Amplify Energy (AMPYW) 10-Q 2 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 28, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2,016
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		83,831,331

UNAUDITED CONDENSED CONSOLIDATE

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 15,845	$ 599
Accounts receivable	38,695	60,239
Short-term derivative instruments	154,840	272,320
Prepaid expenses and other current assets	9,504	7,028
Total current assets	218,884	340,186
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	3,111,123	3,616,325
Support equipment and facilities	198,861	205,876
Other	15,080	2,671
Accumulated depreciation, depletion and impairment	(1,535,043)	(1,878,549)
Property and equipment, net	1,790,021	1,946,323
Long-term derivative instruments	300,695	461,810
Restricted investments	158,273	152,631
Other long-term assets	5,867	5,053
Total assets	2,473,740	2,906,003
Current liabilities:
Accounts payable	7,194	8,792
Accounts payable - affiliates	0	3,339
Revenues payable	25,941	25,504
Accrued liabilities (Note 2)	60,797	52,923
Short-term derivative instruments	2,135	2,850
Total current liabilities	96,067	93,408
Long-term debt (Note 7)	1,798,895	2,000,579
Asset retirement obligations	150,829	162,989
Long-term derivative instruments	1,072	1,441
Deferred tax liabilities	2,223	2,094
Other long-term liabilities	4,129	0
Total liabilities	2,053,215	2,260,511
Commitments and contingencies (Note 12)
Partners' equity:
General partner (86,797 units outstanding at December 31, 2015)	0	848
Total partners' equity	420,525	645,492
Total liabilities and equity	2,473,740	2,906,003
Limited Partners Common Units [Member]
Partners' equity:
Limited partners units	420,525	644,644
Total partners' equity	$ 420,525	$ 644,644

UNAUDITED CONDENSED CONSOLIDAT3

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Sep. 30, 2016	Dec. 31, 2015
General partner, units outstanding	0	86,797
Limited Partners Common Units [Member]
Limited partners, units outstanding	83,838,320	82,906,400

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, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues:
Oil & natural gas sales	$ 74,222	$ 87,519	$ 202,625	$ 276,689
Other revenues	0	564	529	2,350
Total revenues	74,222	88,083	203,154	279,039
Costs and expenses:
Lease operating	31,575	45,416	96,625	130,782
Gathering, processing, and transportation	8,519	8,595	26,551	26,809
Exploration	12	2,141	149	2,263
Taxes other than income	3,945	6,896	11,438	19,609
Depreciation, depletion, and amortization	43,219	53,305	132,061	150,857
Impairment of proved oil and natural gas properties	0	361,836	8,342	613,183
General and administrative	12,605	13,910	41,375	42,798
Accretion of asset retirement obligations	2,383	1,716	7,802	5,036
(Gain) loss on commodity derivative instruments	(21,938)	(244,888)	50,897	(328,944)
(Gain) loss on sale of properties	60	0	(3,575)	0
Other, net	178		245	(943)
Total costs and expenses	80,558	248,927	371,910	661,450
Operating income (loss)	(6,336)	(160,844)	(168,756)	(382,411)
Other income (expense):
Interest expense, net	(27,209)	(31,255)	(91,904)	(88,405)
Other income (expense)	6	11	6	295
Gain on extinguishment of debt	673		42,337	422
Total other income (expense)	(26,530)	(31,244)	(49,561)	(87,688)
Income (loss) before income taxes	(32,866)	(192,088)	(218,317)	(470,099)
Income tax benefit (expense)	0	107	(196)	1,601
Net income (loss)	(32,866)	(191,981)	(218,513)	(468,498)
Net income (loss) attributable to noncontrolling interest	0	104	0	328
Net income (loss) attributable to Memorial Production Partners LP	(32,866)	(192,085)	(218,513)	(468,826)
Limited partners' interest in net income (loss):
Net income (loss) attributable to Memorial Production Partners LP	(32,866)	(192,085)	(218,513)	(468,826)
Net (income) loss allocated to previous owners	0		0	2,268
Net (income) loss allocated to general partner	0	174	168	402
Net (income) loss allocated to NGP IDRs	0	(27)	0	(83)
Limited partners' interest in net income (loss)	$ (32,866)	$ (191,938)	$ (218,345)	$ (466,239)
Earnings per unit: (Note 9)
Basic and diluted earnings per unit	$ (0.39)	$ (2.31)	$ (2.62)	$ (5.57)
Weighted average limited partner units outstanding:
Basic and diluted	83,621	82,973	83,189	83,732

UNAUDITED CONDENSED STATEMENTS5

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities:
Net income (loss)	$ (218,513)	$ (468,498)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	132,061	150,857
Impairment of proved oil and natural gas properties	8,342	613,183
(Gain) loss on derivative instruments	54,991	(322,316)
Cash settlements (paid) received on expired derivative instruments	183,221	175,703
Cash settlements on terminated commodity derivatives	39,299	27,063
Premiums paid for commodity derivatives	0	(27,063)
Bad debt expense	1,601	0
Deferred income tax expense (benefit)	129	(1,789)
Amortization of deferred financing costs	3,862	4,375
Gain on extinguishment of debt	(42,337)	(422)
Accretion of senior notes net discount	1,769	1,818
Accretion of asset retirement obligations	7,802	5,036
Unit-based compensation (see Note 10)	7,370	7,899
Settlement of asset retirement obligations	(1,099)	(780)
Exploration costs	0	2,078
Gain on sale of properties	(3,575)	0
Changes in operating assets and liabilities:
Accounts receivable	20,873	17,629
Prepaid expenses and other assets	(833)	(162)
Payables and accrued liabilities	931	323
Other	3,253	638
Net cash provided by operating activities	199,147	185,572
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	0	(6,095)
Acquisition post-closing adjustments receipts	0	9,570
Additions to oil and gas properties	(50,534)	(196,055)
Additions to other property and equipment	(7,611)	0
Additions to restricted investments	(5,642)	(3,893)
Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold	54,724	0
Net cash used in investing activities	(9,063)	(196,473)
Cash flows from financing activities:
Advances on revolving credit facilities	144,000	345,000
Payments on revolving credit facilities	(266,000)	(61,000)
Deferred financing costs	(1,350)	(319)
Repurchase of senior notes	(41,261)	(2,914)
Capital contributions from previous owners	0	1,912
Contributions related to sale of assets to NGP affiliate	26	0
Transfer of operating subsidiary from Memorial Resource	2,363	0
Proceeds from the issuance of common units	2,385	0
Costs incurred in conjunction with issuance of common units	(312)	0
Distributions to partners	(13,300)	(138,349)
Distribution to Memorial Resource (see Note 1)	0	(78,396)
Acquisition of General Partner (see Note 1)	(750)	0
Acquisition of IDRs from NGP (see Note 1)	(50)	0
Restricted units returned to plan	(589)	(1,288)
Repurchases under unit repurchase program	0	(54,184)
Net cash (used in) provided by financing activities	(174,838)	10,462
Net change in cash and cash equivalents	15,246	(439)
Cash and cash equivalents, beginning of period	599	970
Cash and cash equivalents, end of period	$ 15,845	$ 531

UNAUDITED CONDENSED STATEMENTS6

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY - 9 months ended Sep. 30, 2016 - USD ($) $ in Thousands	Total	Limited Partners Common Units [Member]	General Partner [Member]
Balance at Dec. 31, 2015	$ 645,492	$ 644,644	$ 848
Net income (loss)	(218,513)	(218,345)	(168)
Distributions	(13,300)	(13,289)	(11)
Purchase of equity interest of general partner (Note 1)	(750)	(81)	(669)
Acquisition of IDRs from NGP (Note 1)	(50)	(50)	0
Net proceeds from issuance of common units	2,073	2,073	0
Amortization of unit-based awards	6,134	6,134	0
Restricted units repurchased and other	(561)	(561)	0
Balance at Sep. 30, 2016	$ 420,525	$ 420,525	$ 0

Organization and Basis of Prese

Organization and Basis of Presentation	9 Months Ended
	Sep. 30, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation General Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries. We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as the economic environments are not different within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Wyoming and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. Unless the context requires otherwise, references to: (i) “our general partner” or “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner and wholly-owned subsidiary; (ii) “Memorial Resource” refer collectively to Memorial Resource Development Corp. and its subsidiaries; (iii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (iv) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (v) “Finance Corp.” refer to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; and (vi) “NGP” refer to Natural Gas Partners. On April 27, 2016, we entered into an agreement pursuant to which the Partnership agreed to acquire, among other things, all of the equity interests in our general partner, MEMP GP, from Memorial Resource (the “MEMP GP Acquisition”) for cash consideration of approximately $0.8 million. MEMP GP held an approximate 0.1% general partner interest and 50% of the incentive distribution rights ("IDRs") in us. In conjunction with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with an NGP affiliate pursuant to which we agreed to acquire the other 50% of the IDRs. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition. In connection with the closing of the transactions on June 1, 2016, our partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Partnership held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Partnership will elect the members of MEMP GP’s board of directors beginning with the annual meeting in 2017. In addition, we terminated the omnibus agreement under which Memorial Resource provided management, administrative and operations personnel to us and our general partner, and we entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 11 and Note 12 for additional information regarding the MEMP GP Acquisition and the transition services agreement. Liquidity As of September 30, 2016, we were in compliance with our financial covenants under our revolving credit facility. Effective October 28, 2016, in connection with the semi-annual borrowing redetermination by the lenders under our revolving credit facility, the borrowing base under our revolving credit facility was reduced to $740.0 million and will automatically be further reduced to $720.0 million on December 1, 2016. With our borrowing base at such levels, we will have limited to no available borrowing capacity and will likely be unable to remain in compliance with certain financial covenants under our revolving credit facility as early as the fourth quarter of 2016. In addition, if we are unable to remain in compliance with the covenants under our revolving credit facility or the indentures governing our senior notes, or a cross-default occurs under either, absent relief from our lenders or noteholders, as applicable, we may be forced to repay or refinance such indebtedness and we may incur other damages. Upon the occurrence of an event of default, the lenders under our revolving credit facility or holders of our senior notes, as applicable, could elect to declare all amounts outstanding immediately due and payable or seek other remedies and the lenders could terminate all commitments to extend further credit under our revolving credit facility. If an event of default occurs under our revolving credit facility or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding or seek other remedies, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. We might also be required to seek relief under the Bankruptcy Code. See Note 7 for more information. 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. The Property Swap was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information were retrospectively revised to give effect to the Property Swap as if the Partnership owned the assets for periods after common control commenced through the acquisition date. Basis of Presentation Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements of the previous owners were derived from their historical accounting records and reflect their historical financial position, results of operations and cash flows. The inclusion of MEMP GP in our consolidated financial statements was effective June 1, 2016 due to the MEMP GP Acquisition. See Note 11 for more information. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Our results of operations for the three and nine months ended September 30, 2016 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the SEC. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Use of Estimates The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies A discussion of our significant accounting policies and estimates is included in our 2015 Form 10-K. Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): September 30, December 31, 2016 2015 Accrued interest payable $ 26,063 $ 23,192 Accrued lease operating expense 12,364 16,843 Accrued capital expenditures 7,622 8,110 Accrued general and administrative expenses 5,130 1,961 Accrued ad valorem tax 3,879 1,426 Asset retirement obligation 830 1,175 Environmental liability — 216 Other 4,909 — $ 60,797 $ 52,923 Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Nine Months Ended September 30, 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 80,446 $ 75,378 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (488 ) (6,937 ) (Increase) decrease in accounts receivable related to acquisitions — 9,570 (Increase) decrease in accounts receivable/payable related to divestitures 856 — Asset retirement obligation removal related to divestitures (19,591 ) — Restricted units returned to plan — 3 New Accounting Pronouncements Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments. In August 2016, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to address eight specific cash flow issues with the objective of reducing the current and potential future diversity in practice. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involves several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, entities will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required. The new guidance is effective for reporting periods beginning after December 15, 2016 and interim periods within those fiscal years. Early adoption is permitted, but all of the guidance must be adopted in the same period. For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. Entities should apply the new guidance retrospectively for all periods presented related to the classification of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirements. Entities may apply the presentation changes for excess tax benefits in the statement of cash flows either prospectively or retrospectively. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Leases. In February 2016, the FASB issued a revision to lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The revised guidance must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Partnership is currently evaluating the standard and the impact on the consolidated financial statements and related footnote disclosures. Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. In April 2015, the FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method are also required. The guidance was effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. We adopted this guidance on January 1, 2016. Since the Partnership has historically allocated the earnings (losses) of transferred businesses that occurred in periods before the date of the dropdown transaction entirely to affiliates of the general partner (i.e., the previous owners) and did not adjust previously reported earnings per unit of the limited partners, the impact of adopting this guidance was not material to the Partnership’s financial statements and related disclosures. Revenue from Contracts with Customers. In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. The guidance is effective for interim and annual reporting periods beginning after December 15, 2017, and early adoption is permitted. The new standard permits adoption through the use of either the full retrospective approach or a modified retrospective approach. The Partnership is currently evaluating the standard and the impact on the consolidated financial statements and related footnote disclosures. Presentation of Financial Statements — Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern . In August 2014, the FASB issued an accounting standards update that requires management to perform interim and annual assessments of whether there are conditions or events that raise substantial doubt of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. Certain disclosures are required if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, and with early adoption permitted. The amendments will not impact our financial position or results of operations but will require management to perform a formal going concern assessment. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated 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, 2016
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Related Party Acquisitions See Note 11 for further information regarding related party acquisitions that have been accounted for as transactions between entities under common control that impact the basis of presentation for the periods presented. Acquisition and Divestiture related Expenses Acquisition and divestiture related expenses 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, 2016 2015 2016 2015 $ 416 $ 16 $ 1,429 $ 1,612 2015 Acquisitions On November 3, 2015, we closed a transaction to acquire the noncontrolling interest in San Pedro Bay Pipeline Company (“SPBPC”) and the remaining interests in our oil and gas properties offshore Southern California (the “Beta Properties”) from a third party (the “2015 Beta Acquisition”), which was discussed in our 2015 Form 10-K. The following unaudited pro forma combined results of operations are provided for the three and nine months ended September 30, 2015 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical consolidated and combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, (iii) accretion expense associated with asset retirement obligations recorded and (iv) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Three Months Ended For the Nine Months Ended September 30, September 30, 2015 2015 (In thousands, except per unit amounts) Revenues $ 94,497 $ 300,346 Net income (loss) (191,710 ) (463,823 ) Basic and diluted earnings per unit (2.31 ) (5.52 ) Divestitures On July 14, 2016, we closed a transaction to divest assets located in Colorado and Wyoming (the “Rockies Divestiture”) for a total proceeds of approximately $16.9 million, including estimated post-closing adjustments, which included $18.1 million in cash and $1.3 million in accounts payable. We recorded a loss of approximately $3.9 million in “(gain) loss on sale of properties” in the accompanying statement of operations. The proceeds from this transaction were used to reduce borrowings under our revolving credit facility. This disposition does not qualify as a discontinued operation. On June 14, 2016, we closed a transaction to divest assets located in the Permian Basin (the “Permian Divestiture”) for a total purchase price of approximately $36.9 million including estimated post-closing adjustments, which included $36.4 million in cash and $0.5 million in accounts receivable. We recognized a gain of $6.5 million on the sale of properties related to the Permian Divestiture in “(gain) loss on sale of properties” in the accompanying statement of operations. The proceeds from this transaction were used to reduce borrowings under our revolving credit facility. This disposition does not qualify as a discontinued operation. During the nine months ended September 30, 2016, the Partnership completed other immaterial divestitures for which we recorded a gain of $0.9 million on the sale that is recorded in “(gain) loss on sale of properties” in the accompanying statement of operations. The income (loss) before income taxes, including the associated (gain) loss on sale of properties, related to the Permian Divestiture and Rockies Divestiture included in the unaudited condensed statements of consolidated and combined operations of the Partnership is as follows (in thousands): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Permian Divestiture $ (40 ) $ (56,078 ) $ 4,792 $ (62,312 ) Rockies Divestiture 445 (111 ) (7,175 ) (55,844 )

