Amplify Energy (AMPYW) 10-K 12 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 02, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Trading Symbol	AMPY
Entity Registrant Name	AMPLIFY ENERGY CORP
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		25,000,000
Entity Public Float			$ 250

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents		$ 6,392
Accounts receivable		36,391
Short-term derivative instruments		28,546
Prepaid expenses and other current assets		7,220
Total current assets		78,549
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		603,053
Support equipment and facilities		100,225
Other		6,133
Accumulated depreciation, depletion and impairment		(35,979)
Property and equipment, net		673,432
Long-term derivative instruments		0
Restricted investments		156,938
Other long-term assets		8,545
Total assets		917,464
Current liabilities:
Accounts payable		1,941
Revenues payable		22,427
Accrued liabilities (see Note 4)		18,233
Current portion of long-term debt (see Note 10)	[1]	0
Total current liabilities		42,601
Long-term debt (see Note 10)		376,000
Asset retirement obligations		99,460
Long-term derivative instruments		5,470
Deferred tax liabilities		0
Other long-term liabilities		0
Total liabilities		523,531
Commitments and contingencies (see Note 15)
Stockholders'/ partners' equity:
Successor preferred stock, $0.0001 par value: 45,000,000 shares authorized; no shares issued and outstanding at December 31, 2017 and 2016, respectively		0
Successor warrants, 2,173,913 warrants issued and outstanding at December 31, 2017 and no warrants issued or outstanding at December 31, 2016		4,788
Successor common stock, $0.0001 par value: 300,000,000 shares authorized; 25,000,000 shares issued and outstanding at December 31, 2017 and no shares authorized or issued at December 31, 2016		3
Successor additional paid-in capital		387,856
Successor accumulated earnings (deficit)		1,286
Total stockholders' equity		393,933
Total liabilities and equity		$ 917,464
Predecessor [Member]
Current assets:
Cash and cash equivalents			$ 15,373
Accounts receivable			34,584
Short-term derivative instruments			69,464
Prepaid expenses and other current assets			13,163
Total current assets			132,584
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method			3,115,012
Support equipment and facilities			199,093
Other			15,344
Accumulated depreciation, depletion and impairment			(1,749,747)
Property and equipment, net			1,579,702
Long-term derivative instruments			102,630
Restricted investments			156,234
Other long-term assets			2,104
Total assets			1,973,254
Current liabilities:
Accounts payable			4,353
Revenues payable			21,285
Accrued liabilities (see Note 4)			65,235
Current portion of long-term debt (see Note 10)	[1]		1,622,904
Total current liabilities			1,713,777
Long-term debt (see Note 10)			0
Asset retirement obligations			154,913
Long-term derivative instruments			0
Deferred tax liabilities			2,280
Other long-term liabilities			2,795
Total liabilities			1,873,765
Commitments and contingencies (see Note 15)
Stockholders'/ partners' equity:
Successor preferred stock, $0.0001 par value: 45,000,000 shares authorized; no shares issued and outstanding at December 31, 2017 and 2016, respectively			0
Successor warrants, 2,173,913 warrants issued and outstanding at December 31, 2017 and no warrants issued or outstanding at December 31, 2016			0
Successor common stock, $0.0001 par value: 300,000,000 shares authorized; 25,000,000 shares issued and outstanding at December 31, 2017 and no shares authorized or issued at December 31, 2016			0
Successor additional paid-in capital			0
Successor accumulated earnings (deficit)			0
Total partners' equity			99,489
Total liabilities and equity			1,973,254
Limited Partners Common Units [Member] | Predecessor [Member]
Stockholders'/ partners' equity:
Predecessor common units, no units issued or outstanding at December 31, 2017 and 83,827,920 units issued and outstanding at December 31, 2016			99,489
Total partners' equity			$ 99,489
[1]	Due to an existing and anticipated financial covenant violations, the Predecessor’s revolving credit facility and senior notes were classified as current at December 31, 2016. There were no existing or anticipated financial covenant violations as of December 31, 2017.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Preferred stock, par value	$ 0.0001
Preferred stock, shares authorized	45,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Warrants issued	2,173,913	0
Warrants outstanding	2,173,913	0
Common stock, par value	$ 0.0001
Common stock, shares authorized	300,000,000	0
Common stock, shares issued	25,000,000	0
Common stock, shares outstanding	25,000,000
Limited Partners Common Units [Member] | Predecessor [Member]
Limited partners, units issued	0	83,827,920
Limited partners, units outstanding	0	83,827,920

STATEMENTS OF CONSOLIDATED AND

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Oil and natural gas sales		$ 205,176,000
Other revenues		303,000
Total revenues		205,479,000
Costs and expenses:
Lease operating expense		74,547,000
Gathering, processing and transportation		18,652,000
Exploration		32,000
Taxes other than income		11,101,000
Depreciation, depletion and amortization		35,979,000
Impairment of proved oil and natural gas properties	$ 0	0	$ 183,400,000	$ 616,800,000
General and administrative expense		29,506,000
Accretion of asset retirement obligations		4,384,000
(Gain) loss on commodity derivative instruments		31,609,000
(Gain) loss on sale of properties		0
Other, net		485,000
Total costs and expenses		206,295,000
Operating income (loss)		(816,000)
Other income (expense):
Interest expense, net		(15,936,000)
Other income (expense)		16,981,000
Gain on extinguishment of debt		0
Total other income (expense)		1,045,000
Income (loss) before reorganization items, net and income taxes		229,000
Reorganization items, net		(1,119,000)
Income tax benefit (expense)		2,176,000
Net income (loss)		1,286,000
Net income (loss) attributable to noncontrolling interest		0
Net income (loss) attributable to Successor/Predecessor		1,286,000
Successor/Predecessor interest in net income (loss):
Net income (loss) attributable to Successor/Predecessor		1,286,000
Net (income) loss allocated to previous owners		0
Net (income) loss allocated to Predecessor's general partner		0
Net (income) loss allocated to NGP IDRs		0
Net (income) allocated to participating restricted stockholders		(35,000)
Net income (loss) available to common stockholders/limited partners		$ 1,251,000
Earnings per share/unit: (See Note 12)
Basic and diluted earnings per share/unit		$ 0.05
Weighted average common shares/units outstanding:
Basic and diluted		25,000
Predecessor [Member]
Revenues:
Oil and natural gas sales	108,970,000		284,051,000	355,422,000
Other revenues	231,000		529,000	2,725,000
Total revenues	109,201,000		284,580,000	358,147,000
Costs and expenses:
Lease operating expense	35,568,000		126,175,000	168,199,000
Gathering, processing and transportation	10,772,000		34,979,000	34,939,000
Exploration	21,000		981,000	2,317,000
Taxes other than income	5,187,000		15,540,000	25,828,000
Depreciation, depletion and amortization	37,717,000		171,629,000	195,814,000
Impairment of proved oil and natural gas properties	0		183,437,000	616,784,000
General and administrative expense	31,606,000		63,280,000	56,671,000
Accretion of asset retirement obligations	3,407,000		10,231,000	7,125,000
(Gain) loss on commodity derivative instruments	(23,076,000)		117,105,000	(462,890,000)
(Gain) loss on sale of properties	0		(2,754,000)	(2,998,000)
Other, net	36,000		516,000	(665,000)
Total costs and expenses	101,238,000		721,119,000	641,124,000
Operating income (loss)	7,963,000		(436,539,000)	(282,977,000)
Other income (expense):
Interest expense, net	(10,243,000)		(146,031,000)	(115,154,000)
Other income (expense)	8,000		8,000	43,000
Gain on extinguishment of debt	0		42,337,000	422,000
Total other income (expense)	(10,235,000)		(103,686,000)	(114,689,000)
Income (loss) before reorganization items, net and income taxes	(2,272,000)		(540,225,000)	(397,666,000)
Reorganization items, net	(88,774,000)		0	0
Income tax benefit (expense)	91,000		(173,000)	2,175,000
Net income (loss)	(90,955,000)		(540,398,000)	(395,491,000)
Net income (loss) attributable to noncontrolling interest	0		0	386,000
Net income (loss) attributable to Successor/Predecessor	(90,955,000)		(540,398,000)	(395,877,000)
Successor/Predecessor interest in net income (loss):
Net income (loss) attributable to Successor/Predecessor	(90,955,000)		(540,398,000)	(395,877,000)
Net (income) loss allocated to previous owners	0		0	2,268,000
Net (income) loss allocated to Predecessor's general partner	0		168,000	327,000
Net (income) loss allocated to NGP IDRs	0		0	(83,000)
Net (income) allocated to participating restricted stockholders	0		0	0
Net income (loss) available to common stockholders/limited partners	$ (90,955,000)		$ (540,230,000)	$ (393,365,000)
Earnings per share/unit: (See Note 12)
Basic and diluted earnings per share/unit	$ (1.09)		$ (6.48)	$ (4.71)
Weighted average common shares/units outstanding:
Basic and diluted	83,807		83,351	83,528

