Amplify Energy (AMPYW) 10-Q 3 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Jul. 29, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
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		83,484,115

UNAUDITED CONDENSED CONSOLIDATE

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents		$ 599
Accounts receivable	$ 46,087	60,239
Short-term derivative instruments	140,492	272,320
Prepaid expenses and other current assets	12,040	7,028
Total current assets	198,619	340,186
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	3,128,180	3,616,325
Support equipment and facilities	198,645	205,876
Other	15,024	2,671
Accumulated depreciation, depletion and impairment	(1,521,606)	(1,878,549)
Property and equipment, net	1,820,243	1,946,323
Long-term derivative instruments	329,231	461,810
Restricted investments	156,873	152,631
Assets held for sale (Note 3)	30,143
Other long-term assets	4,974	5,053
Total assets	2,540,083	2,906,003
Current liabilities:
Accounts payable	12,447	8,792
Accounts payable - affiliates		3,339
Revenues payable	23,509	25,504
Accrued liabilities (Note 2)	52,174	52,923
Assets held for sale (Note 3)	599
Short-term derivative instruments	2,140	2,850
Total current liabilities	90,869	93,408
Long-term debt (Note 7)	1,824,604	2,000,579
Asset retirement obligations	149,865	162,989
Long-term derivative instruments	2,220	1,441
Deferred tax liabilities	2,223	2,094
Assets held for sale (Note 3)	11,819
Other long-term liabilities	4,240
Total liabilities	2,085,840	2,260,511
Commitments and contingencies (Note 12)
Partners' equity:
General partner (86,797 units outstanding at December 31, 2015)		848
Total partners' equity	454,243	645,492
Total liabilities and equity	2,540,083	2,906,003
Limited Partners Common Units [Member]
Partners' equity:
Limited partners units	454,243	644,644
Total partners' equity	$ 454,243	$ 644,644

UNAUDITED CONDENSED CONSOLIDAT3

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Jun. 30, 2016	Dec. 31, 2015
General partner, units outstanding	0	86,797
Limited Partners Common Units [Member]
Limited partners, units outstanding	83,488,304	82,906,400

UNAUDITED CONDENSED STATEMENTS

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues:
Oil & natural gas sales	$ 67,780	$ 97,221	$ 128,403	$ 189,170
Other revenues	286	917	529	1,786
Total revenues	68,066	98,138	128,932	190,956
Costs and expenses:
Lease operating	29,354	44,888	65,050	85,366
Gathering, processing, and transportation	8,823	9,548	18,032	18,214
Exploration	15	32	137	122
Taxes other than income	3,485	6,058	7,493	12,713
Depreciation, depletion, and amortization	44,413	46,286	88,842	97,552
Impairment of proved oil and natural gas properties			8,342	251,347
General and administrative	15,246	14,377	28,770	28,888
Accretion of asset retirement obligations	2,712	1,686	5,419	3,320
(Gain) loss on commodity derivative instruments	124,580	61,403	72,835	(84,056)
(Gain) loss on sale of properties	(3,539)		(3,635)
Other, net	(52)	(943)	67	(943)
Total costs and expenses	225,037	183,335	291,352	412,523
Operating income (loss)	(156,971)	(85,197)	(162,420)	(221,567)
Other income (expense):
Interest expense, net	(32,143)	(27,910)	(64,695)	(57,150)
Other income (expense)		124		284
Gain on extinguishment of debt	41,664		41,664	422
Total other income (expense)	9,521	(27,786)	(23,031)	(56,444)
Income (loss) before income taxes	(147,450)	(112,983)	(185,451)	(278,011)
Income tax benefit (expense)	(100)	(876)	(196)	1,494
Net income (loss)	(147,550)	(113,859)	(185,647)	(276,517)
Net income (loss) attributable to noncontrolling interest		65		224
Net income (loss) attributable to Memorial Production Partners LP	(147,550)	(113,924)	(185,647)	(276,741)
Limited partners' interest in net income (loss):
Net income (loss) attributable to Memorial Production Partners LP	(147,550)	(113,924)	(185,647)	(276,741)
Net (income) loss allocated to previous owners				2,268
Net (income) loss allocated to general partner	128	90	168	228
Net (income) loss allocated to NGP IDRs		(28)		(56)
Limited partners' interest in net income (loss)	$ (147,422)	$ (113,862)	$ (185,479)	$ (274,301)
Earnings per unit: (Note 9)
Basic and diluted earnings per unit	$ (1.78)	$ (1.36)	$ (2.24)	$ (3.26)
Weighted average limited partner units outstanding:
Basic and diluted	83,007	83,902	82,971	84,119

UNAUDITED CONDENSED STATEMENTS5

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities:
Net income (loss)	$ (185,647)	$ (276,517)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	88,842	97,552
Impairment of proved oil and natural gas properties	8,342	251,347
(Gain) loss on derivative instruments	78,361	(80,970)
Cash settlements (paid) received on expired derivative instruments	146,817	112,315
Cash settlements on terminated commodity derivatives	39,299	27,063
Premiums paid for commodity derivatives		(27,063)
Bad debt expense	1,601
Deferred income tax expense (benefit)	129	(1,637)
Amortization of deferred financing costs	2,550	3,116
Gain on extinguishment of debt	(41,664)	(422)
Accretion of senior notes net discount	1,201	1,204
Accretion of asset retirement obligations	5,419	3,320
Unit-based compensation (see Note 10)	5,299	4,906
Settlement of asset retirement obligations	(869)	(780)
Gain on sale of properties	(3,635)
Changes in operating assets and liabilities:
Accounts receivable	13,414	9,668
Prepaid expenses and other assets	(2,268)	(849)
Payables and accrued liabilities	(4,460)	(11,056)
Other	3,241	521
Net cash provided by operating activities	155,972	111,718
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(6,095)
Acquisition post-closing adjustments receipts		9,570
Additions to oil and gas properties	(36,553)	(128,323)
Additions to other property and equipment	(7,265)	(83)
Additions to restricted investments	(4,242)	(2,735)
Deposits and proceeds from the sale of oil and natural gas properties	37,918
Net cash used in investing activities	(10,142)	(127,666)
Cash flows from financing activities:
Advances on revolving credit facilities	94,358	252,000
Payments on revolving credit facilities	(191,000)	(22,000)
Deferred financing costs	(1,075)	(235)
Repurchase of senior notes	(40,470)	(2,914)
Capital contributions from previous owners		1,912
Contributions related to sale of assets to NGP affiliate	26
Transfer of operating subsidiary from Memorial Resource	2,363
Proceeds from the issuance of common units	1,703
Costs incurred in conjunction with issuance of common units	(146)
Distributions to partners	(10,797)	(92,628)
Distribution to Memorial Resource (see Note 1)		(78,396)
Acquisition of General Partner (see Note 1)	(750)
Acquisition of IDRs from NGP (see Note 1)	(50)
Restricted units returned to plan	(591)	(7)
Repurchases under unit repurchase program		(42,591)
Net cash (used in) provided by financing activities	(146,429)	15,141
Net change in cash and cash equivalents	(599)	(807)
Cash and cash equivalents, beginning of period	$ 599	970
Cash and cash equivalents, end of period		$ 163