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. The carrying values of accounts receivables, accounts payables (including accrued liabilities), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at September 30, 2016 and December 31, 2015. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 7 for the estimated fair value of our outstanding fixed-rate debt. Assets and Liabilities Measured at Fair Value on a Recurring Basis The fair market values of the derivative financial instruments reflected on the balance sheets as of September 30, 2016 and December 31, 2015 were based on estimated forward commodity prices and forward interest rate yield curves. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2016 and December 31, 2015 for each of the fair value hierarchy levels: Fair Value Measurements at September 30, 2016 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 494,081 $ — $ 494,081 Interest rate derivatives — — — — Total assets $ — $ 494,081 $ — $ 494,081 Liabilities: Commodity derivatives $ — $ 36,518 $ — $ 36,518 Interest rate derivatives — 5,235 — 5,235 Total liabilities $ — $ 41,753 $ — $ 41,753 Fair Value Measurements at December 31, 2015 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 816,995 $ — $ 816,995 Interest rate derivatives — — — — Total assets $ — $ 816,995 $ — $ 816,995 Liabilities: Commodity derivatives $ — $ 84,501 $ — $ 84,501 Interest rate derivatives — 2,655 — 2,655 Total liabilities $ — $ 87,156 $ — $ 87,156 See Note 5 for additional information regarding our derivative instruments. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: • The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs. • If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. • Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, estimates of probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties. • During the nine months ended September 30, 2016, we recognized approximately $8.3 million of impairments related to certain properties located in East Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. The carrying value of the East Texas properties after the impairment was approximately $11.0 million. 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 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, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments	Note 5. Risk Management and Derivative Instruments Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease. Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $267.0 million against amounts outstanding under our revolving credit facility at September 30, 2016, reducing our maximum credit exposure to approximately $188.7 million, of which approximately $59.9 million was with one counterparty. See Note 7 for additional information regarding our revolving credit facility. Commodity Derivatives We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our put option derivative instruments have a deferred premium, which reduces the asset. For the deferred premium puts, the Partnership agrees to pay a premium to the counterparty at the time of settlement. At settlement, if the applicable index price is below the strike price of the put, the Partnership receives the difference between the strike price and the applicable index price multiplied by the contract volumes less the premium. If the applicable index price settles at or above the strike price of the put, the Partnership pays only the premium at settlement. During the nine months ended September 30, 2016, we terminated certain “in-the-money” crude oil and NGL derivatives settling in 2016 and certain crude oil basis swaps settling in 2016 and 2017. We received cash settlements of approximately $39.3 million from the termination of these crude oil and NGL derivatives. During the nine months ended September 30, 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 these crude oil derivatives were applied as premiums for the new NGL derivatives. We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, CIG and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX-WTI, ICE Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At September 30, 2016, we had the following open commodity positions: Remaining 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,565,775 3,350,067 3,060,000 2,814,583 Weighted-average fixed price $ 4.14 $ 4.06 $ 4.18 $ 4.31 Basis swaps: Average Monthly Volume (MMBtu) 3,555,000 2,210,000 1,315,000 900,000 Spread $ (0.07 ) $ (0.04 ) $ (0.02 ) $ 0.01 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 184,313 301,600 312,000 160,000 Weighted-average fixed price $ 74.27 $ 85.00 $ 83.74 $ 85.52 Basis swaps: Average Monthly Volume (Bbls) 99,000 37,500 — — Spread $ (12.28 ) $ (12.20 ) $ — $ — Purchased put option contracts: Average Monthly Volume (Bbls) 60,000 — — — Weighted-average strike price $ 40.00 $ — $ — $ — Weighted-average deferred premium $ (0.86 ) $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 195,100 43,300 — — Weighted-average fixed price $ 34.01 $ 37.55 $ — $ — Our basis swaps included in the table above are presented on a disaggregated basis below: Remaining 2016 2017 2018 2019 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 2,980,000 1,800,000 1,200,000 900,000 Spread-Henry Hub $ (0.07 ) $ (0.07 ) $ (0.03 ) $ 0.01 HSC basis swaps: Average Monthly Volume (MMBtu) 135,000 115,000 115,000 — Spread-Henry Hub $ 0.07 $ 0.14 $ 0.15 $ — CIG basis swaps: Average Monthly Volume (MMBtu) 170,000 — — — Spread-Henry Hub $ (0.30 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 270,000 295,000 — — Spread-Henry Hub $ 0.06 $ 0.03 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 99,000 37,500 — — Spread - Brent $ (12.28 ) $ (12.20 ) $ — $ — 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, 2016, we had the following interest rate swap open positions: Remaining 2016 2017 2018 Average Monthly Notional (in thousands) $ 400,000 $ 400,000 $ 300,000 Weighted-average fixed rate 0.943 % 1.612 % 1.427 % Floating rate 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR Balance Sheet Presentation The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2016 and December 31, 2015. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives September 30, December 31, September 30, December 31, Type Balance Sheet Location 2016 2015 2016 2015 (In thousands) Commodity contracts Short-term derivative instruments $ 186,168 $ 324,265 $ 30,132 $ 53,581 Interest rate swaps Short-term derivative instruments — — 3,331 1,214 Gross fair value 186,168 324,265 33,463 54,795 Netting arrangements Short-term derivative instruments (31,328 ) (51,945 ) (31,328 ) (51,945 ) Net recorded fair value Short-term derivative instruments $ 154,840 $ 272,320 $ 2,135 $ 2,850 Commodity contracts Long-term derivative instruments $ 307,913 $ 492,730 $ 6,386 $ 30,920 Interest rate swaps Long-term derivative instruments — — 1,904 1,441 Gross fair value 307,913 492,730 8,290 32,361 Netting arrangements Long-term derivative instruments (7,218 ) (30,920 ) (7,218 ) (30,920 ) Net recorded fair value Long-term derivative instruments $ 300,695 $ 461,810 $ 1,072 $ 1,441 (Gains) Losses on Derivatives We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands): For the Three Months Ended For the Nine Months Ended Statements of September 30, September 30, Operations Location 2016 2015 2016 2015 Commodity derivative contracts (Gain) loss on commodity derivatives $ (21,938 ) $ (244,888 ) $ 50,897 $ (328,944 ) Interest rate derivatives Interest expense, net (1,432 ) 3,543 4,094 6,628

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. Asset Retirement Obligations The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2016 (in thousands): Asset retirement obligations at beginning of period $ 164,164 Liabilities added from acquisitions or drilling 30 Liabilities removed upon sale of wells (19,591 ) Liabilities settled (1,099 ) Accretion expense 7,802 Revision of estimates 353 Asset retirement obligations at end of period 151,659 Less: Current portion (830 ) Asset retirement obligations - long-term portion $ 150,829