STATEMENTS OF CONSOLIDATED AND5

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($)	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss)		$ 1,286,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		35,979,000
Impairment of proved oil and natural gas properties	$ 0	0	$ 183,400,000	$ 616,800,000
(Gain) loss on derivative instruments		31,609,000
Cash settlements (paid) received on expired derivative instruments		30,446,000
Cash settlements (paid) on terminated derivatives		0
Premiums paid for commodity derivatives		0
Bad debt expense		0
Deferred income tax expense (benefit)		(2,206,000)
Amortization and write-off of deferred financing costs		2,093,000
Amortization and write-off of senior notes discount		0
Gain on extinguishment of debt		0
Accretion of asset retirement obligations		4,384,000
(Gain) loss on sale of properties		0
Share/unit-based compensation (see Note 13)		2,516,000
Settlement of asset retirement obligations		(633,000)
Exploration costs		0
Reorganization items, net		0
Other		0
Changes in operating assets and liabilities:
Accounts receivable		(2,830,000)
Prepaid expenses and other assets		5,578,000
Payables and accrued liabilities		(13,590,000)
Restricted cash		7,561,000
Other		10,000
Net cash provided by operating activities		102,203,000
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		0
Acquisition post-closing adjustments receipts		0
Additions to oil and gas properties		(52,735,000)
Additions to other property and equipment		(127,000)
Additions to restricted investments		(495,000)
Withdrawals of restricted investments		0
Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold		0
Net cash (used in) investing activities		(53,357,000)
Cash flows from financing activities:
Advances on revolving credit facilities		9,000,000
Payments on revolving credit facilities		(63,000,000)
Deferred financing costs		(642,000)
Payment to holders of the Notes		(8,193,000)
Payment to Predecessor common unitholders		(1,250,000)
Contribution from management		1,500,000
Repurchase of senior notes		0
Capital contributions from previous owners		0
Contributions related to sale of assets to NGP affiliate		0
Transfer of operating subsidiary from Memorial Resource		0
Proceeds from the issuance of Predecessor common units		0
Costs incurred in conjunction with issuance of Predecessor common units		0
Purchase of noncontrolling interest		0
Distributions to partners		0
Distribution to Memorial Resource (see Note 1)		0
Acquisition of Predecessor's general partner (see Note 1)		0
Acquisition of incentive distribution rights from NGP (see Note 1)		0
Restricted units returned to plan		0
Repurchases under unit repurchase program		0
Other		(9,000)
Net cash (used in) provided by financing activities		(62,594,000)
Net change in cash and cash equivalents		(13,748,000)
Cash and cash equivalents, beginning of period		20,140,000
Cash and cash equivalents, end of period	20,140,000	6,392,000
Predecessor [Member]
Cash flows from operating activities:
Net income (loss)	(90,955,000)		(540,398,000)	(395,491,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	37,717,000		171,629,000	195,814,000
Impairment of proved oil and natural gas properties	0		183,437,000	616,784,000
(Gain) loss on derivative instruments	(23,076,000)		118,395,000	(458,216,000)
Cash settlements (paid) received on expired derivative instruments	15,895,000		210,704,000	250,043,000
Cash settlements (paid) on terminated derivatives	94,146,000		228,646,000	47,930,000
Premiums paid for commodity derivatives	0		0	(47,930,000)
Bad debt expense	0		2,050,000	0
Deferred income tax expense (benefit)	(74,000)		187,000	(2,234,000)
Amortization and write-off of deferred financing costs	0		22,106,000	6,058,000
Amortization and write-off of senior notes discount	0		13,185,000	2,430,000
Gain on extinguishment of debt	0		(42,337,000)	(422,000)
Accretion of asset retirement obligations	3,407,000		10,231,000	7,125,000
(Gain) loss on sale of properties	0		(2,754,000)	(2,998,000)
Share/unit-based compensation (see Note 13)	3,667,000		7,350,000	10,809,000
Settlement of asset retirement obligations	(164,000)		(1,442,000)	(1,430,000)
Exploration costs	0		792,000	2,078,000
Reorganization items, net	68,356,000		0	0
Other	56,000		229,000	0
Changes in operating assets and liabilities:
Accounts receivable	1,024,000		23,928,000	15,528,000
Prepaid expenses and other assets	735,000		(4,088,000)	2,275,000
Payables and accrued liabilities	15,030,000		4,084,000	(32,068,000)
Restricted cash	(7,561,000)		0	0
Other	(266,000)		2,692,000	666,000
Net cash provided by operating activities	117,937,000		408,626,000	216,751,000
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	0		0	(100,730,000)
Acquisition post-closing adjustments receipts	0		0	9,570,000
Additions to oil and gas properties	(6,211,000)		(57,675,000)	(241,299,000)
Additions to other property and equipment	(76,000)		(7,875,000)	0
Additions to restricted investments	(209,000)		(8,443,000)	(5,690,000)
Withdrawals of restricted investments	0		4,840,000	0
Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold	0		52,711,000	580,000
Net cash (used in) investing activities	(6,496,000)		(16,442,000)	(337,569,000)
Cash flows from financing activities:
Advances on revolving credit facilities	16,600,000		144,000,000	562,000,000
Payments on revolving credit facilities	(98,252,000)		(468,348,000)	(138,000,000)
Deferred financing costs	(8,575,000)		(1,350,000)	(341,000)
Payment to holders of the Notes	(16,446,000)		0	0
Payment to Predecessor common unitholders	0		0	0
Contribution from management	0		0	0
Repurchase of senior notes	0		(41,261,000)	(2,914,000)
Capital contributions from previous owners	0		0	1,912,000
Contributions related to sale of assets to NGP affiliate	0		26,000	860,000
Transfer of operating subsidiary from Memorial Resource	0		2,363,000	0
Proceeds from the issuance of Predecessor common units	0		2,385,000	0
Costs incurred in conjunction with issuance of Predecessor common units	0		(536,000)	0
Purchase of noncontrolling interest	0		0	(5,946,000)
Distributions to partners	0		(13,300,000)	(163,259,000)
Distribution to Memorial Resource (see Note 1)	0		0	(78,396,000)
Acquisition of Predecessor's general partner (see Note 1)	0		(750,000)	0
Acquisition of incentive distribution rights from NGP (see Note 1)	0		(50,000)	0
Restricted units returned to plan	(10,000)		(589,000)	(1,285,000)
Repurchases under unit repurchase program	0		0	(54,184,000)
Other	9,000		0	0
Net cash (used in) provided by financing activities	(106,674,000)		(377,410,000)	120,447,000
Net change in cash and cash equivalents	4,767,000		14,774,000	(371,000)
Cash and cash equivalents, beginning of period	15,373,000	$ 20,140,000	599,000	970,000
Cash and cash equivalents, end of period	$ 20,140,000		$ 15,373,000	$ 599,000