UNAUDITED CONDENSED STATEMENTS6

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY - 6 months ended Jun. 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)	(185,647)	(185,479)	(168)
Distributions	(10,797)	(10,786)	(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	1,557	1,557	0
Amortization of equity-based awards	4,999	4,999	0
Restricted units repurchased and other	(561)	(561)	0
Balance at Jun. 30, 2016	$ 454,243	$ 454,243	$ 0

Organization and Basis of Prese

Organization and Basis of Presentation	6 Months Ended
	Jun. 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, Colorado, Wyoming and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. Unless the context requires otherwise, references to: (i) “our general partner” or “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner 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 connection with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with a 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. 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 six months ended June 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	6 Months Ended
	Jun. 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): June 30, December 31, 2016 2015 Accrued interest payable $ 21,865 $ 23,192 Accrued lease operating expense 13,469 16,843 Accrued capital expenditures 6,351 8,110 Accrued general and administrative expenses 3,657 1,961 Accrued ad valorem tax 3,927 1,426 Asset retirement obligation 830 1,175 Environmental liability — 216 Other 2,075 — $ 52,174 $ 52,923 Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Six Months Ended June 30, 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized 57,589 49,369 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (1,759 ) 1,434 (Increase) decrease in accounts receivable related to acquisitions — 9,570 Repurchases under unit repurchase program — 2,710 (Increase) decrease in accounts receivable related to divestitures (856 ) — Asset retirement obligation removal related to divestitures 6,212 — Restricted units returned to plan — 1,281 New Accounting Pronouncements Improvements to Employee Share-Based Payment Accounting . In March 2016, the FASB issued an accounting standards update to reduce complexity involving several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, entities will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required. The new guidance is effective for reporting periods beginning after December 15, 2016 and interim periods within those fiscal years. Early adoption is permitted, but all of the guidance must be adopted in the same period. For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. Entities should apply the new guidance retrospectively for all periods presented related to the classification of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirements. Entities may apply the presentation changes for excess tax benefits in the statement of cash flows either prospectively or retrospectively. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Leases. In February 2016, 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. 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	6 Months Ended
	Jun. 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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 $ 927 $ 297 $ 1,013 $ 1,596 2015 Acquisitions 2015 Beta Acquisition. Pro forma Information. The following unaudited pro forma combined results of operations are provided for the three and six months ended June 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 Six Months Ended June 30, June 30, 2015 2015 (In thousands, except per unit amounts) Revenues $ 106,769 $ 205,849 Net income (loss) (109,807 ) (272,113 ) Basic and diluted earnings per unit (1.31 ) (3.21 ) Divestitures On June 14, 2016, we closed a transaction to divest assets located in the Permian Basin (“Permian Divestiture”) for a total purchase price of approximately $37.2 million, which included $36.4 million in cash and $0.8 million in accounts receivable, subject to post-closing adjustments. We recognized a gain of $7.6 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. There were no significant divestitures for the six months ended June 30, 2015. Assets Held for Sale On June 17, 2016, we entered into a definitive agreement to divest certain of our non-core assets in Colorado and Wyoming (the “Rockies Divestiture”). The assets held for sale are recorded at the lower of their carrying value or fair value less cost to sell. We recorded a loss as a result of the planned disposal of approximately $4.0 million during the three and six months ended June 30, 2016 in “(gain) loss on sale of properties” in the accompanying statement of operations. The major categories of assets and liabilities were: June 30, 2016 Assets classified as held for sale (In thousands) Property and equipment, at cost: Oil and natural gas properties, successful efforts method $ 128,375 Accumulated depreciation, depletion, and impairment (98,232 ) Property and equipment, net 30,143 Total assets classified as held for sale $ 30,143 Liabilities associated with assets held for sale Current Liabilities: Revenue payable $ 414 Accrued liabilities 185 Total current liabilities 599 Asset retirement obligations 11,819 Total liabilities associated with assets held for sale $ 12,418 Subsequent Event. We closed the Rockies Divestiture on July 14, 2016 for total proceeds of approximately $18.1 million, subject to post-closing adjustments. Proceeds from this transaction were used to reduce borrowings under our revolving credit facility. This disposition does not qualify as a discontinued operation. The income (loss) before income taxes, including the associated (gain) loss on sale of properties, related to the Permian Divestiture and the 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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 Permian Divestiture $ 6,855 $ (3,686 ) $ 4,832 $ (6,233 ) Rockies Divestiture (5,860 ) 670 (7,620 ) (55,733 )

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	6 Months Ended
	Jun. 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 June 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 June 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 June 30, 2016 and December 31, 2015 for each of the fair value hierarchy levels: Fair Value Measurements at June 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 $ — $ 519,722 $ — $ 519,722 Interest rate derivatives — — — — Total assets $ — $ 519,722 $ — $ 519,722 Liabilities: Commodity derivatives $ — $ 47,221 $ — $ 47,221 Interest rate derivatives — 7,138 — 7,138 Total liabilities $ — $ 54,359 $ — $ 54,359 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 six months ended June 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 six months ended June 30, 2015, we recognized $251.3 million of impairments primarily related to certain properties located in East Texas, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable in part due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs. · During the three and six months ended June 30, 2016, we recognized approximately $4.0 million in losses related to the Rockies Divestiture. The held for sale assets were recorded at the lower of their carrying value or fair value less cost to sell. See Note 3 for additional information regarding the Rockies Divestiture.

Risk Management and Derivative

Risk Management and Derivative Instruments	6 Months Ended
	Jun. 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 $272.7 million against amounts outstanding under our revolving credit facility at June 30, 2016, reducing our maximum credit exposure to approximately $197.3 million, of which approximately $64.3 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 three months ended June 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. In February 2015, we restructured a portion of our commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor. Cash settlement receipts of approximately $27.1 million from the termination of 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 June 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) 3,574,108 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) 3,561,667 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) 2,986,667 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 June 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 June 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 June 30, December 31, June 30, December 31, Type Balance Sheet Location 2016 2015 2016 2015 (In thousands) Commodity contracts Short-term derivative instruments $ 176,076 $ 324,265 $ 34,216 $ 53,581 Interest rate swaps Short-term derivative instruments — — 3,508 1,214 Gross fair value 176,076 324,265 37,724 54,795 Netting arrangements Short-term derivative instruments (35,584 ) (51,945 ) (35,584 ) (51,945 ) Net recorded fair value Short-term derivative instruments $ 140,492 $ 272,320 $ 2,140 $ 2,850 Commodity contracts Long-term derivative instruments $ 343,646 $ 492,730 $ 13,005 $ 30,920 Interest rate swaps Long-term derivative instruments — — 3,630 1,441 Gross fair value 343,646 492,730 16,635 32,361 Netting arrangements Long-term derivative instruments (14,415 ) (30,920 ) (14,415 ) (30,920 ) Net recorded fair value Long-term derivative instruments $ 329,231 $ 461,810 $ 2,220 $ 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 Six Months Ended Statements of June 30, June 30, Operations Location 2016 2015 2016 2015 Commodity derivative contracts (Gain) loss on commodity derivatives $ 124,580 $ 61,403 $ 72,835 $ (84,056 ) Interest rate derivatives Interest expense, net 1,844 644 5,526 3,085