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Long-Term Debt	Note 7. Long-Term Debt The following table presents our consolidated debt obligations at the dates indicated: September 30, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 714,000 $ 836,000 2021 Senior Notes, fixed-rate, due May 2021 (2) (4) 646,287 700,000 2022 Senior Notes, fixed-rate, due August 2022 (3) (4) 464,965 496,990 Senior notes debt issuance costs, net (14,940 ) (18,297 ) Unamortized discounts (11,417 ) (14,114 ) Total long-term debt $ 1,798,895 $ 2,000,579 (1) The carrying amount of our revolving credit facility approximates fair value because the interest rates are variable and reflective of market rates. (2) The estimated fair value of our 2021 Senior Notes was $329.6 million and $210.0 million at September 30, 2016 and December 31, 2015, respectively. (3) The estimated fair value of our 2022 Senior Notes was $232.5 million and $149.1 million at September 30, 2016 and December 31, 2015, respectively. (4) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. Subsidiary Guarantors Our outstanding debt securities are, and any debt securities issued in the future will likely be, jointly and severally, fully and unconditionally guaranteed (subject to customary release provisions) by certain of the Partnership’s subsidiaries (collectively, the “Guarantor Subsidiaries”). The Guarantor Subsidiaries are 100% owned by the Partnership. The Partnership has no material assets or operations independent of the Guarantor Subsidiaries and there are no significant restrictions upon the ability of the Guarantor Subsidiaries to distribute funds to the Partnership. OLLC Revolving Credit Facility OLLC is a party to a $2.0 billion revolving credit facility, which is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries). On April 14, 2016, we entered into a tenth amendment to our credit agreement, dated as of December 14, 2011 (as previously amended, the “Credit Agreement”), by and among the Partnership, OLLC, the administrative agent and the other agents and lenders party thereto (the “Tenth Amendment”). The Tenth Amendment, among other things, amended the Credit Agreement to: • establish a new Applicable Margin (as defined in the Credit Agreement) that ranges from 1.25% to 2.25% per annum (based on borrowing base usage) on alternate base rate loans and from 2.25% to 3.25% per annum (based on borrowing base usage) on Eurodollar or LIBOR loans and sets the committee fee for the unused portion of the borrowing base to 0.50% per annum regardless of the borrowing base usage; • reduce the borrowing base thereunder from $1,175 million to $925 million; • require the Partnership to maintain a ratio of Consolidated First Lien Net Secured Debt (as defined in the Credit Agreement) to Consolidated EBITDAX (as defined in the Credit Agreement) of not greater than 3.25 to 1.00 as of the end of each fiscal quarter; • permit the issuance by the Partnership of secured second lien notes solely in exchange for the Partnership’s outstanding senior unsecured notes pursuant to one or more senior debt exchanges; provided that, among other things: (i) such debt shall be (A) in an aggregate principal amount not to exceed $600 million (plus any principal representing payment of interest in kind) and (B) such debt is subject to an intercreditor agreement at all times; and (ii) such debt shall not (A) have any scheduled principal amortization or have a scheduled maturity date or a date of mandatory redemption in full prior to 180 days after March 19, 2018, or (B) not contain any covenants or events of default that are more onerous or restrictive than those set forth in the Credit Agreement other than covenants or events of default that are contained in the Partnership’s existing senior unsecured notes and (C) the Consolidated Net Interest Expense (as defined in the Credit Agreement) for the 12-month period following the exchange, after giving pro forma effect to the exchange, shall be no greater than the Consolidated Net Interest Expense for such period had the exchange not occurred; • permit the payment by the Partnership of cash distributions to its equity holders out of available cash in accordance with its partnership agreement so long as, among other things, the pro forma Availability (as defined in the Credit Agreement) shall be not less than the greater of $75 million or (x) 10% of the borrowing base then in effect with respect to any such distributions made prior to June 1, 2016 or (y) 15% of the borrowing base then in effect with respect to any such distributions made on or after June 1, 2016; provided that the aggregate amount of all such payments made in any fiscal quarter for which the ratio of the Partnership’s total debt at the time of such payment to its Consolidated EBITDAX for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available is greater than or equal to 4.00 to 1.00 will not exceed $4.15 million during such fiscal quarter; • permit the repurchase of the Partnership’s (i) outstanding senior unsecured notes, or if any, second lien debt with proceeds from Swap Liquidations (as defined in the Credit Agreement) or the sale or other disposition of oil and gas properties and (ii) outstanding senior unsecured notes with the proceeds from the release of cash securing certain governmental obligations located in the Beta Field offshore Southern California, provided that, among other things, (A) the pro forma Availability is not less than the greater of $75 million or (x) 10% of the borrowing base then in effect through May 31, 2016 or (y) 15% of the borrowing base then in effect on or after June 1, 2016, (B) the Partnership’s pro forma ratio of Consolidated First Lien Net Secured Debt to Consolidated EBITDAX is not greater than 3.00 to 1.00, and (C) the amount of proceeds from all Swap Liquidations and sales or other dispositions of oil and gas properties used to repurchase outstanding senior unsecured notes or secured second lien notes does not exceed $40 million in the aggregate, or in the case of the release of cash securing such obligations, the amount of proceeds used to repurchase outstanding senior unsecured notes does not exceed $60 million in the aggregate; • require that the oil and gas properties of the Partnership mortgaged as collateral security for the loans under the Credit Agreement represent not less than 90% of the total value of the oil and gas properties of the Partnership evaluated in the most recently completed reserve report; and • require the Partnership, in the event that at the close of any business day the aggregate amount of any unrestricted cash or cash equivalents exceeds $25 million in the aggregate, to prepay the loans under the Credit Agreement and cash collateralize any letter of credit exposure with such excess. We incurred approximately $1.0 million in fees related to the Tenth Amendment which are included as deferred financing costs within “Other long-term assets” in the accompanying balance sheet. 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, 2016 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 925,000 Subsequent Event On October 28, 2016, we entered into an eleventh amendment to our credit agreement, dated as of December 14, 2011 (as previously amended, the “Credit Agreement”), by and among the Partnership, OLLC, the administrative agent and the other agents and lenders party thereto (the “Eleventh Amendment”). The Eleventh Amendment, among other things, (i) pursuant to a regularly-scheduled semi-annual redetermination of the borrowing base, decreases the borrowing base from $925 million to $740 million, effective as of October 28, 2016, and schedules a further decrease of the borrowing base to $720 million, effective as of December 1, 2016 and (ii) amends the Credit Agreement to add a new event of default limiting the Partnership’s, OLLC and their respective subsidiaries’ ability to call, make or offer to make any redemption of, or make any other payments in respect of the Partnership’s senior unsecured notes if, on a pro forma basis, the Partnership’s and its subsidiaries’ aggregate liquidity (unrestricted cash and cash equivalents plus amounts available to be drawn under the Credit Agreement), is less than $30 million. See Note 1 for additional information regarding liquidity. 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, 2016 2015 2016 2015 OLLC revolving credit facility (1) 3.57 % 2.14 % 3.11 % 2.06 % (1) As noted in our 2015 Form 10-K, the Applicable Margin (as defined in our revolving credit facility), or credit spread, varies based on the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect). The Applicable Margin for the three months and nine months ended for September 30, 2016 was 3.00% and 2.62%, respectively. The Applicable Margin for the three months and nine months ended September 30, 2015, was 1.95% and 1.86%, respectively. 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, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 3,304 $ 3,672 2021 Senior Notes (2) 8,960 11,194 2022 Senior Notes (2) 5,980 7,103 Total $ 18,244 $ 21,969 (1) Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility. (2) Unamortized deferred financing costs are amortized using the straight line method, which generally approximates the effective interest method. Letters of Credit At September 30, 2016, we had $2.4 million of letters of credit outstanding, all related to operations at our Wyoming properties. Repurchases of Senior Notes During the three and nine months ended September 30, 2016, the Partnership repurchased on the open market an aggregate principal amount of approximately $1.5 million and $53.7 million, respectively, of its 7.625% senior notes due May 2021. During the nine months ended September 30, 2016, the Partnership repurchased on the open market an aggregate principal amount of $32.0 million of its 6.875% senior notes due August 2022. In connection with the repurchases, the Partnership paid approximately $0.8 million and $41.3 million for the three and nine months ended September 30, 2016, respectively. We recorded a gain on extinguishment of debt of approximately $0.7 million and $42.3 million for the three and nine months ended September 30, 2016, respectively. During the nine months ended September 30, 2015, the Partnership repurchased on the open market approximately $3.0 million of its 6.875% senior notes due August 2022. In connection with the repurchase, the Partnership paid approximately $2.6 million and recorded a gain on extinguishment of debt of approximately $0.4 million for the nine months ended September 30, 2015. Subsequent Event In addition, we elected to defer an approximately $24.6 million interest payment due on November 1, 2016 with respect to the 2021 Senior Notes. The interest payment is subject to a 30-day grace period under the indenture. After the grace period, the failure to pay interest would constitute a default and an event of default under our indentures. During the 30-day grace period, we expect to continue working with our noteholders regarding an effort to develop a comprehensive plan to de-lever the Partnership and strengthen our balance sheet. Failure to pay interest on the 2021 Senior Notes on November 1, 2016 constituted a default and an event of default under our revolving credit facility, which default was waived by the lenders under our revolving credit facility. On November 1, 2016, the Partnership, OLLC, certain subsidiaries of the Partnership, the administrative agent, and the lenders consenting thereto entered into the limited waiver and twelfth amendment (the “Waiver and Twelfth Amendment”) to the Credit Agreement. Pursuant to the Waiver and Twelfth Amendment, the requisite lenders under the Credit Agreement agreed to the limited waiver of certain defaults and events of default that will occur under the Credit Agreement as a result of the Partnership’s and Finance Corp’s (collectively, the “Issuers”) election to avail themselves of the 30-day grace period under the indenture governing the Issuers’ 7.625% Senior Notes due May 2021 for the payment of the semi-annual interest payment in respect of such senior notes due November 1, 2016. Pursuant to the Waiver and Twelfth Amendment, from the date thereof until November 30, 2016 (the “Waiver Period”), the Partnership and OLLC agree to pay 100% of the net cash proceeds from any asset sale, transfer or other disposition (including with respect to notes receivable and accounts receivable) and from the liquidation of any swap transaction or hedge transaction arising under swap or hedge agreements between or among the Partnership, OLLC and/or any other loan party and any lender under the Credit Agreement and/or its affiliates, in each case, to the administrative agent for the ratable account of each lender under the Credit Agreement, for application to the outstanding loans under the Credit Agreement. Amounts so applied will also reduce the aggregate commitments of the lender under the Credit Agreement by an equivalent amount. Further, pursuant to the Waiver and Twelfth Amendment, the Partnership and OLLC agree, during the Waiver Period, to additional restrictive covenants. These restrictions further limit, until the expiration of the Waiver Period, the ability of, among other things, the Partnership, OLLC and certain of their respective subsidiaries from incurring additional indebtedness, creating liens on assets, paying certain dividends and distributions, making any optional or voluntary payments or redemptions in respect of any other indebtedness, making investments (including in respect of the creation of subsidiaries), entering into certain lease agreements, entering into certain business combinations, entering into any sale-leaseback transaction and entering into certain transactions with affiliates. A failure to comply with these restrictions could result in an event of default under the Credit Agreement. In the event of the occurrence of any such event of default, the debtor’s obligations under the Credit Agreement could, under certain circumstances, become immediately due and payable. Finally, pursuant to the Waiver and Twelfth Amendment, the Partnership and OLLC agreed to amend, to be effective from and after the date of the Waiver and Twelfth Amendment, the Credit Agreement to increase, from 90% to 95% (or such lesser amount agreed to by the administrative agent in its sole discretion, which lesser amount shall not be less than 92%), the percentage of the total value of OLLC’s and its subsidiary-loan parties’ oil and gas properties subject to a mortgage or similar instruments in favor of the administrative agent. See Note 1 for additional information.

Equity and Distributions

Equity and Distributions	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Equity and Distributions	Note 8. Equity & Distributions Equity Outstanding The following table summarizes changes in the number of outstanding units since December 31, 2015: General Common Partner Balance, December 31, 2015 82,906,400 86,797 Restricted common units issued 50,000 — Restricted common units forfeited (18,450 ) — Restricted common units repurchased (1) (277,732 ) — Cancellation of General Partner units — (86,797 ) Issuance of common units 1,178,102 — Balance, September 30, 2016 83,838,320 — (1) Restricted common units are generally net-settled by unitholders to cover the required withholding tax upon vesting. Unitholders surrendered units with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were approximately $0.6 million for the nine months ended September 30, 2016. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership. Restricted common units are a component of common units as presented on our unaudited condensed consolidated balance sheets. See Note 10 for additional information regarding restricted common units that were granted during the nine months ended September 30, 2016. “At-the-Market” Equity Program On May 25, 2016, the Partnership entered into an equity distribution agreement for the sale of up to $60.0 million of common units under an at-the-market program (the “ATM Program”). Sales of common units, if any, will be made under the ATM Program by means of ordinary brokers’ transactions, through the facilities of the NASDAQ Global Market at market prices, or as otherwise agreed between the Partnership and a sales agent. The Partnership expects to use the net proceeds from any sale of common units for general partnership purposes, which may include repaying or refinancing a portion of our outstanding indebtedness and funding working capital, capital expenditures or acquisitions. During the three and nine months ended September 30, 2016, the Partnership sold 355,789 and 1,178,102 common units, respectively, under the ATM program. The sale of the units generated proceeds of approximately $0.5 million and $2.1 million for the three and nine months ended September 30, 2016, which was net of approximately $0.2 million and $0.3 million in fees, respectively. At September 30, 2016, approximately $57.6 million of common units remained available for issuance under the ATM Program. 2015 Repurchases of Common Units During the nine months ended September 30, 2015, we repurchased $52.8 million in common units, which represented a repurchase and retirement of 3,547,921 common units under the December 2014 repurchase program. The December 2014 repurchase program expired in December 2015. Allocations of Net Income (Loss) Prior to the MEMP GP Acquisition, net income (loss) attributable to the Partnership was allocated between our general partner and the common unitholders in proportion to their pro rata ownership after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner and the Funds. Net income (loss) attributable to acquisitions accounted for as a transaction between entities under common control in a manner similar to the pooling of interest method prior to their acquisition date is allocated to the previous owners since they were affiliates of our general partner. Subsequent to the MEMP GP Acquisition, net income (loss) attributable to the Partnership is allocated entirely to the common unit holders. 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 Payment Date Per Unit Distribution Affiliates 2 nd July 26, 2016 August 5, 2016 August 12, 2016 $ 0.0300 $ 2.5 $ < 0.1 1 st April 26, 2016 May 6, 2016 May 13, 2016 $ 0.0300 $ 2.5 $ < 0.1 4 th January 26, 2016 February 5, 2016 February 12, 2016 $ 0.1000 $ 8.3 $ < 0.1 3 rd October 26, 2015 November 5, 2015 November 12, 2015 $ 0.3000 $ 24.9 $ < 0.1 2 nd July 24, 2015 August 5, 2015 August 12, 2015 $ 0.5500 $ 45.7 $ 0.1 1 st April 24, 2015 May 6, 2015 May 13, 2015 $ 0.5500 $ 46.3 $ 0.2 4 th January 26, 2015 February 5, 2015 February 12, 2015 $ 0.5500 $ 46.3 $ 3.1 In October 2016, the board of directors of our general partner suspended distributions on common units primarily due to the current and expected commodity price environment and market conditions and their impact on our future business as well as restrictions imposed by our debt instruments, including our revolving credit facility. The board of directors of our general partner believes the suspension in distributions is in the best interest of the Partnership. See Note 1 for additional discussions regarding liquidity.

