Amplify Energy (AMPYW) 10-K 10 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Mar. 03, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Trading Symbol	MEMP
Entity Registrant Name	MEMORIAL PRODUCTION PARTNERS LP
Entity Central Index Key	1,521,847
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		83,804,848
Entity Public Float			$ 166.5

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents		$ 15,373	$ 599
Accounts receivable		34,584	60,239
Short-term derivative instruments		69,464	272,320
Prepaid expenses and other current assets		13,163	7,028
Total current assets		132,584	340,186
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		3,115,012	3,616,325
Support equipment and facilities		199,093	205,876
Other		15,344	2,671
Accumulated depreciation, depletion and impairment		(1,749,747)	(1,878,549)
Property and equipment, net		1,579,702	1,946,323
Long-term derivative instruments		102,630	461,810
Restricted investments		156,234	152,631
Other long-term assets		2,104	5,053
Total assets		1,973,254	2,906,003
Current liabilities:
Accounts payable		4,353	8,792
Accounts payable - affiliates		0	3,339
Revenues payable		21,285	25,504
Accrued liabilities (see Note 3)		65,235	52,923
Short-term derivative instruments		0	2,850
Current portion of long-term debt (see Note 9)	[1]	1,622,904	0
Total current liabilities		1,713,777	93,408
Long-term debt (see Note 9)		0	2,000,579
Asset retirement obligations		154,913	162,989
Long-term derivative instruments		0	1,441
Deferred tax liabilities		2,280	2,094
Other long-term liabilities		2,795	0
Total liabilities		1,873,765	2,260,511
Commitments and contingencies (see Note 14)
Partners' equity:
General partner (86,797 units outstanding at December 31, 2015)		0	848
Total partners' equity		99,489	645,492
Total liabilities and equity		1,973,254	2,906,003
Limited Partners Common Units [Member]
Partners' equity:
Limited partners units		99,489	644,644
Total partners' equity		$ 99,489	$ 644,644
[1]	Due to an existing and anticipated financial covenant violations, the Partnership’s revolving credit facility and senior notes were classified as current at December 31, 2016.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
General partner, units outstanding	0	86,797
Limited Partners Common Units [Member]
Limited partners, units outstanding	83,827,920	82,906,400	80,421,992	55,877,831

STATEMENTS OF CONSOLIDATED AND

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Oil & natural gas sales	$ 284,051	$ 355,422	$ 561,677
Other revenues	529	2,725	4,366
Total revenues	284,580	358,147	566,043
Costs and expenses:
Lease operating	126,175	168,199	143,733
Gathering, processing, and transportation	34,979	34,939	31,892
Exploration	981	2,317	2,750
Taxes other than income	15,540	25,828	33,141
Depreciation, depletion, and amortization	171,629	195,814	185,955
Impairment of proved oil and natural gas properties	183,437	616,784	407,540
General and administrative	63,280	56,671	49,124
Accretion of asset retirement obligations	10,231	7,125	5,773
(Gain) loss on commodity derivative instruments	117,105	(462,890)	(492,254)
(Gain) loss on sale of properties	(2,754)	(2,998)	0
Other, net	516	(665)	(11)
Total costs and expenses	721,119	641,124	367,643
Operating income (loss)	(436,539)	(282,977)	198,400
Other income (expense):
Interest expense, net	(146,031)	(115,154)	(83,550)
Other income (expense)	8	43	(657)
Gain on extinguishment of debt	42,337	422	0
Total other income (expense)	(103,686)	(114,689)	(84,207)
Income (loss) before income taxes	(540,225)	(397,666)	114,193
Income tax benefit (expense)	(173)	2,175	1,421
Net income (loss)	(540,398)	(395,491)	115,614
Net income (loss) attributable to noncontrolling interest	0	386	32
Net income (loss) attributable to Memorial Production Partners LP	(540,398)	(395,877)	115,582
Limited partners' interest in net income (loss):
Net income (loss) attributable to Memorial Production Partners LP	(540,398)	(395,877)	115,582
Net (income) loss allocated to previous owners	0	2,268	2,465
Net (income) loss allocated to general partner	168	327	(206)
Net (income) loss allocated to NGP IDRs	0	(83)	(88)
Limited partners' interest in net income (loss)	$ (540,230)	$ (393,365)	$ 117,753
Earnings per unit: (Note 11)
Basic and diluted earnings per unit	$ (6.48)	$ (4.71)	$ 1.66
Weighted average limited partner units outstanding:
Basic and diluted	83,351	83,528	70,859

STATEMENTS OF CONSOLIDATED AND5

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income (loss)	$ (540,398)	$ (395,491)	$ 115,614
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	171,629	195,814	185,955
Impairment of proved oil and natural gas properties	183,437	616,784	407,540
(Gain) loss on derivative instruments	118,395	(458,216)	(492,405)
Cash settlements (paid) received on expired derivative instruments	210,704	250,043	11,693
Cash settlements (paid) on terminated derivatives	228,646	47,930	0
Premiums paid for commodity derivatives	0	(47,930)	0
Bad debt expense	2,050	0	0
Deferred income tax expense (benefit)	187	(2,234)	(1,548)
Amortization and write-off of deferred financing costs	22,106	6,058	4,227
Amortization and write-off of senior notes discount	13,185	2,430	1,921
Gain on extinguishment of debt	(42,337)	(422)	0
Accretion of asset retirement obligations	10,231	7,125	5,773
(Gain) loss on sale of properties	(2,754)	(2,998)	0
Unit-based compensation (see Note 12)	7,350	10,809	7,874
Settlement of asset retirement obligations	(1,442)	(1,430)	0
Exploration costs	792	2,078	1,960
Other	229	0	0
Changes in operating assets and liabilities:
Accounts receivable	23,928	15,528	(18,022)
Prepaid expenses and other assets	(4,088)	2,275	(2,695)
Payables and accrued liabilities	4,084	(32,068)	27,037
Other	2,692	666	(651)
Net cash provided by operating activities	408,626	216,751	254,273
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	0	(100,730)	(1,083,761)
Acquisition post-closing adjustments receipts	0	9,570	0
Additions to oil and gas properties	(57,675)	(241,299)	(298,274)
Additions to restricted investments	(8,443)	(5,690)	(3,976)
Withdrawals of restricted investments	4,840	0	0
Additions to other property and equipment	(7,875)	0	(98)
Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold	52,711	580	0
Net cash used in investing activities	(16,442)	(337,569)	(1,386,109)
Cash flows from financing activities:
Advances on revolving credit facilities	144,000	562,000	1,446,000
Payments on revolving credit facilities	(468,348)	(138,000)	(1,137,000)
Proceeds from senior notes	0	0	492,425
Deferred financing costs	(1,350)	(341)	(11,494)
Repurchase of senior notes	(41,261)	(2,914)	0
Capital contributions from previous owners	0	1,912	5,990
Contributions related to sale of assets to NGP affiliate	26	860	0
Transfer of operating subsidiary from Memorial Resource	2,363	0	0
Proceeds from general partner contributions	0	0	570
Proceeds from the issuance of common units	2,385	0	553,288
Costs incurred in conjunction with issuance of common units	(536)	0	(12,510)
Purchase of noncontrolling interest	0	(5,946)	0
Distributions to partners	(13,300)	(163,259)	(154,852)
Distribution to Memorial Resource (see Note 1)	0	(78,396)	(48,880)
Acquisition of General Partner (see Note 1)	(750)	0	0
Acquisition of IDRs from NGP (see Note 1)	(50)	0	0
Restricted units returned to plan	(589)	(1,285)	(1,012)
Repurchases under unit repurchase program	0	(54,184)	(11,531)
Distributions made by previous owners	0	0	(9,886)
Net cash (used in) provided by financing activities	(377,410)	120,447	1,111,108
Net change in cash and cash equivalents	14,774	(371)	(20,728)
Cash and cash equivalents, beginning of period	599	970	21,698
Cash and cash equivalents, end of period	$ 15,373	$ 599	$ 970

STATEMENTS OF CONSOLIDATED AND6

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY - USD ($) $ in Thousands	Total	Limited Partners Common Units [Member]	Limited Partners Subordinated [Member]	General Partner [Member]	Previous Owners [Member]	NGP IDR [Member]	Noncontrolling Interest [Member]
Balance at Dec. 31, 2013	$ 863,021	$ 582,075	$ (8,715)	$ 728	$ 283,405	$ 0	$ 5,528
Net income (loss)	115,614	113,573	4,180	206	(2,465)	88	32
Net proceeds from the issuance of common units	540,698	540,698	0	0	0	0	0
Contributions	6,560	0	0	570	5,990	0	0
Distributions	(164,738)	(142,719)	(11,794)	(251)	(9,886)	(88)	0
Distribution attributable to net assets acquired (see Note 13)	(2,413)	(2,321)	(90)	(2)	0	0	0
Distribution of net asset to MRD Holdco	(26,131)	0	0	0	(26,131)	0	0
Amortization of equity/unit-based awards	7,874	7,874	0	0	0	0	0
Tax related effects attributable to Memorial Resource restructuring and initial public offering	(30,483)	0	0	0	(30,483)	0	0
Common units repurchased under repurchase program (see Note 10)	(12,903)	(12,903)	0	0	0	0	0
Restricted units repurchased (see Note 10)	(1,012)	(1,012)	0	0	0	0	0
Other	227	0	0	0	227	0	0
Balance at Dec. 31, 2014	1,296,314	1,085,265	(16,419)	1,251	220,657	0	5,560
Net income (loss)	(395,491)	(393,395)	30	(327)	(2,268)	83	386
Contributions	4,877	2,962	0	3	1,912	0	0
Distributions	(163,259)	(159,975)	(2,949)	(252)	0	(83)	0
Distribution attributable to net assets transferred (see Note 1)	(78,396)	(78,318)	0	(78)	0	0	0
Net book value of net assets exchanged (see Note 1)	2,721	250,791	0	251	(248,321)	0	0
Purchase of noncontrolling interest	(5,946)	0	0	0	0	0	(5,946)
Amortization of equity/unit-based awards	10,809	10,809	0	0	0	0	0
Conversion of subordinated units to common units	0	(19,338)	19,338	0	0	0	0
Common units repurchased under repurchase program (see Note 10)	(52,813)	(52,813)	0	0	0	0	0
Restricted units repurchased and other	(1,344)	(1,344)	0	0	0	0	0
Deferred tax liability retained by previous owner (see Note 3)	28,020	0	0	0	28,020	0	0
Balance at Dec. 31, 2015	645,492	644,644	0	848	0	0	0
Net income (loss)	(540,398)	(540,230)	0	(168)	0	0	0
Net proceeds from the issuance of common units	1,849	1,849	0	0	0	0	0
Distributions	(13,300)	(13,289)	0	(11)	0	0	0
Purchase of equity interest of general partner (see Note 1)	(750)	(81)	0	(669)	0	0	0
Acquisition of IDRs from NGP (see Note 1)	(50)	(50)	0	0	0	0	0
Amortization of equity/unit-based awards	7,206	7,206	0	0	0	0	0
Restricted units repurchased and other	(560)	(560)	0	0	0	0	0
Balance at Dec. 31, 2016	$ 99,489	$ 99,489	$ 0	$ 0	$ 0	$ 0	$ 0

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation General Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” See Note 2 for additional information regarding the Notice of Delisting. Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries. We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, 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” and “MEMP GP” refers to Memorial Production Partners GP LLC, our general partner and wholly-owned subsidiary; (ii) “Memorial Resource” refers to Memorial Resource Development Corp., the former owner of our general partner; (iii) “MRD LLC” refers to Memorial Resource Development LLC, which is the predecessor of Memorial Resource; (iv) “the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; (v) “OLLC” refers to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refers to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; (vii) “MRD Holdco” refers to MRD Holdco LLC, which together with a group controlled Memorial Resource and (viii) “NGP” refer to Natural Gas Partners. On April 27, 2016, we entered into an agreement pursuant to which the Partnership agreed to acquire, among other things, all of the equity interests in our general partner, MEMP GP, from Memorial Resource (the “MEMP GP Acquisition”) for cash consideration of approximately $0.8 million. MEMP GP held an approximate 0.1% general partner interest and 50% of the incentive distribution rights ("IDRs") in us. In conjunction with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with an NGP affiliate pursuant to which we agreed to acquire the other 50% of the IDRs. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition. In connection with the closing of the transactions on June 1, 2016, our partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Partnership held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Partnership will elect the members of MEMP GP’s board of directors beginning with our next annual meeting. 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 13 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 collectively to certain oil and natural gas properties primarily located in East Texas and Louisiana that the Partnership acquired in February 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana. We refer to this transaction as the “Property Swap.” The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”). The acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to such acquisition as if the Partnership owned the assets for periods after common control commenced through the acquisition date. See Note 13 for additional information. Basis of Presentation Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements were derived from the historical accounting records of the previous owners and reflect the historical financial position, results of operations and cash flows for all periods presented. The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of REO, was presented as noncontrolling interest in the financial statements for the periods prior to November 3, 2015. On November 3, 2015, we purchased the noncontrolling interest in SPBPC for approximately $6.0 million and completed an acquisition of the remaining interests in our oil and gas properties located offshore Southern California (the “Beta properties”) from a third party for approximately $94.6 million (the “2015 Beta Acquisition”). See Note 4 for additional information regarding the 2015 Beta Acquisition. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gain on extinguishment of debt were previously accounted for as interest expense, net and are now being presented as other income (expenses) on our statements of operations on a separate line item.