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 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 six months ended June 30, 2016 (in thousands): Asset retirement obligations at beginning of period $ 164,164 Liabilities added from acquisitions or drilling 10 Liabilities removed upon sale of wells (6,212 ) Liabilities settled (869 ) Accretion expense 5,419 Revision of estimates 187 Asset retirement obligations at end of period 162,699 Less: Current portion 830 Less: Current portion - Assets held for sale 185 Less: Long-term portion - Assets held for sale 11,819 Asset retirement obligations - long-term portion $ 149,865

Long Term Debt

Long Term Debt	6 Months Ended
	Jun. 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: June 30, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 739,358 $ 836,000 2021 Senior Notes, fixed-rate, due May 2021 (2) (4) 647,787 700,000 2022 Senior Notes, fixed-rate, due August 2022 (3) (4) 464,965 496,990 Senior notes debt issuance costs, net (15,506 ) (18,297 ) Unamortized discounts (12,000 ) (14,114 ) Total long-term debt $ 1,824,604 $ 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 $349.8 million and $210.0 million at June 30, 2016 and December 31, 2015, respectively. (3) The estimated fair value of our 2022 Senior Notes was $230.2 million and $149.1 million at June 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). 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: June 30, 2016 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 925,000 Amendment to Credit Facility and Borrowing Base Redetermination On April 14, 2016, we entered into a tenth amendment to our credit agreement, dated as of December 14, 2011 (as previously amended, the “Credit Agreement”), by and among the Partnership, OLLC, the administrative agent and the other agents and lenders party thereto (the “Tenth Amendment”). The Tenth Amendment, among other things, amended the Credit Agreement to: · establish a new Applicable Margin (as defined in the Credit Agreement) that ranges from 1.25% to 2.25% per annum (based on borrowing base usage) on alternate base rate loans and from 2.25% to 3.25% per annum (based on borrowing base usage) on Eurodollar or LIBOR loans and sets the committee fee for the unused portion of the borrowing base to 0.50% per annum regardless of the borrowing base usage; · reduce the borrowing base thereunder from $1,175 million to $925 million; · require the Partnership to maintain a ratio of Consolidated First Lien Net Secured Debt (as defined in the Credit Agreement) to Consolidated EBITDAX (as defined in the Credit Agreement) of not greater than 3.25 to 1.00 as of the end of each fiscal quarter; · permit the issuance by the Partnership of secured second lien notes solely in exchange for the Partnership’s outstanding senior unsecured notes pursuant to one or more senior debt exchanges; provided that, among other things: (i) such debt shall be (A) in an aggregate principal amount not to exceed $600 million (plus any principal representing payment of interest in kind) and (B) such debt is subject to an intercreditor agreement at all times; and (ii) such debt shall not (A) have any scheduled principal amortization or have a scheduled maturity date or a date of mandatory redemption in full prior to 180 days after March 19, 2018, or (B) not contain any covenants or events of default that are more onerous or restrictive than those set forth in the Credit Agreement other than covenants or events of default that are contained in the Partnership’s existing senior unsecured notes and (C) the Consolidated Net Interest Expense (as defined in the Credit Agreement) for the 12-month period following the exchange, after giving pro forma effect to the exchange, shall be no greater than the Consolidated Net Interest Expense for such period had the exchange not occurred; · permit the payment by the Partnership of cash distributions to its equity holders out of available cash in accordance with its partnership agreement so long as, among other things, the pro forma Availability (as defined in the Credit Agreement) shall be not less than the greater of $75 million or (x) 10% of the borrowing base then in effect with respect to any such distributions made prior to June 1, 2016 or (y) 15% of the borrowing base then in effect with respect to any such distributions made on or after June 1, 2016; provided that the aggregate amount of all such payments made in any fiscal quarter for which the ratio of the Partnership’s total debt at the time of such payment to its Consolidated EBITDAX for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available is greater than or equal to 4.00 to 1.00 will not exceed $4.15 million during such fiscal quarter; · permit the repurchase of the Partnership’s (i) outstanding senior unsecured notes, or if any, second lien debt with proceeds from Swap Liquidations (as defined in the Credit Agreement) or the sale or other disposition of oil and gas properties and (ii) outstanding senior unsecured notes with the proceeds from the release of cash securing certain governmental obligations located in the Beta Field offshore Southern California, provided that, among other things, (A) the pro forma Availability is not less than the greater of $75 million or (x) 10% of the borrowing base then in effect through May 31, 2016 or (y) 15% of the borrowing base then in effect on or after June 1, 2016, (B) the Partnership’s pro forma ratio of Consolidated First Lien Net Secured Debt to Consolidated EBITDAX is not greater than 3.00 to 1.00, and (C) the amount of proceeds from all Swap Liquidations and sales or other dispositions of oil and gas properties used to repurchase outstanding senior unsecured notes or secured second lien notes does not exceed $40 million in the aggregate, or in the case of the release of cash securing such obligations, the amount of proceeds used to repurchase outstanding senior unsecured notes does not exceed $60 million in the aggregate; · require that the oil and gas properties of the Partnership mortgaged as collateral security for the loans under the Credit Agreement represent not less than 90% of the total value of the oil and gas properties of the Partnership evaluated in the most recently completed reserve report; and · require the Partnership, in the event that at the close of any business day the aggregate amount of any unrestricted cash or cash equivalents exceeds $25 million in the aggregate, to prepay the loans under the Credit Agreement and cash collateralize any letter of credit exposure with such excess. Weighted-Average Interest Rates The following table presents the weighted-average interest rates paid, excluding commitment fees, on our consolidated variable-rate debt obligations for the periods presented: For the Three Months Ended For the Six Months Ended June 30, June 30, 2016 2015 2016 2015 OLLC revolving credit facility 3.30 % 2.08 % 2.85 % 2.01 % Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: June 30, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 3,797 $ 3,672 2021 Senior Notes (2) 9,370 11,194 2022 Senior Notes (2) 6,136 7,103 Total $ 19,303 $ 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 June 30, 2016, we had $2.1 million of letters of credit outstanding, all related to operations at our Wyoming properties. Repurchases of Senior Notes During the three and six months ended June 30, 2016, the Partnership repurchased on the open market approximately $52.2 million of its 7.625% senior notes due May 2021 and approximately $32.0 million of its 6.875% senior notes due August 2022. In connection with the repurchases, the Partnership paid approximately $40.5 million and recorded a gain on extinguishment of debt of approximately $41.7 million for the three and six months ended June 30, 2016. During the six months ended June 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 six months ended June 30, 2015.