Earnings per Unit

Earnings per Unit	9 Months Ended
	Sep. 30, 2016
Earnings Per Share [Abstract]
Earnings per Unit	Note 9. Earnings per Unit The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Net income (loss) attributable to Memorial Production Partners LP $ (32,866 ) $ (192,085 ) $ (218,513 ) $ (468,826 ) Less: Previous owners interest in net income (loss) — — — (2,268 ) Less: General partner's 0.1% interest in net income (loss) (1) — (198 ) (168 ) (483 ) Less: IDRs attributable to corresponding period — — — 112 Net income (loss) available to limited partners $ (32,866 ) $ (191,887 ) $ (218,345 ) $ (466,187 ) Weighted average limited partner units outstanding: Common units 83,621 82,973 83,189 82,888 Subordinated units — — — 844 Total (2) 83,621 82,973 83,189 83,732 Basic and diluted EPU $ (0.39 ) $ (2.31 ) $ (2.62 ) $ (5.57 ) (1) As a result of repurchases under the December 2014 repurchase program, our general partner had an approximate average 0.105% interest in us prior to the MEMP GP Acquisition for the nine months ended September 30, 2016 and an approximate average of 0.105% and 0.104% interest in us for the three and nine months ended September 30, 2015. (2) For the three and nine months ended September 30, 2016, 162,973 and 1,562,656 incremental phantom units under the treasury stock method were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were in a loss position.

Unit-based Awards

Unit-based Awards	9 Months Ended
	Sep. 30, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Unit-based Awards	Note 10. Unit-Based Awards Restricted Common Units The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for the periods presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted common units outstanding at December 31, 2015 1,368,538 $ 17.61 Granted (2) 50,000 $ 2.41 Forfeited (18,450 ) $ 16.94 Vested (954,808 ) $ 18.06 Restricted common units outstanding at September 30, 2016 445,280 $ 14.96 (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 during the nine months ended September 30, 2016 was $0.1 million based on a grant date market price of $2.41 per unit. The unrecognized compensation cost associated with restricted common unit awards was $5.1 million at September 30, 2016. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.33 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to partners as presented on our unaudited condensed statements of consolidated and combined cash flows. LTIP Modification On June 1, 2016, in connection with the MEMP GP Acquisition as discussed in Note 1, the board of directors of our general partner approved the acceleration of the vesting schedule of unvested awards under the LTIP for the employees that remained with Memorial Resource. The grant-date fair value compensation cost of approximately $0.1 million was reversed and the modified-date grant fair value compensation cost of $0.5 million was recognized. On March 9, 2016, certain employees were impacted by an involuntary termination which, upon the approval of the board of directors of our general partner, accelerated the vesting schedule of unvested awards under the LTIP that otherwise would have been forfeited upon an involuntary termination. The acceleration of the LTIP vesting schedule represents an improbable-to-probable modification. The grant-date fair value compensation cost of approximately $0.5 million was reversed and the modified-date grant fair value compensation cost of approximately $0.3 million was recognized. Phantom Units The following table summarizes information regarding phantom unit awards granted under the LTIP: Number of Units Phantom units outstanding at December 31, 2015 — Granted 6,169,018 Forfeited (37,486 ) Phantom units outstanding at September 30, 2016 6,131,532 Phantom units issued to non-employee directors in January will vest on the first anniversary of the date of grant. Phantom units issued to certain employees in June will vest in substantially equal one-third increments on the first, second, and third anniversaries of the date of grant. The awards included distribution equivalent rights (“DERs”) pursuant to which the recipient will receive a cash payment with respect to each phantom unit equal to any cash distributions that we pay to a holder of a common unit. DERs are treated as additional compensation expense. Upon vesting, the phantom units will be settled through an amount of cash in a single lump sum payment equal to the product of (y) the closing price of our common units on the vesting date and (z) the number of such vested phantom units. In lieu of a cash payment, the board of directors of our general partner, in its discretion, may elect for the recipient to receive either a number of common units equal to the number of such vested phantom units or a combination of cash and common units. For the three and nine months ended September 30, 2016, the phantom units issued are classified as liability awards due to the Partnership not having sufficient common units available under the LTIP to settle in common units upon vesting. Compensation Expense The following table summarizes the amount of recognized compensation expense associated with the LTIP awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Equity classified awards Restricted common units $ 1,135 $ 2,993 $ 6,134 $ 7,899 Liability classified awards Phantom units 1,189 — 1,413 — $ 2,324 $ 2,993 $ 7,547 $ 7,899

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Note 11. Related Party Transactions Amounts due to Memorial Resource and certain affiliates of NGP at December 31, 2015 are presented within “Accounts payable – NGP Affiliated Companies During the nine months ended September 30, 2016, we paid less than $0.1 million, to Multi-Shot, LLC, an NGP affiliate company, for services related to our drilling and completion activities. During the three and nine months ended September 30, 2015, we paid less than $0.1 million and $0.3 million to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities. Common Control Acquisitions MEMP GP Acquisition. On June 1, 2016, as discussed in Note 1, the Partnership acquired all of the equity interests in our general partner, MEMP GP, from Memorial Resource for cash consideration of approximately $0.8 million. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition. In connection with the closing of the transaction, our partnership agreement was amended and restated to, among other things, (i) convert MEMP GP’s 0.1% general partnership interest into a non-economic general partner interest, (ii) cancel the IDRs of the Partnership, and (iii) provide that the limited partners of the Partnership will elect the members of MEMP GP’s board of directors beginning with an annual meeting in 2017. On June 1, 2016, the Partnership also acquired the remaining 50% of the IDRs of the Partnership owned by an NGP affiliate. February 2015 Acquisition. On February 23, 2015, as discussed in Note 1, we consummated the Property Swap. The Partnership recorded the following net assets (in thousands): Accounts receivable $ 2,372 Other receivables 5,478 Prepaid expenses and other current assets 1,874 Property and equipment, net 263,210 Accounts payable (3,586 ) Accounts payable - affiliate (1,290 ) Revenues payable (1,110 ) Accrued liabilities (11,347 ) Asset retirement obligations (4,559 ) Net assets $ 251,042 Related Party Agreements We and certain of our former affiliates entered into various documents and agreements. These agreements were negotiated among affiliated parties and, consequently, were not the result of arm’s-length negotiations. Omnibus Agreement Memorial Resource provided management, administrative and operating services to the Partnership and our general partner pursuant to our omnibus agreement. Upon completion of the MEMP GP Acquisition, the omnibus agreement was terminated and the Partnership entered into a transition services agreement with Memorial Resource. See Note 12 for additional information related to the transition services 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, 2016 2015 2016 2015 $ — $ 8,439 $ 11,867 $ 25,448 Beta Management Agreement Memorial Resource, through its wholly-owned subsidiary Beta Operating Company, LLC (“Beta Operating”), provided management and administrative oversight related to our offshore Southern California oil and gas properties in exchange for an annual management fee. Memorial Resource had the right to receive approximately $0.4 million from Rise Energy Beta, LLC annually. During the three and nine months ended September 30, 2015 we recognized $0.1 million and $0.3 million, respectively, under this agreement. This agreement was terminated in November 2015 in connection with the 2015 Beta Acquisition. On June 1, 2016, Memorial Resource assigned and transferred Beta Operating to the Partnership in connection with the MEMP GP Acquisition. Classic Gas Gathering and Water Disposal Agreements A discussion of these agreements is included in our 2015 Form 10-K. The amended gas gathering agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline and Gathering LLC’s (“Classic Pipeline”) Joaquin gathering system. Additionally, Classic Pipeline assigned its salt water system to OLLC in November 2015. For the three and nine months ended September 30, 2015, we incurred gathering and saltwater disposal fees of approximately $0.7 million and $2.7 million under these agreements.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 12. Commitments and Contingencies Transition Services Agreement On June 1, 2016 we closed the MEMP GP Acquisition. Upon closing of the MEMP GP Acquisition, we and Memorial Resource became unaffiliated entities. We terminated our omnibus agreement and entered into a transition services agreement with Memorial Resource to manage post-closing separation costs and activities. During the three and nine months ended September 30, 2016, we recorded $0.9 million and $1.4 million, respectively, of general and administrative expenses related to the transition services agreement with Memorial Resource. 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, 2016, we had no environmental reserves recorded. As of December 31, 2015, we had approximately $0.2 million of environmental reserves recorded on our balance sheet. Supplemental Bond for Decommissioning Liabilities Trust Agreement The trust account must maintain minimum balances as follows (in thousands): December 31, 2016 $ 152,000 In the event the account balance is less than the contractual amount, we must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by us. As of September 30, 2016, the remaining obligation was approximately $2.7 million. In 2015, the BOEM issued a preliminary report that indicated the estimated costs of decommissioning may further increase, and we expect the amount to be finalized during the fourth quarter of 2016 after negotiations are completed. The held-to-maturity investments held in the trust account as of September 30, 2016 for the U.S. Bank money market cash equivalent was $149.3 million.

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	Note 13. Subsequent Events Amendment to Credit Facility and Borrowing Base Redetermination For additional information, see Note 7. Deferred Interest Payment and Limited Waiver and Twelfth Amendment to the Credit Agreement For additional information, see Note 7. Compensatory Arrangements of Certain Employees On October 27, 2016, the Board of Directors (the “Board”) of MEMP GP, approved the adoption of a key employee incentive plan and a key employee retention program for the benefit of certain employees identified by the Board, including the named executive officers of the Partnership, whose continued employment and performance is critical to the success of MEMP GP and the Partnership. In adopting the plans, the Board relied upon the market analysis and advice of Pearl Meyers & Partners, LLC, the independent compensation consultant to the Partnership.