Chapter 11 Proceedings, Ability

Chapter 11 Proceedings, Ability to Continue as a Going Concern and Covenant Violations	12 Months Ended
	Dec. 31, 2016
Reorganizations [Abstract]
Chapter 11 Proceedings, Ability to Continue as a Going Concern and Covenant Violations	Note 2. Chapter 11 Proceedings, Ability to Continue as a Going Concern and Covenant Violations Throughout 2016, the Partnership along with its legal and financial advisors, explored strategic alternatives with a focus on liquidity and financial flexibility. The Partnership specifically evaluated options with the lenders under our revolving credit facility and holders of the Partnership’s senior notes that would improve liquidity and deleverage the Partnership. During this process, we elected to defer an approximately $24.6 million interest payment due on November 1, 2016 with respect to the 7.625% senior notes due May 2021 (“2021 Senior Notes”). The interest payment was subject to a 30-day grace period under the indenture. Failure to pay such interest payment on November 1, 2016 would have resulted in certain defaults and events of default under our revolving credit facility. The lenders under the revolving credit facility, on November 1, 2016, waived such defaults and event of default through November 30, 2016 (such period from November 1, 2016 to November 30, 2016, the “Waiver Period”), in each case, subject to the terms and conditions set forth in the limited waiver and twelfth amendment (the “Waiver and Twelfth Amendment”) to our revolving credit facility. On November 30, 2016, the Partnership, OLLC, certain subsidiaries of the Partnership, the administrative agent, and the lenders consenting thereto entered into the first amendment to the limited waiver under our revolving credit facility, extending the Waiver Period to December 16, 2016. On November 30, 2016, the Partnership entered into a forbearance agreement with certain noteholders that held approximately 51.7% of the Partnership’s 2021 Senior Notes and 69% of the Partnership’s 6.875% senior notes due August 2022 (“2022 Senior Notes”). Under the forbearance agreement the noteholders agreed to forbear from exercising any and all remedies available to them as a result of the Partnership’s election not to make an interest payment of $24.6 million due on the 2021 Senior Notes. The forbearance agreements initially extended through December 7, 2016 and were subsequently extended through December 16, 2016. On December 16, 2016, the Partnership, OLLC, certain subsidiaries of the Partnership, the administrative agent, and the lenders consenting thereto entered into the second amendment to limited waiver under its revolving credit facility, extending the Waiver Period to January 13, 2017. In addition, the forbearance agreements were extended through January 13, 2017. On December 22, 2016, the Partnership entered into a Plan Support Agreement (the “Noteholder PSA”) with holders of over an aggregate of 50.2% of the aggregate outstanding principal amount of the 2021 Senior Notes and the 2022 Senior Notes (collectively, the “Notes”), as well as reached an agreement-in-principle with the administrative agent under our revolving credit facility on the terms of a financial restructuring. Under the terms of the Noteholder PSA, the financial restructuring would be effected through a prepackaged or prenegotiated plan of reorganization (the “Plan”). Pursuant to the terms of the Plan, which would be subject to approval of the Bankruptcy Court, it is anticipated that, among other things, on the effective date of the Plan (the “Effective Date”): • A newly formed corporation, as successor to the Partnership (“Reorganized Memorial”) would issue (i) new common shares (the “New Common Shares”) and (ii) five year warrants (the “Warrants”) entitling their holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding New Common Shares, at a per share exercise price equal to the principal and accrued interest on the Senior Notes as of December 31, 2016, divided by the number of issued and outstanding New Common Shares (including New Common Shares issuable upon exercise of the Warrants), which New Common Shares and Warrants will be distributed as set forth below; • The Notes would be cancelled and discharged and the holders of those Notes would receive (directly or indirectly) New Common Shares representing, in the aggregate, 98% of the New Common Shares issued on the Effective Date (subject to dilution by the post-emergence management incentive plan and the New Common Shares issuable upon exercise of the Warrants); • The noteholders, at their election, would be entitled to receive an additional cash payment of up to approximately $24.6 million; • Each holder of existing equity interests in the Partnership would receive its pro rata share of (i) New Common Shares representing, in the aggregate, 2% of the New Common Shares issued on the Effective Date and (ii) the Warrants (in each case, subject to dilution by the post-emergence management incentive plan and, in the case of the New Common Shares, subject to dilution by the Warrants); • General unsecured claims, on or after the effective date, would be paid in the ordinary course; and • Reorganized Memorial would enter into an exit credit facility in the form of an amendment and restatement of the existing revolving credit facility (the “Exit Credit Facility”). The Partnership expects to emerge from the Chapter 11 proceedings as a corporation, including for U.S. federal income tax purposes. On January 13, 2017, the Partnership entered into the third amendment to limited waiver, which extended the outside date of the Waiver Period from January 13, 2017 to January 16, 2017. In addition, the Partnership entered into a Plan Support Agreement (the “RBL PSA”) with lenders holding 100% of the loans under our revolving credit facility. The RBL PSA was entered into on terms substantially similar to those of the Noteholder PSA. In addition, among other things, the RBL PSA provided that (i) the consenting lenders (as defined in the RBL PSA) may terminate the RBL PSA upon the termination of the Noteholder PSA or if there is an amendment to the Noteholder PSA that is, or would reasonably be expected to be, adverse to the administrative agent under our revolving credit facility or the consenting lenders and (ii) each of the Debtors agreed to not file a voluntary petition for relief under Chapter 11 of title 11 of the United States Code (“Bankruptcy Code”) until the Debtors terminated certain swap agreements identified in the RBL PSA and used the net proceeds thereof to repay outstanding amounts under the revolving credit facility. An indicative summary of the expected terms and conditions of the Exit Credit Facility is set forth in an annex to the RBL PSA filed with our Current Report on Form 8-K filed with the SEC on January 17, 2017, which terms and conditions may include (but are not limited to) the following: • senior secured revolving credit facility with maximum aggregate commitments of $1 billion, subject to a borrowing base; • an expected initial borrowing base of approximately $474.0 to $492.5 million based on a April emergence date to be effective upon consummation of the restructuring transactions, subject to an amortization schedule thereafter until November 1, 2017; • the first scheduled borrowing base redetermination will occur on November 1, 2017 and thereafter, each April 1st and October 1st; • a maturity date of March 19, 2021; • an ongoing covenant requiring that we grant a security interest in substantially all of our personal and real property that we mortgage, in each case as collateral for the obligations under the Exit Credit Facility, oil and gas properties representing not less than 95% of the total value of our oil and gas properties evaluated in the most recently completed reserve report; • the loans under the Exit Credit Facility shall bear interest at a rate per annum equal to the base rate or LIBOR/Eurodollar rate plus an applicable margin that ranges from 2.00% to 3.00% per annum (based on borrowing base usage) on alternate base rate loans and from 3.00% to 4.00% per annum (based on borrowing base usage) on LIBOR/Eurodollar loans; • the loan commitments under the Exit Credit Facility are subject to a commitment fee on the unused portion of the borrowing base at a rate per annum equal to 0.50%; • customary mandatory prepayments as well as a requirement that, in the event that as of the close of any business day the aggregate amount of our unrestricted cash and cash equivalents exceeds $35.0 million in the aggregate, we must prepay the loans under the Exit Credit Facility (without a corresponding reduction in the available commitments under the Exit Credit Facility) and cash-collateralize any letter of credit exposure in an amount equal to such excess; provided that, we may elect to increase such the excess cash threshold from $35.0 million to $50.0 million at such time as the aggregate amount of net cash proceeds received from asset sales exceeds the borrowing base value attributable to such assets (if any) equals or exceeds $15.0 million; provided further, however, that in the event that we issue certain unsecured debt in an aggregate amount of $10.0 million or greater, we will no longer have the ability to increase such threshold above $35.0 million and, if such threshold is greater than $35.0 million at such time, such threshold will be immediately reduced to $35.0 million; • financial covenants, requiring that we maintain a ratio of (i) consolidated EBITDAX (to be defined in the Exit Credit Facility) for the four fiscal quarter period then ending to consolidated net interest expense for such period of not less than 2.50 to 1.00, which we refer to as the interest coverage ratio, (ii) consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0; and (iii) consolidated total debt as of such time to consolidated EBITDAX for the four fiscal quarter period then ending on such day of not greater than 4.0 to 1.0; • a requirement that we hedge no less than 50% of our forecasted proved developed producing production through 2019 on or prior to December 31, 2017; and • representation and warranties, affirmative covenants, negative covenants, events of default and other restrictive provisions substantially consistent with our current revolving credit facility, subject to certain exceptions and a provision permitting us, under specified and limited circumstances, to incur additional unsecured indebtedness in an original aggregate principal amount not to exceed $80.0 million. On January 16, 2017, the Partnership and certain of its subsidiaries (collectively with the Partnership, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 proceedings”) under the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) to pursue a Joint Chapter 11 Plan of Reorganization for the Debtors. The Debtors’ Chapter 11 proceedings are being jointly administered under the caption In re Memorial Production Partners LP, et al. For the duration of the Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to risks and uncertainties associated with Chapter 11 proceedings described in Item 1A, “Risk Factors.” As a result of these risks and uncertainties, our assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this annual report may not accurately reflect our operations, properties and capital plans following the Chapter 11 proceedings. Ability to Continue as a Going Concern Continued low commodity prices have resulted in significantly lower levels of cash flow from operating activities and have limited the Partnership’s ability to access the capital markets. In addition, the borrowing base under our revolving credit facility is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Continued low commodity prices have adversely impacted our redeterminations. During the second semi-annual redetermination in October, the lenders under our revolving credit facility decreased our borrowing base from $925.0 million to $740.0 million with a further reduction to $720.0 million in December 2016. The borrowing base was further reduced in December 2016 to $530.7 million due to the monetization of certain derivative instruments, as discussed in Note 6. The reduced borrowing base has had a significant negative impact on the Partnership’s liquidity and ability to remain in compliance with certain financial covenants. On January 16, 2017, the Debtors’ Chapter 11 proceedings accelerated the Partnership’s obligations under its revolving credit facility, 2021 Senior Notes and 2022 Senior Notes. The significant risks and uncertainties related to the Partnership’s liquidity and Chapter 11 proceedings described above raise substantial doubt about the Partnership’s ability to continue as a going concern. The condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material. In order to decrease the Partnership’s level of indebtedness and maintain the Partnership’s liquidity at levels sufficient to meet its commitments, the Partnership undertook a number of actions, including divesting certain non-core assets, minimizing capital expenditures and further reducing its recurring operating expenses. Despite taking these actions, the Partnership did not have sufficient liquidity to satisfy its debt service obligations, meet other financial obligations and comply with its debt covenants. As a result, the Debtors filed bankruptcy petitions under Chapter 11 of the Bankruptcy Code. Notice of Delisting On January 17, 2017, the Partnership received a letter from the Listing Qualifications Department of The NASDAQ Stock Market LLC (“NASDAQ”) notifying the Partnership that (1) as a result of the Chapter 11 proceedings, and in accordance with NASDAQ Listing Rules 5101, 5110(b) and IM-5101-1, NASDAQ had determined that the Partnership’s common units would be delisted from NASDAQ and (2) accordingly, unless the Partnership requested an appeal of this determination, trading of the common units would have been suspended at the opening of business on January 26, 2017 and the Partnership’s securities would have been removed from listing and registration on NASDAQ. The Partnership has appealed this determination.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 3. Summary of Significant Accounting Policies Use of Estimates The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. Principles of Consolidation and Combination Our consolidated financial statements include our accounts and those of our majority-owned subsidiary in which we have a controlling interest and acquired the remaining interests on November 3, 2015, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of the previous owners as discussed above in Note 1. All material intercompany balances and transactions have been eliminated. Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less. Concentrations of Credit Risk Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts which are held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. At December 31, 2016, we recorded $1.9 million as an allowance for doubtful accounts. Management determined that an allowance for uncollectible accounts was unnecessary at December 31, 2015. If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. Oil and Natural Gas Properties Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs attributable to unproved locations are expensed as incurred. As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Support equipment and facilities, which are primarily related to our Wyoming and California assets, are depreciated using the straight-line method generally based on estimated useful lives of fifteen to forty years. On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2016, 2015 and 2014. Oil and Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We engaged Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2016. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. Other Property & Equipment Other property and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to seven years. Restricted Investments Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense, net in the statement of operations. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 8 for additional information. Debt Issuance Costs These costs were historically recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method and generally approximates the effective yield method. The remaining unamortized debt issuance cost was written off at December 31, 2016, due to (i) the uncertainty regarding the Partnership’s ability to cure the default discussed above in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2016, 2015 and 2014 was approximately $22.1 million, $6.1 million, and $4.2 million, respectively. Impairments Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved and 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 gas properties. Impairment expense for the years ended December 31, 2016, 2015 and 2014 was approximately $183.4 million, $616.8 million, and $407.5 million, respectively. Asset Retirement Obligations An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 7 for further discussion of asset retirement obligations. Book Overdrafts Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows. Revenue Recognition Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2016 or 2015. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: For the Year Ending December 31, 2016 2015 2014 Major customers: Phillips 66 19% 12% 12% Sinclair Oil & Gas Company 16% 18% 11% Royal Dutch Shell plc and subsidiaries 14% 14% n/a General and Administrative Expense Prior to June 1, 2016, 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 on June 1, 2016, and the Partnership entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. Prior to the MEMP GP Acquisition, our partnership agreement provided that our general partner determined in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its former affiliates on our behalf. Memorial Resource allocated indirect general and administrative costs based on time allocations for the three months ended March 31, 2016 and the years ended December 31, 2015 and 2014 and based on the terms as set forth by the MEMP GP Acquisition purchase and sale agreement for the period from April 1, 2016 through the closing date. Under our partnership agreement and the omnibus agreement, we reimbursed Memorial Resource for all direct and indirect costs incurred on our behalf. See Note 13 for additional information regarding the omnibus agreement. General and administrative expenses associated with the previous owners included the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production. Derivative Instruments Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions. Capitalized Interest We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. For the years ended December 31, 2016, 2015 and 2014, we had $0.5 million, $2.1 million and $2.8 million in capitalized interest, respectively. Income Tax We are currently organized as a pass-through entity for federal and most state income tax purposes. As a result, our partners are responsible for federal and state income taxes on their share of our taxable income. Certain of our consolidated subsidiaries are taxed as corporations for federal and state income tax purposes. We are also subject to the Texas margin tax for partnership activity in the state of Texas. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our consolidated statement of operations. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority. Earnings Per Unit Basic and diluted earnings per unit (“EPU”) is determined by dividing net income or loss available to the limited partners by the weighted average number of outstanding limited partner units during the period. Net income or loss available to the limited partners is determined by applying the two-class method. The two-class method of computing EPU is an earnings allocation formula that determines EPU based on distributions declared. The amount of net income or loss used in the determination of EPU is reduced (or increased) by the amount of available cash that has been or will be distributed to the limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the limited partners in accordance with the contractual terms of the partnership agreement. The total earnings allocated to the limited partners is determined by adding together the amount allocated for distributions declared and the amount allocated for the undistributed earnings or excess distributions over earnings. Basic and diluted EPU are equivalent, as all restricted common units and subordinated units participate in distributions. See Note 11 for additional information. Equity Compensation The fair value of equity-classified awards (e.g., restricted common unit awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., phantom units awards) are recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. We currently have no awards subject to performance criteria; however, such awards would vest when it is probable that the performance criteria will be met and the requisite service period has been met. Generally, no compensation expense is recognized for equity instruments that do not vest. See Note 12 for further information. Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, December 31, 2016 2015 Accrued interest payable $ 46,417 $ 23,192 Accrued lease operating expense 10,411 16,843 Accrued capital expenditures 1,826 8,110 Accrued general and administrative expenses 3,040 1,961 Accrued ad valorem tax 977 1,426 Asset retirement obligation 789 1,175 Environmental liability — 216 Other 1,775 — $ 65,235 $ 52,923 Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2016 2015 2014 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 87,527 $ 107,272 $ 63,709 Cash paid for taxes — 472 151 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (6,284 ) (27,932 ) 13,759 (Increase) decrease in accounts receivable related to acquisitions — 9,698 (5,854 ) (Increase) decrease in accounts receivable/payable related to divestitures (289 ) — — Repurchases under unit repurchase program — — 1,372 Assumptions of asset retirement obligations related to acquisitions — 23,754 4,265 Asset retirement obligation removal related to divestitures (19,669 ) — — New Accounting Pronouncements Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Issues Task Force. In November 2016, the FASB issued an accounting standards update to clarify the guidance on the classification and presentation of restricted cash in the statement of cash flows. The changes in restricted cash and restricted cash equivalents that result from the transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued an accounting standards update to address eight specific cash flow issues with the objective of reducing the current and potential future diversity in practice. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involves several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, entities will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required. 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. The Partnership adopted this guidance as of January 1, 2017, and it will not have a material impact on the Partnership’s future consolidated financial statements. 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 Partnership is the lessee under various agreements for office space, compressors, equipment, and surface rentals that are currently accounted for as operating leases, refer to Note 14, Commitments and Contingencies. As a result, these new rules will increase reported assets and liabilities. The Partnership will not early adopt this standard. The Partnership will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using a modified retrospective approach, including several optional practical expedients related to leases commenced before the effective date. The Partnership is currently evaluating the impact of these rules on its financial statements and has started the assessment process by evaluating the population of leases under the revised definition. The adoption of this standard will result in an increase in the assets and liabilities on the Partnership’s consolidated balance sheets. The quantitative impacts of the new standard are dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods. Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. In April 2015, the FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method are also required. The guidance was effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. We adopted this guidance on January 1, 2016. Since the Partnership has historically allocated the earnings (losses) of transferred businesses that occurred in periods before the date of the dropdown transaction entirely to affiliates of the general partner (i.e., the previous owners) and did not adjust previously reported earnings per unit of the limited partners, the impact of adopting this guidance was not material to the Partnership’s financial statements and related disclosures. Revenue from Contracts with Customers. In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The guidance is effective for interim and annual reporting periods starting January 1, 2018, and early adoption is permitted. The Partnership will not early adopt the standard, and plans to use a modified retrospective approach upon adoption, with the cumulative effect of initial application recognized at the date of initial application subject to certain additional disclosures. The Partnership has started the assessment process by evaluating its revenue streams and evaluating contracts under the revised standards. The Partnership is currently evaluating the standard and the impact it is expected to have on the consolidated financial statements and related footnote disclosures. Presentation of Financial Statements — Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. In August 2014, the FASB issued an accounting standards update that requires management to perform interim and annual assessments of whether there are conditions or events that raise substantial doubt of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. Certain disclosures are required if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, and with early adoption permitted. The amendments will not impact our financial position or results of operations but will require management to perform a formal going concern assessment. The Partnership adopted this guidance and has applied this guidance in its consolidated financial statements and related footnote disclosures. See Note 2 for additional information. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 4. Acquisitions and Divestitures The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through capital contributions and borrowings under our revolving credit facility. The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural properties include estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. The Partnership has consummated several common control acquisitions since completing its IPO in December 2011, as further discussed in Note 13, directly or indirectly from Memorial Resource and certain affiliates of NGP. 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 Year Ended December 31, 2016 2015 2014 $ 1,451 $ 1,928 $ 4,363 2015 Acquisitions 2015 Beta Acquisition . On November 3, 2015, we closed the 2015 Beta Acquisition, which included the acquisition of the noncontrolling interest in SPBPC for approximately $6.0 million and the acquisition of the remaining interests in our oil and gas properties located offshore Southern California from a third party for approximately $94.6 million. During the year ended December 31, 2015, we recorded revenues of $3.6 million in the statement of operations and generated losses of approximately $1.0 million related to the 2015 Beta Acquisition subsequent to the closing date. The following table summarizes the fair value of the third party assets acquired and liabilities assumed in the 2015 Beta Acquisition (in thousands): 2015 Beta Acquisition Oil and gas properties $ 40,029 Prepaid expenses and other current assets 840 Restricted investments 69,579 Derivative instruments 4,568 Accounts receivable - affiliates and other 4,499 Asset retirement obligations (22,871 ) Accrued liabilities (2,010 ) Total identifiable net assets $ 94,634 The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2015 and 2014 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired (iii) accretion expense associated with asset retirement obligations recorded and (iv) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Year Ended December 31, 2015 2014 (In thousands, except per unit amounts) Revenues $ 381,495 $ 613,563 Net income (loss) (394,756 ) 132,630 Basic and diluted earnings per unit (4.73 ) 1.87 2014 Acquisitions Wyoming Acquisition. On July 1, 2014, we consummated a transaction to acquire certain oil and natural gas liquids properties in Wyoming from a third party for a final aggregate purchase price of approximately $906.1 million, after customary post-closing adjustments (the “Wyoming Acquisition”). During the year ended December 31, 2014, we recorded revenues of $72.8 million in the statement of operations and generated earnings of approximately $22.9 million related to the Wyoming Acquisition subsequent to the closing date. The following table summarizes the fair value of the third party assets acquired and liabilities assumed in the Wyoming Acquisition (in thousands): Wyoming Acquisition Oil and gas properties $ 930,168 Asset retirement obligations (3,980 ) Revenues payable (375 ) Accrued liabilities (19,693 ) Total identifiable net assets $ 906,120 Eagle Ford Acquisition. On March 25, 2014, we closed a transaction to acquire certain oil and natural gas producing properties in the Eagle Ford from a third party for approximately $168.1 million (the “Eagle Ford Acquisition”). In addition, we acquired a 30% interest in the seller’s Eagle Ford leasehold. During the year ended December 31, 2014, revenues of approximately $36.6 million were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and we generated earnings of approximately $16.3 million for the year ended December 31, 2014. The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): Eagle Ford Acquisition Oil and gas properties $ 168,606 Asset retirement obligations (285 ) Accrued liabilities (250 ) Total identifiable net assets $ 168,071 The following unaudited pro forma combined results of operations is provided for the year ended December 31, 2014 as though the Eagle Ford Acquisition and Wyoming Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Year Ended December 31, 2014 (In thousands, except per unit amounts) Revenues $ 666,508 Net income (loss) 153,843 Basic and diluted earnings per unit 2.20 2016 Divestitures On July 14, 2016, we closed a transaction to divest certain assets located in Colorado and Wyoming (the “Rockies Divestiture”) to a third party for total proceeds of approximately $16.4 million, including final post-closing adjustments. We recorded a loss of approximately $4.2 million in “(gain) loss on sale of properties” in the accompanying statement of operations. The proceeds from this transaction were used to reduce borrowings under our revolving credit facility. This disposition does not qualify as a discontinued operation. On June 14, 2016, we closed a transaction to divest certain assets located in the Permian Basin (the “Permian Divestiture”) to a third party for a total purchase price of approximately $36.7 million including estimated post-closing adjustments, which included $36.4 million in cash and $0.3 million in accounts receivable at December 31, 2016. We recognized a gain of $6.1 million on the sale of properties related to the Permian Divestiture in “(gain) loss on sale of properties” in the accompanying statement of operations. The proceeds from this transaction were used to reduce borrowings under our revolving credit facility. This disposition does not qualify as a discontinued operation. During the year ended December 31, 2016, the Partnership completed other immaterial divestitures for less than $0.1 million for which we recorded a gain of $0.9 million on the sale that is recorded in “(gain) loss on sale of properties” in the accompanying statement of operations. The income (loss) before income taxes, including the associated (gain) loss on sale of properties, related to the Permian Divestiture and Rockies Divestiture included in the condensed statements of consolidated and combined operations of the Partnership is as follows (in thousands): For the Year Ended December 31, 2016 2015 2014 Permian Divestiture $ 4,297 $ (60,875 ) $ (228,956 ) Rockies Divestiture (7,677 ) (56,917 ) 3,127 2015 Divestitures During the year ended December 31, 2015, we conducted an auction process administered by a third-party and sold interests in certain oil and gas properties located in the Permian Basin in various Texas and New Mexico counties to two third parties for approximately $0.6 million in the aggregate. In addition as part of that auction process, we also sold interests in certain oil and gas properties located in the Permian Basin to a related party for approximately $0.9 million. See Note 13 for additional information regarding this related party divestiture.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 5. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2016 and 2015, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity). Assets and Liabilities Measured at Fair Value on a Recurring Basis The carrying values of cash and cash equivalents, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 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 9 for the estimated fair value of our outstanding fixed-rate debt. The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2016 and December 31, 2015 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2016 and December 31, 2015 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2016 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 189,851 $ — $ 189,851 Total assets $ — $ 189,851 $ — $ 189,851 Liabilities: Commodity derivatives $ — $ 17,757 $ — $ 17,757 Total liabilities $ — $ 17,757 $ — $ 17,757 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 6 for additional information regarding our derivative instruments. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: • The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 7 for a summary of changes in AROs. • If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations is commonly estimated using the depreciated replacement cost approach. • Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. (i) During the year ended December 31, 2016, we recognized $183.4 million of impairments related to certain properties 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 and change in future planned development due to liquidity constraints as a result of our reduced borrowing base during the three months ended December 31, 2016. As a result of the impairments, the carrying value of these properties was reduced to approximately $156.2 million. (ii) During the year ended December 31, 2015, we recognized $616.8 million of impairments. These impairments primarily related to certain properties located in East Texas, South Texas, the Permian Basin, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. As a result of the impairments, the carrying value of these properties was reduced to approximately $408.6 million. (iii) During the year ended December 31, 2014, we recognized $407.5 million of impairments. The impairments primarily related to certain properties located in the Permian Basin, East Texas and South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable. In the Permian Basin, the impairments were in due to a downward revision of estimated proved reserves based on declining commodity prices and updated well performance data. In South Texas, the impairments were due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs. In East Texas, the impairments were due to downward revisions based on declining commodity prices. The carrying value of the: (i) Permian Basin properties after the $234.2 million impairment was approximately $88.7 million; (ii) East Texas properties after the $107.6 million impairment was approximately $88.8 million; and (iii) South Texas properties after the $65.6 million impairment was $71.2 million.

Risk Management and Derivative

Risk Management and Derivative Instruments	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments	Note 6. Risk Management and Derivative Instruments Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease. Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $107.2 million against amounts outstanding under our revolving credit facility at December 31, 2016, reducing our maximum credit exposure to approximately $64.9 million, of which approximately $42.5 million was with a single counterparty. See Note 9 for additional information regarding our revolving credit facility. Commodity Derivatives A combination of commodity derivatives (e.g., floating-for-fixed swaps, costless collars, call spreads and basis swaps) is used to manage exposure to commodity price volatility. In December 2016, in connection with our restructuring efforts, we monetized approximately $191.4 million in commodity hedges and used the proceeds to reduce amounts outstanding under our revolving credit facility. During the periods of April through June 2016, we monetized approximately $39.3 million in commodity hedges and used the proceeds from the settlements to repurchase senior notes. In February 2015, we restructured a portion of our commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor. In February 2015, cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives. In November 2015, we had cash settlement receipts of $16.4 million from the termination of certain WTI crude oil derivatives that were applied as premiums for new Brent crude oil derivatives. As a part of the 2015 Beta Acquisition, we acquired $4.6 million of commodity derivatives. These derivatives were subsequently restructured by terminating “in-the-money” crude oil derivatives settling in 2015 through 2016 and entering into new crude oil derivatives. Cash settlement receipts of approximately $4.4 million from the termination of the crude oil derivatives were applied as premiums for the new crude oil swaps. Subsequent Event. In January 2017, in connection with our restructuring efforts, we monetized $94.1 million in commodity hedges and used a portion of the proceeds to reduce the amounts outstanding under our revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes. We enter into natural gas derivative contracts that are indexed to NYMEX Henry Hub. We also enter into oil derivative contracts indexed to either NYMEX WTI or Inter-Continental Exchange (“ICE”) Brent. Our NGL derivative contracts are indexed to OPIS Mont Belvieu. At December 31, 2016, the Partnership had the following open commodity positions: 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 1,890,000 1,740,000 1,000,000 Weighted-average fixed price $ 3.86 $ 3.83 $ 3.47 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 184,500 182,000 70,000 Weighted-average fixed price $ 84.29 $ 83.44 $ 86.84 NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 43,300 — — Weighted-average fixed price $ 37.55 $ — $ — Interest Rate Swaps Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. During December 2016, in connection with our restructuring efforts, we elected to terminate the interest rate swaps associated with our revolving credit facility and in the aggregate paid our counterparties approximately $2.1 million. The Partnership did not have any interest rate swaps at December 31, 2016. Balance Sheet Presentation The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2016 and 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 December 31, December 31, December 31, December 31, Type Balance Sheet Location 2016 2015 2016 2015 (In thousands) Commodity contracts Short-term derivative instruments $ 86,335 $ 324,265 $ 16,871 $ 53,581 Interest rate swaps Short-term derivative instruments — — — 1,214 Gross fair value 86,335 324,265 16,871 54,795 Netting arrangements Short-term derivative instruments (16,871 ) (51,945 ) (16,871 ) (51,945 ) Net recorded fair value Short-term derivative instruments $ 69,464 $ 272,320 $ — $ 2,850 Commodity contracts Long-term derivative instruments $ 103,515 $ 492,730 $ 885 $ 30,920 Interest rate swaps Long-term derivative instruments — — — 1,441 Gross fair value 103,515 492,730 885 32,361 Netting arrangements Long-term derivative instruments (885 ) (30,920 ) (885 ) (30,920 ) Net recorded fair value Long-term derivative instruments $ 102,630 $ 461,810 $ — $ 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 years ending December 31, 2016, 2015, and 2014: For the Year Ended Statements of December 31, Operations Location 2016 2015 2014 Commodity derivative contracts (Gain) loss on commodity derivatives $ 117,105 $ (462,890 ) $ (492,254 ) Interest rate derivatives Interest expense, net 1,290 4,674 (151 )

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 7. Asset Retirement Obligations The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the years ended December 31, 2016, 2015, and 2014: 2016 2015 2014 (in thousands) Asset retirement obligations at beginning of period $ 164,164 $ 112,702 $ 101,436 Liabilities added from acquisitions or drilling 30 26,876 5,815 Liabilities removed upon sale of wells (19,669 ) (3,412 ) — Liabilities settled (1,442 ) (1,430 ) (651 ) Accretion expense 10,231 7,125 5,773 Revision of estimates 2,388 22,303 329 Asset retirement obligations at end of period 155,702 164,164 112,702 Less: Current portion 789 1,175 — Asset retirement obligations - long-term portion $ 154,913 $ 162,989 $ 112,702

Restricted Investments

Restricted Investments	12 Months Ended
	Dec. 31, 2016
Investments Debt And Equity Securities [Abstract]
Restricted Investments	Note 8. Restricted Investments Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. During 2016, we replaced certain restricted investments with surety bonds. The components of the restricted investment balance are as follows: December 31, December 31, 2016 2015 (In thousands) BOEM platform abandonment (See Note 14) $ 152,000 $ 144,008 BOEM lease bonds — 1,533 Surety bond cash collateral 500 — SPBPC Collateral: Contractual pipeline and surface facilities abandonment 3,627 3,178 California State Lands Commission pipeline right-of-way bond — 3,005 City of Long Beach pipeline facility permit — 500 Federal pipeline right-of-way bond — 307 Port of Long Beach pipeline license 107 100 Restricted investments $ 156,234 $ 152,631