Equity and Distributions

Equity and Distributions	6 Months Ended
	Jun. 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 (15,168 ) — Restricted common units repurchased (1) (275,241 ) — Cancellation of General Partner units — (86,797 ) Issuance of common units 822,313 — Balance, June 30, 2016 83,488,304 — (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 six months ended June 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 six months ended June 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 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 six months ended June 30, 2016, the Partnership sold 822,313 common units under the ATM program, generating net proceeds of approximately $1.6 million (net of approximately $0.1 million in commissions). At June 30, 2016, approximately $58.3 million of common units remained available for issuance under the ATM Program. 2015 Repurchases of Common Units During the six months ended June 30, 2015, we repurchased $43.9 million in common units, which represented a repurchase and retirement of 2,951,612 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 Payable Date Per Unit Distribution Affiliates 2 nd July 26, 2016 August 5, 2016 August 12, 2016 $ 0.0300 $ 2.5 $ — 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

Earnings per Unit

Earnings per Unit	6 Months Ended
	Jun. 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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 Net income (loss) attributable to Memorial Production Partners LP $ (147,550 ) $ (113,924 ) $ (185,647 ) $ (276,741 ) Less: Previous owners interest in net income (loss) — — — (2,268 ) Less: General partner's 0.1% interest in net income (loss) (1) (128 ) (117 ) (168 ) (285 ) Less: IDRs attributable to corresponding period — 54 — 110 Net income (loss) available to limited partners $ (147,422 ) $ (113,861 ) $ (185,479 ) $ (274,298 ) Weighted average limited partner units outstanding: Common units 83,007 83,902 82,971 82,845 Subordinated units — — — 1,274 Total (2) 83,007 83,902 82,971 84,119 Basic and diluted EPU $ (1.78 ) $ (1.36 ) $ (2.24 ) $ (3.26 ) (1) As a result of repurchases under the December 2014 repurchase program, our general partner had an approximate average 0.105% interest is us prior to the MEMP GP Acquisition for the three and six months ended June 30, 2016 and 0.103% interest in us for the three and six months ended June 30, 2015. (2) For the three and six months ended June 30, 2016, 694,528 and 401,460 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	6 Months Ended
	Jun. 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 (15,168 ) $ 17.24 Vested (946,083 ) $ 18.09 Restricted common units outstanding at June 30, 2016 457,287 $ 14.98 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in the six months ended June 30 The unrecognized compensation cost associated with restricted common unit awards was $6.3 million at June 30, 2016. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.54 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 a voluntary termination. The acceleration of the LTIP vesting schedule represents an improbable-to-probable modification. The grant-date fair value compensation cost of approximately $0.5 million was reversed and the modified-date grant fair value compensation cost of approximately $0.3 million was recognized. Phantom Units The following table summarizes information regarding phantom unit awards granted under the LTIP: Number of Units Phantom units outstanding at December 31, 2015 — January 2016 Issuance 155,601 June 2016 Issuance 6,013,417 Phantom units outstanding at June 30, 2016 6,169,018 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 shall be settled through an amount of cash in a single lump sum payment equal to the product of (y) the closing price of our common units on the vesting date and (z) the number of such vested phantom units. In lieu of a cash payment, the board of directors of our general partner, in its discretion, may elect for the recipient to receive either a number of common units equal to the number of such vested phantom units or a combination of cash and common units. For the three and six months ended June 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. 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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 Equity classified awards Restricted common units $ 2,507 $ 2,565 $ 4,999 $ 4,906 Liability classified awards Phantom units 224 — 300 — $ 2,731 $ 2,565 $ 5,299 $ 4,906

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 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 three months ended June 30, 2015, we paid less than $0.1 million to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities. During the six months ended June 30, 2016 and 2015, we paid less than $0.1 million and $0.3 million, respectively, to Multi-Shot, LLC. 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 have 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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 $ 4,418 $ 8,456 $ 11,867 $ 17,009 Beta Management Agreement Memorial Resource, through its wholly-owned subsidiary Beta Operating Company, LLC, provided management and administrative oversight related to our offshore Southern California oil and gas properties in exchange for an annual management fee. Memorial Resource had the right to receive approximately $0.4 million from Rise Energy Beta, LLC annually. This agreement was terminated in November 2015 in connection with the 2015 Beta Acquisition. On June 1, 2016, Memorial Resource assigned and transferred Beta Operating Company, LLC 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 six months ended June 30, 2015, we incurred gathering and saltwater disposal fees of approximately $1.1 million and $2.0 million under these agreements.

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 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. We recorded $0.5 million of general and administrative expenses related to the transition services agreement with Memorial Resource for the three months ended June 30, 2016. 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 June 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): June 30, 2016 $ 148,000 December 31, 2016 $ 152,000 In the event the account balance is less than the contractual amount, we must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by us. As of June 30, 2016, the remaining obligation was approximately $4.0 million. In 2015, the BOEM issued a preliminary report that indicated the estimated costs of decommissioning may further increase, and we expect the amount to be finalized during 2016 after negotiations are completed. The held-to-maturity investments held in the trust account as of June 30, 2016 for the U.S. Bank money market cash equivalent was $148.0 million.

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	Note 13. Subsequent Events See Note 3 for additional information regarding the Rockies Divestiture.

Organization and Basis of Pre20

Organization and Basis of Presentation (Policies)	6 Months Ended
	Jun. 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, Colorado, Wyoming and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. Unless the context requires otherwise, references to: (i) “our general partner” or “MEMP GP” refer to Memorial Production Partners GP LLC, our general partner 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 connection with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with a 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.
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 six months ended June 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): June 30, December 31, 2016 2015 Accrued interest payable $ 21,865 $ 23,192 Accrued lease operating expense 13,469 16,843 Accrued capital expenditures 6,351 8,110 Accrued general and administrative expenses 3,657 1,961 Accrued ad valorem tax 3,927 1,426 Asset retirement obligation 830 1,175 Environmental liability — 216 Other 2,075 — $ 52,174 $ 52,923
Supplemental Cash Flows	Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Six Months Ended June 30, 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized 57,589 49,369 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (1,759 ) 1,434 (Increase) decrease in accounts receivable related to acquisitions — 9,570 Repurchases under unit repurchase program — 2,710 (Increase) decrease in accounts receivable related to divestitures (856 ) — Asset retirement obligation removal related to divestitures 6,212 — Restricted units returned to plan — 1,281
New Accounting Pronouncements	New Accounting Pronouncements Improvements to Employee Share-Based Payment Accounting . In March 2016, the FASB issued an accounting standards update to reduce complexity involving several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, entities will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required. The new guidance is effective for reporting periods beginning after December 15, 2016 and interim periods within those fiscal years. Early adoption is permitted, but all of the guidance must be adopted in the same period. For the amendments that change the recognition and measurement of share-based payment awards, the new guidance requires transition under a modified retrospective approach, with a cumulative-effect adjustment made to retained earnings as of the beginning of the fiscal period in which the guidance is adopted. Prospective application is required for the accounting for excess tax benefits and tax deficiencies. Entities should apply the new guidance retrospectively for all periods presented related to the classification of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirements. Entities may apply the presentation changes for excess tax benefits in the statement of cash flows either prospectively or retrospectively. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Leases. In February 2016, 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. 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)	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Summary of Current Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands): June 30, December 31, 2016 2015 Accrued interest payable $ 21,865 $ 23,192 Accrued lease operating expense 13,469 16,843 Accrued capital expenditures 6,351 8,110 Accrued general and administrative expenses 3,657 1,961 Accrued ad valorem tax 3,927 1,426 Asset retirement obligation 830 1,175 Environmental liability — 216 Other 2,075 — $ 52,174 $ 52,923
Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands): For the Six Months Ended June 30, 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized 57,589 49,369 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (1,759 ) 1,434 (Increase) decrease in accounts receivable related to acquisitions — 9,570 Repurchases under unit repurchase program — 2,710 (Increase) decrease in accounts receivable related to divestitures (856 ) — Asset retirement obligation removal related to divestitures 6,212 — Restricted units returned to plan — 1,281

