Unit	15.04
Forfeited, Weighted-Average Grant Date Fair Value per Unit	19.61
Vested, Weighted-Average Grant Date Fair Value per Unit	20.37
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance	$ 17.70

Equity-based Awards - Summary66

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Stock [Member] $ / shares in Units, $ in Millions	Sep. 30, 2015USD ($)$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted common unit awards issued | $	$ 12.3
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	$ 14.70
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	$ 15.45

Equity-based Awards - Summary67

Equity-based Awards - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Compensation expense	$ 2,993	$ 2,427	$ 7,899	$ 5,387

Equity-based Awards - Additiona

Equity-based Awards - Additional Information (Detail) - Restricted Common Units [Member] $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$ 20
Weighted-average period of unrecognized compensation cost	2 years 11 days

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) $ in Millions	Jul. 02, 2015$ / bbl	May. 31, 2014$ / MMBTU$ / bbl	Nov. 30, 2011MMBTU	Sep. 30, 2015USD ($)	Sep. 30, 2015USD ($)	Feb. 23, 2015USD ($)	Apr. 01, 2014USD ($)
Classic Operating And Classic Pipeline [Member] | Classic Pipeline Gas Gathering Agreement [Member]
Related Party Transaction [Line Items]
Maximum dedication of natural gas produced | MMBTU			50,000
Pipeline transportation agreement expiration year			2,020
Pipeline transportation agreement extension			1 year
Amended gas gathering agreement terms disclosure					Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel
Base gas gathering fee per MMBtu | $ / MMBTU		0.30
Base stage of compression fee per MMBtu | $ / MMBTU		0.07
Annual inflationary escalation, rate		3.50%
Agreement expired, date		Dec. 31, 2023
Classic Operating And Classic Pipeline [Member] | Water Disposal Agreement [Member]
Related Party Transaction [Line Items]
Pipeline water disposal agreement extension		1 year
Water disposal agreement period		3 years
Water disposal fee per barrel | $ / bbl	0.40	1.10
Multi-Shot, LLC [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Drilling and completion expenses				$ 0.1	$ 0.3
Affiliated Entity [Member] | February 2015 Acquisition [Member]
Related Party Transaction [Line Items]
Effective date of acquisition common control					Jan. 1, 2015
Common Control Acquisition Purchase Price						$ 78.4
Affiliated Entity [Member] | April 2014 Acquisition [Member]
Related Party Transaction [Line Items]
Effective date of acquisition common control					Apr. 1, 2014
Common Control Acquisition Purchase Price							$ 33.3
Memorial Resource [Member]
Related Party Transaction [Line Items]
Amount receivable under management agreement				$ 0.4	$ 0.4

Related Party Transactions - Sc

Related Party Transactions - Schedule of Net Assets Recorded by Partnership (Detail) - Property Swap [Member] - USD ($) $ in Thousands	Feb. 23, 2015	Apr. 01, 2014
February 2015 Acquisition [Member]
Related Party Transaction [Line Items]
Accounts receivable	$ 2,372
Other receivables	5,478
Prepaid expenses and other current assets	1,874
Property and equipment, net	263,210
Accounts payable	(3,586)
Accounts payable - affiliate	(1,290)
Revenues payable	(1,110)
Accrued liabilities	(11,347)
Asset retirement obligations	(4,559)
Net assets	$ 251,042
April 2014 Acquisition [Member]
Related Party Transaction [Line Items]
Property and equipment, net		$ 37,838
Asset retirement obligations		(908)
Other current liabilities		(722)
Net assets		$ 36,208

Related Party Transactions - 71

Related Party Transactions - Schedule of Amount of General and Administrative Costs and Expenses Recognized (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
General and administrative costs and expenses under omnibus agreement	$ 8,439	$ 6,528	$ 25,448	$ 16,787

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Environmental reserves liability	$ 0.6	$ 2.1
Maximum remaining obligation	$ 5.2

Commitments and Contingencies73

Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) $ in Thousands	Sep. 30, 2015USD ($)
Held-to-maturity Securities [Abstract]
Amortized Cost	$ 73,488
Less: Outside working interest owners share	(68,517)
U.S. Bank Money Market Cash Equivalent [Member]
Held-to-maturity Securities [Abstract]
Amortized Cost	$ 142,005

Commitments and Contingencies74

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

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) $ in Thousands	Nov. 03, 2015USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Dec. 31, 2012WellPlatformmiin
Subsequent Event [Line Items]
Acquisitions of oil and natural gas properties		$ 6,095	$ 1,083,167
November 2015 Beta Acquisition [Member]
Subsequent Event [Line Items]
Working interest				48.25%
Number of gross wells acquired | Well				58
Number of combined production and drilling platforms acquired | Platform				2
Number of production processing platforms acquired | Platform				1
Length of oil pipeline acquired | mi				17.5
Diameter of oil pipeline acquired | in				16
Business acquisition description				We first acquired our interests in the Beta properties in December 2012. The acquired interests primarily consist of the 48.25% remaining working interests in three Pacific Outer Continental Shelf blocks in the Beta Field, which includes 58 gross wells, that are located in federal waters approximately eleven miles offshore the Port of Long Beach, California. The acquired interests also include the 48.25% remaining interest in associated facilities including (i) two combined production and drilling platforms (ii) one production processing platform, (iii) a 17.5 mile long 16-inch diameter oil pipeline and (iv) an onshore pump station, tankage and metering facility.
Subsequent Event | November 2015 Beta Acquisition [Member]
Subsequent Event [Line Items]
Acquisitions of oil and natural gas properties	$ 101,000