Debt

Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt	Note 9. Debt Our consolidated debt obligations consisted of the following at the dates indicated: December 31, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 511,652 $ 836,000 2021 Senior Notes, fixed-rate, due May 2021 (2) (4) 646,287 700,000 2022 Senior Notes, fixed-rate, due August 2022 (3) (4) 464,965 496,990 Senior notes debt issuance costs, net (5) — (18,297 ) Unamortized discounts (5) — (14,114 ) Total debt 1,622,904 2,000,579 Current portion of long-term debt (6) (1,622,904 ) — Total long-term debt $ — $ 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 $314.3 million and $210.0 million at December 31, 2016 and 2015, respectively. (3) The estimated fair value of our 2022 Senior Notes was $223.2 million and $149.1 million at December 31, 2016 and 2015, respectively. (4) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (5) Approximately $25.0 million in net discounts and deferred financing fees were written off due to a default and event of default and the uncertainty regarding anticipated financial covenant violation at December 31, 2016. (6) Due to an existing and anticipated financial covenant violations, the Partnership’s revolving credit facility and senior notes were classified as current at December 31, 2016. Subsidiary Guarantors Our outstanding debt securities are, and any debt securities issued in the future will likely be, jointly and severally, fully and unconditionally guaranteed (subject to customary release provisions) by certain of the Partnership’s subsidiaries (collectively, the “Guarantor Subsidiaries”). The Guarantor Subsidiaries are 100% owned by the Partnership. The Partnership has no material assets or operations independent of the Guarantor Subsidiaries and there are no significant restrictions upon the ability of the Guarantor Subsidiaries to distribute funds to the Partnership. Borrowing Base Credit facilities tied to a borrowing base are common throughout the oil and gas industry. The borrowing base for our revolving credit facility was the following at the date indicated: December 31, 2016 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 530,653 OLLC Revolving Credit Facility OLLC is a party to a $2.0 billion revolving credit facility, which is guaranteed by us and certain of our current and future subsidiaries. The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In January 2017, we monetized certain hedge positions and used a portion of the cash proceeds to repay outstanding borrowings under our revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes. In conjunction with the hedge monetization, our borrowing base was reduced to $457.2 million on January 13, 2017. See Note 6 for additional information regarding the hedge monetization. In December 2016, with the anticipation of the financial restructuring and to reduce exposure under the revolving credit facility, the Partnership monetized certain hedge positions and used the cash proceeds to repay outstanding borrowings under our revolving credit facility. In conjunction with the hedge monetization, our borrowing base was reduced from $720.0 million to $619.0 million on December 21, 2016 and then further reduced to $530.7 million on December 22, 2016. See Note 6 for additional information regarding the hedge monetization. On November 1, 2016, the Partnership, OLLC, certain subsidiaries of the Partnership, the administrative agent, and the lenders under our revolving credit facility, dated as December 14, 2011 (as the context may require, as amended, supplemented or otherwise modified, the “Credit Agreement” or “revolving credit facility”) entered into the limited waiver and twelfth amendment (the “Waiver and Twelfth Amendment”) to the Credit Agreement. See discussion noted below under “Deferral of Interest Payment, Waiver and Forbearance Agreement” for additional information on the Waiver and Twelfth Amendment. On October 28, 2016, we entered into an eleventh amendment to our Credit Agreement by and among the Partnership, OLLC, the administrative agent and the other agents and lenders party thereto (the “Eleventh Amendment”). The Eleventh Amendment, among other things, (i) pursuant to a regularly-scheduled semi-annual redetermination of the borrowing base, decreased our borrowing base from $925.0 million to $740.0 million, effective October 28, 2016, and scheduled a further decrease of the borrowing base to $720.0 million, which was effective December 1, 2016 and (ii) amended the Credit Agreement to add a new event of default limiting the Partnership’s, OLLC and their respective subsidiaries’ ability to call, make or offer to make any redemption of, or make any other payments in respect of the Partnership’s senior unsecured notes if, on a pro forma basis, the Partnership’s and its subsidiaries’ aggregate liquidity (unrestricted cash and cash equivalents plus amounts available to be drawn under the Credit Agreement), is less than $30.0 million. On April 14, 2016, we entered into the tenth amendment to our 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. Due to (i) the uncertainty regarding the Partnership’s ability to cure the default and event of default as discussed in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes, the Partnership classified the outstanding revolving credit facility balance as a current liability on its balance sheet as of December 31, 2016. As a result of the Chapter 11 filing, the debt has been accelerated. 2021 Senior Notes On April 17, 2013, May 23, 2013 and October 10, 2013, we and Finance Corp.’s (collectively, the “Issuers”) issued $300.0 million, $100.0 million and $300.0 million, respectively, of 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership. The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes are governed by an indenture and are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The Issuers may also be required to repurchase the 2021 Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2021 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers or any subsidiary guarantor that is a significant subsidiary, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately. During the year ended December 31, 2016, the Partnership repurchased on the open market an aggregate principal amount of approximately $53.7 million of its 2021 Senior Notes. In connection with the repurchases, the Partnership paid approximately $26.4 million and recorded a gain of $27.5 million. 2022 Senior Notes On July 17, 2014, the Issuers completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes due 2022 (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership. The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year, commencing February 1, 2015. The 2022 Senior Notes are governed by an indenture and are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The Issuers may also be required to repurchase the 2022 Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately. During the year ended December 31, 2016, the Partnership repurchased on the open market an aggregate principal amount of $32.0 million of its 2022 Senior Notes. In connection with the repurchases, the Partnership paid approximately $14.9 million and recorded a gain of $14.8 million. During the year ended December 31, 2015, the Partnership repurchased on the open market approximately $3.0 million of its 2022 Senior Notes. In connection with the repurchase, the Partnership paid approximately $2.9 million and recorded a gain on extinguishment of debt of approximately $0.4 million. Deferral of Interest Payment, Waiver and Forbearance Agreements In November 2016, we elected to defer an approximately $24.6 million interest payment due on November 1, 2016 with respect to the 2021 Senior Notes. The interest payment was subject to a 30-day grace period under the indenture. Failure to pay such interest payment on November 1, 2016 would have resulted in certain defaults and events of default under our revolving credit facility, which defaults were waived by the lenders under the our revolving credit facility. Pursuant to the Waiver and Twelfth Amendment, the requisite lenders under the Credit Agreement agreed to the limited waiver of certain defaults and events of default that would have occurred under the Credit Agreement as a result of the Issuers election to avail themselves of the 30-day grace period under the indenture governing the Issuers’ 2021 Senior Notes for the payment of the semi-annual interest payment in respect to such senior notes due November 1, 2016. Further pursuant to the Waiver and Twelfth Amendment, from the date thereof until November 30, 2016 (such period from November 1, 2016 to November 30, 2016, the “Waiver Period”), the Partnership and OLLC agreed to pay 100% of the net cash proceeds from any asset sale, transfer or other disposition (including with respect to notes receivable and accounts receivable) and from the liquidation of any swap transaction or hedge transaction arising under swap or hedge agreements between or among the Partnership, OLLC and/or any other loan party and any lender under the Credit Agreement and/or its affiliates, in each case, to the administrative agent for the ratable account of each lender under the Credit Agreement, for application to the outstanding loans under the Credit Agreement. Amounts so applied would have also reduced the aggregate elected commitments of the lenders under the Credit Agreement by an equivalent amount. Further, pursuant to the Waiver and Twelfth Amendment, from the date thereof until the termination of the Waiver Period the Partnership and OLLC agreed, to additional restrictive covenants. These restrictions further limited, until the expiration of the Waiver Period, the ability of, among other things, the Partnership, OLLC and certain of their respective subsidiaries from incurring additional indebtedness, creating liens on assets, paying certain dividends and distributions, making any optional or voluntary payments or redemptions in respect of any other indebtedness, making investments (including in respect of the creation of subsidiaries), entering into certain lease agreements, entering into certain business combinations, entering into any sale-leaseback transaction and entering into certain transactions with affiliates. Finally, pursuant to the Waiver and Twelfth Amendment, the Partnership and OLLC agreed to amend, to be effective from and after the date of the Waiver and Twelfth Amendment, subject to the Chapter 11 proceedings, the Credit Agreement to increase, from 90% to 95% (or such lesser amount agreed to by the administrative agent in its sole discretion, which lesser amount shall not be less than 92%), the percentage of the total value of OLLC’s and its subsidiary-loan parties’ oil and gas properties subject to a mortgage or similar instruments in favor of the administrative agent. On November 30, 2016, the Partnership, OLLC, certain subsidiaries of the partnership, the administrative agent, and the lenders consenting thereto entered into the first amendment to the limited waiver under our revolving credit facility, extending the Waiver Period to December 16, 2016. On November 30, 2016, the Partnership entered into (i) a forbearance (the “2021 Notes Forbearance”) among the Issuers, certain guarantors party thereto, and certain beneficial owners and/or investment advisors or managers of discretionary accounts for the holders or beneficial owners (the “2021 Holders”) of 51.7% of the aggregate principal amount of the Partnership’s 2021 Senior Notes and (ii) a Forbearance (the “2022 Notes Forbearance” and, together with the 2021 Notes Forbearance, the “Forbearances”) among the Issuers, certain guarantors party thereto, and certain beneficial owners and/or investment advisors or managers of discretionary accounts for the holders or beneficial owners (the “2022 Holders”) of 69% of the aggregate principal amount of the Partnership’s 2022 Senior Notes. Pursuant to each Forbearance, among other provisions, each of the 2021 Holders and 2022 Holders agreed that during the forbearance period, subject to certain conditions, they would not enforce, or otherwise take any action to direct enforcement of, any of the rights and remedies available to the 2021 Holders, the 2022 Holders or the trustee, as applicable, including, without limitation, any action to accelerate, or join in any request for acceleration of, the 2021 Senior Notes or the 2022 Senior Notes, solely with respect to the failure to make the interest payment due on November 1, 2016 on the 2021 Senior Notes, and the subsequent default for 30 days in such payment, which constituted an event of default under the 2021 Senior Notes indenture and may result in a cross default under the 2022 Senior Notes indenture. The forbearance agreements initially extended through December 7, 2016, and were subsequently extended through December 16, 2016. On December 16, 2016, the Partnership, OLLC, certain subsidiaries of the partnership, the administrative agent, and the lenders consenting thereto entered into the second amendment to limited waiver under our revolving credit facility, which among other things, extending the Waiver Period to January 13, 2017. In addition, the forbearance agreements were extended through January 13, 2017. On December 22, 2016, the Partnership entered into a Plan Support Agreement (the “Noteholder PSA”) with holders of over an aggregate of 50.2% of the aggregate outstanding principal amount of the 2021 Senior Notes and the 2022 Senior Notes (collectively, the “Notes”), as well as reached an agreement-in-principle with the administrative agent under our revolving credit facility on the terms of a financial restructuring. Under the terms of the Noteholder PSA, the financial restructuring would be effected through a prepackaged or prenegotiated plan of reorganization (the “Plan”). Pursuant to the terms of the Plan, which would be subject to approval of the Bankruptcy Court, it is anticipated that, among other things, on the effective date of the Plan (the “Effective Date”): • A newly formed corporation, as successor to the Partnership (“Reorganized Memorial”) would issue (i) new common shares (the “New Common Shares”) and (ii) five year warrants (the “Warrants”) entitling their holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding New Common Shares, at a per share exercise price equal to the principal and accrued interest on the senior notes as of December 31, 2016, divided by the number of issued and outstanding New Common Shares (including New Common Shares issuable upon exercise of the Warrants), which New Common Shares and Warrants will be distributed as set forth below; • The Notes would be cancelled and discharged and the holders of those Notes would receive (directly or indirectly) New Common Shares representing, in the aggregate, 98% of the New Common Shares issued on the Effective Date (subject to dilution by the post-emergence management incentive plan and the New Common Shares issuable upon exercise of the Warrants); • The noteholders, at their election, would be entitled to receive an additional cash payment of up to approximately $24.6 million; • Each holder of existing equity interests in the Partnership would receive its pro rata share of (i) New Common Shares representing, in the aggregate, 2% of the New Common Shares issued on the Effective Date and (ii) the Warrants (in each case, subject to dilution by the post-emergence management incentive plan and, in the case of the New Common Shares, subject to dilution by the Warrants); • General unsecured claims, on or after the effective date, would be paid in the ordinary course; and • Reorganized Memorial would enter an Exit Credit Facility, in the form of an amendment and restatement of the existing revolving credit facility. See Note 2 for additional information related to the expected terms of the Exit Credit Facility. The Partnership expects to emerge from the Chapter 11 proceedings as a corporation, including for U.S. federal income tax purposes. On January 13, 2017, the Partnership entered into the third amendment to limited waiver, which extended the outside date of the Waiver Period from January 13, 2017 to January 16, 2017. In addition, the Partnership entered into a Plan Support Agreement (the “RBL PSA”) with lenders holding 100% of the loans under our revolving credit facility. The RBL PSA was entered into on terms substantially similar to those of the Noteholder PSA. In addition, among other things, the RBL PSA provided that (i) the consenting lenders (as defined in the RBL PSA) may terminate the RBL PSA upon the termination of the Noteholder PSA or if there is an amendment to the Noteholder PSA that is, or would reasonably be expected to be, adverse to the administrative agent under our revolving credit facility or the Consenting Lenders and (ii) each of the Debtors agreed to not file a voluntary petition for relief under Chapter 11 until the Debtors terminated certain swap agreements identified in the RBL PSA and used the net proceeds thereof to repay outstanding amounts under the revolving credit facility. The Partnership did not pay the interest due on the 2021 Senior Notes prior to the expiration of the 30-day grace period. Due to (i) the uncertainty regarding the Partnership’s ability to cure the default and event of default as discussed in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes, the Partnership classified the outstanding balance of the senior notes as a current liability on its balance sheet as of December 31, 2016. As a result of the Chapter 11 filing, the debt has been accelerated. Weighted-Average Interest Rates The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented: For the Year Ended December 31, 2016 2015 2014 OLLC revolving credit facility (1) 3.28% 2.12% 2.67% (1) The Applicable Margin (as defined in our revolving credit facility), or credit spread, varies based on the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect). The Applicable Margin for the year ended for December 31, 2016, 2015, and 2014 was 2.76%, 1.90%, and 1.80% respectively. Deferred Financing Costs At December 31, 2016, approximately $1.3 million in deferred financing fees were written off related to our revolving credit facility, approximately $8.5 million were written off for the 2021 Senior Notes and approximately $5.7 million were written off for the 2022 Senior Notes due to (i) the uncertainty regarding the Partnership’s ability to cure the default as discussed in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes. Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: December 31, December 31, 2016 (3) 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ — $ 3,672 2021 Senior Notes (2) — 11,194 2022 Senior Notes (2) — 7,103 Total $ — $ 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. (3) At December 31, 2016, there were no remaining unamortized deferred financing costs as such costs were written off due to a default and event of default and the uncertainty regarding anticipated financial covenant violation at December 31, 2016. See discussion noted above. Letters of credit At December 31, 2016, we had $2.4 million letters of credit outstanding, all related to operations at our Wyoming properties.

Equity and Distributions

Equity and Distributions	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Equity and Distributions	Note 10. Equity and Distributions 2015 Purchase of Noncontrolling Interest In connection with the 2015 Beta Acquisition, we purchased the noncontrolling interests in SPBPC. See Note 4 for further information. 2014 Public Equity Offerings On September 9, 2014, we issued 14,950,000 common units representing limited partner interests in the Partnership (including 1,950,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $22.29 per unit generating total net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility. On July 15, 2014, we issued 9,890,000 common units representing limited partner interests in the Partnership (including 1,290,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the underwriters at a negotiated price of $22.25 per unit generating total net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility. Equity Outstanding The following table summarizes changes in the number of outstanding units since December 31, 2013: General Common Subordinated Partner Balance, December 31, 2013 55,877,831 5,360,912 61,300 Common units issued 24,840,000 — — Restricted common units issued 684,954 — — Restricted common units forfeited (38,294 ) — — Restricted common units repurchased (1) (42,587 ) — — Common units repurchased under repurchase program (899,912 ) — — General partner units issued — — 25,497 Balance, December 31, 2014 80,421,992 5,360,912 86,797 Restricted common units issued 827,704 — — Restricted common units forfeited (69,059 ) — — Restricted common units repurchased (1) (87,228 ) — — Common units repurchased under repurchase program (3,547,921 ) — — Subordinated units converted to common units 5,360,912 (5,360,912 ) — Balance, December 31, 2015 82,906,400 — 86,797 Common units issued 1,178,102 Restricted common units issued 50,000 — — Restricted common units forfeited (27,537 ) — — Restricted common units repurchased (1) (279,045 ) — — Cancellation of general partner units — — (86,797 ) Balance, December 31, 2016 83,827,920 — — (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 $0.6 million, $1.3 million and $1.0 million for the years ended December 31, 2016, 2015 and 2014, respectively. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership. Restricted common units are a component of common units as presented on our consolidated balance sheets. See Note 12 for additional information regarding restricted common units that were granted during the years ended December 31, 2016, 2015 and 2014. General Partner Interest and IDRs. On April 27, 2016, we acquired MEMP GP from Memorial Resource for cash consideration of approximately $0.8 million. MEMP GP held an approximate 0.1% general partner interest and 50% of the IDRs in us. In conjunction with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with an NGP affiliate pursuant to which we agreed to acquire the other 50% of the IDRs. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition. In connection with the MEMP GP Acquisition, our partnership agreement was amended and restated to convert the 0.1% general partner interest in the Partnership held by MEMP GP into a non-economic general partner interest. Prior to June 1, 2016, Memorial Resource owned 100% of our general partner, which owned 50% of our incentive distribution rights. The Funds collectively indirectly owned 50% of our incentive distribution rights. Common Units. The common units are a separate class of the limited partner interest in us and have limited voting rights as set forth in our partnership agreement. The holders of units are entitled to participate in partnership distributions as discussed further below under “Cash Distribution Policy” and exercise the rights or privileges available to limited partners under our partnership agreement. On February 13, 2015, all of the 5,360,912 outstanding subordinated units owned by MRD Holdco were converted into common units. The subordinated units converted on a one-for-one basis into common units upon the payment of MEMP's fourth quarter 2014 distribution. MRD Holdco sold all of the common units during the three months ended June 30, 2015 and no longer owns any of our outstanding common units. “At-the-Market” Equity Program On May 25, 2016, the Partnership entered into an equity distribution agreement for the sale of up to $60.0 million of common units under an at-the-market program (the “ATM Program”). Sales of common units, if any, will be made under the ATM Program by means of ordinary brokers’ transactions, through the facilities of the NASDAQ Global Market at market prices, or as otherwise agreed between the Partnership and a sales agent. During the year ended December 31, 2016, the Partnership sold 1,178,102 common units under the ATM program. The sale of the units generated proceeds of approximately $1.8 million for the year ended December 31, 2016, which was net of approximately $0.5 million in fees. The Partnership used the net proceeds from the sale of common units to repurchase senior notes. 2015 and 2014 Repurchases of Common Units In December 2014, the board of directors of our general partner authorized the repurchase of up to $150.0 million of our common units (“MEMP Repurchase Program”). Under the MEMP Repurchase Program, units could be repurchased and retired from time to time at our discretion on the open market. The MEMP Repurchase Program did not obligate us to repurchase any dollar amount or specific number of common units and could have been discontinued at any time. During the year ended December 31, 2015, we repurchased $52.8 million in common units, which represents a repurchase and retirement of 3,547,921 common units under the MEMP Repurchase Program. During the year ended December 31, 2014, we repurchased $12.9 million in common units, which represented a repurchase and retirement of 899,912 common units. The MEMP 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 Distribution Policy In October 2016, the board of directors of our general partner suspended distributions on common units primarily due to the current and expected commodity price environment and market conditions and their impact on our future business as well as restrictions imposed by our debt instruments, including our revolving credit facility. Additionally, under our revolving credit facility, we will not be able to pay distributions to unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with our revolving credit facility after giving effect to such distribution. Available Cash . Our amended partnership agreement requires that within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to our unitholders of record on the applicable record date. Generally, available cash refers to all cash on hand at the end of the quarter less cash reserves established by our general partner to: (i) operate our business (e.g., future capital expenditures, working capital and operating expenses); (ii) comply with applicable law, debt, and other agreements; and (iii) provide funds for distribution to our unitholders for any one or more of the next four quarters. If our general partner so determines, available cash may include borrowings made after the end of the quarter. Minimum Quarterly Distribution. During the subordination period, the common units had the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4750 per common unit plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus could be made on the subordinated units. These units were deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units were not entitled to receive any distributions from operating surplus until the common units had received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages were paid on the subordinated units. The practical effect of the subordinated units was to increase the likelihood that during the subordination period there would be available cash from operating surplus to be distributed on the common units. The subordination period ended on February 13, 2015. Cash Distributions to Unitholders The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts): Distribution Amount Aggregate Received by Quarter Declaration Date Record Date Payment Date Per Unit Distribution Affiliates 2 nd July 26, 2016 August 5, 2016 August 12, 2016 $ 0.0300 $ 2.5 $ < 0.1 1 st April 26, 2016 May 6, 2016 May 13, 2016 $ 0.0300 $ 2.5 $ < 0.1 4 th January 26, 2016 February 5, 2016 February 12, 2016 $ 0.1000 $ 8.3 $ < 0.1 3 rd October 26, 2015 November 5, 2015 November 12, 2015 $ 0.3000 $ 24.9 $ < 0.1 2 nd July 24, 2015 August 5, 2015 August 12, 2015 $ 0.5500 $ 45.7 $ 0.1 1 st April 24, 2015 May 6, 2015 May 13, 2015 $ 0.5500 $ 46.3 $ 0.2 4 th January 26, 2015 February 5, 2015 February 12, 2015 $ 0.5500 $ 46.3 $ 3.1 3 rd October 23, 2014 November 5, 2014 November 12, 2014 $ 0.5500 $ 47.8 $ 3.1 2 nd July 24, 2014 August 5, 2014 August 12, 2014 $ 0.5500 $ 39.5 $ 3.0 1 st April 24, 2014 May 6, 2014 May 13, 2014 $ 0.5500 $ 33.8 $ 3.0 Previous Owners Capital The following table summarizes our previous owners’ equity transactions related to the Property Swap with respect to the period indicated (dollars in thousands): Previous Owners Balance, December 31, 2013 $ 283,405 Net income (loss) (2,465 ) Contributions 5,990 Distributions (9,886 ) Distribution of net asset to MRD Holdco (26,131 ) Tax related effects attributable to Memorial Resource restructuring transactions and initial public offering (30,483 ) Other 227 Balance, December 31, 2014 $ 220,657 Net income (loss) (2,268 ) Contributions 1,912 Net book value of net assets exchanged (248,321 ) Deferred tax liability retained by previous owner 28,020 Balance, December 31, 2015 $ —

Earnings per Unit

Earnings per Unit	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Earnings per Unit	Note 11. Earnings per Unit The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts): For the Year Ended December 31, 2016 2015 2014 Net income (loss) attributable to Memorial Production Partners LP $ (540,398 ) $ (395,877 ) $ 115,582 Less: Previous owners interest in net income (loss) — (2,268 ) (2,465 ) Less: General partner's 0.1% interest in net income (loss) (1) (168 ) (412 ) 118 Less: IDRs attributable to corresponding period — 112 202 Net income (loss) available to limited partners $ (540,230 ) $ (393,309 ) $ 117,727 Weighted average limited partner units outstanding: Common units 83,351 82,897 65,498 Subordinated units — 631 5,361 Total (2) 83,351 83,528 70,859 Basic and diluted EPU $ (6.48 ) $ (4.71 ) $ 1.66 (1) As a result of repurchases under the MEMP Repurchase Program, our general partner had an approximate average 0.105% interest in us prior to the MEMP GP Acquisition for the five months ended May 31, 2016 and an approximate average of 0.105% interest in us for the year ended December 31, 2015. (2) For the year ended December 31, 2016, 3,325,318 incremental phantom units under the treasury stock method were excluded from the calculation of diluted earnings per unit, due to their antidilutive effect as we were in a loss position.