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	6 Months Ended
	Jun. 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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 $ 927 $ 297 $ 1,013 $ 1,596
Supplemental Pro Forma Information	The following unaudited pro forma combined results of operations are provided for the three and six months ended June 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 Six Months Ended June 30, June 30, 2015 2015 (In thousands, except per unit amounts) Revenues $ 106,769 $ 205,849 Net income (loss) (109,807 ) (272,113 ) Basic and diluted earnings per unit (1.31 ) (3.21 )
Assets and Liabilities Classified as Assets Held for Sale	The major categories of assets and liabilities were: June 30, 2016 Assets classified as held for sale (In thousands) Property and equipment, at cost: Oil and natural gas properties, successful efforts method $ 128,375 Accumulated depreciation, depletion, and impairment (98,232 ) Property and equipment, net 30,143 Total assets classified as held for sale $ 30,143 Liabilities associated with assets held for sale Current Liabilities: Revenue payable $ 414 Accrued liabilities 185 Total current liabilities 599 Asset retirement obligations 11,819 Total liabilities associated with assets held for sale $ 12,418
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 the 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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 Permian Divestiture $ 6,855 $ (3,686 ) $ 4,832 $ (6,233 ) Rockies Divestiture (5,860 ) 670 (7,620 ) (55,733 )

Fair Value Measurements of Fi23

Fair Value Measurements of Financial Instruments (Tables)	6 Months Ended
	Jun. 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 June 30, 2016 and December 31, 2015 for each of the fair value hierarchy levels: Fair Value Measurements at June 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 $ — $ 519,722 $ — $ 519,722 Interest rate derivatives — — — — Total assets $ — $ 519,722 $ — $ 519,722 Liabilities: Commodity derivatives $ — $ 47,221 $ — $ 47,221 Interest rate derivatives — 7,138 — 7,138 Total liabilities $ — $ 54,359 $ — $ 54,359 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)	6 Months Ended
	Jun. 30, 2016
Open Commodity Positions	At June 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) 3,574,108 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) 3,561,667 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 June 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 June 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 June 30, December 31, June 30, December 31, Type Balance Sheet Location 2016 2015 2016 2015 (In thousands) Commodity contracts Short-term derivative instruments $ 176,076 $ 324,265 $ 34,216 $ 53,581 Interest rate swaps Short-term derivative instruments — — 3,508 1,214 Gross fair value 176,076 324,265 37,724 54,795 Netting arrangements Short-term derivative instruments (35,584 ) (51,945 ) (35,584 ) (51,945 ) Net recorded fair value Short-term derivative instruments $ 140,492 $ 272,320 $ 2,140 $ 2,850 Commodity contracts Long-term derivative instruments $ 343,646 $ 492,730 $ 13,005 $ 30,920 Interest rate swaps Long-term derivative instruments — — 3,630 1,441 Gross fair value 343,646 492,730 16,635 32,361 Netting arrangements Long-term derivative instruments (14,415 ) (30,920 ) (14,415 ) (30,920 ) Net recorded fair value Long-term derivative instruments $ 329,231 $ 461,810 $ 2,220 $ 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 Six Months Ended Statements of June 30, June 30, Operations Location 2016 2015 2016 2015 Commodity derivative contracts (Gain) loss on commodity derivatives $ 124,580 $ 61,403 $ 72,835 $ (84,056 ) Interest rate derivatives Interest expense, net 1,844 644 5,526 3,085
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) 2,986,667 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)	6 Months Ended
	Jun. 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 six months ended June 30, 2016 (in thousands): Asset retirement obligations at beginning of period $ 164,164 Liabilities added from acquisitions or drilling 10 Liabilities removed upon sale of wells (6,212 ) Liabilities settled (869 ) Accretion expense 5,419 Revision of estimates 187 Asset retirement obligations at end of period 162,699 Less: Current portion 830 Less: Current portion - Assets held for sale 185 Less: Long-term portion - Assets held for sale 11,819 Asset retirement obligations - long-term portion $ 149,865

Long Term Debt (Tables)

Long Term Debt (Tables)	6 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations at the dates indicated: June 30, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 739,358 $ 836,000 2021 Senior Notes, fixed-rate, due May 2021 (2) (4) 647,787 700,000 2022 Senior Notes, fixed-rate, due August 2022 (3) (4) 464,965 496,990 Senior notes debt issuance costs, net (15,506 ) (18,297 ) Unamortized discounts (12,000 ) (14,114 ) Total long-term debt $ 1,824,604 $ 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 $349.8 million and $210.0 million at June 30, 2016 and December 31, 2015, respectively. (3) The estimated fair value of our 2022 Senior Notes was $230.2 million and $149.1 million at June 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: June 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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 OLLC revolving credit facility 3.30 % 2.08 % 2.85 % 2.01 %
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: June 30, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 3,797 $ 3,672 2021 Senior Notes (2) 9,370 11,194 2022 Senior Notes (2) 6,136 7,103 Total $ 19,303 $ 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)	6 Months Ended
	Jun. 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 (15,168 ) — Restricted common units repurchased (1) (275,241 ) — Cancellation of General Partner units — (86,797 ) Issuance of common units 822,313 — Balance, June 30, 2016 83,488,304 — (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 six months ended June 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 Payable Date Per Unit Distribution Affiliates 2 nd July 26, 2016 August 5, 2016 August 12, 2016 $ 0.0300 $ 2.5 $ — 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

Earnings per Unit (Tables)