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]	Common Stock [Member]	Warrants [Member]	Additional Paid in Capital [Member]	Accumulated Earnings (Deficit)
Balance (Predecessor [Member]) at Dec. 31, 2014	$ 1,296,314	$ 1,085,265	$ (16,419)	$ 1,251	$ 220,657	$ 0	$ 5,560
Net income (loss) | Predecessor [Member]	(395,491)	(393,395)	30	(327)	(2,268)	83	386
Contributions (see Note 14) | Predecessor [Member]	4,877	2,962	0	3	1,912	0	0
Distributions | Predecessor [Member]	(163,259)	(159,975)	(2,949)	(252)	0	(83)	0
Distribution attributable to net assets transferred | Predecessor [Member]	(78,396)	(78,318)	0	(78)	0	0	0
Net book value of net assets exchanged | Predecessor [Member]	2,721	250,791	0	251	(248,321)	0	0
Purchase of noncontrolling interest | Predecessor [Member]	(5,946)	0	0	0	0	0	(5,946)
Cancellation and amortization of equity/unit-based awards | Predecessor [Member]	10,809	10,809	0	0	0	0	0
Conversion of subordinated units to common units | Predecessor [Member]	0	(19,338)	19,338	0	0	0	0
Common units repurchased under repurchase program (see Note 11) | Predecessor [Member]	(52,813)	(52,813)	0	0	0	0	0
Restricted units repurchased and other | Predecessor [Member]	(1,344)	(1,344)	0	0	0	0	0
Deferred tax liability retained by previous owner | Predecessor [Member]	28,020	0	0	0	28,020	0	0
Balance (Predecessor [Member]) at Dec. 31, 2015	645,492	644,644	0	848	0	0	0
Net income (loss) | Predecessor [Member]	(540,398)	(540,230)	0	(168)	0	0	0
Net proceeds from the issuance of common units | Predecessor [Member]	1,849	1,849	0	0	0	0	0
Distributions | Predecessor [Member]	(13,300)	(13,289)	0	(11)	0	0	0
Purchase of equity interest of general partner (see Note 1) | Predecessor [Member]	(750)	(81)	0	(669)	0	0	0
Acquisition of IDRs from NGP (see Note 1) | Predecessor [Member]	(50)	(50)	0	0	0	0	0
Cancellation and amortization of equity/unit-based awards | Predecessor [Member]	7,206	7,206	0	0	0	0	0
Restricted units repurchased and other | Predecessor [Member]	(560)	(560)	0	0	0	0	0
Balance (Predecessor [Member]) at Dec. 31, 2016	99,489	99,489	0	0	0	0	0
Net income (loss) | Predecessor [Member]	(90,955)	(90,955)	0	0	0	0	0
Cancellation and amortization of equity/unit-based awards | Predecessor [Member]	3,713	3,713	0	0	0	0	0
Restricted units repurchased and other | Predecessor [Member]	(2)	(2)	0	0	0	0	0
Issuance of common stock to Predecessor common unitholders | Predecessor [Member]	(7,707)	(7,707)	0	0	0	0	0
Issuance of warrants to Predecessor common unitholders | Predecessor [Member]	(4,788)	(4,788)	0	0	0	0	0
Contribution from management | Predecessor [Member]	1,500	1,500	0	0	0	0	0
Settlement with Predecessor common unitholders | Predecessor [Member]	(1,250)	(1,250)	0	0	0	0	0
Balance (Predecessor [Member]) at May. 04, 2017	0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
Issuance of Successor common stock to holders of the Notes	377,645							$ 3	$ 0	$ 377,642	$ 0
Issuance of Successor warrants to Predecessor common unitholders | Predecessor [Member]	4,788							0	4,788	0	0
Issuance of Successor common stock to Predecessor common unitholders | Predecessor [Member]	7,707							0	0	7,707	0
Balance at May. 04, 2017	390,140							3	4,788	385,349	0
Net income (loss)	1,286							0	0	0	1,286
Share-based compensation expense	2,516							0	0	2,516	0
Other	(9)							0	0	(9)	0
Balance at Dec. 31, 2017	$ 393,933							$ 3	$ 4,788	$ 387,856	$ 1,286