Equity-based Awards

Equity-based Awards	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Equity-based Awards	Note 12. Equity-based Awards Long-Term Incentive Plan In December 2011, the board of directors of our general partner adopted the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) for employees, officers, consultants and directors of the general partner and any of its affiliates, who perform services for the Partnership. The LTIP authorizes the grant of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights (“DERs”), other unit-based awards and unit awards. The LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP is administered by the board of directors of our general partner or a committee thereof. During the years ended December 31, 2016, 2015 and 2014 there were multiple awards of restricted common units that were granted under the LTIP to executive officers and independent directors of our general partner and other Memorial Resource employees. The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and typically graded vesting provisions in which one-third of each award vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in the partnership with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by the Partnership to its unitholders. The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires. Based on the market price per unit on the date of grant, the aggregate fair value of the restricted common units awarded to our general partner’s executive officers and other employees during the years ended December 31, 2016, 2015 and 2014 was $0.1 million, $12.3 million and $15.0 million, respectively. The restricted common units granted are accounted for as equity-classified awards. The grant-date fair value net of estimated forfeitures is recognized as compensation cost on a straight-line basis over the requisite service period. The fair value of the restricted unit awards granted to the independent directors of our general partner are also recognized as compensation cost on a straight-line basis over the requisite service period. Compensation costs are recorded as direct general and administrative expenses. The following table summarizes information regarding restricted common unit awards for the periods presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted common units outstanding at December 31, 2013 706,927 $ 18.62 Granted (2) 684,954 $ 22.39 Forfeited (38,294 ) $ 20.54 Vested (260,067 ) $ 18.56 Restricted common units outstanding at December 31, 2014 1,093,520 $ 20.93 Granted (3) 827,704 $ 14.90 Forfeited (69,059 ) $ 18.35 Vested (483,627 ) $ 20.37 Restricted common units outstanding at December 31, 2015 1,368,538 $ 17.61 Granted (4) 50,000 $ 2.41 Forfeited (27,537 ) $ 16.99 Vested (958,841 ) $ 18.01 Restricted common units outstanding at December 31, 2016 432,160 $ 15.00 (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 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 per unit. (3) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.3 million based on grant date market prices ranging from of $6.20 to $15.45 per unit. (4) The aggregate grant date fair value of restricted common unit awards issued in 2016 was $0.1 million based on grant date market price of $2.41 per unit. LTIP Modification On June 1, 2016, in connection with the MEMP GP Acquisition, as discussed in Note 1, the board of directors of our general partner approved the acceleration of the vesting schedule of unvested awards under the LTIP for the employees that remained with Memorial Resource. The grant-date fair value compensation cost of approximately $0.1 million was reversed and the modified-date grant fair value compensation cost of $0.5 million was recognized. On March 9, 2016, certain employees were impacted by an involuntary termination which, upon the approval of the board of directors of our general partner, accelerated the vesting schedule of unvested awards under the LTIP that otherwise would have been forfeited upon an involuntary termination. The acceleration of the LTIP vesting schedule represents an improbable-to-probable modification. The grant-date fair value compensation cost of approximately $0.5 million was reversed and the modified-date grant fair value compensation cost of approximately $0.3 million was recognized. Phantom Units The following table summarizes information regarding phantom unit awards granted under the LTIP: Number of Units Phantom units outstanding at December 31, 2015 — Granted 6,169,018 Forfeited (188,325 ) Phantom units outstanding at December 31, 2016 5,980,693 Phantom units issued to non-employee directors in January 2016 will vest on the first anniversary of the date of grant. Phantom units issued to certain employees in June 2016 will vest in substantially equal one-third increments on the first, second, and third anniversaries of the date of grant. The awards included distribution equivalent rights (“DERs”) pursuant to which the recipient will receive a cash payment with respect to each phantom unit equal to any cash distributions that we pay to a holder of a common unit. DERs are treated as additional compensation expense. Upon vesting, the phantom units will be settled through an amount of cash in a single lump sum payment equal to the product of (y) the closing price of our common units on the vesting date and (z) the number of such vested phantom units. In lieu of a cash payment, the board of directors of our general partner, in its discretion, may elect for the recipient to receive either a number of common units equal to the number of such vested phantom units or a combination of cash and common units. For the year ended December 31, 2016, the phantom units issued are classified as liability awards due to the Partnership not having sufficient common units available under the LTIP to settle in common units upon vesting. Compensation Expense The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2016 2015 2014 Equity classified awards Restricted common units $ 7,206 $ 10,809 $ 7,874 Liability classified awards Phantom units 322 — — $ 7,528 $ 10,809 $ 7,874 The unrecognized compensation cost associated with restricted common unit awards was an aggregate $3.8 million at December 31, 2016. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.1 years. Since the restricted common units are participating securities, any distributions received by the restricted common unitholders are included in distributions to partners as presented on our statements of consolidated and combined cash flows. During the years ended December 31, 2016, 2015 and 2014, the restricted common unitholders received a distribution of approximately $0.2 million, $2.8 million and $1.9 million, respectively.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Note 13. 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 year ended December 31, 2016 and 2015, we paid less than $0.1 million and $0.3 million, respectively, to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities. Common Control Acquisitions 2016 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 our next annual meeting. On June 1, 2016, the Partnership also acquired the remaining 50% of the IDRs of the Partnership owned by an NGP affiliate. 2015 Acquisition On February 23, 2015, we and Memorial Resource completed a transaction in which we exchanged our oil and gas properties in North Louisiana and approximately $78.4 million in cash for Memorial Resource’s East Texas and Louisiana oil and gas properties. The properties MEMP received are primarily located in the Joaquin Field in Shelby and Panola counties in East Texas. This acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to such acquisition as if the Partnership owned the assets for the period after common control commenced through the acquisition date. The Partnership recorded the following net assets (in thousands): Accounts receivable $ 2,372 Other receivables 5,478 Prepaid expenses and other current assets 1,874 Property and equipment, net 263,210 Accounts payable (3,586 ) Accounts payable - affiliate (1,290 ) Revenues payable (1,110 ) Accrued liabilities (11,347 ) Asset retirement obligations (4,559 ) Net assets $ 251,042 2014 Acquisitions On April 1, 2014, we acquired certain oil and natural gas properties in East Texas from a subsidiary of MRD LLC, for approximately $33.3 million, including customary post-closing adjustments (the “Double A Acquisition”). The acquired properties primarily represent additional working interests in wells currently owned by us and located in Polk and Tyler Counties in the Double A Field of East Texas as well as the Sunflower, Segno and Sugar Creek Fields. Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors. This acquisition was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date. On October 1, 2014, we acquired certain oil and natural gas properties in Weld County, Colorado from Memorial Resource for approximately $15.0 million in cash consideration. The acquired properties represent working interests in wells located in the Wattenberg Field (the “Wattenberg Acquisition”). Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee. This acquisition was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date. The Partnership recorded the following net assets (in thousands): Double A Wattenberg Acquisition Acquisition Property and equipment, net $ 37,838 $ 9,822 Asset retirement obligations (908 ) (149 ) Other current liabilities (722 ) — Net assets $ 36,208 $ 9,673 Due to common control considerations, the difference between the purchase price and the total identifiable assets has been recorded as a contribution or distribution, respectively, on our Statements of Consolidated and Combined Equity. 2015 Divestiture On November 2, 2015, in connection with an auction process administered by a third-party, we divested certain oil and natural gas properties in the Permian Basin with a net value of approximately $0.2 million to an affiliate of NGP for a purchase price of approximately $0.9 million. Due to common control considerations, $0.7 million difference between the proceeds from the sale and the net book value of the properties was recognized in the equity statement as a contribution. Related Party Agreements We and certain of our former affiliates entered into various documents and agreements. These agreements were negotiated among affiliated parties and, consequently, were not the result of arm’s-length negotiations. Omnibus Agreement Memorial Resource provided management, administrative and operating services to the Partnership and our general partner pursuant to our omnibus agreement. Upon completion of the MEMP GP Acquisition, the omnibus agreement was terminated and the Partnership entered into a transition services agreement with Memorial Resource. See Note 14 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 Year Ended December 31, 2016 2015 2014 $ 11,867 $ 32,281 $ 24,372 Beta Management Agreement In connection with the December 2012 Beta acquisition, Memorial Resource entered into a management agreement with its wholly-owned subsidiary, Beta Operating Company, LLC (“Beta Operating”), pursuant to which Memorial Resource agreed to provide management and administrative oversight with respect to the services provided by such subsidiary under certain operating agreements with our subsidiary, Rise Energy Beta, LLC, related to the Beta properties in exchange for an annual management fee. Pursuant to such management agreement and in connection with such operating agreements, Memorial Resource had the right to receive approximately $0.4 million from Rise Energy Beta, LLC annually. This agreement was terminated in November 2015 in connection with the 2015 Beta Acquisition. On June 1, 2016, Memorial Resource assigned and transferred Beta Operating to the Partnership in connection with the MEMP GP Acquisition. Transition Service Agreements The Partnership entered into transition service agreements related to an October 2013 common control acquisition. The term of these agreements were from October 1, 2013 through February 28, 2014. The Partnership paid transition service fees of approximately $0.8 million in the aggregate under these agreements. Classic Agreements In November 2011, Classic Hydrocarbons Operating, LLC, a subsidiary of Memorial Resource (“Classic Operating”), and Classic Pipeline & Gathering, LLC (“Classic Pipeline”), a subsidiary of MRD Holdco, entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline’s Joaquin gathering system. In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement had a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. Effective July 1, 2015, the fee was reduced to $0.40 per barrel. In February 2015, in connection with and as part of the Property Swap, Classic Hydrocarbons Holdings, L.P. sold all of the equity interests owned by it in Classic Operating as well as Craton Energy GP III, LLC (“Craton GP”) and Craton Energy Holdings III, LP (“Craton LP”), two subsidiaries of Memorial Resource, to OLLC, and Classic Operating, Craton GP and Craton LP were merged into OLLC. OLLC was therefore the successor to Classic Operating under the terminated amended gas gathering agreement and water disposal agreement. Classic Pipeline assigned its saltwater disposal system to OLLC in November 2015. Due to common control considerations, we recorded the receipt of this asset at historical cost and recognized a contribution of approximately $2.1 million in the equity statement. Prior to the assignment from Classic Pipeline, for the years ended December 31, 2015 and 2014, the Partnership incurred gathering and salt water disposal fees of approximately $3.2 million and $1.8 million respectively, from Classic Pipeline, an affiliate.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 14. Commitments and Contingencies Transition Services Agreement On June 1, 2016 we closed the MEMP GP Acquisition. Upon closing of the MEMP GP Acquisition, we and Memorial Resource became unaffiliated entities. We terminated our omnibus agreement and entered into a transition services agreement with Memorial Resource to manage post-closing separation costs and activities. During the year ended December 31, 2016, we recorded $1.6 million, of general and administrative expenses related to the transition services agreement with Memorial Resource. Litigation & Environmental On January 16, 2017, the Debtors filed voluntary petitions under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the Chapter 11 proceedings, attempts to prosecute, collect, secure or enforce remedies with respect to pre-petition claims against the Debtors are subject to the automatic stay provisions of Section 362(a) of the Bankruptcy Code, including litigation relating to the entities involved in the Chapter 11 proceedings. See Note 2 for additional information. As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows. Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. The following table presents the activity of our environmental reserves for the periods presented: 2016 2015 2014 (In thousands) Balance at beginning of period $ 216 $ 2,092 $ 437 Charged to costs and expenses — — 2,852 Payments (216 ) (1,876 ) (1,197 ) Balance at end of period $ — $ 216 $ 2,092 At December 31, 2016, we had no environmental reserves recorded. At December 31, 2015, we had approximately $0.2 million, of environmental reserves recorded on our balance sheet. Sinking Fund Trust Agreement REO assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Beta properties, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within State waters and the surface facilities. Under the terms of the agreement, REO, as the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2016, the account balance included in restricted investments was approximately $3.6 million. Supplemental Bond for Decommissioning Liabilities Trust Agreement REO assumed an obligation with the BOEM in connection with its 2009 acquisition of the Beta properties. Under the terms of the agreement dated March 1, 2007, the seller of the Beta properties was obligated to deliver a $90.0 million U.S. Treasury Note into a trust account for the decommissioning of the offshore production facilities. At the time of acquisition, all obligations under this existing agreement had been met. In January 2010, the BOEM issued a report that revised upward, the estimated cost of decommissioning. In June 2010, REO agreed to make quarterly payments to the trust account of no less than $1.25 million in response to the revision. The trust account has the required minimum balances of $152.0 million at December 31, 2016. In the event the account balance is less than the contractual amount, the working interest owners must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by the working interest owners. In 2015, the BOEM issued a preliminary report that indicated the estimated cost of decommissioning may further increase, and we expect the amount to be finalized during 2017 after negotiations are completed. The gross held-to-maturity investments held in the trust account as of December 31, 2016 for the U.S. Bank money market cash equivalent was $152.0 million. Operating Leases We have leases for offshore Southern California pipeline right-of-way use as well as office space in our operating regions. We also lease equipment, compressors and incur surface rentals related to our business operations. The previous owners also leased equipment and office space under various operating leases and incurred surface rentals related to their operations. For the years ended December 31, 2016, 2015 and 2014, we recognized $10.9 million, $16.9 million and $6.4 million of rent expense, respectively. The previous owners recorded rent expense of approximately $0.5 million for the year ended December 31, 2014. Amounts shown in the following table represent minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year (in thousands): Payment or Settlement Due by Period Purchase commitment Total 2017 2018 2019 2020 2021 Thereafter Operating leases $ 24,922 $ 7,938 $ 5,058 $ 3,309 $ 3,083 $ 2,748 $ 2,786 Purchase Commitments At December 31, 2016, we had a CO 2 2 2 Payment or Settlement Due by Period Purchase commitment Total 2017 2018 2019 2020 2021 Thereafter CO 2 $ 19,665 $ 6,740 $ 4,567 $ 4,548 $ 3,810 $ — $ — Minimum Volume Commitment At December 31, 2016, we had a long-term minimum volume commitment with a third party associated with a certain portion of our properties located in East Texas. The table below outlines the payment commitments associated with this minimum volume commitment (in thousands): Payment or Settlement Due by Period Purchase commitment Total 2017 2018 2019 2020 2021 Thereafter Midstream services $ 30,668 $ 5,121 $ 5,106 $ 5,107 $ 5,106 $ 5,121 $ 5,107

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Tax	Note 15. Income Tax The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2016 2015 2014 (In thousands) Current taxes: Federal $ 6 $ (11 ) $ — State 8 (48 ) (127 ) Total current income tax benefit (expense) 14 (59 ) (127 ) Deferred taxes: Federal 8 1,193 2,057 State (195 ) 1,041 (509 ) Total deferred income tax benefit (expense) (187 ) 2,234 1,548 Total income tax benefit (expense) $ (173 ) $ 2,175 $ 1,421 The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows (in thousands): For the Year Ended December 31, 2016 2015 2014 Expected tax benefit (expense) at federal statutory rate $ 191,870 $ 139,183 $ (39,966 ) State income tax benefit (expense), net of federal benefit 382 645 (1,907 ) Pass-through entities (1) (191,921 ) (137,704 ) 42,000 Other (504 ) 51 1,294 Total income tax benefit (expense) $ (173 ) $ 2,175 $ 1,421 (1) MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes. The components of net deferred income tax liabilities recognized were as follows: December 31, 2016 2015 (In thousands) Deferred income tax assets: Net operating loss carryforward $ 9 $ 56 Asset retirement obligation 875 694 Other 33 38 Total deferred income tax assets: 917 788 Valuation allowance (865 ) — Net deferred income tax assets 52 788 Deferred income tax liabilities: Property, plant and equipment $ 1,522 $ 1,324 Derivatives 770 1,514 Other 40 44 Total deferred income tax liabilities 2,332 2,882 Net deferred income tax liabilities $ 2,280 $ 2,094 A deferred tax liability was recorded in equity by the previous owners and related to Memorial Resource’s initial public offering and restructuring transactions as it represented a transaction among shareholders. Subsequent to the Memorial Resource’s initial public offering, income tax related to the Property Swap was calculated on a separate return basis. Uncertain Income Tax Position. We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. We had no unrecognized tax benefits as of December 31, 2016. Tax Audits and Settlements. Generally, our income tax years 2011 through 2016 remain open and subject to examination by the Internal Revenue Service or state tax jurisdictions where we conduct operations. In certain jurisdictions we operate through more than one legal entity, each of which may have different open years subject to examination. Tax Attribute carryforwards and Valuation Allowance. As of December 31, 2016, we had federal net operating loss of less than $0.1 million, which would expire in 2031. Valuation allowance was established on deferred tax assets applicable to a state jurisdiction where realization of the related deferred tax assets from future taxable income is not reasonably assured.

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information (Unaudited)	Note 16. Quarterly Financial Information (Unaudited) The following tables present selected quarterly financial data for the periods indicated. Earnings per unit are computed independently for each of the quarters presented and the sum of the quarterly earnings per unit may not necessarily equal the total for the year. First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per unit amounts) For the Year Ended December 31, 2016 Revenues $ 60,866 $ 68,066 $ 74,222 $ 81,426 Operating income (loss) (5,449 ) (156,971 ) (6,336 ) (267,783 ) Net income (loss) (38,097 ) (147,550 ) (32,866 ) (321,885 ) Net income (loss) attributable to Memorial Production Partners LP (38,097 ) (147,550 ) (32,866 ) (321,885 ) Limited partners’ interest in net income (loss) (38,057 ) (147,422 ) (32,866 ) (321,885 ) Basic and diluted earnings per unit (0.46 ) (1.78 ) (0.39 ) (3.85 ) First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per unit amounts) For the Year Ended December 31, 2015 Revenues $ 92,818 $ 98,138 $ 88,083 $ 79,108 Operating income (loss) (136,370 ) (85,197 ) (160,844 ) 99,434 Net income (loss) (162,658 ) (113,859 ) (191,981 ) 73,007 Net income (loss) attributable to Memorial Production Partners LP (162,817 ) (113,924 ) (192,085 ) 72,949 Net income (loss) allocated to previous owners (2,268 ) — — — Net income (loss) noncontrolling interest 159 65 104 58 Limited partners’ interest in net income (loss) (160,439 ) (113,862 ) (191,938 ) 72,874 Basic and diluted earnings per unit (1.90 ) (1.36 ) (2.31 ) 0.88 See Notes 3 and 11 for additional information regarding earnings per unit.

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Supplemental Oil and Gas Information (Unaudited)	N ote 17. Supplemental Oil and Gas Information (Unaudited) Capitalized Costs Relating to Oil and Natural Gas Producing Activities The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. Years Ended December 31, 2016 2015 2014 (In thousands) Evaluated oil and natural gas properties $ 3,115,012 $ 3,616,325 $ 3,329,338 Support equipment and facilities 199,093 205,876 198,088 Accumulated depletion, depreciation, and amortization (1,743,274 ) (1,878,549 ) (1,060,114 ) Total $ 1,570,831 $ 1,943,652 $ 2,467,312 Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: Years Ended December 31, 2016 2015 2014 (In thousands) Property acquisition costs, proved $ — $ 77,834 $ 983,076 Property acquisition costs, unproved — 1,887 720 Exploration 792 2,078 — Development 54,310 233,241 308,724 Total $ 55,102 $ 315,040 $ 1,292,520 Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Partnership’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change. Oil and Natural Gas Reserves Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures. Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. We engaged Ryder Scott to audit our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2016. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules. The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented: 2016 2015 2014 Oil ($/Bbl): WTI (1) $ 42.75 $ 46.79 $ 91.48 NGL ($/Bbl): WTI (1) $ 42.75 $ 46.79 $ 91.48 Natural Gas ($/MMbtu): Henry Hub (2) $ 2.48 $ 2.58 $ 4.35 (1) The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The weighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. The following tables set forth estimates of the net reserves as of December 31, 2016, 2015 and 2014, respectively: Year Ended December 31, 2016 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 90,945 461,526 43,395 1,267,571 Extensions and discoveries 297 288 42 2,320 Production (3,883 ) (44,776 ) (2,283 ) (81,773 ) Sale of minerals in place (3,228 ) (15,227 ) (123 ) (35,328 ) Revision of previous estimates (18,390 ) (30,795 ) (15,847 ) (236,225 ) End of year 65,741 371,016 25,184 916,565 Proved developed reserves: Beginning of year 50,817 311,147 30,315 797,936 End of year 45,536 280,035 18,923 666,786 Proved undeveloped reserves: Beginning of year 40,128 150,379 13,080 469,635 End of year 20,205 90,981 6,261 249,779 Year Ended December 31, 2015 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 100,258 727,216 59,034 1,682,960 Extensions and discoveries 2,319 8,686 558 25,950 Purchase of minerals in place 10,132 34,128 367 97,122 Production (4,087 ) (50,875 ) (2,820 ) (92,315 ) Sale of minerals in place (380 ) (13,731 ) (758 ) (20,559 ) Revision of previous estimates (17,297 ) (243,898 ) (12,986 ) (425,587 ) End of year 90,945 461,526 43,395 1,267,571 Proved developed reserves: Beginning of year 54,723 417,247 37,260 969,141 End of year 50,817 311,147 30,315 797,936 Proved undeveloped reserves: Beginning of year 45,535 309,969 21,774 713,819 End of year 40,128 150,379 13,080 469,635 Year Ended December 31, 2014 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 39,635 737,908 35,794 1,190,484 Extensions and discoveries 849 12,783 711 22,145 Purchase of minerals in place 69,095 13,036 22,351 561,713 Production (3,135 ) (48,721 ) (2,498 ) (82,520 ) Revision of previous estimates (6,186 ) 12,210 2,676 (8,862 ) End of year 100,258 727,216 59,034 1,682,960 Proved developed reserves: Beginning of year 22,429 427,983 17,637 668,381 End of year 54,723 417,247 37,260 969,141 Proved undeveloped reserves: Beginning of year 17,206 309,925 18,157 522,103 End of year 45,535 309,969 21,774 713,819 Noteworthy amounts included in the categories of proved reserve changes in the above tables include: • The 351.0 Bcfe reduction in reserves for the year ended December 31, 2016 is primarily due to a 148.3 Bcfe downward pricing revision and a 87.9 Bcfe downward revision due to updated well performance data. We divested 35.3 Bcfe during the year ended December 31, 2016. Proved undeveloped reserves decreased primarily due to downward pricing during the year ended December 31, 2016. • The 415.4 Bcfe reduction in reserves for the year ended December 31, 2015 is primarily due to a 413 Bcfe downward pricing revision and a 13 Bcfe downward revision due to updated well performance data. We acquired 97.1 Bcfe during the year ended December 31, 2015, the largest being the 2015 Beta Acquisition of 58.5 Bcfe. Proved undeveloped reserves decreased primarily due to downward pricing during the year ended December 31, 2015. • We acquired 561.7 Bcfe in multiple acquisitions during the year ended December 31, 2014, the largest being the Wyoming Acquisition of 497.2 Bcfe. We also acquired 45.0 Bcfe from the Eagle Ford Acquisition. An upward revision of natural gas for the year ended December 31, 2014 was due to increased natural gas prices on certain East Texas properties. The upward revision was partially offset by a downward revision of natural gas for the year ended December 31, 2014, which was primarily due to updated well performance data in certain other East Texas fields. Proved undeveloped reserves increased during the year ended December 31, 2014 primarily due to the Wyoming Acquisition. See Note 4 for additional information on acquisitions and divestitures. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. The standardized measure of discounted future net cash flows is as follows: Years Ended December 31, 2016 2015 2014 (In thousands) Future cash inflows $ 3,666,731 $ 5,952,935 $ 14,190,450 Future production costs (2,384,195 ) (3,194,577 ) (4,821,051 ) Future development costs (440,496 ) (808,512 ) (1,455,926 ) Future income tax expense (1) — — (119,675 ) Future net cash flows for estimated timing of cash flows 842,040 1,949,846 7,793,798 10% annual discount for estimated timing of cash flows (446,199 ) (1,360,292 ) (4,881,811 ) Standardized measure of discounted future net cash flows $ 395,841 $ 589,554 $ 2,911,987 (1) We are subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality we have excluded the impact of this tax for the years ended December 31, 2016, 2015 and 2014. The 2014 amount was related to Classic since its reserves were a part of a taxable entity for federal income tax purposes for the year ended December 31, 2014. Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2016: Years Ended December 31, 2016 2015 2014 (In thousands) Beginning of year $ 589,554 $ 2,911,987 $ 1,718,204 Sale of oil and natural gas produced, net of production costs (107,357 ) (128,382 ) (354,932 ) Purchase of minerals in place — 75,998 1,489,477 Sale of minerals in place (28,277 ) (45,100 ) — Extensions and discoveries 2,016 18,582 44,843 Changes in income taxes, net — 63,180 (63,180 ) Changes in prices and costs (404,870 ) (2,764,481 ) (170,682 ) Previously estimated development costs incurred 89,748 322,446 275,078 Net changes in future development costs 254,043 448,089 (133,098 ) Revisions of previous quantities 14,414 (344,775 ) (48,087 ) Accretion of discount 58,956 297,517 171,820 Change in production rates and other (72,386 ) (265,507 ) (17,456 ) End of year $ 395,841 $ 589,554 $ 2,911,987

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Note. 18 Subsequent Events Hedge Monetization For additional information, see Note 6 and Note 9. Chapter 11 Bankruptcy Filings For additional information, see Note 2 and Note 9. Entry into a Material Definitive Agreement On January 13, 2017, the Partnership entered into a Plan Support Agreement with lenders holding 100% of the loans under the Credit Agreement, by and among OLLC, the Partnership, and Wells Fargo Bank, National Association as administrative agent. See Note 2 and Note 9 for additional information. On January 13, 2017, the Partnership entered into the third amendment to limited waiver, which extended the outside date of the limited waiver period under the limited waiver from January 13, 2017 to January 16, 2017. See Note 2 and 9 for additional information. Notice of Delisting For additional information, see Note 2.