Organization and Basis of Pre20

Organization and Basis of Presentation (Policies)	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
General	General Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries. We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as the economic environments are not different within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, Wyoming and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. Unless the context requires otherwise, references to: (i) “our general partner” or “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner and wholly-owned subsidiary; (ii) “Memorial Resource” refer collectively to Memorial Resource Development Corp. and its subsidiaries; (iii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.; (iv) “OLLC” refer to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (v) “Finance Corp.” refer to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; and (vi) “NGP” refer to Natural Gas Partners. On April 27, 2016, we entered into an agreement pursuant to which the Partnership agreed to acquire, among other things, all of the equity interests in our general partner, MEMP GP, from Memorial Resource (the “MEMP GP Acquisition”) for cash consideration of approximately $0.8 million. MEMP GP held an approximate 0.1% general partner interest and 50% of the incentive distribution rights ("IDRs") in us. In conjunction with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with an NGP affiliate pursuant to which we agreed to acquire the other 50% of the IDRs. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition. In connection with the closing of the transactions on June 1, 2016, our partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Partnership held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Partnership will elect the members of MEMP GP’s board of directors beginning with the annual meeting in 2017. In addition, we terminated the omnibus agreement under which Memorial Resource provided management, administrative and operations personnel to us and our general partner, and we entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 11 and Note 12 for additional information regarding the MEMP GP Acquisition and the transition services agreement.
Liquidity	Liquidity As of September 30, 2016, we were in compliance with our financial covenants under our revolving credit facility. Effective October 28, 2016, in connection with the semi-annual borrowing redetermination by the lenders under our revolving credit facility, the borrowing base under our revolving credit facility was reduced to $740.0 million and will automatically be further reduced to $720.0 million on December 1, 2016. With our borrowing base at such levels, we will have limited to no available borrowing capacity and will likely be unable to remain in compliance with certain financial covenants under our revolving credit facility as early as the fourth quarter of 2016. In addition, if we are unable to remain in compliance with the covenants under our revolving credit facility or the indentures governing our senior notes, or a cross-default occurs under either, absent relief from our lenders or noteholders, as applicable, we may be forced to repay or refinance such indebtedness and we may incur other damages. Upon the occurrence of an event of default, the lenders under our revolving credit facility or holders of our senior notes, as applicable, could elect to declare all amounts outstanding immediately due and payable or seek other remedies and the lenders could terminate all commitments to extend further credit under our revolving credit facility. If an event of default occurs under our revolving credit facility or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding or seek other remedies, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. We might also be required to seek relief under the Bankruptcy Code. See Note 7 for more information.
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. The Property Swap was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information were retrospectively revised to give effect to the Property Swap as if the Partnership owned the assets for periods after common control commenced through the acquisition date.
Basis of Presentation	Basis of Presentation Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements of the previous owners were derived from their historical accounting records and reflect their historical financial position, results of operations and cash flows. The inclusion of MEMP GP in our consolidated financial statements was effective June 1, 2016 due to the MEMP GP Acquisition. See Note 11 for more information. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Our results of operations for the three and nine months ended September 30, 2016 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the SEC. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements.
Use of Estimates	Use of Estimates The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.
Accrued Liabilities	Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): September 30, December 31, 2016 2015 Accrued interest payable $ 26,063 $ 23,192 Accrued lease operating expense 12,364 16,843 Accrued capital expenditures 7,622 8,110 Accrued general and administrative expenses 5,130 1,961 Accrued ad valorem tax 3,879 1,426 Asset retirement obligation 830 1,175 Environmental liability — 216 Other 4,909 — $ 60,797 $ 52,923
Supplemental Cash Flows	Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Nine Months Ended September 30, 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 80,446 $ 75,378 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (488 ) (6,937 ) (Increase) decrease in accounts receivable related to acquisitions — 9,570 (Increase) decrease in accounts receivable/payable related to divestitures 856 — Asset retirement obligation removal related to divestitures (19,591 ) — Restricted units returned to plan — 3
New Accounting Pronouncements	New Accounting Pronouncements Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments. In August 2016, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update to address eight specific cash flow issues with the objective of reducing the current and potential future diversity in practice. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involves several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, entities will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required. The new guidance is effective for reporting periods beginning after December 15, 2016 and interim periods within those fiscal years. Early adoption is permitted, but all of the guidance must be adopted in the same period. For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. Entities should apply the new guidance retrospectively for all periods presented related to the classification of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirements. Entities may apply the presentation changes for excess tax benefits in the statement of cash flows either prospectively or retrospectively. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Leases. In February 2016, the FASB issued a revision to lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The revised guidance must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. The Partnership is currently evaluating the standard and the impact on the consolidated financial statements and related footnote disclosures. Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. In April 2015, the FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method are also required. The guidance was effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. We adopted this guidance on January 1, 2016. Since the Partnership has historically allocated the earnings (losses) of transferred businesses that occurred in periods before the date of the dropdown transaction entirely to affiliates of the general partner (i.e., the previous owners) and did not adjust previously reported earnings per unit of the limited partners, the impact of adopting this guidance was not material to the Partnership’s financial statements and related disclosures. Revenue from Contracts with Customers. In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. The guidance is effective for interim and annual reporting periods beginning after December 15, 2017, and early adoption is permitted. The new standard permits adoption through the use of either the full retrospective approach or a modified retrospective approach. The Partnership is currently evaluating the standard and the impact on the consolidated financial statements and related footnote disclosures. Presentation of Financial Statements — Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern . In August 2014, the FASB issued an accounting standards update that requires management to perform interim and annual assessments of whether there are conditions or events that raise substantial doubt of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. Certain disclosures are required if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, and with early adoption permitted. The amendments will not impact our financial position or results of operations but will require management to perform a formal going concern assessment. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Summary of Significant Accoun21

Summary of Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2016
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, 2016 2015 Accrued interest payable $ 26,063 $ 23,192 Accrued lease operating expense 12,364 16,843 Accrued capital expenditures 7,622 8,110 Accrued general and administrative expenses 5,130 1,961 Accrued ad valorem tax 3,879 1,426 Asset retirement obligation 830 1,175 Environmental liability — 216 Other 4,909 — $ 60,797 $ 52,923
Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands): For the Nine Months Ended September 30, 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 80,446 $ 75,378 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (488 ) (6,937 ) (Increase) decrease in accounts receivable related to acquisitions — 9,570 (Increase) decrease in accounts receivable/payable related to divestitures 856 — Asset retirement obligation removal related to divestitures (19,591 ) — Restricted units returned to plan — 3

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	9 Months Ended
	Sep. 30, 2016
Business Combinations [Abstract]
Acquisition and Divestiture-Related Expenses	Acquisition and divestiture related expenses 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, 2016 2015 2016 2015 $ 416 $ 16 $ 1,429 $ 1,612
Supplemental Pro Forma Information	The following unaudited pro forma combined results of operations are provided for the three and nine months ended September 30, 2015 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical consolidated and combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, (iii) accretion expense associated with asset retirement obligations recorded and (iv) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations For the Three Months Ended For the Nine Months Ended September 30, September 30, 2015 2015 (In thousands, except per unit amounts) Revenues $ 94,497 $ 300,346 Net income (loss) (191,710 ) (463,823 ) Basic and diluted earnings per unit (2.31 ) (5.52 )
Schedule of Income (Loss) before Income Taxes Including (Gain) Loss on Divestiture	The income (loss) before income taxes, including the associated (gain) loss on sale of properties, related to the Permian Divestiture and Rockies Divestiture included in the unaudited condensed statements of consolidated and combined operations of the Partnership is as follows (in thousands): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Permian Divestiture $ (40 ) $ (56,078 ) $ 4,792 $ (62,312 ) Rockies Divestiture 445 (111 ) (7,175 ) (55,844 )

Fair Value Measurements of Fi23

Fair Value Measurements of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2016 and December 31, 2015 for each of the fair value hierarchy levels: Fair Value Measurements at September 30, 2016 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 494,081 $ — $ 494,081 Interest rate derivatives — — — — Total assets $ — $ 494,081 $ — $ 494,081 Liabilities: Commodity derivatives $ — $ 36,518 $ — $ 36,518 Interest rate derivatives — 5,235 — 5,235 Total liabilities $ — $ 41,753 $ — $ 41,753 Fair Value Measurements at December 31, 2015 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 816,995 $ — $ 816,995 Interest rate derivatives — — — — Total assets $ — $ 816,995 $ — $ 816,995 Liabilities: Commodity derivatives $ — $ 84,501 $ — $ 84,501 Interest rate derivatives — 2,655 — 2,655 Total liabilities $ — $ 87,156 $ — $ 87,156

Risk Management and Derivativ24

Risk Management and Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2016
Open Commodity Positions	At September 30, 2016, we had the following open commodity positions: Remaining 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,565,775 3,350,067 3,060,000 2,814,583 Weighted-average fixed price $ 4.14 $ 4.06 $ 4.18 $ 4.31 Basis swaps: Average Monthly Volume (MMBtu) 3,555,000 2,210,000 1,315,000 900,000 Spread $ (0.07 ) $ (0.04 ) $ (0.02 ) $ 0.01 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 184,313 301,600 312,000 160,000 Weighted-average fixed price $ 74.27 $ 85.00 $ 83.74 $ 85.52 Basis swaps: Average Monthly Volume (Bbls) 99,000 37,500 — — Spread $ (12.28 ) $ (12.20 ) $ — $ — Purchased put option contracts: Average Monthly Volume (Bbls) 60,000 — — — Weighted-average strike price $ 40.00 $ — $ — $ — Weighted-average deferred premium $ (0.86 ) $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 195,100 43,300 — — Weighted-average fixed price $ 34.01 $ 37.55 $ — $ —
Interest Rate Swap Open Positions	At September 30, 2016, we had the following interest rate swap open positions: Remaining 2016 2017 2018 Average Monthly Notional (in thousands) $ 400,000 $ 400,000 $ 300,000 Weighted-average fixed rate 0.943 % 1.612 % 1.427 % Floating rate 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR
Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet	The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2016 and December 31, 2015. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives September 30, December 31, September 30, December 31, Type Balance Sheet Location 2016 2015 2016 2015 (In thousands) Commodity contracts Short-term derivative instruments $ 186,168 $ 324,265 $ 30,132 $ 53,581 Interest rate swaps Short-term derivative instruments — — 3,331 1,214 Gross fair value 186,168 324,265 33,463 54,795 Netting arrangements Short-term derivative instruments (31,328 ) (51,945 ) (31,328 ) (51,945 ) Net recorded fair value Short-term derivative instruments $ 154,840 $ 272,320 $ 2,135 $ 2,850 Commodity contracts Long-term derivative instruments $ 307,913 $ 492,730 $ 6,386 $ 30,920 Interest rate swaps Long-term derivative instruments — — 1,904 1,441 Gross fair value 307,913 492,730 8,290 32,361 Netting arrangements Long-term derivative instruments (7,218 ) (30,920 ) (7,218 ) (30,920 ) Net recorded fair value Long-term derivative instruments $ 300,695 $ 461,810 $ 1,072 $ 1,441
Unrealized and Realized Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands): For the Three Months Ended For the Nine Months Ended Statements of September 30, September 30, Operations Location 2016 2015 2016 2015 Commodity derivative contracts (Gain) loss on commodity derivatives $ (21,938 ) $ (244,888 ) $ 50,897 $ (328,944 ) Interest rate derivatives Interest expense, net (1,432 ) 3,543 4,094 6,628
Disaggregated Basis Swap [Member]
Open Commodity Positions	Our basis swaps included in the table above are presented on a disaggregated basis below: Remaining 2016 2017 2018 2019 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 2,980,000 1,800,000 1,200,000 900,000 Spread-Henry Hub $ (0.07 ) $ (0.07 ) $ (0.03 ) $ 0.01 HSC basis swaps: Average Monthly Volume (MMBtu) 135,000 115,000 115,000 — Spread-Henry Hub $ 0.07 $ 0.14 $ 0.15 $ — CIG basis swaps: Average Monthly Volume (MMBtu) 170,000 — — — Spread-Henry Hub $ (0.30 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 270,000 295,000 — — Spread-Henry Hub $ 0.06 $ 0.03 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 99,000 37,500 — — Spread - Brent $ (12.28 ) $ (12.20 ) $ — $ —

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2016 (in thousands): Asset retirement obligations at beginning of period $ 164,164 Liabilities added from acquisitions or drilling 30 Liabilities removed upon sale of wells (19,591 ) Liabilities settled (1,099 ) Accretion expense 7,802 Revision of estimates 353 Asset retirement obligations at end of period 151,659 Less: Current portion (830 ) Asset retirement obligations - long-term portion $ 150,829

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations at the dates indicated: September 30, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 714,000 $ 836,000 2021 Senior Notes, fixed-rate, due May 2021 (2) (4) 646,287 700,000 2022 Senior Notes, fixed-rate, due August 2022 (3) (4) 464,965 496,990 Senior notes debt issuance costs, net (14,940 ) (18,297 ) Unamortized discounts (11,417 ) (14,114 ) Total long-term debt $ 1,798,895 $ 2,000,579 (1) The carrying amount of our revolving credit facility approximates fair value because the interest rates are variable and reflective of market rates. (2) The estimated fair value of our 2021 Senior Notes was $329.6 million and $210.0 million at September 30, 2016 and December 31, 2015, respectively. (3) The estimated fair value of our 2022 Senior Notes was $232.5 million and $149.1 million at September 30, 2016 and December 31, 2015, respectively. (4) 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, 2016 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 925,000
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, 2016 2015 2016 2015 OLLC revolving credit facility (1) 3.57 % 2.14 % 3.11 % 2.06 % (1) As noted in our 2015 Form 10-K, the Applicable Margin (as defined in our revolving credit facility), or credit spread, varies based on the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect). The Applicable Margin for the three months and nine months ended for September 30, 2016 was 3.00% and 2.62%, respectively. The Applicable Margin for the three months and nine months ended September 30, 2015, was 1.95% and 1.86%, respectively.
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, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 3,304 $ 3,672 2021 Senior Notes (2) 8,960 11,194 2022 Senior Notes (2) 5,980 7,103 Total $ 18,244 $ 21,969 (1) Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility. (2) Unamortized deferred financing costs are amortized using the straight line method, which generally approximates the effective interest method.