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation General When referring to Amplify Energy Corp. (formerly known as Memorial Production Partners LP and also referred to as “Successor,” “Amplify Energy,” or the “Company”), the intent is to refer to Amplify Energy, a newly formed Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Amplify Energy is the successor reporting company of Memorial Production Partners LP (“MEMP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended. When referring to the “Predecessor” or the “Company” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to MEMP, the predecessor that was dissolved following the effective date of the Plan (as defined below) and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. We operate in one reportable segment engaged in the acquisition, development exploitation 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 Company’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 “Predecessor’s general partner” and “MEMP GP” refers to Memorial Production Partners GP LLC, our Predecessor’s general partner, which was dissolved following the effective date of the Plan; (ii) “Memorial Resource” refers to Memorial Resource Development Corp., the former owner of our Predecessor’s 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 controlled MRD Holdco LLC; (v) “OLLC” refers to Amplify Energy Operating LLC, formerly known as Memorial Production Operating LLC, our wholly owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refers to Memorial Production Finance Corporation, our Predecessor’s wholly owned subsidiary, whose activities were limited to co-issuing our debt securities and engaging in other activities incidental thereto and which was dissolved following the effective date of the Plan; (vii) “MRD Holdco” refers to MRD Holdco LLC, which together with a group controlled Memorial Resource and (viii) “NGP” refers to Natural Gas Partners. On April 27, 2016, we entered into an agreement pursuant to which the Predecessor agreed to acquire, among other things, all of the equity interests in our Predecessor’s 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 Predecessor’s partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Predecessor held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Predecessor will have the ability to elect the members of MEMP GP’s board of directors. In addition, we terminated the Predecessor’s Omnibus Agreement under which Memorial Resource provided management, administrative and operations personnel to us and our Predecessor’s general partner, and we entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 14 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 Predecessor 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 Predecessor owned the assets for periods after common control commenced through the acquisition date. See Note 14 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 Beta Operating Company LLC, 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 5 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 was 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. Bankruptcy Accounting On January 16, 2017, MEMP and certain of its subsidiaries (collectively with MEMP, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 proceedings”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code” or “Chapter 11”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). The Debtors operated their business as “debtors-in-possession” under the Bankruptcy Code for the period from January 16, 2017 through May 4, 2017. The Consolidated and Combined Financial Statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that were realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s Statement of Consolidated and Combined Operations. Comparability of Financial Statements to Prior Periods As discussed in further detail in Note 3 below, we have adopted and applied the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”). Accordingly, our Consolidated and Combined Financial Statements and Notes after May 4, 2017, are not comparable to the Consolidated and Combined Financial Statements and Notes prior to that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Consolidated and Combined Financial Statements and Notes as the “Successor” for periods subsequent to May 4, 2017 and “Predecessor” for periods prior to May 5, 2017. Furthermore, our Consolidated and Combined Financial Statements and Notes have been presented with a “black line” division to delineate the lack of comparability between the Predecessor and Successor.

Emergence from Voluntary Reorga

Emergence from Voluntary Reorganization under Chapter 11	12 Months Ended
	Dec. 31, 2017
Reorganizations [Abstract]
Emergence from Voluntary Reorganization under Chapter 11	Note 2. Emergence from Voluntary Reorganization under Chapter 11 On January 16, 2017 (the “Petition Date”), the Debtors filed voluntary petitions under the Bankruptcy Code in the Bankruptcy Court to pursue a Joint Chapter 11 Plan of Reorganization for the Debtors. The Debtors’ Chapter 11 proceedings were jointly administered under the caption In re Memorial Production Partners LP, et al. On April 14, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) approving the Second Amended Joint Plan of Reorganization of Memorial Production Partners LP and its affiliated Debtors, dated April 13, 2017 (as amended and supplemented, the “Plan”). On May 4, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the Plan, the Plan became effective in accordance with its terms and the Company emerged from bankruptcy. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession from January 16, 2017 through May 4, 2017. As such, certain aspects of the Chapter 11 proceedings and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented. Plan of Reorganization In accordance with the Plan, on the Effective Date: • The Successor issued (i) 25,000,000 new shares (the “New Common Shares”) of its common stock, par value $0.0001 per share (“common stock”); and (ii) warrants (the “Warrants”) to purchase up to 2,173,913 shares of the Company’s common stock exercisable for a five-year period commencing on the Effective Date entitling their holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding common shares (including common shares as of the Effective Date issuable upon full exercise of the Warrants, but excluding any common shares issuable under the Management Incentive Plan (the “MIP”)), at a per share exercise price of $42.60. • The holders of claims under the Predecessor’s revolving credit facility received a full recovery, consisting of a cash pay down and their pro rata share of the $1 billion exit senior secured reserve-based revolving credit facility (the “Credit Facility”), as further discussed in Note 10. • The 7.625% senior notes due May 2021 (“2021 Senior Notes”) and 6.875% senior notes due August 2022 (“2022 Senior Notes” and collectively, the “Notes”) were cancelled and the Predecessor’s liability thereunder discharged, and the holders of the Notes received (directly or indirectly) their pro rata share of New Common Shares representing, in the aggregate, 98% of the New Common Shares on the Effective Date (subject to dilution by the MIP and the common shares issuable upon exercise of the Warrants). Additionally, the holders of the Notes received their pro rata share of a $24.6 million cash distribution. • The Predecessor’s common units were cancelled, and each common unitholder received its pro rata share of: (i) 2% of the New Common Shares, (ii) the Warrants, and (iii) cash in an aggregate amount of approximately $1.3 million. • The holders of administrative expense claims, priority tax claims, other priority claims and general unsecured creditors of the Predecessor received in exchange for their claims payment in full in cash or otherwise had their rights unimpaired under Title 11 of the United States Code. • The Successor entered into a stockholders agreement with certain parties pursuant to which the Successor agreed to, at the direction of such stockholders, use commercially reasonable efforts to effect the sale of their common stock. • The Successor entered into a registration rights agreement with certain parties pursuant to which the Successor agreed to, among other things, file a registration statement with the SEC within 90 days of the receipt of a request from the stockholders party thereto covering the offer and resale of the common stock held by such stockholders. • The Company’s MIP became effective, such that an aggregate of 2,322,404 shares of the Company’s common stock are available for grant pursuant to awards under the MIP. • The terms of the Predecessor’s general partner’s board of directors automatically expired on the Effective Date. The Successor formed a new seven-member board of directors consisting of the President and Chief Executive Officer, one director of the Predecessor, and five new members designated by certain parties to the plan support agreement.