Organization and Basis of Pre25

Organization and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
General	General Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” See Note 2 for additional information regarding the Notice of Delisting. Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries. We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are located in Texas, Louisiana, 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” and “MEMP GP” refers to Memorial Production Partners GP LLC, our general partner and wholly-owned subsidiary; (ii) “Memorial Resource” refers to Memorial Resource Development Corp., the former owner of our general partner; (iii) “MRD LLC” refers to Memorial Resource Development LLC, which is the predecessor of Memorial Resource; (iv) “the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; (v) “OLLC” refers to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refers to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; (vii) “MRD Holdco” refers to MRD Holdco LLC, which together with a group controlled Memorial Resource and (viii) “NGP” refer to Natural Gas Partners. On April 27, 2016, we entered into an agreement pursuant to which the Partnership agreed to acquire, among other things, all of the equity interests in our general partner, MEMP GP, from Memorial Resource (the “MEMP GP Acquisition”) for cash consideration of approximately $0.8 million. MEMP GP held an approximate 0.1% general partner interest and 50% of the incentive distribution rights ("IDRs") in us. In conjunction with the MEMP GP Acquisition, on April 27, 2016, we also entered into an agreement with an NGP affiliate pursuant to which we agreed to acquire the other 50% of the IDRs. The acquisition was accounted for as an equity transaction and no gain or loss was recognized as a result of the acquisition. In connection with the closing of the transactions on June 1, 2016, our partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Partnership held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Partnership will elect the members of MEMP GP’s board of directors beginning with our next annual meeting. 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 13 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 collectively to certain oil and natural gas properties primarily located in East Texas and Louisiana that the Partnership acquired in February 2015 from certain operating subsidiaries of Memorial Resource in exchange for cash and certain of our oil and natural gas properties primarily located in North Louisiana. We refer to this transaction as the “Property Swap.” The acquired East Texas oil and natural gas properties were owned by Classic Hydrocarbons Holdings, L.P. or its subsidiaries (“Classic”). The acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to such acquisition as if the Partnership owned the assets for periods after common control commenced through the acquisition date. See Note 13 for additional information.
Basis of Presentation	Basis of Presentation Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements were derived from the historical accounting records of the previous owners and reflect the historical financial position, results of operations and cash flows for all periods presented. The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of REO, was presented as noncontrolling interest in the financial statements for the periods prior to November 3, 2015. On November 3, 2015, we purchased the noncontrolling interest in SPBPC for approximately $6.0 million and completed an acquisition of the remaining interests in our oil and gas properties located offshore Southern California (the “Beta properties”) from a third party for approximately $94.6 million (the “2015 Beta Acquisition”). See Note 4 for additional information regarding the 2015 Beta Acquisition. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gain on extinguishment of debt were previously accounted for as interest expense, net and are now being presented as other income (expenses) on our statements of operations on a separate line item.
Use of Estimates	Use of Estimates The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.
Principles of Consolidation and Combination	Principles of Consolidation and Combination Our consolidated financial statements include our accounts and those of our majority-owned subsidiary in which we have a controlling interest and acquired the remaining interests on November 3, 2015, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of the previous owners as discussed above in Note 1. All material intercompany balances and transactions have been eliminated.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.
Concentrations of Credit Risk	Concentrations of Credit Risk Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These restricted investments consist of money market deposit accounts which are held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. At December 31, 2016, we recorded $1.9 million as an allowance for doubtful accounts. Management determined that an allowance for uncollectible accounts was unnecessary at December 31, 2015. If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.
Oil and Natural Gas Properties	Oil and Natural Gas Properties Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs attributable to unproved locations are expensed as incurred. As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Support equipment and facilities, which are primarily related to our Wyoming and California assets, are depreciated using the straight-line method generally based on estimated useful lives of fifteen to forty years. On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2016, 2015 and 2014.
Oil And Gas Reserves	Oil and Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We engaged Ryder Scott Company, L.P. (“Ryder Scott”), our independent reserve engineers, to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2016. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
Other Property & Equipment	Other Property & Equipment Other property and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to seven years.
Restricted Investments	Restricted Investments Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense, net in the statement of operations. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 8 for additional information.
Debt Issuance Costs	Debt Issuance Costs These costs were historically recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method and generally approximates the effective yield method. The remaining unamortized debt issuance cost was written off at December 31, 2016, due to (i) the uncertainty regarding the Partnership’s ability to cure the default discussed above in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2016, 2015 and 2014 was approximately $22.1 million, $6.1 million, and $4.2 million, respectively.
Impairments	Impairments Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved and 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 gas properties. Impairment expense for the years ended December 31, 2016, 2015 and 2014 was approximately $183.4 million, $616.8 million, and $407.5 million, respectively.
Asset Retirement Obligations	Asset Retirement Obligations An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 7 for further discussion of asset retirement obligations.
Book Overdrafts	Book Overdrafts Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.
Revenue Recognition	Revenue Recognition Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2016 or 2015. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: For the Year Ending December 31, 2016 2015 2014 Major customers: Phillips 66 19% 12% 12% Sinclair Oil & Gas Company 16% 18% 11% Royal Dutch Shell plc and subsidiaries 14% 14% n/a
General and Administrative Expense	General and Administrative Expense Prior to June 1, 2016, 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 on June 1, 2016, and the Partnership entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. Prior to the MEMP GP Acquisition, our partnership agreement provided that our general partner determined in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its former affiliates on our behalf. Memorial Resource allocated indirect general and administrative costs based on time allocations for the three months ended March 31, 2016 and the years ended December 31, 2015 and 2014 and based on the terms as set forth by the MEMP GP Acquisition purchase and sale agreement for the period from April 1, 2016 through the closing date. Under our partnership agreement and the omnibus agreement, we reimbursed Memorial Resource for all direct and indirect costs incurred on our behalf. See Note 13 for additional information regarding the omnibus agreement. General and administrative expenses associated with the previous owners included the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production.
Derivative Instruments	Derivative Instruments Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.
Capitalized Interest	Capitalized Interest We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. For the years ended December 31, 2016, 2015 and 2014, we had $0.5 million, $2.1 million and $2.8 million in capitalized interest, respectively.
Income Tax	Income Tax We are currently organized as a pass-through entity for federal and most state income tax purposes. As a result, our partners are responsible for federal and state income taxes on their share of our taxable income. Certain of our consolidated subsidiaries are taxed as corporations for federal and state income tax purposes. We are also subject to the Texas margin tax for partnership activity in the state of Texas. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our consolidated statement of operations. We recognize a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority.
Earnings Per Unit	Earnings Per Unit Basic and diluted earnings per unit (“EPU”) is determined by dividing net income or loss available to the limited partners by the weighted average number of outstanding limited partner units during the period. Net income or loss available to the limited partners is determined by applying the two-class method. The two-class method of computing EPU is an earnings allocation formula that determines EPU based on distributions declared. The amount of net income or loss used in the determination of EPU is reduced (or increased) by the amount of available cash that has been or will be distributed to the limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the limited partners in accordance with the contractual terms of the partnership agreement. The total earnings allocated to the limited partners is determined by adding together the amount allocated for distributions declared and the amount allocated for the undistributed earnings or excess distributions over earnings. Basic and diluted EPU are equivalent, as all restricted common units and subordinated units participate in distributions. See Note 11 for additional information.
Equity Compensation	Equity Compensation The fair value of equity-classified awards (e.g., restricted common unit awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., phantom units awards) are recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. We currently have no awards subject to performance criteria; however, such awards would vest when it is probable that the performance criteria will be met and the requisite service period has been met. Generally, no compensation expense is recognized for equity instruments that do not vest. See Note 12 for further information.
Accrued Liabilities	Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, December 31, 2016 2015 Accrued interest payable $ 46,417 $ 23,192 Accrued lease operating expense 10,411 16,843 Accrued capital expenditures 1,826 8,110 Accrued general and administrative expenses 3,040 1,961 Accrued ad valorem tax 977 1,426 Asset retirement obligation 789 1,175 Environmental liability — 216 Other 1,775 — $ 65,235 $ 52,923
Supplemental Cash Flows	Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2016 2015 2014 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 87,527 $ 107,272 $ 63,709 Cash paid for taxes — 472 151 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (6,284 ) (27,932 ) 13,759 (Increase) decrease in accounts receivable related to acquisitions — 9,698 (5,854 ) (Increase) decrease in accounts receivable/payable related to divestitures (289 ) — — Repurchases under unit repurchase program — — 1,372 Assumptions of asset retirement obligations related to acquisitions — 23,754 4,265 Asset retirement obligation removal related to divestitures (19,669 ) — —
New Accounting Pronouncements	New Accounting Pronouncements Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Issues Task Force. In November 2016, the FASB issued an accounting standards update to clarify the guidance on the classification and presentation of restricted cash in the statement of cash flows. The changes in restricted cash and restricted cash equivalents that result from the transfers between cash, cash equivalents, and restricted cash and restricted cash equivalents should not be presented as cash flow activities in the statement of cash flows. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Statement of Cash Flows – Classification of Certain Cash Receipts and Cash Payments. In August 2016, the FASB issued an accounting standards update to address eight specific cash flow issues with the objective of reducing the current and potential future diversity in practice. The new guidance is effective for reporting periods beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The new guidance requires transition under a retrospective approach for each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Partnership is currently assessing the impact the adoption of this new guidance will have on our consolidated financial statements and related disclosures. Improvements to Employee Share-Based Payment Accounting. In March 2016, the FASB issued an accounting standards update to simplify the guidance on employee share-based payment accounting. The update involves several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Entities will no longer record excess tax benefits and certain tax deficiencies in equity. Instead, they will record all excess tax benefits and tax deficiencies as income tax expense or benefit in the income statement. In addition, the new guidance eliminates the requirement that excess tax benefits be realized before entities can recognize them and requires entities to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. Furthermore, the new guidance will increase the amount an employer can withhold to cover income taxes on awards and still qualify for the exception to liability classification for shares used to satisfy the employer’s statutory income tax withholding obligation. The new guidance requires an entity to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on the statement of cash flows. In addition, entities will now have to elect whether to account for forfeitures on share-based payments by: (i) recognizing forfeitures of awards as they occur or (ii) estimating the number of awards expected to be forfeited and adjusting the estimate when it is likely to change, as is currently required. 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. The Partnership adopted this guidance as of January 1, 2017, and it will not have a material impact on the Partnership’s future consolidated financial statements. 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 Partnership is the lessee under various agreements for office space, compressors, equipment, and surface rentals that are currently accounted for as operating leases, refer to Note 14, Commitments and Contingencies. As a result, these new rules will increase reported assets and liabilities. The Partnership will not early adopt this standard. The Partnership will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using a modified retrospective approach, including several optional practical expedients related to leases commenced before the effective date. The Partnership is currently evaluating the impact of these rules on its financial statements and has started the assessment process by evaluating the population of leases under the revised definition. The adoption of this standard will result in an increase in the assets and liabilities on the Partnership’s consolidated balance sheets. The quantitative impacts of the new standard are dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods. Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. In April 2015, the FASB issued an accounting standards update that specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the dropdown transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method are also required. The guidance was effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. We adopted this guidance on January 1, 2016. Since the Partnership has historically allocated the earnings (losses) of transferred businesses that occurred in periods before the date of the dropdown transaction entirely to affiliates of the general partner (i.e., the previous owners) and did not adjust previously reported earnings per unit of the limited partners, the impact of adopting this guidance was not material to the Partnership’s financial statements and related disclosures. Revenue from Contracts with Customers. In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The guidance is effective for interim and annual reporting periods starting January 1, 2018, and early adoption is permitted. The Partnership will not early adopt the standard, and plans to use a modified retrospective approach upon adoption, with the cumulative effect of initial application recognized at the date of initial application subject to certain additional disclosures. The Partnership has started the assessment process by evaluating its revenue streams and evaluating contracts under the revised standards. The Partnership is currently evaluating the standard and the impact it is expected to have on the consolidated financial statements and related footnote disclosures. Presentation of Financial Statements — Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. In August 2014, the FASB issued an accounting standards update that requires management to perform interim and annual assessments of whether there are conditions or events that raise substantial doubt of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. Certain disclosures are required if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, and with early adoption permitted. The amendments will not impact our financial position or results of operations but will require management to perform a formal going concern assessment. The Partnership adopted this guidance and has applied this guidance in its consolidated financial statements and related footnote disclosures. See Note 2 for additional information. 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 Accoun26

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Major Customers	The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: For the Year Ending December 31, 2016 2015 2014 Major customers: Phillips 66 19% 12% 12% Sinclair Oil & Gas Company 16% 18% 11% Royal Dutch Shell plc and subsidiaries 14% 14% n/a
Summary of Current Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, December 31, 2016 2015 Accrued interest payable $ 46,417 $ 23,192 Accrued lease operating expense 10,411 16,843 Accrued capital expenditures 1,826 8,110 Accrued general and administrative expenses 3,040 1,961 Accrued ad valorem tax 977 1,426 Asset retirement obligation 789 1,175 Environmental liability — 216 Other 1,775 — $ 65,235 $ 52,923
Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2016 2015 2014 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 87,527 $ 107,272 $ 63,709 Cash paid for taxes — 472 151 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (6,284 ) (27,932 ) 13,759 (Increase) decrease in accounts receivable related to acquisitions — 9,698 (5,854 ) (Increase) decrease in accounts receivable/payable related to divestitures (289 ) — — Repurchases under unit repurchase program — — 1,372 Assumptions of asset retirement obligations related to acquisitions — 23,754 4,265 Asset retirement obligation removal related to divestitures (19,669 ) — —

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 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 Year Ended December 31, 2016 2015 2014 $ 1,451 $ 1,928 $ 4,363
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed	The following table summarizes the fair value of the third party assets acquired and liabilities assumed in the 2015 Beta Acquisition (in thousands): 2015 Beta Acquisition Oil and gas properties $ 40,029 Prepaid expenses and other current assets 840 Restricted investments 69,579 Derivative instruments 4,568 Accounts receivable - affiliates and other 4,499 Asset retirement obligations (22,871 ) Accrued liabilities (2,010 ) Total identifiable net assets $ 94,634 The following table summarizes the fair value of the third party assets acquired and liabilities assumed in the Wyoming Acquisition (in thousands): Wyoming Acquisition Oil and gas properties $ 930,168 Asset retirement obligations (3,980 ) Revenues payable (375 ) Accrued liabilities (19,693 ) Total identifiable net assets $ 906,120 The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): Eagle Ford Acquisition Oil and gas properties $ 168,606 Asset retirement obligations (285 ) Accrued liabilities (250 ) Total identifiable net assets $ 168,071
Supplemental Pro Forma Information	The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2015 and 2014 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired (iii) accretion expense associated with asset retirement obligations recorded and (iv) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Year Ended December 31, 2015 2014 (In thousands, except per unit amounts) Revenues $ 381,495 $ 613,563 Net income (loss) (394,756 ) 132,630 Basic and diluted earnings per unit (4.73 ) 1.87 The following unaudited pro forma combined results of operations is provided for the year ended December 31, 2014 as though the Eagle Ford Acquisition and Wyoming Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Year Ended December 31, 2014 (In thousands, except per unit amounts) Revenues $ 666,508 Net income (loss) 153,843 Basic and diluted earnings per unit 2.20
Schedule of Income (Loss) before Income Taxes Including (Gain) Loss on Divestiture	The income (loss) before income taxes, including the associated (gain) loss on sale of properties, related to the Permian Divestiture and Rockies Divestiture included in the condensed statements of consolidated and combined operations of the Partnership is as follows (in thousands): For the Year Ended December 31, 2016 2015 2014 Permian Divestiture $ 4,297 $ (60,875 ) $ (228,956 ) Rockies Divestiture (7,677 ) (56,917 ) 3,127

Fair Value Measurements of Fi28

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2016 and December 31, 2015 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2016 Using Quoted Prices in Significant Other Significant Active Market Observable Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 189,851 $ — $ 189,851 Total assets $ — $ 189,851 $ — $ 189,851 Liabilities: Commodity derivatives $ — $ 17,757 $ — $ 17,757 Total liabilities $ — $ 17,757 $ — $ 17,757 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 Derivativ29

Risk Management and Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Open Commodity Positions	At December 31, 2016, the Partnership had the following open commodity positions: 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 1,890,000 1,740,000 1,000,000 Weighted-average fixed price $ 3.86 $ 3.83 $ 3.47 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 184,500 182,000 70,000 Weighted-average fixed price $ 84.29 $ 83.44 $ 86.84 NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 43,300 — — Weighted-average fixed price $ 37.55 $ — $ —
Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet	The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2016 and 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 December 31, December 31, December 31, December 31, Type Balance Sheet Location 2016 2015 2016 2015 (In thousands) Commodity contracts Short-term derivative instruments $ 86,335 $ 324,265 $ 16,871 $ 53,581 Interest rate swaps Short-term derivative instruments — — — 1,214 Gross fair value 86,335 324,265 16,871 54,795 Netting arrangements Short-term derivative instruments (16,871 ) (51,945 ) (16,871 ) (51,945 ) Net recorded fair value Short-term derivative instruments $ 69,464 $ 272,320 $ — $ 2,850 Commodity contracts Long-term derivative instruments $ 103,515 $ 492,730 $ 885 $ 30,920 Interest rate swaps Long-term derivative instruments — — — 1,441 Gross fair value 103,515 492,730 885 32,361 Netting arrangements Long-term derivative instruments (885 ) (30,920 ) (885 ) (30,920 ) Net recorded fair value Long-term derivative instruments $ 102,630 $ 461,810 $ — $ 1,441
Unrealized and Realized Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the years ending December 31, 2016, 2015, and 2014: For the Year Ended Statements of December 31, Operations Location 2016 2015 2014 Commodity derivative contracts (Gain) loss on commodity derivatives $ 117,105 $ (462,890 ) $ (492,254 ) Interest rate derivatives Interest expense, net 1,290 4,674 (151 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the years ended December 31, 2016, 2015, and 2014: 2016 2015 2014 (in thousands) Asset retirement obligations at beginning of period $ 164,164 $ 112,702 $ 101,436 Liabilities added from acquisitions or drilling 30 26,876 5,815 Liabilities removed upon sale of wells (19,669 ) (3,412 ) — Liabilities settled (1,442 ) (1,430 ) (651 ) Accretion expense 10,231 7,125 5,773 Revision of estimates 2,388 22,303 329 Asset retirement obligations at end of period 155,702 164,164 112,702 Less: Current portion 789 1,175 — Asset retirement obligations - long-term portion $ 154,913 $ 162,989 $ 112,702

Restricted Investments (Tables)

Restricted Investments (Tables)	12 Months Ended
	Dec. 31, 2016
Investments Debt And Equity Securities [Abstract]
Restricted Investment Balance	The components of the restricted investment balance are as follows December 31, December 31, 2016 2015 (In thousands) BOEM platform abandonment (See Note 14) $ 152,000 $ 144,008 BOEM lease bonds — 1,533 Surety bond cash collateral 500 — SPBPC Collateral: Contractual pipeline and surface facilities abandonment 3,627 3,178 California State Lands Commission pipeline right-of-way bond — 3,005 City of Long Beach pipeline facility permit — 500 Federal pipeline right-of-way bond — 307 Port of Long Beach pipeline license 107 100 Restricted investments $ 156,234 $ 152,631

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Consolidated Debt Obligations	Our consolidated debt obligations consisted of the following at the dates indicated: December 31, December 31, 2016 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ 511,652 $ 836,000 2021 Senior Notes, fixed-rate, due May 2021 (2) (4) 646,287 700,000 2022 Senior Notes, fixed-rate, due August 2022 (3) (4) 464,965 496,990 Senior notes debt issuance costs, net (5) — (18,297 ) Unamortized discounts (5) — (14,114 ) Total debt 1,622,904 2,000,579 Current portion of long-term debt (6) (1,622,904 ) — Total long-term debt $ — $ 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 $314.3 million and $210.0 million at December 31, 2016 and 2015, respectively. (3) The estimated fair value of our 2022 Senior Notes was $223.2 million and $149.1 million at December 31, 2016 and 2015, respectively. (4) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (5) Approximately $25.0 million in net discounts and deferred financing fees were written off due to a default and event of default and the uncertainty regarding anticipated financial covenant violation at December 31, 2016. (6) Due to an existing and anticipated financial covenant violations, the Partnership’s revolving credit facility and senior notes were classified as current at December 31, 2016.
Borrowing Base Credit Facility	Credit facilities tied to a borrowing base are common throughout the oil and gas industry. The borrowing base for our revolving credit facility was the following at the date indicated: December 31, 2016 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 $ 530,653
Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations	The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented: For the Year Ended December 31, 2016 2015 2014 OLLC revolving credit facility (1) 3.28% 2.12% 2.67% (1) The Applicable Margin (as defined in our revolving credit facility), or credit spread, varies based on the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect). The Applicable Margin for the year ended for December 31, 2016, 2015, and 2014 was 2.76%, 1.90%, and 1.80% respectively.
Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: December 31, December 31, 2016 (3) 2015 (In thousands) OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) $ — $ 3,672 2021 Senior Notes (2) — 11,194 2022 Senior Notes (2) — 7,103 Total $ — $ 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. (3) At December 31, 2016, there were no remaining unamortized deferred financing costs as such costs were written off due to a default and event of default and the uncertainty regarding anticipated financial covenant violation at December 31, 2016. See discussion noted above.

Equity and Distributions (Table

Equity and Distributions (Tables)	12 Months Ended
	Dec. 31, 2016
Limited Partners Capital Account [Line Items]
Summary of Changes in Number of Outstanding Units	The following table summarizes changes in the number of outstanding units since December 31, 2013: General Common Subordinated Partner Balance, December 31, 2013 55,877,831 5,360,912 61,300 Common units issued 24,840,000 — — Restricted common units issued 684,954 — — Restricted common units forfeited (38,294 ) — — Restricted common units repurchased (1) (42,587 ) — — Common units repurchased under repurchase program (899,912 ) — — General partner units issued — — 25,497 Balance, December 31, 2014 80,421,992 5,360,912 86,797 Restricted common units issued 827,704 — — Restricted common units forfeited (69,059 ) — — Restricted common units repurchased (1) (87,228 ) — — Common units repurchased under repurchase program (3,547,921 ) — — Subordinated units converted to common units 5,360,912 (5,360,912 ) — Balance, December 31, 2015 82,906,400 — 86,797 Common units issued 1,178,102 Restricted common units issued 50,000 — — Restricted common units forfeited (27,537 ) — — Restricted common units repurchased (1) (279,045 ) — — Cancellation of general partner units — — (86,797 ) Balance, December 31, 2016 83,827,920 — — (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 $0.6 million, $1.3 million and $1.0 million for the years ended December 31, 2016, 2015 and 2014, respectively. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership.
Summary of Quarterly Cash Distribution Rates	The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts): Distribution Amount Aggregate Received by Quarter Declaration Date Record Date Payment Date Per Unit Distribution Affiliates 2 nd July 26, 2016 August 5, 2016 August 12, 2016 $ 0.0300 $ 2.5 $ < 0.1 1 st April 26, 2016 May 6, 2016 May 13, 2016 $ 0.0300 $ 2.5 $ < 0.1 4 th January 26, 2016 February 5, 2016 February 12, 2016 $ 0.1000 $ 8.3 $ < 0.1 3 rd October 26, 2015 November 5, 2015 November 12, 2015 $ 0.3000 $ 24.9 $ < 0.1 2 nd July 24, 2015 August 5, 2015 August 12, 2015 $ 0.5500 $ 45.7 $ 0.1 1 st April 24, 2015 May 6, 2015 May 13, 2015 $ 0.5500 $ 46.3 $ 0.2 4 th January 26, 2015 February 5, 2015 February 12, 2015 $ 0.5500 $ 46.3 $ 3.1 3 rd October 23, 2014 November 5, 2014 November 12, 2014 $ 0.5500 $ 47.8 $ 3.1 2 nd July 24, 2014 August 5, 2014 August 12, 2014 $ 0.5500 $ 39.5 $ 3.0 1 st April 24, 2014 May 6, 2014 May 13, 2014 $ 0.5500 $ 33.8 $ 3.0
Previous Owners [Member]
Limited Partners Capital Account [Line Items]
Summary of Predecessor's Equity Transactions Related to Property Swap	The following table summarizes our previous owners’ equity transactions related to the Property Swap with respect to the period indicated (dollars in thousands): Previous Owners Balance, December 31, 2013 $ 283,405 Net income (loss) (2,465 ) Contributions 5,990 Distributions (9,886 ) Distribution of net asset to MRD Holdco (26,131 ) Tax related effects attributable to Memorial Resource restructuring transactions and initial public offering (30,483 ) Other 227 Balance, December 31, 2014 $ 220,657 Net income (loss) (2,268 ) Contributions 1,912 Net book value of net assets exchanged (248,321 ) Deferred tax liability retained by previous owner 28,020 Balance, December 31, 2015 $ —

Earnings per Unit (Tables)

Earnings per Unit (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Calculation of Earnings (Loss) Per Unit	The following sets forth the calculation of earnings (loss) per unit, or EPU, for the periods indicated (in thousands, except per unit amounts): For the Year Ended December 31, 2016 2015 2014 Net income (loss) attributable to Memorial Production Partners LP $ (540,398 ) $ (395,877 ) $ 115,582 Less: Previous owners interest in net income (loss) — (2,268 ) (2,465 ) Less: General partner's 0.1% interest in net income (loss) (1) (168 ) (412 ) 118 Less: IDRs attributable to corresponding period — 112 202 Net income (loss) available to limited partners $ (540,230 ) $ (393,309 ) $ 117,727 Weighted average limited partner units outstanding: Common units 83,351 82,897 65,498 Subordinated units — 631 5,361 Total (2) 83,351 83,528 70,859 Basic and diluted EPU $ (6.48 ) $ (4.71 ) $ 1.66 (1) As a result of repurchases under the MEMP Repurchase Program, our general partner had an approximate average 0.105% interest in us prior to the MEMP GP Acquisition for the five months ended May 31, 2016 and an approximate average of 0.105% interest in us for the year ended December 31, 2015. (2) For the year ended December 31, 2016, 3,325,318 incremental phantom units under the treasury stock method were excluded from the calculation of diluted earnings per unit, due to their antidilutive effect as we were in a loss position.