Earnings per Unit (Tables)	6 Months Ended
	Jun. 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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 Net income (loss) attributable to Memorial Production Partners LP $ (147,550 ) $ (113,924 ) $ (185,647 ) $ (276,741 ) Less: Previous owners interest in net income (loss) — — — (2,268 ) Less: General partner's 0.1% interest in net income (loss) (1) (128 ) (117 ) (168 ) (285 ) Less: IDRs attributable to corresponding period — 54 — 110 Net income (loss) available to limited partners $ (147,422 ) $ (113,861 ) $ (185,479 ) $ (274,298 ) Weighted average limited partner units outstanding: Common units 83,007 83,902 82,971 82,845 Subordinated units — — — 1,274 Total (2) 83,007 83,902 82,971 84,119 Basic and diluted EPU $ (1.78 ) $ (1.36 ) $ (2.24 ) $ (3.26 ) (1) As a result of repurchases under the December 2014 repurchase program, our general partner had an approximate average 0.105% interest is us prior to the MEMP GP Acquisition for the three and six months ended June 30, 2016 and 0.103% interest in us for the three and six months ended June 30, 2015. (2) For the three and six months ended June 30, 2016, 694,528 and 401,460 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)	6 Months Ended
	Jun. 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 (15,168 ) $ 17.24 Vested (946,083 ) $ 18.09 Restricted common units outstanding at June 30, 2016 457,287 $ 14.98 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in the six months ended June 30
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 — January 2016 Issuance 155,601 June 2016 Issuance 6,013,417 Phantom units outstanding at June 30, 2016 6,169,018
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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 Equity classified awards Restricted common units $ 2,507 $ 2,565 $ 4,999 $ 4,906 Liability classified awards Phantom units 224 — 300 — $ 2,731 $ 2,565 $ 5,299 $ 4,906

Related Party Transactions (Tab

Related Party Transactions (Tables)	6 Months Ended
	Jun. 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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 $ 4,418 $ 8,456 $ 11,867 $ 17,009

Commitments and Contingencies (

Commitments and Contingencies (Tables)	6 Months Ended
	Jun. 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): June 30, 2016 $ 148,000 December 31, 2016 $ 152,000

Organization and Basis of Pre32

Organization and Basis of Presentation - Additional Information (Detail)	Apr. 27, 2016USD ($)	Jun. 30, 2016Segment	Jun. 01, 2016
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments | Segment		1
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	Jun. 30, 2016	Dec. 31, 2015
Accrued Liabilities Current [Abstract]
Accrued interest payable	$ 21,865	$ 23,192
Accrued lease operating expense	13,469	16,843
Accrued capital expenditures	6,351	8,110
Accrued general and administrative expenses	3,657	1,961
Accrued ad valorem tax	3,927	1,426
Asset retirement obligation	830	1,175
Environmental liability	0	216
Other	2,075
Accrued liabilities, Total	$ 52,174	$ 52,923

Summary of Significant Accoun34

Summary of Significant Accounting Policies - Summary of Supplemental Cash Flows (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$ 57,589	$ 49,369
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	(1,759)	1,434
(Increase) decrease in accounts receivable related to acquisitions		9,570
Repurchases under unit repurchase program		2,710
(Increase) decrease in accounts receivable related to divestitures	(856)
Asset retirement obligation removal related to divestitures	$ 6,212
Restricted units returned to plan		$ 1,281

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisition and Divestiture-Related Expenses (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
General and Administrative Expense
Business Acquisition [Line Items]
Business Acquisition and Divestiture, Related Expenses	$ 927	$ 297	$ 1,013	$ 1,596

Acquisitions and Divestitures36

Acquisitions and Divestitures - Supplemental Pro Forma Information (Detail) - 2015 Beta Acquisition [Member] - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2015
Business Acquisition [Line Items]
Revenues	$ 106,769	$ 205,849
Net income (loss)	$ (109,807)	$ (272,113)
Basic and diluted earnings per unit	$ (1.31)	$ (3.21)

Acquisitions and Divestitures37

Acquisitions and Divestitures - Additional Information (Detail) - USD ($) $ in Millions	Jul. 14, 2016	Jun. 14, 2016	Jun. 30, 2016	Jun. 30, 2016
Permian Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Disposal group, not discontinued operation, (gain) loss on properties		$ 7.6
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Disposal group, not discontinued operation, (gain) loss on properties			$ (4)	$ (4)
Disposal Group Not Discontinued Operation [Member] | Permian Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Purchase price of divestitures		37.2
Disposal Group Not Discontinued Operation [Member] | Permian Divestiture [Member] | Accounts Receivable [Member]
Business Acquisition And Divestiture [Line Items]
Purchase price of divestitures		0.8
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] | Subsequent Event [Member]
Business Acquisition And Divestiture [Line Items]
Purchase price of divestitures	$ 18.1

Acquisitions and Divestitures38

Acquisitions and Divestitures - Assets and Liabilities Classified as Assets Held for Sale (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	$ 3,128,180	$ 3,616,325
Accumulated depreciation, depletion, and impairment	(1,521,606)	(1,878,549)
Property and equipment, net	1,820,243	1,946,323
Total assets classified as held for sale	30,143
Current Liabilities:
Revenue payable	23,509	25,504
Accrued liabilities	52,174	52,923
Total current liabilities	90,869	93,408
Asset retirement obligations	149,865	$ 162,989
Rockies Divestiture [Member]
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	128,375
Accumulated depreciation, depletion, and impairment	(98,232)
Property and equipment, net	30,143
Total assets classified as held for sale	30,143
Current Liabilities:
Revenue payable	414
Accrued liabilities	185
Total current liabilities	599
Asset retirement obligations	11,819
Total liabilities associated with assets held for sale	$ 12,418

Acquisitions and Divestitures39

Acquisitions and Divestitures - Schedule of Income (Loss) before Income Taxes Including Gain Loss on Divestiture (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Business Acquisition And Divestiture [Line Items]
Income (loss) before income taxes	$ 147,450	$ 112,983	$ 185,451	$ 278,011
Permian Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Income (loss) before income taxes	6,855	(3,686)	4,832	(6,233)
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Income (loss) before income taxes	$ (5,860)	$ 670	$ (7,620)	$ (55,733)

Fair Value Measurements of Fi40

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value [Member] - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	$ 519,722	$ 816,995
Interest rate derivatives, Assets	0	0
Liabilities	54,359	87,156
Interest rate derivatives, Liabilities	7,138	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	519,722	816,995
Interest rate derivatives, Assets	0	0
Liabilities	54,359	87,156
Interest rate derivatives, Liabilities	7,138	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	519,722	816,995
Liabilities	47,221	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	519,722	816,995
Liabilities	47,221	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 Fi41

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties		$ 8,342	$ 251,347
Carrying value of properties after impairment charges	$ 1,820,243	1,820,243		$ 1,946,323
Rockies Divestiture [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Carrying value of properties after impairment charges	30,143	30,143
Disposal group, not discontinued operation, (gain) loss on properties	4,000	4,000
East Texas, Wyoming and Colorado [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties		8,300	$ 251,300
Carrying value of properties after impairment charges	$ 11,000	$ 11,000

Risk Management and Derivativ42

Risk Management and Derivative Instruments - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	6 Months Ended
	Feb. 28, 2015	Jun. 30, 2016	Jun. 30, 2016
Derivative Instruments Gain Loss [Line Items]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk			$ 272.7
Maximum amount of loss due to credit risk			197.3
Cash settlement receipt	$ 27.1	$ 39.3
One Counterparty [Member]
Derivative Instruments Gain Loss [Line Items]
Maximum amount of loss due to credit risk			$ 64.3