Fresh Start Accounting

Fresh Start Accounting	12 Months Ended
	Dec. 31, 2017
Fresh Start Accounting [Abstract]
Fresh Start Accounting	Note 3. Fresh Start Accounting Upon emergence from the Chapter 11 proceedings on May 4, 2017, we adopted fresh start accounting as required by GAAP. We met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of the Company and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims. Reorganization Value The Successor’s enterprise value, as approved by the Bankruptcy Court, was estimated to be within a range of $700 million to $900 million, with a midpoint estimate of approximately $800 million. Enterprise value represents the estimated fair value of a company’s interest-bearing debt and its shareholders’ equity. Based on the estimates and assumptions utilized in our fresh start accounting process, we estimated the Successor’s enterprise value to be approximately $800 million before the consideration of cash and cash equivalents on hand at the Effective Date. Reorganization value represents the fair value of the Successor’s total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value, which was derived from the Successor’s enterprise value, was allocated to our individual assets based on their estimated fair values. The following table is a reconciliation of the enterprise value to the reorganization value of the Successor assets at the Effective Date (in thousands): Enterprise value $ 800,000 Plus: Cash and cash equivalents 20,140 Plus: Other working capital liabilities 63,817 Plus: Other long-term liabilities 97,470 Reorganization value of Successor assets $ 981,427 Our assets consist primarily of producing oil and natural gas properties. The fair values of proved and unproved oil and natural gas properties were estimated using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. 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. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with NYMEX forward curve pricing and is adjusted for estimated location and quality differentials, as well as other factors as necessary that the Company’s management believes will impact realizable prices. The fair value of support equipment and facilities were estimated using a cost approach, based on current replacement costs of the assets less depreciation based on the estimated economic useful lives of the assets and age of the assets. See below under the caption “Fresh Start Adjustments” for additional information regarding assumptions used in the valuation of the Company’s various other significant assets and liabilities. Condensed Consolidated Balance Sheet The adjustments included in the following condensed consolidated balance sheet reflect the effect of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the fair values and significant assumptions. As of May 4, 2017 Reorganization Fresh Start Predecessor Adjustments (1) Adjustments Successor (In thousands) ASSETS Current assets: Cash and cash equivalents $ 83,050 $ (62,910 ) (2) $ — $ 20,140 Restricted cash — 7,411 (3) — 7,411 Accounts receivable 33,560 — — 33,560 Short-term derivative instruments 51,329 — — 51,329 Prepaid expenses and other current assets 10,229 675 (4) — 10,904 Total current assets 178,168 (54,824 ) — 123,344 Property and equipment, net 1,551,500 — (894,164 ) (11) 657,336 Long-term derivative instruments 33,800 — — 33,800 Restricted investments 156,443 — — 156,443 Other long-term assets 1,929 8,575 (5) — 10,504 Total assets $ 1,921,840 $ (46,249 ) $ (894,164 ) $ 981,427 LIABILITIES AND EQUITY Current liabilities: Accounts payable $ 1,501 $ 1,389 (6) $ — $ 2,890 Revenues payable 22,747 — — 22,747 Accrued liabilities 36,954 2,939 (7) (1,713 ) (12) 38,180 Current portion of long-term debt 454,799 (454,799 ) (8) — — Total current liabilities 516,001 (450,471 ) (1,713 ) 63,817 Liabilities subject to compromise 1,162,437 (1,162,437 ) (9) — — Long-term debt — 430,000 (8) — 430,000 Asset retirement obligations 158,114 — (62,928 ) (13) 95,186 Deferred tax liabilities 2,206 — — 2,206 Other long-term liabilities 2,481 — (2,403 ) (12) 78 Total liabilities 1,841,239 (1,182,908 ) (67,044 ) 591,287 Commitments and contingencies (see Note 14) Stockholders'/partners' equity: Predecessor common units 80,601 (80,601 ) (10) — — Successor warrants — 4,788 (10) — 4,788 Successor common stock — 3 (10) — 3 Successor additional paid-in capital — 1,212,469 (10) (827,120 ) (14) 385,349 Total stockholders'/ partners' equity 80,601 1,136,659 (827,120 ) 390,140 Total liabilities and equity $ 1,921,840 $ (46,249 ) $ (894,164 ) $ 981,427 Reorganization Adjustments (1) Reflects amounts recorded as of the Effective Date for the implementation of the Plan, including among other items, settlement of the Predecessor’s liabilities subject to compromise, cancellation of the Predecessor’s equity, issuance of the Successor New Common Shares and the Warrants, repayment of certain of Predecessor’s debt and settlement with holders of the Notes. (2) Reflects the changes in cash and cash equivalents, including the following (in thousands): Payment on the Predecessor's revolving credit facility $ (24,799 ) Payment to holders of the Notes (1) (16,446 ) Payment of fees related to Credit Facility (8,575 ) Funding of the professional fees escrow account (7,411 ) Payment of professional fees (4,295 ) Other (1,384 ) Changes in cash and cash equivalents $ (62,910 ) (1) The total cash settlement to the holders of the Notes was approximately $24.6 million, of which $16.4 million was paid upon emergence and $8.2 million was paid post-emergence and is reflected in accrued liabilities in the above condensed consolidated balance sheet. (3) Reflects the transfer to restricted cash to fund the professional fees escrow account. (4) Reflects the pre-payment of certain professional fees. (5) Reflects the deferred financing costs related to the Credit Facility. (6) Reflects the recognition of payables for general unsecured claims. (7) Net increase in accrued liabilities reflects the following (in thousands): Recognition of liability for settlement with holders of the Notes $ 8,193 Payment of professional fees (4,295 ) Recognition of contribution from management (1,500 ) Recognition of settlement with Predecessor common unitholders 1,250 Other (709 ) Net increase in accrued liabilities due to reorganization items $ 2,939 (8) Reflects a repayment of $24.8 million on the Predecessor’s revolving credit facility and the reclassification of $430.0 million in borrowings under the Credit Facility to long-term debt. (9) Settlement of liabilities subject to compromise and the resulting net gain were determined as follows (in thousands): Accounts payable $ 1,389 Accrued interest payable 49,796 Debt 1,111,252 Total liabilities subject to compromise of Predecessor 1,162,437 Recognition of payables for general unsecured claims (1,389 ) Recognition of settlement with holders of the Notes (24,639 ) Issuance of common stock to holders of the Notes (377,645 ) Gain on settlement of liabilities subject to compromise $ 758,764 (10) Net increase in our stockholders’/partners’ equity reflects the following (in thousands): Issuance of common stock to holders of the Notes $ 377,645 Issuance of common stock to Predecessor common unitholders 7,707 Cancellation of the Predecessor's units issued and outstanding 80,601 Recognition on gain on settlement of liabilities subject to compromise 758,764 Recognition of issuance of common stock to Predecessor common unitholders (7,707 ) Recognition of issuance of warrants to Predecessor common unitholders (4,788 ) Recognition of contribution from management 1,500 Recognition of settlement with Predecessor common unitholders (1,250 ) Par value of common stock (3 ) Change in Successor additional paid-in capital 1,212,469 Issuance of warrants to Predecessor common unitholders 4,788 Par value of common stock 3 Predecessor units issued and outstanding (80,601 ) Net increase in capital accounts $ 1,136,659 Fresh Start Adjustments (11) Reflects a decrease of property and equipment, net based on the methodology discussed above and the elimination of accumulated depreciation, depletion and impairment. The fresh start adjustments to property and equipment, net are as follow: Predecessor Fresh Start Adjustments Successor (In thousands) Property and equipment at cost: Proved oil and natural gas properties $ 3,124,137 $ (2,615,076 ) $ 509,061 Support equipment and facilities 199,463 (101,883 ) 97,580 Unproved oil and natural gas properties — 44,688 44,688 Other 15,420 (9,413 ) 6,007 Property and equipment 3,339,020 (2,681,684 ) 657,336 Accumulated depreciation, depletion and impairment (1,787,520 ) 1,787,520 — Property and equipment, net $ 1,551,500 $ (894,164 ) $ 657,336 (12) Reflects the write-off of the deferred rent and loss on sublease liabilities. (13) Reflects a decrease of $62.9 million for asset retirement obligations. The fair value of asset retirement obligations were estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plugging and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk free rate. (14) Reflects the cumulative impact of our fresh start accounting adjustments discussed above. Reorganization Items, Net The Company has incurred significant costs associated with the reorganization. These costs, which are expensed as incurred, were expected to significantly affect the Company’s results of operations. Reorganization items, net represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date. The following table summarizes the components of reorganization items, net included in the accompanying Statements of Consolidated and Combined Operations (in thousands): Successor Predecessor Period from Period from May 5, 2017 January 1, through 2017 through December 31, 2017 May 4, 2017 Gain on settlement of liabilities subject to compromise $ — $ 758,764 Fresh start valuation adjustments — (827,120 ) Professional fees (724 ) (19,824 ) Other (395 ) (594 ) Reorganization items, net $ (1,119 ) $ (88,774 )