Equity-based Awards (Tables)

Equity-based Awards (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Information Regarding Restricted Common Unit Awards	The following table summarizes information regarding restricted common unit awards for the periods presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted common units outstanding at December 31, 2013 706,927 $ 18.62 Granted (2) 684,954 $ 22.39 Forfeited (38,294 ) $ 20.54 Vested (260,067 ) $ 18.56 Restricted common units outstanding at December 31, 2014 1,093,520 $ 20.93 Granted (3) 827,704 $ 14.90 Forfeited (69,059 ) $ 18.35 Vested (483,627 ) $ 20.37 Restricted common units outstanding at December 31, 2015 1,368,538 $ 17.61 Granted (4) 50,000 $ 2.41 Forfeited (27,537 ) $ 16.99 Vested (958,841 ) $ 18.01 Restricted common units outstanding at December 31, 2016 432,160 $ 15.00 (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 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 per unit. (3) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.3 million based on grant date market prices ranging from of $6.20 to $15.45 per unit. (4) The aggregate grant date fair value of restricted common unit awards issued in 2016 was $0.1 million based on grant date market price of $2.41 per unit.
Summary of Information Regarding Phantom Unit Awards	The following table summarizes information regarding phantom unit awards granted under the LTIP: Number of Units Phantom units outstanding at December 31, 2015 — Granted 6,169,018 Forfeited (188,325 ) Phantom units outstanding at December 31, 2016 5,980,693
Summary of Amount of Compensation Expense Recognized	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2016 2015 2014 Equity classified awards Restricted common units $ 7,206 $ 10,809 $ 7,874 Liability classified awards Phantom units 322 — — $ 7,528 $ 10,809 $ 7,874

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Double A and Wattenberg Acquisition [Member]
Related Party Transaction [Line Items]
Schedule of Net Assets Recorded by Partnership	The Partnership recorded the following net assets (in thousands): Double A Wattenberg Acquisition Acquisition Property and equipment, net $ 37,838 $ 9,822 Asset retirement obligations (908 ) (149 ) Other current liabilities (722 ) — Net assets $ 36,208 $ 9,673
February 2015 Acquisition [Member]
Related Party Transaction [Line Items]
Schedule of Net Assets Recorded by Partnership	The Partnership recorded the following net assets (in thousands): Accounts receivable $ 2,372 Other receivables 5,478 Prepaid expenses and other current assets 1,874 Property and equipment, net 263,210 Accounts payable (3,586 ) Accounts payable - affiliate (1,290 ) Revenues payable (1,110 ) Accrued liabilities (11,347 ) Asset retirement obligations (4,559 ) Net assets $ 251,042
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
Schedule of Amount of General and Administrative Costs and Expenses Recognized	The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2016 2015 2014 $ 11,867 $ 32,281 $ 24,372

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Environmental Reserves	The following table presents the activity of our environmental reserves for the periods presented: 2016 2015 2014 (In thousands) Balance at beginning of period $ 216 $ 2,092 $ 437 Charged to costs and expenses — — 2,852 Payments (216 ) (1,876 ) (1,197 ) Balance at end of period $ — $ 216 $ 2,092
Lease Obligations	Amounts shown in the following table represent minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year (in thousands): Payment or Settlement Due by Period Purchase commitment Total 2017 2018 2019 2020 2021 Thereafter Operating leases $ 24,922 $ 7,938 $ 5,058 $ 3,309 $ 3,083 $ 2,748 $ 2,786
Purchase Commitments Under the Contracts	At December 31, 2016, we had a CO 2 2 2 Payment or Settlement Due by Period Purchase commitment Total 2017 2018 2019 2020 2021 Thereafter CO 2 $ 19,665 $ 6,740 $ 4,567 $ 4,548 $ 3,810 $ — $ — At December 31, 2016, we had a long-term minimum volume commitment with a third party associated with a certain portion of our properties located in East Texas. The table below outlines the payment commitments associated with this minimum volume commitment (in thousands): Payment or Settlement Due by Period Purchase commitment Total 2017 2018 2019 2020 2021 Thereafter Midstream services $ 30,668 $ 5,121 $ 5,106 $ 5,107 $ 5,106 $ 5,121 $ 5,107

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Components of Income Tax Expense (Benefit)	The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2016 2015 2014 (In thousands) Current taxes: Federal $ 6 $ (11 ) $ — State 8 (48 ) (127 ) Total current income tax benefit (expense) 14 (59 ) (127 ) Deferred taxes: Federal 8 1,193 2,057 State (195 ) 1,041 (509 ) Total deferred income tax benefit (expense) (187 ) 2,234 1,548 Total income tax benefit (expense) $ (173 ) $ 2,175 $ 1,421
Reconciliation of Income Tax Benefit (Provision)	The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows (in thousands): For the Year Ended December 31, 2016 2015 2014 Expected tax benefit (expense) at federal statutory rate $ 191,870 $ 139,183 $ (39,966 ) State income tax benefit (expense), net of federal benefit 382 645 (1,907 ) Pass-through entities (1) (191,921 ) (137,704 ) 42,000 Other (504 ) 51 1,294 Total income tax benefit (expense) $ (173 ) $ 2,175 $ 1,421 (1) MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes.
Components of Net Deferred Income Tax Liabilities	The components of net deferred income tax liabilities recognized were as follows: December 31, 2016 2015 (In thousands) Deferred income tax assets: Net operating loss carryforward $ 9 $ 56 Asset retirement obligation 875 694 Other 33 38 Total deferred income tax assets: 917 788 Valuation allowance (865 ) — Net deferred income tax assets 52 788 Deferred income tax liabilities: Property, plant and equipment $ 1,522 $ 1,324 Derivatives 770 1,514 Other 40 44 Total deferred income tax liabilities 2,332 2,882 Net deferred income tax liabilities $ 2,280 $ 2,094

Quarterly Financial Informati39

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data	The following tables present selected quarterly financial data for the periods indicated. Earnings per unit are computed independently for each of the quarters presented and the sum of the quarterly earnings per unit may not necessarily equal the total for the year. First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per unit amounts) For the Year Ended December 31, 2016 Revenues $ 60,866 $ 68,066 $ 74,222 $ 81,426 Operating income (loss) (5,449 ) (156,971 ) (6,336 ) (267,783 ) Net income (loss) (38,097 ) (147,550 ) (32,866 ) (321,885 ) Net income (loss) attributable to Memorial Production Partners LP (38,097 ) (147,550 ) (32,866 ) (321,885 ) Limited partners’ interest in net income (loss) (38,057 ) (147,422 ) (32,866 ) (321,885 ) Basic and diluted earnings per unit (0.46 ) (1.78 ) (0.39 ) (3.85 ) First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per unit amounts) For the Year Ended December 31, 2015 Revenues $ 92,818 $ 98,138 $ 88,083 $ 79,108 Operating income (loss) (136,370 ) (85,197 ) (160,844 ) 99,434 Net income (loss) (162,658 ) (113,859 ) (191,981 ) 73,007 Net income (loss) attributable to Memorial Production Partners LP (162,817 ) (113,924 ) (192,085 ) 72,949 Net income (loss) allocated to previous owners (2,268 ) — — — Net income (loss) noncontrolling interest 159 65 104 58 Limited partners’ interest in net income (loss) (160,439 ) (113,862 ) (191,938 ) 72,874 Basic and diluted earnings per unit (1.90 ) (1.36 ) (2.31 ) 0.88

Supplemental Oil and Gas Info40

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Extractive Industries [Abstract]
Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities	The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. Years Ended December 31, 2016 2015 2014 (In thousands) Evaluated oil and natural gas properties $ 3,115,012 $ 3,616,325 $ 3,329,338 Support equipment and facilities 199,093 205,876 198,088 Accumulated depletion, depreciation, and amortization (1,743,274 ) (1,878,549 ) (1,060,114 ) Total $ 1,570,831 $ 1,943,652 $ 2,467,312
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities	Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: Years Ended December 31, 2016 2015 2014 (In thousands) Property acquisition costs, proved $ — $ 77,834 $ 983,076 Property acquisition costs, unproved — 1,887 720 Exploration 792 2,078 — Development 54,310 233,241 308,724 Total $ 55,102 $ 315,040 $ 1,292,520
Schedule of Product Prices Used for Valuing the Reserves	The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented: 2016 2015 2014 Oil ($/Bbl): WTI (1) $ 42.75 $ 46.79 $ 91.48 NGL ($/Bbl): WTI (1) $ 42.75 $ 46.79 $ 91.48 Natural Gas ($/MMbtu): Henry Hub (2) $ 2.48 $ 2.58 $ 4.35 (1) The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The weighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
Schedule of Net Reserves	The following tables set forth estimates of the net reserves as of December 31, 2016, 2015 and 2014, respectively: Year Ended December 31, 2016 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 90,945 461,526 43,395 1,267,571 Extensions and discoveries 297 288 42 2,320 Production (3,883 ) (44,776 ) (2,283 ) (81,773 ) Sale of minerals in place (3,228 ) (15,227 ) (123 ) (35,328 ) Revision of previous estimates (18,390 ) (30,795 ) (15,847 ) (236,225 ) End of year 65,741 371,016 25,184 916,565 Proved developed reserves: Beginning of year 50,817 311,147 30,315 797,936 End of year 45,536 280,035 18,923 666,786 Proved undeveloped reserves: Beginning of year 40,128 150,379 13,080 469,635 End of year 20,205 90,981 6,261 249,779 Year Ended December 31, 2015 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 100,258 727,216 59,034 1,682,960 Extensions and discoveries 2,319 8,686 558 25,950 Purchase of minerals in place 10,132 34,128 367 97,122 Production (4,087 ) (50,875 ) (2,820 ) (92,315 ) Sale of minerals in place (380 ) (13,731 ) (758 ) (20,559 ) Revision of previous estimates (17,297 ) (243,898 ) (12,986 ) (425,587 ) End of year 90,945 461,526 43,395 1,267,571 Proved developed reserves: Beginning of year 54,723 417,247 37,260 969,141 End of year 50,817 311,147 30,315 797,936 Proved undeveloped reserves: Beginning of year 45,535 309,969 21,774 713,819 End of year 40,128 150,379 13,080 469,635 Year Ended December 31, 2014 Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 39,635 737,908 35,794 1,190,484 Extensions and discoveries 849 12,783 711 22,145 Purchase of minerals in place 69,095 13,036 22,351 561,713 Production (3,135 ) (48,721 ) (2,498 ) (82,520 ) Revision of previous estimates (6,186 ) 12,210 2,676 (8,862 ) End of year 100,258 727,216 59,034 1,682,960 Proved developed reserves: Beginning of year 22,429 427,983 17,637 668,381 End of year 54,723 417,247 37,260 969,141 Proved undeveloped reserves: Beginning of year 17,206 309,925 18,157 522,103 End of year 45,535 309,969 21,774 713,819
Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows is as follows: Years Ended December 31, 2016 2015 2014 (In thousands) Future cash inflows $ 3,666,731 $ 5,952,935 $ 14,190,450 Future production costs (2,384,195 ) (3,194,577 ) (4,821,051 ) Future development costs (440,496 ) (808,512 ) (1,455,926 ) Future income tax expense (1) — — (119,675 ) Future net cash flows for estimated timing of cash flows 842,040 1,949,846 7,793,798 10% annual discount for estimated timing of cash flows (446,199 ) (1,360,292 ) (4,881,811 ) Standardized measure of discounted future net cash flows $ 395,841 $ 589,554 $ 2,911,987 (1) We are subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality we have excluded the impact of this tax for the years ended December 31, 2016, 2015 and 2014. The 2014 amount was related to Classic since its reserves were a part of a taxable entity for federal income tax purposes for the year ended December 31, 2014.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves	The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2016: Years Ended December 31, 2016 2015 2014 (In thousands) Beginning of year $ 589,554 $ 2,911,987 $ 1,718,204 Sale of oil and natural gas produced, net of production costs (107,357 ) (128,382 ) (354,932 ) Purchase of minerals in place — 75,998 1,489,477 Sale of minerals in place (28,277 ) (45,100 ) — Extensions and discoveries 2,016 18,582 44,843 Changes in income taxes, net — 63,180 (63,180 ) Changes in prices and costs (404,870 ) (2,764,481 ) (170,682 ) Previously estimated development costs incurred 89,748 322,446 275,078 Net changes in future development costs 254,043 448,089 (133,098 ) Revisions of previous quantities 14,414 (344,775 ) (48,087 ) Accretion of discount 58,956 297,517 171,820 Change in production rates and other (72,386 ) (265,507 ) (17,456 ) End of year $ 395,841 $ 589,554 $ 2,911,987

Organization and Basis of Pre41

Organization and Basis of Presentation - Additional Information (Detail)	Apr. 27, 2016USD ($)	Nov. 03, 2015USD ($)	Dec. 31, 2016USD ($)Segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 01, 2016
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments | Segment			1
Acquisitions of oil and natural gas properties			$ 0	$ 100,730,000	$ 1,083,761,000
2015 Beta Acquisition [Member]
Consolidation And Basis Of Presentation [Line Items]
Acquisitions of oil and natural gas properties		$ 94,600,000
Purchase of noncontrolling interest in SPBPC		$ 6,000,000
MEMP GP [Member]
Consolidation And Basis Of Presentation [Line Items]
Acquisition purchase price	$ 800,000
Partnership ownership percentage	0.10%
Gain (loss) on acquisition	$ 0
Related party transaction, description of transaction			In connection with the closing of the transactions on June 1, 2016, our partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Partnership held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Partnership will elect the members of MEMP GP’s board of directors beginning with our next annual meeting.
Incentive Distribution Rights (“IDRs”) [Member] | MEMP GP [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage	50.00%
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%

Chapter 11 Proceedings, Abili42

Chapter 11 Proceedings, Ability to Continue as a Going Concern and Covenant Violations - Additional Information (Detail) - USD ($)	Jan. 13, 2017	Dec. 22, 2016	Apr. 14, 2016	Dec. 31, 2016	Dec. 21, 2016	Dec. 01, 2016	Nov. 30, 2016	Nov. 01, 2016	Oct. 28, 2016	Apr. 13, 2016	Dec. 31, 2015
Subsequent Event [Member]
Reorganizations [Line Items]
Lenders holding percentage on loans	100.00%
Noteholder Plan Support Agreement [Member]
Reorganizations [Line Items]
Warrant life period		5 years
Percentage of common shares to be issued upon exercise of warrants		8.00%
Percentage of new common shares issued		98.00%
Percentage of new common shares issued to exiting equity interests		2.00%
Noteholder Plan Support Agreement [Member] | Maximum [Member]
Reorganizations [Line Items]
Additional cash payment		$ 24,600,000
Noteholder Plan Support Agreement [Member] | Notes Due 2021 and Notes Due 2022 [Member]
Reorganizations [Line Items]
Minimum note holder percentage to financial restructuring for prepackaged plan of reorganization		50.20%
RBL PSA [Member] | Exit Credit Facility [Member]
Reorganizations [Line Items]
Debt covenant terms				customary mandatory prepayments as well as a requirement that, in the event that as of the close of any business day the aggregate amount of our unrestricted cash and cash equivalents exceeds $35.0 million in the aggregate, we must prepay the loans under the Exit Credit Facility (without a corresponding reduction in the available commitments under the Exit Credit Facility) and cash-collateralize any letter of credit exposure in an amount equal to such excess; provided that, we may elect to increase such the excess cash threshold from $35.0 million to $50.0 million at such time as the aggregate amount of net cash proceeds received from asset sales exceeds the borrowing base value attributable to such assets (if any) equals or exceeds $15.0 million; provided further, however, that in the event that we issue certain unsecured debt in an aggregate amount of $10.0 million or greater, we will no longer have the ability to increase such threshold above $35.0 million and, if such threshold is greater than $35.0 million at such time, such threshold will be immediately reduced to $35.0 million
RBL PSA [Member] | Subsequent Event [Member]
Reorganizations [Line Items]
Lenders holding percentage on loans	100.00%
RBL PSA [Member] | Subsequent Event [Member] | Exit Credit Facility [Member]
Reorganizations [Line Items]
Revolving credit facility	$ 1,000,000,000
Maturity date	Mar. 19, 2021
Minimum Percentage of Oil and Gas Properties mortgage as collateral security for the obligations	95.00%
Percentage of revolving unused commitment fee	0.50%
Debt covenant, minimum aggregate amount of unrestricted cash and cash equivalents to prepay loans and cash collateralize letter of credit exposure	$ 35,000,000
Debt covenant, maximum threshold amount of unrestricted cash or cash equivalents	50,000,000
Debt covenant, minimum aggregate amount of net cash proceeds from asset sales in excess of borrowing base value	15,000,000
Debt covenant, minimum aggregate amount of unsecured debt	$ 10,000,000
Interest coverage ratio on EBITDAX to net interest expenses	250.00%
Interest coverage ratio consolidated current assets to consolidated current liabilities	100.00%
Debt covenant, debt to EBITDAX ratio maximum	400.00%
Debt covenant, minimum hedge percentage of forecasted proved developed producing production	50.00%
Debt covenant, maximum unsecured indebtedness principal amount	$ 80,000,000
RBL PSA [Member] | Subsequent Event [Member] | Maximum [Member] | Exit Credit Facility [Member]
Reorganizations [Line Items]
Borrowing base	$ 492,500,000
RBL PSA [Member] | Subsequent Event [Member] | Maximum [Member] | Exit Credit Facility [Member] | Alternative Base Rate [Member]
Reorganizations [Line Items]
Base rate borrowing percentage	3.00%
RBL PSA [Member] | Subsequent Event [Member] | Maximum [Member] | Exit Credit Facility [Member] | LIBOR/Eurodollar [Member]
Reorganizations [Line Items]
Base rate borrowing percentage	4.00%
RBL PSA [Member] | Subsequent Event [Member] | Minimum [Member] | Exit Credit Facility [Member]
Reorganizations [Line Items]
Borrowing base	$ 474,000,000
RBL PSA [Member] | Subsequent Event [Member] | Minimum [Member] | Exit Credit Facility [Member] | Alternative Base Rate [Member]
Reorganizations [Line Items]
Base rate borrowing percentage	2.00%
RBL PSA [Member] | Subsequent Event [Member] | Minimum [Member] | Exit Credit Facility [Member] | LIBOR/Eurodollar [Member]
Reorganizations [Line Items]
Base rate borrowing percentage	3.00%
2021 Senior Notes [Member]
Reorganizations [Line Items]
Interest Payment							$ 24,600,000	$ 24,600,000
Senior notes				7.625%				7.625%
Interest payment grace period under indenture				30 days
Notes in forbearance as percentage of principal amount							51.70%
2022 Senior Notes [Member]
Reorganizations [Line Items]
Senior notes							6.875%
Notes in forbearance as percentage of principal amount							69.00%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Reorganizations [Line Items]
Revolving credit facility				$ 2,000,000,000							$ 2,000,000,000
Borrowing base		$ 530,700,000	$ 925,000,000	$ 530,653,000	$ 619,000,000	$ 720,000,000			$ 740,000,000	$ 1,175,000,000
Percentage of revolving unused commitment fee			0.50%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Maximum [Member] | Alternative Base Rate [Member]
Reorganizations [Line Items]
Base rate borrowing percentage			2.25%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Minimum [Member] | Alternative Base Rate [Member]
Reorganizations [Line Items]
Base rate borrowing percentage			1.25%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Subsequent Event [Member]
Reorganizations [Line Items]
Borrowing base	$ 457,200,000

Summary of Significant Accoun43

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Line Items]
Allowance for doubtful accounts	$ 1,900,000
Capitalized exploratory drilling costs pending evaluation	0	$ 0	$ 0
Amortization expense including write-off of debt issuance costs	22,100,000	6,100,000	4,200,000
Impairment expense	183,437,000	616,784,000	407,540,000
Capitalized interest	$ 500,000	$ 2,100,000	$ 2,800,000
Chance of tax benefit likely to be realized	greater than 50%
Customer Concentration Risk [Member] | Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of total revenue	10.00%
Minimum [Member] | Other Property & Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	3 years
Maximum [Member] | Other Property & Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	7 years
Support Equipment and Facilities [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	15 years
Support Equipment and Facilities [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	40 years

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Major Customers (Detail) - Customer Concentration Risk [Member] - Revenues [Member]	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Significant Accounting Policies [Line Items]
Total Reported Revenues	10.00%
Phillips 66 [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	19.00%	12.00%	12.00%
Sinclair Oil & Gas Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	16.00%	18.00%	11.00%
Royal Dutch Shell plc and subsidiaries [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	14.00%	14.00%

Summary of Significant Accoun45

Summary of Significant Accounting Policies - Summary of Current Accrued Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accrued Liabilities Current [Abstract]
Accrued interest payable	$ 46,417	$ 23,192
Accrued lease operating expense	10,411	16,843
Accrued capital expenditures	1,826	8,110
Accrued general and administrative expenses	3,040	1,961
Accrued ad valorem tax	977	1,426
Asset retirement obligation	789	1,175	$ 0
Environmental liability	0	216
Other	1,775	0
Accrued liabilities, Total	$ 65,235	$ 52,923

Summary of Significant Accoun46

Summary of Significant Accounting Policies - Summary of Supplemental Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$ 87,527	$ 107,272	$ 63,709
Cash paid for taxes	0	472	151
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	(6,284)	(27,932)	13,759
(Increase) decrease in accounts receivable related to acquisitions	0	9,698	(5,854)
(Increase) decrease in accounts receivable/payable related to divestitures	(289)	0	0
Repurchases under unit repurchase program	0	0	1,372
Assumptions of asset retirement obligations related to acquisitions	0	23,754	4,265
Asset retirement obligation removal related to divestitures	$ (19,669)	$ 0	$ 0

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisition and Divestiture Related Expenses (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
General and Administrative Expense
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	$ 1,451	$ 1,928	$ 4,363

Acquisitions and Divestitures48

Acquisitions and Divestitures - Additional Information (Detail) - USD ($)	Jul. 14, 2016	Jun. 14, 2016	Nov. 03, 2015	Jul. 01, 2014	Mar. 25, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition And Divestiture [Line Items]
Acquisitions of oil and natural gas properties						$ 0	$ 100,730,000	$ 1,083,761,000
Permian Basin
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures							900,000
Permian Basin | Texas And New Mexico
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures							600,000
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Disposal group, not discontinued operation, (gain) loss on properties						4,200,000
Permian Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Disposal group, not discontinued operation, (gain) loss on properties						(6,100,000)
Immaterial Divestitures [Member]
Business Acquisition And Divestiture [Line Items]
Disposal group, not discontinued operation, (gain) loss on properties						(900,000)
Immaterial Divestitures [Member] | Maximum [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures						100,000
Disposal Group Not Discontinued Operation [Member] | Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures	$ 16,400,000
Disposal Group Not Discontinued Operation [Member] | Permian Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures		$ 36,700,000
Disposal Group Not Discontinued Operation [Member] | Permian Divestiture [Member] | Accounts Receivable [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures						300,000
Disposal Group Not Discontinued Operation [Member] | Permian Divestiture [Member] | Cash [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures						$ 36,400,000
2015 Beta Acquisition [Member]
Business Acquisition And Divestiture [Line Items]
Purchase of noncontrolling interest in SPBPC			$ 6,000,000
Acquisitions of oil and natural gas properties			$ 94,600,000
Revenue recorded in statement of operations							3,600,000
Earnings (Losses) recorded in statement of operations							$ (1,000,000)
Wyoming Acquisition [Member]
Business Acquisition And Divestiture [Line Items]
Revenue recorded in statement of operations				$ 72,800,000
Earnings (Losses) recorded in statement of operations				22,900,000
Purchase price				$ 906,100,000
Eagle Ford [Member]
Business Acquisition And Divestiture [Line Items]
Revenue recorded in statement of operations								36,600,000
Earnings (Losses) recorded in statement of operations								$ 16,300,000
Purchase price					$ 168,100,000
Eagle Ford [Member] | Leasehold [Member]
Business Acquisition And Divestiture [Line Items]
Percentage of leasehold interest acquired					30.00%