Equity and Distributions (Table

Equity and Distributions (Tables)	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Summary of Changes in Number of Outstanding Units	The following table summarizes changes in the number of outstanding units since December 31, 2015: General Common Partner Balance, December 31, 2015 82,906,400 86,797 Restricted common units issued 50,000 — Restricted common units forfeited (18,450 ) — Restricted common units repurchased (1) (277,732 ) — Cancellation of General Partner units — (86,797 ) Issuance of common units 1,178,102 — Balance, September 30, 2016 83,838,320 — (1) Restricted common units are generally net-settled by unitholders to cover the required withholding tax upon vesting. Unitholders surrendered units with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were approximately $0.6 million for the nine months ended September 30, 2016. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership.
Summary of Quarterly Cash Distribution Rates	The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts): Distribution Amount Aggregate Received by Quarter Declaration Date Record Date Payment Date Per Unit Distribution Affiliates 2 nd July 26, 2016 August 5, 2016 August 12, 2016 $ 0.0300 $ 2.5 $ < 0.1 1 st April 26, 2016 May 6, 2016 May 13, 2016 $ 0.0300 $ 2.5 $ < 0.1 4 th January 26, 2016 February 5, 2016 February 12, 2016 $ 0.1000 $ 8.3 $ < 0.1 3 rd October 26, 2015 November 5, 2015 November 12, 2015 $ 0.3000 $ 24.9 $ < 0.1 2 nd July 24, 2015 August 5, 2015 August 12, 2015 $ 0.5500 $ 45.7 $ 0.1 1 st April 24, 2015 May 6, 2015 May 13, 2015 $ 0.5500 $ 46.3 $ 0.2 4 th January 26, 2015 February 5, 2015 February 12, 2015 $ 0.5500 $ 46.3 $ 3.1

Earnings per Unit (Tables)

Earnings per Unit (Tables)	9 Months Ended
	Sep. 30, 2016
Earnings Per Share [Abstract]
Calculation of Earnings (Loss) Per Unit	The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Net income (loss) attributable to Memorial Production Partners LP $ (32,866 ) $ (192,085 ) $ (218,513 ) $ (468,826 ) Less: Previous owners interest in net income (loss) — — — (2,268 ) Less: General partner's 0.1% interest in net income (loss) (1) — (198 ) (168 ) (483 ) Less: IDRs attributable to corresponding period — — — 112 Net income (loss) available to limited partners $ (32,866 ) $ (191,887 ) $ (218,345 ) $ (466,187 ) Weighted average limited partner units outstanding: Common units 83,621 82,973 83,189 82,888 Subordinated units — — — 844 Total (2) 83,621 82,973 83,189 83,732 Basic and diluted EPU $ (0.39 ) $ (2.31 ) $ (2.62 ) $ (5.57 ) (1) As a result of repurchases under the December 2014 repurchase program, our general partner had an approximate average 0.105% interest in us prior to the MEMP GP Acquisition for the nine months ended September 30, 2016 and an approximate average of 0.105% and 0.104% interest in us for the three and nine months ended September 30, 2015. (2) For the three and nine months ended September 30, 2016, 162,973 and 1,562,656 incremental phantom units under the treasury stock method were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were in a loss position.

Unit-based Awards (Tables)

Unit-based Awards (Tables)	9 Months Ended
	Sep. 30, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Information Regarding Restricted Common Unit Awards	Restricted Common Units The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for the periods presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted common units outstanding at December 31, 2015 1,368,538 $ 17.61 Granted (2) 50,000 $ 2.41 Forfeited (18,450 ) $ 16.94 Vested (954,808 ) $ 18.06 Restricted common units outstanding at September 30, 2016 445,280 $ 14.96 (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 during the nine months ended September 30, 2016 was $0.1 million based on a grant date market price of $2.41 per unit.
Summary of Information Regarding Phantom Unit Awards	The following table summarizes information regarding phantom unit awards granted under the LTIP: Number of Units Phantom units outstanding at December 31, 2015 — Granted 6,169,018 Forfeited (37,486 ) Phantom units outstanding at September 30, 2016 6,131,532
Summary of Amount of Compensation Expense Recognized	The following table summarizes the amount of recognized compensation expense associated with the LTIP awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2016 2015 2016 2015 Equity classified awards Restricted common units $ 1,135 $ 2,993 $ 6,134 $ 7,899 Liability classified awards Phantom units 1,189 — 1,413 — $ 2,324 $ 2,993 $ 7,547 $ 7,899

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2016
February 2015 Acquisition [Member]
Related Party Transaction [Line Items]
Schedule of Net Assets Recorded by Partnership	The Partnership recorded the following net assets (in thousands): Accounts receivable $ 2,372 Other receivables 5,478 Prepaid expenses and other current assets 1,874 Property and equipment, net 263,210 Accounts payable (3,586 ) Accounts payable - affiliate (1,290 ) Revenues payable (1,110 ) Accrued liabilities (11,347 ) Asset retirement obligations (4,559 ) Net assets $ 251,042
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
Schedule of Amount of General and Administrative Costs and Expenses Recognized	The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended For the Nine Months Ended September 30, September 30, 2016 2015 2016 2015 $ — $ 8,439 $ 11,867 $ 25,448

Commitments and Contingencies (

Commitments and Contingencies (Tables)	9 Months Ended
	Sep. 30, 2016
Commitments And Contingencies Disclosure [Abstract]
Minimum Balances Attributable to Net Working Interest	The trust account must maintain minimum balances as follows (in thousands): December 31, 2016 $ 152,000

Organization and Basis of Pre32

Organization and Basis of Presentation - Additional Information (Detail)	Apr. 27, 2016USD ($)	Sep. 30, 2016USD ($)Segment	Oct. 28, 2016USD ($)	Jun. 01, 2016	Apr. 14, 2016USD ($)
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments | Segment		1
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Consolidation And Basis Of Presentation [Line Items]
Borrowing base		$ 925,000,000			$ 1,175,000,000
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Subsequent Event [Member]
Consolidation And Basis Of Presentation [Line Items]
Borrowing base			$ 740,000,000
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Subsequent Event [Member] | December 1, 2016 [Member]
Consolidation And Basis Of Presentation [Line Items]
Borrowing base			$ 720,000,000
MEMP GP [Member]
Consolidation And Basis Of Presentation [Line Items]
Acquisition purchase price	$ 800,000
Partnership ownership percentage	0.10%
Gain (loss) on acquisition	$ 0
Related party transaction, description of transaction		In connection with the closing of the transactions on June 1, 2016, our partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Partnership held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Partnership will elect the members of MEMP GP’s board of directors beginning with the annual meeting in 2017.
General Partner [Member] | Incentive Distribution Rights (“IDRs”) [Member] | MEMP GP [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage	50.00%
Natural Gas Partners [Member] | Incentive Distribution Rights (“IDRs”) [Member]
Consolidation And Basis Of Presentation [Line Items]
Agreed ownership interest percentage to acquire	50.00%			50.00%

Summary of Significant Accoun33

Summary of Significant Accounting Policies - Summary of Current Accrued Liabilities (Detail) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Accrued Liabilities Current [Abstract]
Accrued interest payable	$ 26,063	$ 23,192
Accrued lease operating expense	12,364	16,843
Accrued capital expenditures	7,622	8,110
Accrued general and administrative expenses	5,130	1,961
Accrued ad valorem tax	3,879	1,426
Asset retirement obligation	830	1,175
Environmental liability	0	216
Other	4,909	0
Accrued liabilities, Total	$ 60,797	$ 52,923

Summary of Significant Accoun34

Summary of Significant Accounting Policies - Summary of Supplemental Cash Flows (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$ 80,446	$ 75,378
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	(488)	(6,937)
(Increase) decrease in accounts receivable related to acquisitions	0	9,570
(Increase) decrease in accounts receivable/payable related to divestitures	856	0
Asset retirement obligation removal related to divestitures	(19,591)	0
Restricted units returned to plan	$ 0	$ 3

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisition and Divestiture-Related Expenses (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
General and Administrative Expense
Business Acquisition [Line Items]
Business Acquisition and Divestiture, Related Expenses	$ 416	$ 16	$ 1,429	$ 1,612

Acquisitions and Divestitures36

Acquisitions and Divestitures - Supplemental Pro Forma Information (Detail) - 2015 Beta Acquisition [Member] - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Business Acquisition [Line Items]
Revenues	$ 94,497	$ 300,346
Net income (loss)	$ (191,710)	$ (463,823)
Basic and diluted earnings per unit	$ (2.31)	$ (5.52)

Acquisitions and Divestitures37

Acquisitions and Divestitures - Additional Information (Detail) - USD ($) $ in Millions	Jul. 14, 2016	Jun. 14, 2016	Sep. 30, 2016
Permian Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Disposal group, not discontinued operation, (gain) loss on properties		$ (6.5)
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Disposal group, not discontinued operation, (gain) loss on properties			$ 3.9
Immaterial Divestitures [Member]
Business Acquisition And Divestiture [Line Items]
Disposal group, not discontinued operation, (gain) loss on properties			$ (0.9)
Disposal Group Not Discontinued Operation [Member] | Permian Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Purchase price of divestitures		36.9
Disposal Group Not Discontinued Operation [Member] | Permian Divestiture [Member] | Accounts Receivable [Member]
Business Acquisition And Divestiture [Line Items]
Purchase price of divestitures		0.5
Disposal Group Not Discontinued Operation [Member] | Permian Divestiture [Member] | Cash [Member]
Business Acquisition And Divestiture [Line Items]
Purchase price of divestitures		$ 36.4
Disposal Group Not Discontinued Operation [Member] | Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Purchase price of divestitures	$ 16.9
Disposal Group Not Discontinued Operation [Member] | Rockies Divestiture [Member] | Accounts Payable [Member]
Business Acquisition And Divestiture [Line Items]
Purchase price of divestitures	1.3
Disposal Group Not Discontinued Operation [Member] | Rockies Divestiture [Member] | Cash [Member]
Business Acquisition And Divestiture [Line Items]
Purchase price of divestitures	$ 18.1

Acquisitions and Divestitures38

Acquisitions and Divestitures - Schedule of Income (Loss) before Income Taxes Including (Gain) Loss on Divestiture (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Business Acquisition And Divestiture [Line Items]
Income (loss) before income taxes	$ 32,866	$ 192,088	$ 218,317	$ 470,099
Permian Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Income (loss) before income taxes	(40)	(56,078)	4,792	(62,312)
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Income (loss) before income taxes	$ 445	$ (111)	$ (7,175)	$ (55,844)

Fair Value Measurements of Fi39

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, 2016	Dec. 31, 2015
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	$ 494,081	$ 816,995
Interest rate derivatives, Assets	0	0
Liabilities	41,753	87,156
Interest rate derivatives, Liabilities	5,235	2,655
Quoted Prices in Active Market (Level 1) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0	0
Interest rate derivatives, Assets	0	0
Liabilities	0	0
Interest rate derivatives, Liabilities	0	0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	494,081	816,995
Interest rate derivatives, Assets	0	0
Liabilities	41,753	87,156
Interest rate derivatives, Liabilities	5,235	2,655
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0	0
Interest rate derivatives, Assets	0	0
Liabilities	0	0
Interest rate derivatives, Liabilities	0	0
Commodity derivatives [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	494,081	816,995
Liabilities	36,518	84,501
Commodity derivatives [Member] | Quoted Prices in Active Market (Level 1) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0	0
Liabilities	0	0
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	494,081	816,995
Liabilities	36,518	84,501
Commodity derivatives [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0	0
Liabilities	$ 0	$ 0

Fair Value Measurements of Fi40

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	$ 0	$ 361,836	$ 8,342	$ 613,183
East Texas [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties			8,300
Carrying value of properties after impairment charges	$ 11,000		$ 11,000
East Texas, Wyoming and Colorado [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties		$ 361,800		$ 613,200

Risk Management and Derivativ41

Risk Management and Derivative Instruments - Additional Information (Detail) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	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	$ 267
Maximum amount of loss due to credit risk	188.7
Cash settlement receipt	39.3	$ 27.1
One Counterparty [Member]
Derivative Instruments Gain Loss [Line Items]
Maximum amount of loss due to credit risk	$ 59.9