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 4. Summary of Significant Accounting Policies Fresh Start Accounting Upon the Effective Date, we adopted fresh start accounting as required by GAAP. We met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of the Company and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims. Fresh start accounting involved a comprehensive valuation process in which we determined the fair value of all of our assets and liabilities on the Effective Date. See Note 3 for additional information. 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, 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. We recorded $1.9 million as an allowance for doubtful accounts at December 31, 2017 and 2016, respectively. 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, seismic costs and delay rental payments 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 twelve to twenty-four 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, 2017 and 2016. Oil and Natural 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, 2017. 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 and U.S. Government securities. See Note 9 for additional information. Debt Issuance Costs These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the period from May 5, 2017 through December 31, 2017 and the years ended December 31, 2016 and 2015 was approximately $2.1 million, $22.1 million, and $6.1 million, respectively. No amortization of deferred financing cost was recorded for the period from January 1, 2017 through May 4, 2017 as the unamortized amount of deferred financing cost at December 31, 2016 was written off due to (i) the uncertainty regarding the Predecessor’s ability to cure the default that existed at December 31, 2016, (ii) the Predecessor’s inability to comply with certain financial covenants contained in our Predecessor’s revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes. 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. No impairment expense was recorded for the period from May 5, 2017 through December 31, 2017 or the period from January 1, 2017 through May 4, 2017. Impairment expense for the years ended December 31, 2016 and 2015 was approximately $183.4 million and $616.8 million, respectively. Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, the expense is reported in exploration expenses. We did not record any impairments related to unproved properties for the year ended December 31, 2017, 2016 and 2015. 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 8 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, 2017 and 2016. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 through through For the Year Ending December 31, December 31, 2017 May 4, 2017 2016 2015 Major customers: Phillips 66 23% 19% 19% 12% Sinclair Oil & Gas Company 19% 20% 16% 18% CIMA Energy 11% n/a n/a n/a BP America Production Company 10% 10% n/a n/a Royal Dutch Shell plc and subsidiaries n/a n/a 14% 14% General and Administrative Expense Prior to June 1, 2016, Memorial Resource provided management, administrative and operating services to the Predecessor and our Predecessor’s general partner pursuant to our Predecessor’s Omnibus Agreement. Upon completion of the MEMP GP Acquisition, the Predecessor’s Omnibus Agreement was terminated on June 1, 2016, and the Predecessor 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 Predecessor’s partnership agreement provided that our Predecessor’s general partner determined in good faith the expenses that were allocated to us, including expenses incurred by our Predecessor’s 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 year ended December 31, 2015 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 Predecessor’s partnership agreement and the Predecessor’s Omnibus Agreement, we reimbursed Memorial Resource for all direct and indirect costs incurred on our behalf. See Note 14 for additional information regarding the Predecessor’s 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) are used to reduce the impact of natural gas and oil price fluctuations. 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 period from May 5, 2017 through December 31, 2017 and the years ended December 31, 2016 and 2015, we had $0.4 million, $0.5 million and $2.1 million in capitalized interest, respectively. No capitalized interest recorded for the period from January 1, 2017 through May 4, 2017. Income Tax We are a corporation subject to federal and certain state income taxes. Our Predecessor was organized as a pass-through entity for federal and most state income tax purposes. Certain of our consolidated subsidiaries were taxed as corporations for federal and state income tax purposes. We are also subject to the Texas margin tax for 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 Statement of Consolidated and Combined 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 by taxing authorities, 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. Although we believe our assumptions, judgements and estimates are reasonable, changes in tax laws or our interpretation of tax laws and the resolution of any tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). The provisions of the Tax Act that impact us include, but are not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3) temporary bonus depreciation that will allow for full expensing of qualified property, and (4) limitations on net operating losses (NOLs) generated after December 31, 2017, to 80 percent of taxable income. Earnings Per Share/Unit Basic and diluted earnings per share/unit (“EPS” or “EPU”) is determined by dividing net income or loss available to the common stockholders/limited partners by the weighted average number of outstanding shares/units during the period. Diluted earnings (loss) per common share is calculated under the two-class method and the treasury stock method by dividing net income (loss) available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. Net income or loss available to the Predecessor limited partners was determined by applying the two-class method. The two-class method of computing the Predecessor’s EPU was an earnings allocation formula that determined EPU based on distributions declared. The amount of net income or loss used in the determination of EPU was reduced (or increased) by the amount of available cash that had been distributed to the Predecessor’s limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings were allocated to the Predecessor’s limited partners in accordance with the contractual terms of the Predecessor’s partnership agreement. The total earnings allocated to the Predecessor’s limited partners was 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 participated in distributions. See Note 12 for additional information. Equity Compensation The fair value of equity-classified awards (e.g., restricted common unit awards, restricted stock units or stock options) 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 re-measured 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 13 for further information. Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): Successor Predecessor December 31, December 31, 2017 2016 Accrued lease operating expense $ 6,439 $ 10,411 Accrued general and administrative expense 4,412 3,040 Accrued capital expenditures 3,854 1,826 Accrued interest payable 1,309 46,417 Asset retirement obligation 713 789 Accrued ad valorem tax 398 977 Other 1,108 1,775 Accrued liabilities $ 18,233 $ 65,235 Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 12,109 $ 6,598 $ 87,527 $ 107,272 Cash paid for reorganization items, net 7,934 11,999 — $ — Cash paid for taxes — — — 472 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (1,080 ) 3,173 (6,284 ) (27,932 ) (Increase) decrease in accounts receivable related to acquisitions — — — 9,698 (Increase) decrease in accounts receivable/payable related to divestitures — — (289 ) — Assumptions of asset retirement obligations related to acquisitions — — — 23,754 Asset retirement obligation removal related to divestitures — — (19,669 ) — New Accounting Pronouncements Compensation—Stock Compensation. In May 2017, the FASB issued an accounting standards update to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance in the terms and conditions of a share-based payment award. The new guidance is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s financial statements and related disclosures. Definition of a Business. In January 2017, the FASB issued an accounting standards update to clarify the definition of a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments provide a more robust framework to use in determining when a set of assets and activities is a business. The amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. Early adoption is permitted and the guidance is to be applied on a prospective basis to purchases or disposals of a business or an asset. The Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s financial statements and related disclosures. 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 Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s 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 Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s financial statements and related disclosures. Leases. In February 2016, the FASB issued a revision to lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The Company 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 15, Commitments and Contingencies. As a result, these new rules will increase reported assets and liabilities. The Company will not early adopt this standard. The Company 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 Company 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 Company’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. 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 Company adopted this guidance as of January 1, 2018 and plans to use the modified retrospective approach, with the cumulative effect of initial application recognized at the date of initial application subject to certain additional disclosures. The Company has performed a detailed review of key contracts and based on that review has concluded the adoption of this new accounting standard will not have a material impact on the consolidated financial statements and related footnote disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 5. 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 Predecessor’s 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 Predecessor had consummated several common control acquisitions since completing its IPO in December 2011, as further discussed in Note 14, 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): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, December 31, 2017 May 4, 2017 2016 2015 $ 609 $ — $ 1,451 $ 1,928 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): Predecessor 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 year ended December 31, 2015 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Predecessor 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. Predecessor For the Year Ended December 31, 2015 (In thousands, except per unit amounts) Revenues $ 381,495 Net income (loss) (394,756 ) Basic and diluted earnings per unit (4.73 ) 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 Predecessor’s revolving credit facility. This disposition did 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 Predecessor’s revolving credit facility. This disposition did not qualify as a discontinued operation. During the year ended December 31, 2016, the Predecessor 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 Statements of Consolidated and Combined Operations of the Company is as follows (in thousands): Predecessor For the Year Ended December 31, 2016 2015 Permian Divestiture $ 4,297 $ (60,875 ) Rockies Divestiture (7,677 ) (56,917 ) 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 14 for additional information regarding this related party divestiture.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 6. 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, 2017 and 2016, 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, 2017 and December 31, 2016. 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 10 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, 2017 and December 31, 2016 were based on estimated forward commodity prices (including nonperformance risk). 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, 2017 and December 31, 2016 for each of the fair value hierarchy levels: Successor Fair Value Measurements at December 31, 2017 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 $ — $ 38,188 $ — $ 38,188 Liabilities: Commodity derivatives $ — $ 15,112 $ — $ 15,112 Predecessor 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 Liabilities: Commodity derivatives $ — $ 17,757 $ — $ 17,757 See Note 7 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 8 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) No impairments was recognized for the period from May 5, 2017 through December 31, 2017 or the period from January 1, 2017 through May 4, 2017. (ii) 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 Predecessor’s 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. (iii) 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.