Acquisitions and Divestitures49

Acquisitions and Divestitures - Summary of Fair Value of Assets Acquired and Liabilities Assumed (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Nov. 03, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Revenues payable	$ (21,285)	$ (25,504)
Wyoming Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties				$ 930,168
Revenues payable				(375)
Asset retirement obligations				(3,980)
Accrued liabilities				(19,693)
Total identifiable net assets				906,120
Eagle Ford Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties				168,606
Asset retirement obligations				(285)
Accrued liabilities				(250)
Total identifiable net assets				$ 168,071
2015 Beta Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties			$ 40,029
Prepaid expenses and other current assets			840
Restricted investments			69,579
Derivative instruments			4,568
Accounts receivable - affiliates and other			4,499
Asset retirement obligations			(22,871)
Accrued liabilities			(2,010)
Total identifiable net assets			$ 94,634

Acquisitions and Divestitures50

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

Acquisitions and Divestitures51

Acquisitions and Divestitures - Schedule of Income (Loss) before Income Taxes Including (Gain) Loss on Divestiture (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition And Divestiture [Line Items]
Income (loss) before income taxes	$ 540,225	$ 397,666	$ (114,193)
Permian Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Income (loss) before income taxes	4,297	(60,875)	(228,956)
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Income (loss) before income taxes	$ (7,677)	$ (56,917)	$ 3,127

Fair Value Measurements of Fi52

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value [Member] - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	$ 189,851	$ 816,995
Interest rate derivatives, Assets		0
Liabilities	17,757	87,156
Interest rate derivatives, Liabilities		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
Liabilities	0	0
Interest rate derivatives, Liabilities		0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	189,851	816,995
Interest rate derivatives, Assets		0
Liabilities	17,757	87,156
Interest rate derivatives, Liabilities		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
Liabilities	0	0
Interest rate derivatives, Liabilities		0
Commodity derivatives [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	189,851	816,995
Liabilities	17,757	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	189,851	816,995
Liabilities	17,757	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 Fi53

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	$ 183,437	$ 616,784	$ 407,540
East Texas [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	183,400		107,600
Carrying value of properties after impairment charges	$ 156,200		88,800
East Texas, Wyoming and Colorado [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties		616,800
Carrying value of properties after impairment charges		$ 408,600
Permian Basin
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties			234,200
Carrying value of properties after impairment charges			88,700
South Texas [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties			65,600
Carrying value of properties after impairment charges			$ 71,200

Risk Management and Derivativ54

Risk Management and Derivative Instruments - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended				3 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Nov. 30, 2015	Feb. 28, 2015	Jun. 30, 2016	Dec. 31, 2016	Nov. 03, 2015
Derivative Instruments Gain Loss [Line Items]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk						$ 107.2
Maximum amount of loss due to credit risk						64.9
Cash settlement receipt			$ 16.4	$ 27.1	$ 39.3
Beta Acquisition [Member]
Derivative Instruments Gain Loss [Line Items]
Cash settlement receipt						4.4
Acquired hedges							$ 4.6
Commodity Hedges [Member]
Derivative Instruments Gain Loss [Line Items]
Cash settlement receipt		$ 191.4
Commodity Hedges [Member] | Subsequent Event [Member]
Derivative Instruments Gain Loss [Line Items]
Cash settlement receipt	$ 94.1
Interest Rate Swaps [Member]
Derivative Instruments Gain Loss [Line Items]
Cash settlements paid on terminated interest rate derivative						2.1
Single Counterparty [Member]
Derivative Instruments Gain Loss [Line Items]
Maximum amount of loss due to credit risk						$ 42.5

Risk Management and Derivativ55

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	12 Months Ended
	Dec. 31, 2016MMBTU$ / MMBTU$ / bblbbl
Natural Gas Derivative Contracts Fixed Price Swap 2017 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,890,000
Weighted-average fixed price | $ / MMBTU	3.86
Crude Oil Derivative Contracts Fixed Price Swap 2017 [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	84.29
Average Monthly Volume (Bbls) | bbl	184,500
NGL Derivative Contracts Fixed Price Swap 2017 [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	37.55
Average Monthly Volume (Bbls) | bbl	43,300
Natural Gas Derivative Contracts Fixed Price Swap 2018 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,740,000
Weighted-average fixed price | $ / MMBTU	3.83
Crude Oil Derivative Contracts Fixed Price Swap 2018 [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	83.44
Average Monthly Volume (Bbls) | bbl	182,000
NGL Derivative Contracts Fixed Price Swap Contracts 2018 [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	0
Average Monthly Volume (Bbls) | bbl	0
Natural Gas Derivative Contracts Fixed Price Swap 2019 [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,000,000
Weighted-average fixed price | $ / MMBTU	3.47
Crude Oil Derivative Contracts Fixed Price Swap 2019 [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	86.84
Average Monthly Volume (Bbls) | bbl	70,000
NGL Derivative Contracts Fixed Price Swap Contracts 2019 [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	0
Average Monthly Volume (Bbls) | bbl	0

Risk Management and Derivativ56

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 69,464	$ 272,320
Asset Derivatives, Net recorded fair value	102,630	461,810
Liability Derivatives, Net recorded fair value	0	2,850
Liability Derivatives, Net recorded fair value	0	1,441
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	86,335	324,265
Asset Derivatives, Netting arrangements	(16,871)	(51,945)
Asset Derivatives, Net recorded fair value	69,464	272,320
Liability Derivatives, Gross fair value	16,871	54,795
Liability Derivatives, Netting arrangements	(16,871)	(51,945)
Liability Derivatives, Net recorded fair value	0	2,850
Short-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	86,335	324,265
Liability Derivatives, Gross fair value	16,871	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	0	1,214
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	103,515	492,730
Asset Derivatives, Netting arrangements	(885)	(30,920)
Asset Derivatives, Net recorded fair value	102,630	461,810
Liability Derivatives, Gross fair value	885	32,361
Liability Derivatives, Netting arrangements	(885)	(30,920)
Liability Derivatives, Net recorded fair value	0	1,441
Long-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	103,515	492,730
Liability Derivatives, Gross fair value	885	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	$ 0	$ 1,441

Risk Management and Derivativ57

Risk Management and Derivative Instruments - Unrealized and Realized Gains and Losses Related to Derivative Instruments (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	$ 117,105,000	$ (462,890,000)	$ (492,254,000)
Interest expense, net	146,031,000	115,154,000	83,550,000
Commodity derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	117,105	(462,890)	(492,254)
Interest rate derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net	$ 1,290	$ 4,674	$ (151)

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 164,164	$ 112,702	$ 101,436
Liabilities added from acquisitions or drilling	30	26,876	5,815
Liabilities removed upon sale of wells	(19,669)	(3,412)	0
Liabilities settled	(1,442)	(1,430)	(651)
Accretion expense	10,231	7,125	5,773
Revision of estimates	2,388	22,303	329
Asset retirement obligations at end of period	155,702	164,164	112,702
Less: Current portion	789	1,175	0
Asset retirement obligations - long-term portion	$ 154,913	$ 162,989	$ 112,702

Restricted Investments - Restri

Restricted Investments - Restricted Investment Balance (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Investments [Line Items]
Restricted investments	$ 156,234	$ 152,631
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	152,000	144,008
BOEM lease bonds [Member]
Schedule Of Investments [Line Items]
Restricted investments	0	1,533
Surety bond cash collateral [Member]
Schedule Of Investments [Line Items]
Restricted investments	500	0
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	3,627	3,178
SPBPC Collateral Lands Commission pipeline right-of-way bond [Member] | California State
Schedule Of Investments [Line Items]
Restricted investments	0	3,005
SPBPC Collateral City of Long Beach pipeline facility permit [Member]
Schedule Of Investments [Line Items]
Restricted investments	0	500
SPBPC Collateral Federal pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	0	307
SPBPC Collateral Port of Long Beach pipeline license [Member]
Schedule Of Investments [Line Items]
Restricted investments	$ 107	$ 100

Debt - Consolidated Debt Obliga

Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized discounts	[1]	$ 0	$ (14,114)
Total debt		1,622,904	2,000,579
Current portion of long-term debt	[2]	(1,622,904)	0
Total long-term debt		0	2,000,579
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Revolving credit facility	[3]	511,652	836,000
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Senior Notes, fixed-rate	[4],[5]	646,287	700,000
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Senior Notes, fixed-rate	[4],[6]	464,965	496,990
Senior Notes [Member]
Debt Instrument [Line Items]
Debt issuance costs, net	[1]	$ 0	$ (18,297)
[1]	Approximately $25.0 million in net discounts and deferred financing fees were written off due to a default and event of default and the uncertainty regarding anticipated financial covenant violation at December 31, 2016.
[2]	Due to an existing and anticipated financial covenant violations, the Partnership’s revolving credit facility and senior notes were classified as current at December 31, 2016.
[3]	The carrying amount of our revolving credit facility approximates fair value because the interest rates are variable and reflective of market rates.
[4]	The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[5]	The estimated fair value of our 2021 Senior Notes was $314.3 million and $210.0 million at December 31, 2016 and 2015, respectively.
[6]	The estimated fair value of our 2022 Senior Notes was $223.2 million and $149.1 million at December 31, 2016 and 2015, respectively.

Debt - Consolidated Debt Obli61

Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Written off discounts and deferred financing fees	$ 25,000,000
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	$ 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	$ 314,300,000	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	$ 223,200,000	$ 149,100,000

Debt - Additional Information (

Debt - Additional Information (Detail)	Dec. 31, 2016
Universal Shelf Registration Statement [Member]
Debt Instrument [Line Items]
Universal shelf guarantor subsidiaries ownership percentage	100.00%

Debt - Borrowing Base Credit Fa

Debt - Borrowing Base Credit Facility (Detail) - USD ($)	Dec. 31, 2016	Dec. 22, 2016	Dec. 21, 2016	Dec. 01, 2016	Oct. 28, 2016	Apr. 14, 2016	Apr. 13, 2016
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Line of Credit Facility [Line Items]
Borrowing base	$ 530,653,000	$ 530,700,000	$ 619,000,000	$ 720,000,000	$ 740,000,000	$ 925,000,000	$ 1,175,000,000

Debt - Borrowing Base Credit 64

Debt - Borrowing Base Credit Facility (Parenthetical) (Detail) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
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	$ 2,000,000,000

Debt - Credit Facility - Additi

Debt - Credit Facility - Additional Information (Detail) - USD ($)	Nov. 01, 2016	Apr. 14, 2016	Dec. 31, 2016	Jan. 13, 2017	Dec. 22, 2016	Dec. 21, 2016	Dec. 01, 2016	Oct. 28, 2016	Apr. 13, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Debt covenant, cash distributions to equity holders, pro forma availability minimum		$ 75,000,000
Debt covenant, cash distributions to equity holders, borrowing base amount percentage prior threshold date		10.00%
Debt covenant, cash distributions to equity holders, borrowing base amount percentage after threshold date		15.00%
Debt covenant, cash distributions to equity holders, total debt to EBITDAX ratio minimum		400.00%
Debt covenant, maximum payment of cash distributions to equity holders amount		$ 4,150,000
Debt covenant, repurchase, pro forma availability minimum		$ 75,000,000
Debt covenant, repurchase, borrowing base amount percentage prior threshold date minimum		10.00%
Debt covenant, repurchase, borrowing base amount percentage after threshold date minimum		15.00%
Debt covenant, outstanding senior unsecured notes repurchase, total debt to EBITDAX ratio maximum		300.00%
Maximum amount of proceeds from swap liquidations, sale or other disposition of oil and gas properties to repurchase outstanding senior unsecured notes or second lien debt		$ 40,000,000
Maximum amount of sale and cash proceeds to repurchase outstanding senior unsecured notes aggregate		$ 60,000,000
Minimum Percentage of Oil and Gas Properties mortgaged as collateral security for the loans under the Credit Agreement		90.00%
Debt covenant, minimum aggregate amount of unrestricted cash or cash equivalents to prepay loans and cash collateralize letter of credit exposure		$ 25,000,000
Letters of credit outstanding			$ 2,400,000
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							$ 2,000,000,000
Borrowing base		$ 925,000,000	$ 530,653,000		$ 530,700,000	$ 619,000,000	$ 720,000,000	$ 740,000,000	$ 1,175,000,000
Aggregate Liquidity								$ 30,000,000
Percentage of revolving unused commitment fee		0.50%
Consolidated First Lien Net Secured Debt to Consolidated EBITDAX ratio Maximum		325.00%
Description of debt default			Due to (i) the uncertainty regarding the Partnership’s ability to cure the default and event of default as discussed in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes, the Partnership classified the outstanding revolving credit facility balance as a current liability on its balance sheet as of December 31, 2016.
Percentage of net cash proceeds from any asset sale, transfer or other disposition			100.00%
Percentage of Oil and Gas Properties subject to mortgage	95.00%
Minimum Percentage of Oil and Gas Properties mortgaged as collateral security for the loans under the Credit Agreement	92.00%	90.00%
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%
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018 | Subsequent Event [Member]
Line of Credit Facility [Line Items]
Borrowing base				$ 457,200,000
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
Period of consolidated net interest expense following the exchange		12 months
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
2021 Senior Notes [Member]
Line of Credit Facility [Line Items]
Description of debt default			The Partnership did not pay the interest due on the 2021 Senior Notes prior to the expiration of the 30-day grace period. Due to (i) the uncertainty regarding the Partnership’s ability to cure the default and event of default as discussed in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes, the Partnership classified the outstanding balance of the senior notes as a current liability on its balance sheet as of December 31, 2016.
Interest payment grace period under indenture			30 days

Debt - Senior Notes - Additiona

Debt - Senior Notes - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 22, 2016	Jul. 17, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jan. 13, 2017	Nov. 30, 2016	Nov. 01, 2016	Oct. 10, 2013	May 23, 2013	Apr. 17, 2013
Debt Instrument [Line Items]
Repurchase of senior notes			$ 41,261	$ 2,914	$ 0
Gain on extinguishment of debt			$ 42,337	422	$ 0
Subsequent Event [Member]
Debt Instrument [Line Items]
Lenders holding percentage on loans						100.00%
Noteholder Plan Support Agreement [Member]
Debt Instrument [Line Items]
Warrant life period	5 years
Percentage of common shares to be issued upon exercise of warrants	8.00%
Percentage of new common shares issued	98.00%
Percentage of new common shares issued to exiting equity interests	2.00%
Noteholder Plan Support Agreement [Member] | Maximum [Member]
Debt Instrument [Line Items]
Additional cash payment entitled to be received by noteholders	$ 24,600
Noteholder Plan Support Agreement [Member] | Notes Due 2021 and Notes Due 2022 [Member]
Debt Instrument [Line Items]
Minimum note holder percentage to financial restructuring for prepackaged plan of reorganization	50.20%
2022 Senior Notes [Member]
Debt Instrument [Line Items]
Maturity date			Aug. 1, 2022
Other events of default minimum note holder percentage to accelerate		25.00%
Repurchase of debt			$ 32,000	3,000
Repurchase of senior notes			14,900	2,900
Gain on extinguishment of debt			$ 14,800	$ 400
2022 Senior Notes [Member] | 2022 Holders [Member]
Debt Instrument [Line Items]
Notes in forbearance as percentage of principal amount							69.00%
2021 Senior Notes [Member]
Debt Instrument [Line Items]
Maturity date			May 1, 2021
Senior notes			7.625%					7.625%
Other events of default minimum note holder percentage to accelerate			25.00%
Repurchase of debt			$ 53,700
Repurchase of senior notes			26,400
Gain on extinguishment of debt			$ 27,500
Interest Payment							$ 24,600	$ 24,600
Interest payment grace period under indenture			30 days
Notes in forbearance as percentage of principal amount							51.70%
Description of debt default			The Partnership did not pay the interest due on the 2021 Senior Notes prior to the expiration of the 30-day grace period. Due to (i) the uncertainty regarding the Partnership’s ability to cure the default and event of default as discussed in Note 2, (ii) our inability to comply with certain financial covenants contained in our revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes, the Partnership classified the outstanding balance of the senior notes as a current liability on its balance sheet as of December 31, 2016.
2021 Senior Notes [Member] | 2021 Holders [Member]
Debt Instrument [Line Items]
Notes in forbearance as percentage of principal amount							51.70%
Private Placement of Debt [Member] | 2022 Senior Notes [Member]
Debt Instrument [Line Items]
Face amount of senior notes at time of issuance		$ 500,000
Senior notes		6.875%
Senior notes issued at par		98.485%
Private Placement of Debt [Member] | 2021 Senior Notes [Member]
Debt Instrument [Line Items]
Face amount of senior notes at time of issuance									$ 300,000	$ 100,000	$ 300,000

Debt - Summary of Weighted-Aver

Debt - Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations (Detail)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OLLC revolving credit facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates	3.28%	2.12%	2.67%

Debt - Summary of Weighted-Av68

Debt - Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OLLC revolving credit facility [Member] | Alternative Base Rate [Member]
Debt Instrument [Line Items]
Base rate borrowing percentage	2.76%	1.90%	1.80%

Debt - Deferred Financing Costs

Debt - Deferred Financing Costs - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Deferred financing fees	$ 1.3
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Deferred financing fees	8.5
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Deferred financing fees	$ 5.7

Debt - Summary of Unamortized D

Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Dec. 31, 2016	[1]	Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized deferred financing costs		$ 0		$ 21,969
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Unamortized deferred financing costs	[2]	0		3,672
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[3]	0		11,194
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	[3]	$ 0		$ 7,103
[1]	At December 31, 2016, there were no remaining unamortized deferred financing costs as such costs were written off due to a default and event of default and the uncertainty regarding anticipated financial covenant violation at December 31, 2016. See discussion noted above.
[2]	Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.
[3]	Unamortized deferred financing costs are amortized using the straight line method which generally approximates the effective interest method.

Debt - Summary of Unamortized71

Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)		Dec. 31, 2016		Dec. 31, 2015
Debt Instrument [Line Items]
Unamortized deferred financing costs		$ 0	[1]	$ 21,969,000
OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018
Debt Instrument [Line Items]
Revolving credit facility		2,000,000,000		2,000,000,000
Unamortized deferred financing costs	[2]	$ 0	[1]	$ 3,672,000
[1]	At December 31, 2016, there were no remaining unamortized deferred financing costs as such costs were written off due to a default and event of default and the uncertainty regarding anticipated financial covenant violation at December 31, 2016. See discussion noted above.
[2]	Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility.

Equity and Distributions - Addi

Equity and Distributions - Additional Information (Detail)	Apr. 27, 2016USD ($)	Feb. 13, 2015shares	Sep. 09, 2014USD ($)$ / sharesshares	Jul. 15, 2014USD ($)$ / sharesshares	Dec. 31, 2016USD ($)$ / Partnershipshares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)shares	Jun. 01, 2016	May 31, 2016	May 25, 2016USD ($)
Limited Partners Capital Account [Line Items]
Net proceeds from the issuance of common units					$ 1,849,000		$ 540,698,000
Proceeds from sale of common units, net					2,385,000	$ 0	553,288,000
Fees on sale of common unit					$ 536,000	0	12,510,000
Common units amount repurchased under repurchase program						52,813,000	12,903,000
Minimum Quarterly Distribution amount per common unit | $ / Partnership					0.4750
MEMP Repurchase Program [Member]
Limited Partners Capital Account [Line Items]
Stock repurchase program, authorized amount							150,000,000
Common units amount repurchased under repurchase program						$ 52,800,000	$ 12,900,000
Common units repurchased under repurchase program | shares						3,547,921	899,912
MEMP GP [Member]
Limited Partners Capital Account [Line Items]
Acquisition purchase price	$ 800,000
Partnership ownership percentage	0.10%
Gain (loss) on acquisition	$ 0
Incentive Distribution Rights (“IDRs”) [Member] | MEMP GP [Member]
Limited Partners Capital Account [Line Items]
Partnership ownership percentage	50.00%
Incentive Distribution Rights (“IDRs”) [Member] | The Funds [Member]
Limited Partners Capital Account [Line Items]
Percentage of economic interest in incentive distribution rights									50.00%
Memorial Resource [Member] | Incentive Distribution Rights (“IDRs”) [Member]
Limited Partners Capital Account [Line Items]
Percentage of economic interest in incentive distribution rights									50.00%
Natural Gas Partners [Member] | Incentive Distribution Rights (“IDRs”) [Member]
Limited Partners Capital Account [Line Items]
Agreed ownership interest percentage to acquire	50.00%							50.00%
General Partner [Member] | MEMP GP [Member]
Limited Partners Capital Account [Line Items]
Partnership ownership percentage	0.10%
General Partner [Member] | Memorial Resource [Member]
Limited Partners Capital Account [Line Items]
Partnership ownership percentage									100.00%
Subordinated Units [Member]
Limited Partners Capital Account [Line Items]
Subordinated units converted to common units | shares						(5,360,912)
Common unit, issued | shares					0		0
Common units repurchased under repurchase program | shares						0	0
Subordinated Units [Member] | MRD Holdco [Member]
Limited Partners Capital Account [Line Items]
Subordinated units converted to common units | shares		5,360,912
Conversion of stock description						The subordinated units converted on a one-for-one basis into common units upon the payment of MEMP's fourth quarter 2014 distribution. MRD Holdco sold all of the common units during the three months ended June 30, 2015 and no longer owns any of our outstanding common units.
Limited Partners Common Units [Member]
Limited Partners Capital Account [Line Items]
Net proceeds from the issuance of common units					$ 1,849,000		$ 540,698,000
Subordinated units converted to common units | shares						5,360,912
Common unit, issued | shares					1,178,102		24,840,000
Common units amount repurchased under repurchase program						$ 52,813,000	$ 12,903,000
Common units repurchased under repurchase program | shares						3,547,921	899,912
2014 Public Equity Offerings [Member]
Limited Partners Capital Account [Line Items]
Number of common units issued in public offering | shares			14,950,000	9,890,000
Number of over-allotment common units issued by Partnership | shares			1,950,000	1,290,000
Public offering price per common unit | $ / shares			$ 22.29	$ 22.25
Net proceeds from the issuance of common units			$ 321,300,000	$ 220,000,000
ATM Program
Limited Partners Capital Account [Line Items]
Authorized Value										$ 60,000,000
Proceeds from sale of common units, net					$ 1,800,000
Fees on sale of common unit					$ 500,000

Equity and Distributions - Summ

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Detail) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	86,797
Ending balance	0	86,797
Limited Partners Common Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	82,906,400	80,421,992	55,877,831
Common units issued	1,178,102		24,840,000
Restricted common units issued	50,000	827,704	684,954
Restricted common units forfeited	(27,537)	(69,059)	(38,294)
Restricted common units repurchased	(279,045)	(87,228)	(42,587)
Common units repurchased under repurchase program		(3,547,921)	(899,912)
General partner units issued			0
Subordinated units converted to common units		5,360,912
Cancellation of general partner units	0
Ending balance	83,827,920	82,906,400	80,421,992
Subordinated Units [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	0	5,360,912	5,360,912
Common units issued	0		0
Restricted common units issued	0	0	0
Restricted common units forfeited	0	0	0
Restricted common units repurchased	0	0	0
Common units repurchased under repurchase program		0	0
General partner units issued			0
Subordinated units converted to common units		(5,360,912)
Cancellation of general partner units	0
Ending balance	0	0	5,360,912
General Partner [Member]
Summary Of Changes In Number Of Outstanding Units [Abstract]
Beginning balance	86,797	86,797	61,300
Common units issued	0		0
Restricted common units issued	0	0	0
Restricted common units forfeited	0	0	0
Restricted common units repurchased	0	0	0
Common units repurchased under repurchase program		0	0
General partner units issued			25,497
Subordinated units converted to common units		0
Cancellation of general partner units	(86,797)
Ending balance	0	86,797	86,797