Risk Management and Derivativ43

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	6 Months Ended
	Jun. 30, 2016$ / bblMMBTU$ / MMBTUbbl
Natural Gas Derivative Contracts Fixed Price Swap 2016 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,574,108
Weighted-average fixed price | $ / MMBTU	4.14
Natural Gas Derivative Contracts Basis Swaps 2016 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,561,667
Spread | $ / MMBTU	(0.07)
Crude Oil Derivative Contracts Fixed Price Swap 2016 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	184,313
Weighted-average fixed price	74.27
Crude Oil Derivative Contracts Basis Swaps 2016 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	99,000
Spread	(12.28)
Crude Oil Derivative Contracts Purchased Put Options 2016 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
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]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	195,100
Weighted-average fixed price	34.01
Natural Gas Derivative Contracts Fixed Price Swap 2017 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,350,067
Weighted-average fixed price | $ / MMBTU	4.06
Natural Gas Derivative Contracts Basis Swaps 2017 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	2,210,000
Spread | $ / MMBTU	(0.04)
Crude Oil Derivative Contracts Fixed Price Swap 2017 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	301,600
Weighted-average fixed price	85
Crude Oil Derivative Contracts Basis Swaps 2017 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	37,500
Spread	(12.20)
NGL Derivative Contracts Fixed Price Swap 2017 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	43,300
Weighted-average fixed price	37.55
Natural Gas Derivative Contracts Fixed Price Swap 2018 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	3,060,000
Weighted-average fixed price | $ / MMBTU	4.18
Natural Gas Derivative Contracts Basis Swaps 2018 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	1,315,000
Spread | $ / MMBTU	(0.02)
Crude Oil Derivative Contracts Fixed Price Swap 2018 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	312,000
Weighted-average fixed price	83.74
Natural Gas Derivative Contracts Fixed Price Swap 2019 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	2,814,583
Weighted-average fixed price | $ / MMBTU	4.31
Natural Gas Derivative Contracts Basis Swaps 2019 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	900,000
Spread | $ / MMBTU	0.01
Crude Oil Derivative Contracts Fixed Price Swap 2019 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	160,000
Weighted-average fixed price	85.52

Risk Management and Derivativ44

Risk Management and Derivative Instruments - Open Commodity Positions Disaggregated Basis (Detail) - Disaggregated Basis Swap [Member]	6 Months Ended
	Jun. 30, 2016MMBTU$ / MMBTU$ / bblbbl
Natural Gas Derivative Contracts NGPL TexOk Basis Swaps 2016 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	2,986,667
Spread | $ / MMBTU	(0.07)
Natural Gas Derivative Contracts HSC Basis Swaps 2016 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	135,000
Spread | $ / MMBTU	0.07
Natural Gas Derivative Contracts CIG Basis Swaps 2016 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	170,000
Spread | $ / MMBTU	(0.30)
Natural Gas Derivative Contracts TETCO STX Basis Swaps 2016 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	270,000
Spread | $ / MMBTU	0.06
Crude Oil Derivative Contracts Midway-Sunset Basis Swaps 2016 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	99,000
Spread | $ / bbl	(12.28)
Natural Gas Derivative Contracts NGPL TexOk Basis Swaps 2017 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	1,800,000
Spread | $ / MMBTU	(0.07)
Natural Gas Derivative Contracts HSC Basis Swaps 2017 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	115,000
Spread | $ / MMBTU	0.14
Natural Gas Derivative Contracts TETCO STX Basis Swaps 2017 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	295,000
Spread | $ / MMBTU	0.03
Crude Oil Derivative Contracts Midway-Sunset Basis Swaps 2017 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (Bbls) | bbl	37,500
Spread | $ / bbl	(12.20)
Natural Gas Derivative Contracts NGPL TexOk Basis Swaps 2018 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	1,200,000
Spread | $ / MMBTU	(0.03)
Natural Gas Derivative Contracts HSC Basis Swaps 2018 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	115,000
Spread | $ / MMBTU	0.15
Natural Gas Derivative Contracts NGPL TexOk Basis Swaps 2019 [Member]
Combination Of Commodity Derivatives To Manage Exposure To Commodity Price Volatility [Abstract]
Average Monthly Volume (MMBtu) | MMBTU	900,000
Spread | $ / MMBTU	0.01

Risk Management and Derivativ45

Risk Management and Derivative Instruments - Interest Rate Swap Open Positions (Detail) $ in Thousands	6 Months Ended
	Jun. 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 Derivativ46

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 140,492	$ 272,320
Asset Derivatives, Net recorded fair value	329,231	461,810
Liability Derivatives, Net recorded fair value	2,140	2,850
Liability Derivatives, Net recorded fair value	2,220	1,441
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	176,076	324,265
Asset Derivatives, Netting arrangements	(35,584)	(51,945)
Asset Derivatives, Net recorded fair value	140,492	272,320
Liability Derivatives, Gross fair value	37,724	54,795
Liability Derivatives, Netting arrangements	(35,584)	(51,945)
Liability Derivatives, Net recorded fair value	2,140	2,850
Short-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	176,076	324,265
Liability Derivatives, Gross fair value	34,216	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	3,508	1,214
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	343,646	492,730
Asset Derivatives, Netting arrangements	(14,415)	(30,920)
Asset Derivatives, Net recorded fair value	329,231	461,810
Liability Derivatives, Gross fair value	16,635	32,361
Liability Derivatives, Netting arrangements	(14,415)	(30,920)
Liability Derivatives, Net recorded fair value	2,220	1,441
Long-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	343,646	492,730
Liability Derivatives, Gross fair value	13,005	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	$ 3,630	$ 1,441

Risk Management and Derivativ47

Risk Management and Derivative Instruments - Unrealized and Realized Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	$ 124,580	$ 61,403	$ 72,835	$ (84,056)
Interest expense, net	(32,143)	(27,910)	(64,695)	(57,150)
Commodity derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	124,580	61,403	72,835	(84,056)
Interest rate derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net	$ 1,844	$ 644	$ 5,526	$ 3,085

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 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			10
Liabilities removed upon sale of wells			(6,212)
Liabilities settled			(869)
Accretion expense	$ 2,712	$ 1,686	5,419	$ 3,320
Revision of estimates			187
Asset retirement obligations at end of period	162,699		162,699
Less: Current portion	830		830		$ 1,175
Less: Current portion - Assets held for sale	185		185
Less: Long-term portion - Assets held for sale	11,819		11,819
Asset retirement obligations - long-term portion	$ 149,865		$ 149,865		$ 162,989

Long Term Debt - Consolidated D

Long Term Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized discounts		$ (12,000)	$ (14,114)
Total long-term debt		1,824,604	2,000,579
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Revolving credit facility	[1]	739,358	836,000
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Senior Notes, fixed-rate	[2],[3]	647,787	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		$ (15,506)	$ (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 $349.8 million and $210.0 million at June 30, 2016 and December 31, 2015, respectively.
[4]	The estimated fair value of our 2022 Senior Notes was $230.2 million and $149.1 million at June 30, 2016 and December 31, 2015, respectively.