Risk Management and Derivative

Risk Management and Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments	Note 7. Risk Management and Derivative Instruments Derivative instruments are utilized to manage exposure to commodity price fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production. These transactions limit exposure to declines in prices, but also limit the benefits that would be realized if prices increase. 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, 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. At December 31, 2017, after taking into effect netting arrangements, we had no counterparty exposure related to our derivative instruments. As a result, had all counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $26.5 million against amounts outstanding under our Credit Facility at December 31, 2017. See Note 10 for additional information regarding our 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 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 Predecessor’s revolving credit facility and kept the remaining portion as cash on hand for general partnership purposes. 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 Predecessor’s 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. 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, 2017, the Company had the following open commodity positions: 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average monthly volume (MMBtu) 1,102,000 300,000 Weighted-average fixed price $ 3.91 $ 2.91 Crude Oil Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 152,000 110,000 Weighted-average fixed price $ 71.31 $ 51.34 NGL Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 65,700 — Weighted-average fixed price $ 24.13 $ — 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. The Company did not have any interest rate swaps at December 31, 2017. During December 2016, in connection with our restructuring efforts, we elected to terminate the interest rate swaps associated with our Predecessor’s revolving credit facility and in the aggregate paid our counterparties approximately $2.1 million. The Predecessor 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, 2017 and 2016. 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. Successor Predecessor Asset Derivatives Liability Derivatives Asset Derivatives Liability Derivatives December 31, December 31, December 31, December 31, Type Balance Sheet Location 2017 2017 2016 2016 (In thousands) (In thousands) Commodity contracts $ 37,729 $ 9,183 $ 86,335 $ 16,871 Gross fair value 37,729 9,183 86,335 16,871 Netting arrangements (9,183 ) (9,183 ) (16,871 ) (16,871 ) Net recorded fair value Short-term derivative instruments $ 28,546 $ — $ 69,464 $ — Commodity contracts $ 459 $ 5,929 $ 103,515 $ 885 Gross fair value 459 5,929 103,515 885 Netting arrangements (459 ) (459 ) (885 ) (885 ) Net recorded fair value Long-term derivative instruments $ — $ 5,470 $ 102,630 $ — (Gains) Losses on Derivatives We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended Statements of through through December 31, Operations Location December 31, 2017 May 4, 2017 2016 2015 (Gain) loss on commodity derivatives $ 31,609 $ (23,076 ) $ 117,105 $ (462,890 ) Interest expense, net — — 1,290 4,674

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 8. Asset Retirement Obligations The Company’s asset retirement obligations primarily relate to the Company’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 period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the years ended December 31, 2016 and 2015 (in thousands): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 Asset retirement obligations at beginning of period $ 96,127 $ 155,702 $ 164,164 $ 112,702 Liabilities added from acquisition or drilling 191 6 30 26,876 Liabilities removed upon sale of wells — — (19,669 ) (3,412 ) Liabilities settled (633 ) (164 ) (1,442 ) (1,430 ) Accretion expense 4,384 3,407 10,231 7,125 Revision of estimates 104 104 2,388 22,303 Asset retirement obligation at end of period 100,173 159,055 155,702 164,164 Fresh start adjustment (1) — (62,928 ) — — Less: Current Portion 713 941 789 1,175 Asset retirement obligations - long-term portion $ 99,460 $ 95,186 $ 154,913 $ 162,989 (1) As a result of the application of fresh start accounting, the Successor recorded its asset retirement obligation at fair value as of the Effective date.