Risk Management and Derivativ42

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	9 Months Ended
	Sep. 30, 2016$ / bblMMBTU$ / MMBTUbbl
Natural Gas Derivative Contracts Fixed Price Swap 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,565,775
Weighted-average fixed price | $ / MMBTU	4.14
Natural Gas Derivative Contracts Basis Swaps 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,555,000
Spread | $ / MMBTU	(0.07)
Crude Oil Derivative Contracts Fixed Price Swap 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	184,313
Weighted-average fixed price	74.27
Crude Oil Derivative Contracts Basis Swaps 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	99,000
Spread	(12.28)
Crude Oil Derivative Contracts Purchased Put Options 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	60,000
Weighted-average strike price	40
Weighted-average deferred premium	(0.86)
NGL Derivative Contracts Fixed Price Swap 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	195,100
Weighted-average fixed price	34.01
Natural Gas Derivative Contracts Fixed Price Swap 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,350,067
Weighted-average fixed price | $ / MMBTU	4.06
Natural Gas Derivative Contracts Basis Swaps 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,210,000
Spread | $ / MMBTU	(0.04)
Crude Oil Derivative Contracts Fixed Price Swap 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	301,600
Weighted-average fixed price	85
Crude Oil Derivative Contracts Basis Swaps 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	37,500
Spread	(12.20)
Purchased put option contracts 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	0
Weighted-average strike price	0
Weighted-average deferred premium	0
NGL Derivative Contracts Fixed Price Swap 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	43,300
Weighted-average fixed price	37.55
Natural Gas Derivative Contracts Fixed Price Swap 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,060,000
Weighted-average fixed price | $ / MMBTU	4.18
Natural Gas Derivative Contracts Basis Swaps 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,315,000
Spread | $ / MMBTU	(0.02)
Crude Oil Derivative Contracts Fixed Price Swap 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	312,000
Weighted-average fixed price	83.74
Crude Oil Derivative Contracts Basis Swaps 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	0
Spread	0
Purchased put option contracts 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	0
Weighted-average strike price	0
Weighted-average deferred premium	0
NGL Derivative Contracts Fixed Price Swap Contracts 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	0
Weighted-average fixed price	0
Natural Gas Derivative Contracts Fixed Price Swap 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,814,583
Weighted-average fixed price | $ / MMBTU	4.31
Natural Gas Derivative Contracts Basis Swaps 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	900,000
Spread | $ / MMBTU	0.01
Crude Oil Derivative Contracts Fixed Price Swap 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	160,000
Weighted-average fixed price	85.52
Crude Oil Derivative Contracts Basis Swaps 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	0
Spread	0
Purchased put option contracts 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	0
Weighted-average strike price	0
Weighted-average deferred premium	0
NGL Derivative Contracts Fixed Price Swap Contracts 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	0
Weighted-average fixed price	0

Risk Management and Derivativ43

Risk Management and Derivative Instruments - Open Commodity Positions Disaggregated Basis (Detail) - Not Designated as Hedging Instrument [Member]	9 Months Ended
	Sep. 30, 2016MMBTU$ / MMBTU$ / bblbbl
Natural Gas Derivative Contracts NGPL TexOk Basis Swaps 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,980,000
Spread | $ / MMBTU	(0.07)
Natural Gas Derivative Contracts HSC Basis Swaps 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	135,000
Spread | $ / MMBTU	0.07
Natural Gas Derivative Contracts CIG Basis Swaps 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	170,000
Spread | $ / MMBTU	(0.30)
Natural Gas Derivative Contracts TETCO STX Basis Swaps 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	270,000
Spread | $ / MMBTU	0.06
Crude Oil Derivative Contracts Midway-Sunset Basis Swaps 2016 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	99,000
Spread | $ / bbl	(12.28)
Natural Gas Derivative Contracts NGPL TexOk Basis Swaps 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,800,000
Spread | $ / MMBTU	(0.07)
Natural Gas Derivative Contracts HSC Basis Swaps 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	115,000
Spread | $ / MMBTU	0.14
Natural Gas Derivative Contracts CIG Basis Swaps 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	0
Spread | $ / MMBTU	0
Natural Gas Derivative Contracts TETCO STX Basis Swaps 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	295,000
Spread | $ / MMBTU	0.03
Crude Oil Derivative Contracts Midway-Sunset Basis Swaps 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	37,500
Spread | $ / bbl	(12.20)
Natural Gas Derivative Contracts NGPL TexOk Basis Swaps 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,200,000
Spread | $ / MMBTU	(0.03)
Natural Gas Derivative Contracts HSC Basis Swaps 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	115,000
Spread | $ / MMBTU	0.15
Natural Gas Derivative Contracts CIG Basis Swaps 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	0
Spread | $ / MMBTU	0
Natural Gas Derivative Contracts TETCO STX Basis Swaps 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	0
Spread | $ / MMBTU	0
Crude Oil Derivative Contracts Midway-Sunset Basis Swaps 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	0
Spread | $ / bbl	0
Natural Gas Derivative Contracts NGPL TexOk Basis Swaps 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	900,000
Spread | $ / MMBTU	0.01
Natural Gas Derivative Contracts HSC Basis Swaps 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	0
Spread | $ / MMBTU	0
Natural Gas Derivative Contracts CIG Basis Swaps 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	0
Spread | $ / MMBTU	0
Natural Gas Derivative Contracts TETCO STX Basis Swaps 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	0
Spread | $ / MMBTU	0
Crude Oil Derivative Contracts Midway-Sunset Basis Swaps 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	0
Spread | $ / bbl	0

Risk Management and Derivativ44

Risk Management and Derivative Instruments - Interest Rate Swap Open Positions (Detail) $ in Thousands	9 Months Ended
	Sep. 30, 2016USD ($)
Interest rate swaps Remaining 2016 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	0.943%
Floating rate	1 Month LIBOR
Interest rate swaps 2017 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	1.612%
Floating rate	1 Month LIBOR
Interest rate swaps 2018 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 300,000
Weighted-average fixed rate	1.427%
Floating rate	1 Month LIBOR

Risk Management and Derivativ45

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 154,840	$ 272,320
Asset Derivatives, Net recorded fair value	300,695	461,810
Liability Derivatives, Net recorded fair value	2,135	2,850
Liability Derivatives, Net recorded fair value	1,072	1,441
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	186,168	324,265
Asset Derivatives, Netting arrangements	(31,328)	(51,945)
Asset Derivatives, Net recorded fair value	154,840	272,320
Liability Derivatives, Gross fair value	33,463	54,795
Liability Derivatives, Netting arrangements	(31,328)	(51,945)
Liability Derivatives, Net recorded fair value	2,135	2,850
Short-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	186,168	324,265
Liability Derivatives, Gross fair value	30,132	53,581
Short-Term Derivative Instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	0	0
Liability Derivatives, Gross fair value	3,331	1,214
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	307,913	492,730
Asset Derivatives, Netting arrangements	(7,218)	(30,920)
Asset Derivatives, Net recorded fair value	300,695	461,810
Liability Derivatives, Gross fair value	8,290	32,361
Liability Derivatives, Netting arrangements	(7,218)	(30,920)
Liability Derivatives, Net recorded fair value	1,072	1,441
Long-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	307,913	492,730
Liability Derivatives, Gross fair value	6,386	30,920
Long-Term Derivative Instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	0	0
Liability Derivatives, Gross fair value	$ 1,904	$ 1,441

Risk Management and Derivativ46

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, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	$ (21,938)	$ (244,888)	$ 50,897	$ (328,944)
Interest expense, net	27,209	31,255	91,904	88,405
Commodity derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	(21,938)	(244,888)	50,897	(328,944)
Interest rate derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net	$ (1,432)	$ 3,543	$ 4,094	$ 6,628

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, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period			$ 164,164
Liabilities added from acquisitions or drilling			30
Liabilities removed upon sale of wells			(19,591)
Liabilities settled			(1,099)
Accretion expense	$ 2,383	$ 1,716	7,802	$ 5,036
Revision of estimates			353
Asset retirement obligations at end of period	151,659		151,659
Less: Current portion	(830)		(830)		$ (1,175)
Asset retirement obligations - long-term portion	$ 150,829		$ 150,829		$ 162,989

Long-Term Debt - Consolidated D

Long-Term Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Sep. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized discounts		$ (11,417)	$ (14,114)
Total long-term debt		1,798,895	2,000,579
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Revolving credit facility	[1]	714,000	836,000
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Senior Notes, fixed-rate	[2],[3]	646,287	700,000
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Senior Notes, fixed-rate	[2],[4]	464,965	496,990
Senior Notes [Member]
Debt Instrument [Line Items]
Debt issuance costs, net		$ (14,940)	$ (18,297)
[1]	The carrying amount of our revolving credit facility approximates fair value because the interest rates are variable and reflective of market rates.
[2]	The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[3]	The estimated fair value of our 2021 Senior Notes was $329.6 million and $210.0 million at September 30, 2016 and December 31, 2015, respectively.
[4]	The estimated fair value of our 2022 Senior Notes was $232.5 million and $149.1 million at September 30, 2016 and December 31, 2015, respectively.

Long-Term Debt - Consolidated49

Long-Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Maturity date	Mar. 19, 2018
Revolving credit facility	$ 2,000,000,000
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Maturity date	May 1, 2021
Estimated fair value of fixed-rate debt	$ 329,600,000	$ 210,000,000
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Maturity date	Aug. 1, 2022
Estimated fair value of fixed-rate debt	$ 232,500,000	$ 149,100,000

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail)	Sep. 30, 2016
Universal Shelf Registration Statement [Member]
Debt Instrument [Line Items]
Universal shelf guarantor subsidiaries ownership percentage	100.00%

Long-Term Debt - Credit Facilit

Long-Term Debt - Credit Facility - Additional Information (Detail) - USD ($)	Apr. 14, 2016	Sep. 30, 2016
Line of Credit Facility [Line Items]
Debt covenant, cash distributions to equity holders, pro forma availability minimum	$ 75,000,000
Debt covenant, cash distributions to equity holders, borrowing base amount percentage prior threshold date	10.00%
Debt covenant, cash distributions to equity holders, borrowing base amount percentage after threshold date	15.00%
Debt covenant, cash distributions to equity holders, total debt to EBITDAX ratio minimum	400.00%
Debt covenant, maximum payment of cash distributions to equity holders amount	$ 4,150,000
Debt covenant, repurchase, pro forma availability minimum	$ 75,000,000
Debt covenant, repurchase, borrowing base amount percentage prior threshold date minimum	10.00%
Debt covenant, repurchase, borrowing base amount percentage after threshold date minimum	15.00%
Debt covenant, outstanding senior unsecured notes repurchase, total debt to EBITDAX ratio maximum	300.00%
Maximum amount of proceeds from swap liquidations, sale or other disposition of oil and gas properties to repurchase outstanding senior unsecured notes or second lien debt	$ 40,000,000
Maximum amount of sale and cash proceeds to repurchase outstanding senior unsecured notes aggregate	$ 60,000,000
Minimum Percentage of Oil and Gas Properties mortgaged as collateral security for the loans under the Credit Agreement	90.00%
Debt covenant, minimum aggregate amount of unrestricted cash or cash equivalents to prepay loans and cash collateralize letter of credit exposure	$ 25,000,000
Letters of credit outstanding		$ 2,400,000
Other Long-term Assets [Member]
Line of Credit Facility [Line Items]
Deferred financing fees		1,000,000
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line of Credit Facility [Line Items]
Revolving credit facility, maximum borrowing capacity		2,000,000,000
Percentage of revolving unused commitment fee	0.50%
Borrowing base	$ 1,175,000,000	$ 925,000,000
Consolidated First Lien Net Secured Debt to Consolidated EBITDAX ratio Maximum	325.00%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Minimum [Member] | Alternative Base Rate [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage	1.25%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Minimum [Member] | Eurodollar or LIBOR [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage	2.25%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Maximum [Member] | Alternative Base Rate [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage	2.25%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Maximum [Member] | Eurodollar or LIBOR [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage	3.25%
Issuance Of Secured Second Lien Notes Solely In Exchange Of Outstanding Senior Unsecured Notes
Line of Credit Facility [Line Items]
Debt instrument, redemption period	180 days
Issuance Of Secured Second Lien Notes Solely In Exchange Of Outstanding Senior Unsecured Notes | Maximum [Member]
Line of Credit Facility [Line Items]
Aggregate principal amount	$ 600,000,000