Long Term Debt - Consolidated50

Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)	6 Months Ended
	Jun. 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	$ 349,800,000	$ 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	$ 230,200,000	$ 149,100,000

Long Term Debt - Additional Inf

Long Term Debt - Additional Information (Detail)	Jun. 30, 2016
Universal Shelf Registration Statement [Member]
Line of Credit Facility [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	Jun. 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		$ 2,100,000
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 ($)	Jun. 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 Ba54

Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail)	Jun. 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 - 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		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
OLLC revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates	3.30%	2.08%	2.85%	2.01%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized deferred financing costs		$ 19,303	$ 21,969
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Unamortized deferred financing costs	[1]	3,797	3,672
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[2]	9,370	11,194
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[2]	$ 6,136	$ 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 U57

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Parenthetical) (Detail)	Jun. 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	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2015
Debt Instrument [Line Items]
Payment for repurchase of debt	$ 40,500	$ 40,500	$ 2,600
Gain on extinguishment of debt	41,664	41,664	422
7.625% senior notes due May 2021 [Member]
Debt Instrument [Line Items]
Repurchase of debt	52,200	52,200
6.875% senior notes due August 2022 [Member]
Debt Instrument [Line Items]
Repurchase of debt	$ 32,000	$ 32,000	$ 3,000

Equity and Distributions - Summ

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Detail)	6 Months Ended
	Jun. 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	(15,168)
Restricted common units repurchased	(275,241)
Cancellation of General Partner units	0
Issuance of common units	822,313
Ending balance	83,488,304
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 - Su60

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Parenthetical) (Detail) $ in Millions	6 Months Ended
	Jun. 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	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Jun. 30, 2015	May 25, 2016
Limited Partners Capital Account [Line Items]
Proceeds from sale of common units, net		$ 1,703,000
Common units amount repurchased under repurchase program			$ 43,900,000
Common units repurchased under repurchase program			2,951,612
ATM Program
Limited Partners Capital Account [Line Items]
Authorized Value				$ 60,000,000
Common unit, issued	822,313	822,313
Proceeds from sale of common units, net	$ 1,600,000	$ 1,600,000
Commissions on sale of common unit	100,000	100,000
Authorized Value Remaining	$ 58,300,000	$ 58,300,000

Equity and Distributions - Su62

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
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
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
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
Distribution per unit	$ 0.0300	$ 0.0300	$ 0.1000	$ 0.3000	$ 0.5500	$ 0.5500
Aggregate Distribution	$ 2,500,000	$ 2,500,000	$ 8,300,000	$ 24,900,000	$ 45,700,000	$ 46,300,000
Distribution Received by Affiliates					$ 100,000	$ 200,000
Maximum [Member]
Limited Partners Capital Account [Line Items]
Distribution Received by Affiliates		$ 100,000	$ 100,000	$ 100,000

Earnings Per Unit - Calculation

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Unit [Line Items]
Net income (loss) attributable to Memorial Production Partners LP	$ (147,550)	$ (113,924)	$ (185,647)	$ (276,741)
Less: Previous owners interest in net income (loss)				(2,268)
Less: General partner's 0.1% interest in net income (loss)	(128)	(117)	(168)	(285)
Less: IDRs attributable to corresponding period		54		110
Net income (loss) available to limited partners	$ (147,422)	$ (113,861)	$ (185,479)	$ (274,298)
Weighted average limited partner units outstanding:
Basic and diluted	83,007	83,902	82,971	84,119
Basic and diluted EPU	$ (1.78)	$ (1.36)	$ (2.24)	$ (3.26)
Common Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding	83,007	83,902	82,971	82,845
Subordinated Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding				1,274

Earnings Per Unit - Calculati64

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Parenthetical) (Detail) - shares	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 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	694,528		401,460
Average [Member]
Earnings Per Unit [Line Items]
General partner's interest in net income, percentage	0.105%	0.103%	0.105%	0.103%

Unit-based Awards - Summary of

Unit-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Detail) - Restricted Common Units [Member]	6 Months Ended
	Jun. 30, 2016$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units outstanding, Beginning Balance | shares	1,368,538
Granted, Number of Units | shares	50,000
Restricted common units forfeited | shares	(15,168)
Vested, Number of Units | shares	(946,083)
Units outstanding, Ending Balance | shares	457,287
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance | $ / shares	$ 17.61
Granted, Weighted-Average Grant Date Fair Value per Unit | $ / shares	2.41
Forfeited, Weighted-Average Grant Date Fair Value per Unit | $ / shares	17.24
Vested, Weighted-Average Grant Date Fair Value per Unit | $ / shares	18.09
Restricted common units outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance | $ / shares	$ 14.98

Unit-based Awards - Summary o66

Unit-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Common Units [Member] $ / shares in Units, $ in Millions	Jun. 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	Jun. 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			$ 6.3	$ 6.3
Weighted-average period of unrecognized compensation cost				1 year 6 months 15 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 o68

Unit-based Awards - Summary of Information Regarding Phantom Unit Awards (Detail) - Phantom units [Member]	6 Months Ended
	Jun. 30, 2016shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units outstanding, Beginning Balance	0
Units outstanding, Ending Balance	6,169,018
January 2016 Issuance [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Issuance, Number of Units	155,601
June 2016 Issuance [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Issuance, Number of Units	6,013,417

Unit-based Awards - Summary o69

Unit-based Awards - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	$ 2,731	$ 2,565	$ 5,299	$ 4,906
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	2,507	2,565	4,999	4,906
Phantom units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	$ 224	$ 0	$ 300	$ 0

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($)	Jun. 01, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Apr. 27, 2016
Multi-Shot, LLC [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
Classic Operating And Classic Pipeline [Member] | Water Disposal Agreement [Member]
Related Party Transaction [Line Items]
Salt water disposal fees		$ 1,100,000		$ 2,000,000

Related Party Transactions - Sc

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

Related Party Transactions - 72

Related Party Transactions - Schedule of Amount of General and Administrative Costs and Expenses Recognized (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
General and administrative costs and expenses under omnibus agreement	$ 4,418	$ 8,456	$ 11,867	$ 17,009

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Other Commitments [Line Items]
General and administrative costs and expenses	$ 15,246	$ 14,377	$ 28,770	$ 28,888
Commitments And Contingencies Additional Textual [Abstract]
Remaining environmental accrued liability recorded	0		0		$ 216
Maximum remaining obligation	4,000		4,000
U S Bank Money Market [Member]
Commitments And Contingencies Additional Textual [Abstract]
Held-to-maturity investment, amortized cost	148,000		$ 148,000
Transition Services Agreement [Member]
Other Commitments [Line Items]
General and administrative costs and expenses	$ 500

Commitments and Contingencies74

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