Equity and Distributions - Su74

Equity and Distributions - Summary of Changes in Number of Outstanding Units (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary Of Changes In Number Of Outstanding Units [Abstract]
Withholding tax withheld and paid related to vesting of restricted common units	$ 0.6	$ 1.3	$ 1

Equity and Distributions - Su75

Equity and Distributions - Summary of Quarterly Cash Distribution Rates (Detail) - USD ($)	3 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014
Limited Partners Capital Account [Line Items]
Distribution made to member or limited partner, date of declaration	Jul. 26, 2016	Apr. 26, 2016	Jan. 26, 2016	Oct. 26, 2015	Jul. 24, 2015	Apr. 24, 2015	Jan. 26, 2015	Oct. 23, 2014	Jul. 24, 2014	Apr. 24, 2014
Distribution made to member or limited partner, date of record	Aug. 5, 2016	May 6, 2016	Feb. 5, 2016	Nov. 5, 2015	Aug. 5, 2015	May 6, 2015	Feb. 5, 2015	Nov. 5, 2014	Aug. 5, 2014	May 6, 2014
Distribution made to member or limited partner, date of distribution	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Nov. 12, 2015	Aug. 12, 2015	May 13, 2015	Feb. 12, 2015	Nov. 12, 2014	Aug. 12, 2014	May 13, 2014
Distribution per unit	$ 0.0300	$ 0.0300	$ 0.1000	$ 0.3000	$ 0.5500	$ 0.5500	$ 0.5500	$ 0.5500	$ 0.5500	$ 0.5500
Aggregate Distribution	$ 2,500,000	$ 2,500,000	$ 8,300,000	$ 24,900,000	$ 45,700,000	$ 46,300,000	$ 46,300,000	$ 47,800,000	$ 39,500,000	$ 33,800,000
Distribution Received by Affiliates					$ 100,000	$ 200,000	$ 3,100,000	$ 3,100,000	$ 3,000,000	$ 3,000,000
Maximum [Member]
Limited Partners Capital Account [Line Items]
Distribution Received by Affiliates	$ 100,000	$ 100,000	$ 100,000	$ 100,000

Equity and Distributions - Su76

Equity and Distributions - Summary of Previous Owners' Equity Transactions Related to Property Swap (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity Structure And Transactions [Line Items]
Net income (loss)	$ (321,885)	$ (32,866)	$ (147,550)	$ (38,097)	$ 73,007	$ (191,981)	$ (113,859)	$ (162,658)	$ (540,398)	$ (395,491)	$ 115,614
Contributions										4,877	6,560
Distributions									(13,300)	(163,259)	(164,738)
Distribution of net asset to MRD Holdco											(26,131)
Other											227
Deferred tax liability retained by previous owner										28,020
Previous Owners [Member]
Equity Structure And Transactions [Line Items]
Balance				$ 0				$ 220,657	$ 0	220,657	283,405
Net income (loss)										(2,268)	(2,465)
Contributions										1,912	5,990
Distributions											(9,886)
Distribution of net asset to MRD Holdco											(26,131)
Tax related effects attributable to Memorial Resource restructuring transactions and initial public offering											(30,483)
Other											227
Net book value of net assets exchanged										(248,321)
Deferred tax liability retained by previous owner										28,020
Balance					$ 0					$ 0	$ 220,657

Earnings Per Unit - Calculation

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Unit [Line Items]
Net income (loss) attributable to Memorial Production Partners LP	$ (321,885)	$ (32,866)	$ (147,550)	$ (38,097)	$ 72,949	$ (192,085)	$ (113,924)	$ (162,817)	$ (540,398)	$ (395,877)	$ 115,582
Less: Previous owners interest in net income (loss)								$ (2,268)	0	(2,268)	(2,465)
Less: General partner's 0.1% interest in net income (loss)									(168)	(412)	118
Less: IDRs attributable to corresponding period									0	112	202
Net income (loss) available to limited partners									$ (540,230)	$ (393,309)	$ 117,727
Weighted average limited partner units outstanding:
Basic and diluted									83,351	83,528	70,859
Basic and diluted EPU	$ (3.85)	$ (0.39)	$ (1.78)	$ (0.46)	$ 0.88	$ (2.31)	$ (1.36)	$ (1.90)	$ (6.48)	$ (4.71)	$ 1.66
Common Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding									83,351	82,897	65,498
Subordinated Units [Member]
Weighted average limited partner units outstanding:
Weighted average limited partner units outstanding									0	631	5,361

Earnings Per Unit - Calculati78

Earnings Per Unit - Calculation of Earnings (Loss) Per Unit (Parenthetical) (Detail) - shares shares in Thousands	5 Months Ended	12 Months Ended
	May 31, 2016	Dec. 31, 2016	Dec. 31, 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		3,325,318
Average [Member]
Earnings Per Unit [Line Items]
General partner's interest in net income, percentage	0.105%		0.105%

Equity-based Awards - Additiona

Equity-based Awards - Additional Information (Detail) - USD ($) $ in Millions	Jun. 01, 2016	Mar. 09, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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				$ 3.8
Weighted-average period of unrecognized compensation cost				1 year 1 month 6 days
Cash distributions paid				$ 0.2	$ 2.8	$ 1.9
Certain Employee [Member] | Phantom Units [Member] | First Anniversary Of Grant Date [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage from the date of grant			33.33%
Certain Employee [Member] | Phantom Units [Member] | Second Anniversary Of Grant Date [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage from the date of grant			33.33%
Certain Employee [Member] | Phantom Units [Member] | Third Anniversary Of Grant Date [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage from the date of grant			33.33%
Long-Term Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of common units for awards authorized				2,142,221
Long-Term Incentive Plan [Member] | Executive officers and employees [Member] | Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value of the restricted common units				$ 0.1	$ 12.3	$ 15

Equity-based Awards - Summary o

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Detail) - Restricted Common Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	1,368,538	1,093,520	706,927
Granted, Number of Units	50,000	827,704	684,954
Forfeited, Number of Units	(27,537)	(69,059)	(38,294)
Vested, Number of Units	(958,841)	(483,627)	(260,067)
Outstanding, Number of Units, Ending Balance	432,160	1,368,538	1,093,520
Outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance	$ 17.61	$ 20.93	$ 18.62
Granted, Weighted-Average Grant Date Fair Value per Unit	2.41	14.90	22.39
Forfeited, Weighted-Average Grant Date Fair Value per Unit	16.99	18.35	20.54
Vested, Weighted-Average Grant Date Fair Value per Unit	18.01	20.37	18.56
Outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance	$ 15	$ 17.61	$ 20.93

Equity-based Awards - Summary81

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Common Units [Member] - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted common unit awards issued	$ 0.1	$ 12.3	$ 15.3
Grant date market price	$ 2.41
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price		$ 6.20	$ 21.99
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price		$ 15.45	$ 23.40

Equity-based Awards - Summary82

Equity-based Awards - Summary of Information Regarding Phantom Unit Awards (Detail) - Phantom Units [Member]	12 Months Ended
	Dec. 31, 2016shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	0
Granted, Number of Units	6,169,018
Forfeited, Number of Units	(188,325)
Outstanding, Number of Units, Ending Balance	5,980,693

Equity-based Awards - Summary83

Equity-based Awards - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	$ 7,528	$ 10,809	$ 7,874
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	7,206	10,809	7,874
Phantom Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense	$ 322	$ 0	$ 0

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail)

Jun. 01, 2016USD ($)

Nov. 02, 2015USD ($)

Jul. 01, 2015$ / bbl

Nov. 30, 2015USD ($)

May 31, 2014$ / MMBTU$ / bbl

Nov. 30, 2011MMBTU

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Apr. 27, 2016

Feb. 23, 2015USD ($)

Oct. 01, 2014USD ($)

Apr. 01, 2014USD ($)

Related Party Transaction [Line Items]

Interest sold in oil and gas properties

$ 52,711,000

$ 580,000

$ 0

Transition Service Agreements [Member]

Related Party Transaction [Line Items]

Management fee per month

$ 800,000

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

Related Party Transaction [Line Items]

Maximum dedication of natural gas produced | MMBTU

50,000

Pipeline transportation agreement expiration year

2,020

Pipeline transportation agreement extension

1 year

Amended gas gathering agreement terms disclosure

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

Base gas gathering fee per MMBtu | $ / MMBTU

0.30

Base stage of compression fee per MMBtu | $ / MMBTU

0.07

Annual inflationary escalation, rate

3.50%

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

Related Party Transaction [Line Items]

Pipeline water disposal agreement extension

1 year

Water disposal agreement period

3 years

Water disposal fee per barrel | $ / bbl

0.40

1.10

Gain recognized as contribution

$ 2,100,000

Salt water disposal fee

3,200,000

$ 1,800,000

Multi-Shot, LLC [Member] | Maximum [Member]

Related Party Transaction [Line Items]

Drilling and completion expenses

$ 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 our next annual meeting. 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%

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

Related Party Transaction [Line Items]

Common Control Acquisition Purchase Price

$ 78,400,000

Double A Acquisition [Member]

Related Party Transaction [Line Items]

Common Control Acquisition Purchase Price

$ 33,300,000

Effective date of acquisition common control

Apr. 1, 2014

Wattenberg Acquisition [Member]

Related Party Transaction [Line Items]

Date of acquisition common control

Oct. 1, 2014

Common Control Acquisition Purchase Price

$ 15,000,000

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

Related Party Transaction [Line Items]

Net value of oil and gas properties

$ 200,000

Proceeds in excess of net book value of properties sold

700,000

Interest sold in oil and gas properties

$ 900,000

Memorial Resource [Member]

Related Party Transaction [Line Items]

Amount receivable under management agreement

$ 400,000

Related Party Transactions - Sc

Related Party Transactions - Schedule of Net Assets Recorded by Partnership (Detail) - USD ($) $ in Thousands	Feb. 23, 2015	Oct. 01, 2014	Apr. 01, 2014
Property Swap [Member]
Related Party Transaction [Line Items]
Accounts receivable	$ 2,372
Other receivables	5,478
Prepaid expenses and other current assets	1,874
Property and equipment, net	263,210
Accounts payable	(3,586)
Accounts payable - affiliate	(1,290)
Revenues payable	(1,110)
Accrued liabilities	(11,347)
Asset retirement obligations	(4,559)
Net assets	$ 251,042
Double A Acquisition [Member]
Related Party Transaction [Line Items]
Property and equipment, net			$ 37,838
Asset retirement obligations			(908)
Other current liabilities			(722)
Net assets			$ 36,208
Wattenberg Acquisition [Member]
Related Party Transaction [Line Items]
Property and equipment, net		$ 9,822
Asset retirement obligations		(149)
Other current liabilities		0
Net assets		$ 9,673

Related Party Transactions - 86

Related Party Transactions - Schedule of Amount of General and Administrative Costs and Expenses Recognized (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Omnibus Agreement [Member]
Related Party Transaction [Line Items]
General and administrative costs and expenses under omnibus agreement	$ 11,867	$ 32,281	$ 24,372

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016USD ($)$ / bbl	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 10, 2010USD ($)	Mar. 01, 2007USD ($)
Other Commitments [Line Items]
General and administrative costs and expenses	$ 63,280,000	$ 56,671,000	$ 49,124,000
Commitments and Contingencies Additional Textual [Abstract]
Remaining environmental accrued liability recorded	$ 0	216,000
Obligatory monthly deposit into sinking fund account per barrel of oil | $ / bbl	0.25
Sinking fund account maximum value upon which obligation ceases	$ 4,300,000
Rent expense	10,900,000	$ 16,900,000	6,400,000
Predecessor [Member]
Commitments and Contingencies Additional Textual [Abstract]
Rent expense			$ 500,000
U S Bank Money Market [Member]
Commitments and Contingencies Additional Textual [Abstract]
Held-to-maturity investment, amortized cost	152,000,000
Minimum [Member]
Commitments and Contingencies Additional Textual [Abstract]
Quarterly payments				$ 1,250,000
Minimum [Member] | December 31, 2016 [Member]
Commitments and Contingencies Additional Textual [Abstract]
Minimum balances attributable to REO's net working interest	152,000,000
REO revolving credit facility [Member]
Commitments and Contingencies Additional Textual [Abstract]
Restricted Investment - decommissioning of offshore production facilities					$ 90,000,000
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Commitments and Contingencies Additional Textual [Abstract]
Restricted Investment - decommissioning of offshore production facilities	3,600,000
Transition Services Agreement [Member]
Other Commitments [Line Items]
General and administrative costs and expenses	$ 1,600,000

Commitments and Contingencies88

Commitments and Contingencies - Environmental Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Balance at beginning of period	$ 216	$ 2,092	$ 437
Charged to costs and expenses	0	0	2,852
Payments	(216)	(1,876)	(1,197)
Balance at end of period	$ 0	$ 216	$ 2,092

Commitments and Contingencies89

Commitments and Contingencies - Lease Obligations (Detail) $ in Thousands	Dec. 31, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
Total	$ 24,922
2,017	7,938
2,018	5,058
2,019	3,309
2,020	3,083
2,021	2,748
Thereafter	$ 2,786

Commitments and Contingencies90

Commitments and Contingencies - Purchase Commitments Under the Contracts (Detail) $ in Thousands	Dec. 31, 2016USD ($)
CO2 Minimum Purchase Commitment [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Total	$ 19,665
2,017	6,740
2,018	4,567
2,019	4,548
2,020	3,810
2,021	0
Thereafter	0
Midstream services [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Total	30,668
2,017	5,121
2,018	5,106
2,019	5,107
2,020	5,106
2,021	5,121
Thereafter	$ 5,107

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current taxes:
Federal	$ 6	$ (11)	$ 0
State	8	(48)	(127)
Total current income tax benefit (expense)	14	(59)	(127)
Deferred taxes:
Federal	8	1,193	2,057
State	(195)	1,041	(509)
Total deferred income tax benefit (expense)	(187)	2,234	1,548
Total income tax benefit (expense)	$ (173)	$ 2,175	$ 1,421

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details)	12 Months Ended
	Dec. 31, 2016USD ($)
Income Tax Disclosure [Line Items]
Federal statutory corporate tax rate	35.00%
Unrecognized Tax Benefits	$ 0
United States [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforwards expiration year	2,031
United States [Member] | Maximum [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	$ 100,000

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Income Tax Benefit (Provision) (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Expected tax benefit (expense) at federal statutory rate		$ 191,870	$ 139,183	$ (39,966)
State income tax benefit (expense), net of federal benefit		382	645	(1,907)
Pass-through entities	[1]	(191,921)	(137,704)	42,000
Other		(504)	51	1,294
Total income tax benefit (expense)		$ (173)	$ 2,175	$ 1,421
[1]	MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes.

Income Taxes - Components of Ne

Income Taxes - Components of Net Deferred Income Tax Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred income tax assets:
Net operating loss carryforward	$ 9	$ 56
Asset retirement obligation	875	694
Other	33	38
Total deferred income tax assets:	917	788
Valuation allowance	(865)	0
Net deferred income tax assets	52	788
Deferred income tax liabilities:
Property, plant and equipment	1,522	1,324
Derivatives	770	1,514
Other	40	44
Total deferred income tax liabilities	2,332	2,882
Net deferred income tax liabilities	$ 2,280	$ 2,094

Quarterly Financial Informati95

Quarterly Financial Information (Unaudited) - Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 81,426	$ 74,222	$ 68,066	$ 60,866	$ 79,108	$ 88,083	$ 98,138	$ 92,818	$ 284,580	$ 358,147	$ 566,043
Operating income (loss)	(267,783)	(6,336)	(156,971)	(5,449)	99,434	(160,844)	(85,197)	(136,370)	(436,539)	(282,977)	198,400
Net income (loss)	(321,885)	(32,866)	(147,550)	(38,097)	73,007	(191,981)	(113,859)	(162,658)	(540,398)	(395,491)	115,614
Net income (loss) attributable to Memorial Production Partners LP	(321,885)	(32,866)	(147,550)	(38,097)	72,949	(192,085)	(113,924)	(162,817)	(540,398)	(395,877)	115,582
Net income (loss) allocated to previous owners								(2,268)	0	(2,268)	(2,465)
Net income (loss) attributable to noncontrolling interest					58	104	65	159	0	386	32
Limited partners’ interest in net income (loss)	$ (321,885)	$ (32,866)	$ (147,422)	$ (38,057)	$ 72,874	$ (191,938)	$ (113,862)	$ (160,439)	$ (540,230)	$ (393,365)	$ 117,753
Basic and diluted earnings per unit	$ (3.85)	$ (0.39)	$ (1.78)	$ (0.46)	$ 0.88	$ (2.31)	$ (1.36)	$ (1.90)	$ (6.48)	$ (4.71)	$ 1.66

Supplemental Oil and Gas Info96

Supplemental Oil and Gas Information (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Evaluated oil and natural gas properties	$ 3,115,012	$ 3,616,325	$ 3,329,338
Support equipment and facilities	199,093	205,876	198,088
Accumulated depletion, depreciation, and amortization	(1,743,274)	(1,878,549)	(1,060,114)
Total	$ 1,570,831	$ 1,943,652	$ 2,467,312

Supplemental Oil and Gas Info97

Supplemental Oil and Gas Information (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Property acquisition costs, proved	$ 0	$ 77,834	$ 983,076
Property acquisition costs, unproved	0	1,887	720
Exploration	792	2,078	0
Development	54,310	233,241	308,724
Total	$ 55,102	$ 315,040	$ 1,292,520

Supplemental Oil and Gas Info98

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Detail) - Bcfe	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil And Gas Reserve Information [Line Items]
Percent of discount factor to proved reserves	10.00%
Reduction in reserves	351	415.4
Downward price revisions in proved reserve	148.3	413
Downward revisions due to updated well performance data	87.9	13
Divestiture of oil and gas properties	35.3
Multiple acquisitions		97.1	561.7
2015 Beta Acquisition [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Multiple acquisitions, Largest acquisition		58.5
Wyoming Acquisition [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Multiple acquisitions, Largest acquisition			497.2
Eagle Ford Acquisition [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Multiple acquisitions			45

Supplemental Oil and Gas Info99

Supplemental Oil and Gas Information (Unaudited) - Schedule of Product Prices Used for Valuing the Reserves (Detail)	12 Months Ended
	Dec. 31, 2016$ / MMBTU$ / bbl	Dec. 31, 2015$ / MMBTU$ / bbl	Dec. 31, 2014$ / MMBTU$ / bbl
Oil [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	42.75	46.79	91.48
NGL [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	42.75	46.79	91.48
Natural Gas [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves | $ / MMBTU	2.48	2.58	4.35

Supplemental Oil and Gas Inf100

Supplemental Oil and Gas Information (Unaudited) - Schedule of Net Reserves (Detail)	12 Months Ended
	Dec. 31, 2016MMcfebblMMcf	Dec. 31, 2015MMcfebblMMcf	Dec. 31, 2014MMcfebblMMcf
Oil [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	90,945	100,258	39,635
Extensions and discoveries	297	2,319	849
Production	(3,883)	(4,087)	(3,135)
Sale of minerals in place	(3,228)	(380)
Revision of previous estimates	(18,390)	(17,297)	(6,186)
Proved developed and undeveloped reserves, End of year	65,741	90,945	100,258
Proved developed reserves, Beginning of year	50,817	54,723	22,429
Proved developed reserves, End of year	45,536	50,817	54,723
Proved undeveloped reserves, Beginning of year	40,128	45,535	17,206
Proved undeveloped reserves, End of year	20,205	40,128	45,535
Purchase of minerals in place		10,132	69,095
Natural Gas [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MMcf	461,526	727,216	737,908
Extensions and discoveries | MMcf	288	8,686	12,783
Production | MMcf	(44,776)	(50,875)	(48,721)
Sale of minerals in place | MMcf	(15,227)	(13,731)
Revision of previous estimates | MMcf	(30,795)	(243,898)	12,210
Proved developed and undeveloped reserves, End of year | MMcf	371,016	461,526	727,216
Proved developed reserves, Beginning of year | MMcf	311,147	417,247	427,983
Proved developed reserves, End of year | MMcf	280,035	311,147	417,247
Proved undeveloped reserves, Beginning of year | MMcf	150,379	309,969	309,925
Proved undeveloped reserves, End of year | MMcf	90,981	150,379	309,969
Purchase of minerals in place | MMcf		34,128	13,036
NGL [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	43,395	59,034	35,794
Extensions and discoveries	42	558	711
Production	(2,283)	(2,820)	(2,498)
Sale of minerals in place	(123)	(758)
Revision of previous estimates	(15,847)	(12,986)	2,676
Proved developed and undeveloped reserves, End of year	25,184	43,395	59,034
Proved developed reserves, Beginning of year	30,315	37,260	17,637
Proved developed reserves, End of year	18,923	30,315	37,260
Proved undeveloped reserves, Beginning of year	13,080	21,774	18,157
Proved undeveloped reserves, End of year	6,261	13,080	21,774
Purchase of minerals in place		367	22,351
Equivalent [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MMcfe	1,267,571	1,682,960	1,190,484
Extensions and discoveries | MMcfe	2,320	25,950	22,145
Production | MMcfe	(81,773)	(92,315)	(82,520)
Sale of minerals in place | MMcfe	(35,328)	(20,559)
Revision of previous estimates | MMcfe	(236,225)	(425,587)	(8,862)
Proved developed and undeveloped reserves, End of year | MMcfe	916,565	1,267,571	1,682,960
Proved developed reserves, Beginning of year | MMcfe	797,936	969,141	668,381
Proved developed reserves, End of year | MMcfe	666,786	797,936	969,141
Proved undeveloped reserves, Beginning of year | MMcfe	469,635	713,819	522,103
Proved undeveloped reserves, End of year | MMcfe	249,779	469,635	713,819
Purchase of minerals in place | MMcfe		97,122	561,713

Supplemental Oil and Gas Inf101

Supplemental Oil and Gas Information (Unaudited) -Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Future cash inflows	$ 3,666,731	$ 5,952,935	$ 14,190,450
Future production costs	(2,384,195)	(3,194,577)	(4,821,051)
Future development costs	(440,496)	(808,512)	(1,455,926)
Future income tax expense	0	0	(119,675)
Future net cash flows for estimated timing of cash flows	842,040	1,949,846	7,793,798
10% annual discount for estimated timing of cash flows	(446,199)	(1,360,292)	(4,881,811)
Standardized measure of discounted future net cash flows	$ 395,841	$ 589,554	$ 2,911,987	$ 1,718,204

Supplemental Oil and Gas Inf102

Supplemental Oil and Gas Information (Unaudited) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Beginning of year	$ 589,554	$ 2,911,987	$ 1,718,204
Sale of oil and natural gas produced, net of production costs	(107,357)	(128,382)	(354,932)
Purchase of minerals in place	0	75,998	1,489,477
Sale of minerals in place	(28,277)	(45,100)
Extensions and discoveries	2,016	18,582	44,843
Changes in income taxes, net	0	63,180	(63,180)
Changes in prices and costs	(404,870)	(2,764,481)	(170,682)
Previously estimated development costs incurred	89,748	322,446	275,078
Net changes in future development costs	254,043	448,089	(133,098)
Revisions of previous quantities	14,414	(344,775)	(48,087)
Accretion of discount	58,956	297,517	171,820
Change in production rates and other	(72,386)	(265,507)	(17,456)
End of year	$ 395,841	$ 589,554	$ 2,911,987

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - Subsequent Event [Member]	Jan. 13, 2017
Subsequent Event [Line Items]
Lenders holding percentage on loans	100.00%
Plan Support Agreement [Member]
Subsequent Event [Line Items]
Lenders holding percentage on loans	100.00%