Long-Term Debt - Borrowing Base

Long-Term Debt - Borrowing Base Credit Facility (Detail) - USD ($)	Sep. 30, 2016	Apr. 14, 2016
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line of Credit Facility [Line Items]
Borrowing base	$ 925,000,000	$ 1,175,000,000

Long-Term Debt - Borrowing Ba53

Long-Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail)	Sep. 30, 2016USD ($)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line of Credit Facility [Line Items]
Revolving credit facility	$ 2,000,000,000

Long-Term Debt - Subsequent Eve

Long-Term Debt - Subsequent Event - Additional Information (Detail) - USD ($)	Nov. 01, 2016	Apr. 14, 2016	Sep. 30, 2016	Oct. 28, 2016
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line of Credit Facility [Line Items]
Borrowing base		$ 1,175,000,000	$ 925,000,000
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Borrowing base				$ 740,000,000
Aggregate Liquidity				30,000,000
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Subsequent Event [Member] | December 1, 2016 [Member]
Line of Credit Facility [Line Items]
Borrowing base				$ 720,000,000
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Line of Credit Facility [Line Items]
Interest payment grace period under indenture			30 days
Debt Instrument, Interest Rate, Stated Percentage			7.625%
Minimum Percentage of Oil and Gas Properties mortgaged as collateral security for the loans under the Credit Agreement		90.00%
2021 Senior Notes, fixed-rate, due May 2021 [Member] | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Interest Payment	$ 24,600,000
Percentage of Oil and Gas Properties subject to mortgage	95.00%
Minimum Percentage of Oil and Gas Properties mortgaged as collateral security for the loans under the Credit Agreement	92.00%

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, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
OLLC revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates	[1]	3.57%	2.14%	3.11%	2.06%
[1]	As noted in our 2015 Form 10-K, the Applicable Margin (as defined in our revolving credit facility), or credit spread, varies based on the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect). The Applicable Margin for the three months and nine months ended for September 30, 2016 was 3.00% and 2.62%, respectively. The Applicable Margin for the three months and nine months ended September 30, 2015, was 1.95% and 1.86%, respectively.

Long-Term Debt - Summary of W56

Long-Term Debt - Summary of Weighted-Average Interest Rates Paid Excluding Commitment Fees on Variable-Rate Debt Obligations (Parenthetical) (Detail)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
OLLC revolving credit facility [Member] | Alternative Base Rate [Member]
Debt Instrument [Line Items]
Base rate borrowing percentage	3.00%	1.95%	2.62%	1.86%

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, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized deferred financing costs		$ 18,244	$ 21,969
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Unamortized deferred financing costs	[1]	3,304	3,672
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[2]	8,960	11,194
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[2]	$ 5,980	$ 7,103
[1]	Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.
[2]	Unamortized deferred financing costs are amortized using the straight line method, which generally approximates the effective interest method.

Long-Term Debt - Summary of U58

Long-Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Parenthetical) (Detail)	Sep. 30, 2016USD ($)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Revolving credit facility	$ 2,000,000,000

Long-Term Debt - Senior Notes -

Long-Term Debt - Senior Notes - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015
Debt Instrument [Line Items]
Repurchase of senior notes	$ 800	$ 41,261	$ 2,914
Gain on extinguishment of debt	673	42,337	422
7.625% senior notes due May 2021 [Member]
Debt Instrument [Line Items]
Repurchase of debt	$ 1,500	53,700
6.875% senior notes due August 2022 [Member]
Debt Instrument [Line Items]
Repurchase of debt		$ 32,000	3,000
Repurchase of senior notes			$ 2,600

Equity and Distributions - Summ

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Detail)	9 Months Ended
	Sep. 30, 2016shares
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	86,797
Ending balance	0
Limited Partners Common Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	82,906,400
Restricted common units issued	50,000
Restricted common units forfeited	(18,450)
Restricted common units repurchased	(277,732)
Cancellation of General Partner units	0
Issuance of common units	1,178,102
Ending balance	83,838,320
General Partner [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	86,797
Restricted common units issued	0
Restricted common units forfeited	0
Restricted common units repurchased	0
Cancellation of General Partner units	(86,797)
Issuance of common units	0
Ending balance	0

Equity and Distributions - Su61

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Parenthetical) (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)
Summary Of Changes In Number Of Outstanding Units [Abstract]
Withholding tax withheld and paid related to vesting of restricted common units	$ 0.6

Equity and Distributions - Addi

Equity and Distributions - Additional Information (Detail) - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	May 25, 2016
Limited Partners Capital Account [Line Items]
Proceeds from sale of common units, net		$ 2,385,000	$ 0
Common units amount repurchased under repurchase program			$ 52,800,000
Common units repurchased under repurchase program			3,547,921
ATM Program
Limited Partners Capital Account [Line Items]
Authorized Value				$ 60,000,000
Common unit, issued	355,789	1,178,102
Proceeds from sale of common units, net	$ 500,000	$ 2,100,000
Fees on sale of common unit	200,000	300,000
Authorized Value Remaining	$ 57,600,000	$ 57,600,000

Equity and Distributions - Su63

Equity and Distributions - Summary of Quarterly Cash Distribution Rates (Detail) - USD ($)	3 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
Limited Partners Capital Account [Line Items]
Distribution made to member or limited partner, date of declaration	Jul. 26, 2016	Apr. 26, 2016	Jan. 26, 2016	Oct. 26, 2015	Jul. 24, 2015	Apr. 24, 2015	Jan. 26, 2015
Distribution made to member or limited partner, date of record	Aug. 5, 2016	May 6, 2016	Feb. 5, 2016	Nov. 5, 2015	Aug. 5, 2015	May 6, 2015	Feb. 5, 2015
Distribution made to member or limited partner, date of distribution	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Nov. 12, 2015	Aug. 12, 2015	May 13, 2015	Feb. 12, 2015
Distribution per unit	$ 0.0300	$ 0.0300	$ 0.1000	$ 0.3000	$ 0.5500	$ 0.5500	$ 0.5500
Aggregate Distribution	$ 2,500,000	$ 2,500,000	$ 8,300,000	$ 24,900,000	$ 45,700,000	$ 46,300,000	$ 46,300,000
Distribution Received by Affiliates					$ 100,000	$ 200,000	$ 3,100,000
Maximum [Member]
Limited Partners Capital Account [Line Items]
Distribution Received by Affiliates	$ 100,000	$ 100,000	$ 100,000	$ 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, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Unit [Line Items]
Net income (loss) attributable to Memorial Production Partners LP	$ (32,866)	$ (192,085)	$ (218,513)	$ (468,826)
Less: Previous owners interest in net income (loss)	0		0	(2,268)
Less: General partner's 0.1% interest in net income (loss)	0	(198)	(168)	(483)
Less: IDRs attributable to corresponding period	0		0	112
Net income (loss) available to limited partners	$ (32,866)	$ (191,887)	$ (218,345)	$ (466,187)
Weighted average limited partner units outstanding:
Basic and diluted	83,621	82,973	83,189	83,732
Basic and diluted EPU	$ (0.39)	$ (2.31)	$ (2.62)	$ (5.57)
Common Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding	83,621	82,973	83,189	82,888
Subordinated Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding	0		0	844

Earnings Per Unit - Calculati65

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Parenthetical) (Detail) - shares shares in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Unit [Line Items]
General partner's interest in net income, percentage			0.10%
Phantom units excluded from computation of diluted earnings per unit	162,973		1,562,656
Average [Member]
Earnings Per Unit [Line Items]
General partner's interest in net income, percentage		0.105%	0.105%	0.104%

Unit-Based Awards - Summary of

Unit-Based Awards - Summary of Information Regarding Restricted Common Unit Awards (Detail) - Restricted Common Units [Member]	9 Months Ended
	Sep. 30, 2016$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance | shares	1,368,538
Granted, Number of Units | shares	50,000
Forfeited, Number of Units | shares	(18,450)
Vested, Number of Units | shares	(954,808)
Outstanding, Number of Units, Ending Balance | shares	445,280
Outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance | $ / shares	$ 17.61
Granted, Weighted-Average Grant Date Fair Value per Unit | $ / shares	2.41
Forfeited, Weighted-Average Grant Date Fair Value per Unit | $ / shares	16.94
Vested, Weighted-Average Grant Date Fair Value per Unit | $ / shares	18.06
Outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance | $ / shares	$ 14.96

Unit-Based Awards - Summary o67

Unit-Based Awards - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Common Units [Member] $ / shares in Units, $ in Millions	Sep. 30, 2016USD ($)$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted common unit awards issued | $	$ 0.1
Grant date market price | $ / shares	$ 2.41

Unit-Based Awards - Additional

Unit-Based Awards - Additional Information (Detail) - USD ($) $ in Millions	Jun. 01, 2016	Mar. 09, 2016	Jun. 30, 2016	Sep. 30, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Reversed share based compensation	$ 0.1	$ 0.5
Fair value of compensation cost recognized on the date of plan modification	$ 0.5	$ 0.3
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost				$ 5.1
Weighted-average period of unrecognized compensation cost				1 year 3 months 29 days
Phantom Units [Member] | First Anniversary Of Grant Date [Member] | Certain Employee [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage from the date of grant			33.33%
Phantom Units [Member] | Second Anniversary Of Grant Date [Member] | Certain Employee [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage from the date of grant			33.33%
Phantom Units [Member] | Third Anniversary Of Grant Date [Member] | Certain Employee [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage from the date of grant			33.33%

Unit-Based Awards - Summary o69

Unit-Based Awards - Summary of Information Regarding Phantom Unit Awards (Detail) - Phantom Units [Member]	9 Months Ended
	Sep. 30, 2016shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	0
Granted, Number of Units	6,169,018
Forfeited, Number of Units	(37,486)
Outstanding, Number of Units, Ending Balance	6,131,532

Unit-Based Awards - Summary o70

Unit-Based Awards - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	$ 2,324	$ 2,993	$ 7,547	$ 7,899
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	1,135	2,993	6,134	7,899
Phantom Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	$ 1,189	$ 0	$ 1,413	$ 0

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($)	Jun. 01, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Apr. 27, 2016
Multi-Shot, LLC [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Drilling and completion expenses		$ 100,000	$ 100,000	$ 300,000
MEMP GP [Member]
Related Party Transaction [Line Items]
Common Control Acquisition Purchase Price	$ 800,000
Gain (loss) on acquisition	$ 0
Date of acquisition common control			Jun. 1, 2016
Partnership ownership percentage	0.10%
Related party transaction, description of transaction			In connection with the closing of the transaction, our partnership agreement was amended and restated to, among other things, (i) convert MEMP GP’s 0.1% general partnership interest into a non-economic general partner interest, (ii) cancel the IDRs of the Partnership, and (iii) provide that the limited partners of the Partnership will elect the members of MEMP GP’s board of directors beginning with an annual meeting in 2017. On June 1, 2016, the Partnership also acquired the remaining 50% of the IDRs of the Partnership owned by an NGP affiliate.
Natural Gas Partners [Member] | Incentive Distribution Rights (“IDRs”) [Member]
Related Party Transaction [Line Items]
Date of acquisition common control			Jun. 1, 2016
Agreed ownership interest percentage to acquire	50.00%				50.00%
Memorial Resource [Member]
Related Party Transaction [Line Items]
Amount receivable under management agreement			$ 400,000
Amount recognized under management agreement		100,000		300,000
Classic Operating And Classic Pipeline [Member] | Water Disposal Agreement [Member]
Related Party Transaction [Line Items]
Salt water disposal fees		$ 700,000		$ 2,700,000

Related Party Transactions - Sc

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

Related Party Transactions - 73

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, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
General and administrative costs and expenses under omnibus agreement	$ 0	$ 8,439	$ 11,867	$ 25,448

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Other Commitments [Line Items]
General and administrative costs and expenses	$ 12,605	$ 13,910	$ 41,375	$ 42,798
Commitments And Contingencies Additional Textual [Abstract]
Remaining environmental accrued liability recorded	0		0		$ 216
Maximum remaining obligation	2,700		2,700
U S Bank Money Market [Member]
Commitments And Contingencies Additional Textual [Abstract]
Held-to-maturity investment, amortized cost	149,300		149,300
Transition Services Agreement [Member]
Other Commitments [Line Items]
General and administrative costs and expenses	$ 900		$ 1,400

Commitments and Contingencies75

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