Restricted Investments

Restricted Investments	12 Months Ended
	Dec. 31, 2017
Investments Debt And Equity Securities [Abstract]
Restricted Investments	Note 9. 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 balances are as follows: Successor Predecessor December 31, December 31, 2017 2016 (In thousands) BOEM platform abandonment (See Note 15) $ 152,272 $ 152,000 Surety bond cash collateral 501 500 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 4,058 3,627 Port of Long Beach pipeline license 107 107 Restricted investments $ 156,938 $ 156,234

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	Note 10. Debt Our consolidated debt obligations consisted of the following at the dates indicated: Successor Predecessor December 31, December 31, 2017 2016 (In thousands) Successor $1.0 billion Credit Facility, variable-rate, due March 2021 (1) $ 376,000 $ — Predecessor $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) — 511,652 2021 Senior Notes, fixed-rate, due May 2021 (2) (4) — 646,287 2022 Senior Notes, fixed-rate, due August 2022 (3) (4) — 464,965 Total debt 376,000 1,622,904 Less: current portion of long-term debt (5) — (1,622,904 ) Long-term debt $ 376,000 $ — (1) The carrying amount of our Predecessor’s revolving credit facility and Successor 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 at December 31, 2016. (3) The estimated fair value of our 2022 Senior Notes was $223.2 million at December 31, 2016. (4) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (5) Due to an existing and anticipated financial covenant violations, the Predecessor’s revolving credit facility and senior notes were classified as current at December 31, 2016. There were no existing or anticipated financial covenant violations as of December 31, 2017. Credit Facility On May 4, 2017, OLLC, as borrower, entered into the Amended and Restated Credit Agreement (the “Credit Agreement”) among Amplify Acquisitionco Inc., a Delaware corporation (“Acquisitionco”), as parent guarantor, the lenders from time to time party thereto and Wells Fargo Bank, National Association, as Administrative Agent. Pursuant to the Credit Agreement the lenders party thereto agreed to provide OLLC with the Credit Facility (the loans thereunder, the “Loans”). The aggregate principal amount of Loans outstanding under the Credit Facility as of the Effective Date was $430.0 million. The terms and conditions under the Credit Agreement include (but are not limited to) the following: 1. a borrowing base of approximately $490.0 million (which borrowing base amount will be reduced by $2.5 million each month until the next scheduled redetermination of the borrowing base to occur in November 2017); 2. a maturity date of March 19, 2021 for the Credit Facility; 3. the Loans shall bear interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 2.00% to 3.00% or (ii) adjusted LIBOR plus an applicable margin of 3.00% to 4.00%, in each case based on the borrowing base utilization percentage under the Credit Facility; 4. the unused commitments under the Credit Facility will accrue a commitment fee of 0.50%, payable quarterly in arrears; 5. the obligations under the Credit Agreement are guaranteed by Acquisitionco and substantially all of OLLC’s subsidiaries (the “Guarantors”), subject to limited exceptions, and secured on a first-priority basis by substantially all of OLLC’s and the Guarantors’ assets, including, without limitation, liens on at least 95% of the total value of OLLC’s and the Guarantors’ oil and gas properties, a non-recourse pledge by the Company of the capital stock of Acquisitionco, a pledge by Acquisitionco of the membership interests of OLLC and pledges of stock of all other direct and indirect subsidiaries of OLLC, subject to certain limited exceptions; 6. certain financial covenants, including the maintenance of (i) an interest coverage ratio not to exceed 2.50 to 1.00, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending, commencing with the fiscal quarter ending September 30, 2017, (ii) a current ratio, determined as of the last day of each fiscal quarter, commencing with the fiscal quarter ending September 30, 2017, of not less than 1.00 to 1.00 and (iii) a total leverage ratio, determined as of the last day of each fiscal quarter, commencing with the fiscal quarter ending September 30, 2017, of less than or equal to 4.00 to 1.00; 7. a hedging requirement of 50% of reasonably anticipated projected production of hydrocarbons from proved developed producing reserves for each calendar month during 2018; and 8. certain events of default, including, without limitation: non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy. First Amendment to Credit Facility On November 30, 2017, we entered into the first amendment to our Credit Agreement. The first amendment, among other things, amended the Credit Agreement to: 9. reflect the reduction of the borrowing base under the Credit Facility from $475.0 million to $450.0 million, effective as of November 30, 2017, with the borrowing base to be automatically reduced by $2.5 million each month until the next scheduled redetermination of the borrowing base to occur on or about April 2018; 10. remove the requirement to make mandatory prepayments of borrowings in respect of excess unrestricted cash and cash equivalents greater than $35.0 million; and 11. increase the hedging requirement from 50% to 75% of reasonably anticipated projected production of hydrocarbons from proved developed producing reserves for each calendar month for 2018 and 2019 and extended the deadline for entry into such hedging arrangements from December 31, 2017 to April 30, 2018. The borrowing base for our Credit Facility was $447.5 million at December 31, 2017. 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. Predecessor’s Revolving Credit Facility Our Predecessor was a party to a $2.0 billion revolving credit facility, which was guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries). On the Effective Date of the Plan, the holders of claims under the Predecessor’s revolving credit facility received a full recovery, which included a $24.8 million pay down and their pro rata share of the Credit Facility. See Note 2 for additional information. Weighted-Average Interest Rates The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented: Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 Successor Credit Facility 5.08% n/a n/a n/a Predecessor's revolving credit facility n/a 4.18% 3.28% 2.12% Senior Notes On April 17, 2013, May 23, 2013 and October 10, 2013, our Predecessor and Finance Corp.’s (collectively, the “Issuers”) issued $300.0 million, $100.0 million and $300.0 million, respectively, the 2021 Senior Notes. The 2021 Senior Notes were fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain subsidiaries of the Predecessor. The 2021 Senior Notes would have matured on May 1, 2021 with interest accruing at a rate of 7.625% per annum and was payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes were governed by an indenture and were subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. On July 17, 2014, the Issuers completed a private placement of $500.0 million aggregate principal amount of 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 Predecessor. The 2022 Senior Notes would have matured on August 1, 2022 with interest accruing at 6.875% per annum and was payable semi-annually in arrears on February 1 and August 1 of each year, commencing February 1, 2015. The 2022 Senior Notes were governed by an indenture and were subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. During the year ended December 31, 2016, the Predecessor 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 Predecessor paid approximately $26.4 million and recorded a gain of $27.5 million. During the year ended December 31, 2016, the Predecessor repurchased on the open market an aggregate principal amount of $32.0 million of its 2022 Senior Notes. In connection with the repurchases, the Predecessor paid approximately $14.9 million and recorded a gain of $14.8 million. During the year ended December 31, 2015, the Predecessor repurchased on the open market approximately $3.0 million of its 2022 Senior Notes. In connection with the repurchase, the Predecessor paid approximately $2.9 million and recorded a gain on extinguishment of debt of approximately $0.4 million. The Company’s voluntary petitions as described in Note 2 constituted an event of default that accelerated the obligations under the Notes. For the period from January 17, 2017 through May 4, 2017 our contractual interest that was not recorded on the Notes was approximately $24.2 million. On the Effective Date, the Notes were cancelled and the Predecessor’s liability thereunder discharged, and the holders of the Notes received their pro rata share of the New Common Shares. Additionally, the holders of the Notes received their pro rata share of a $24.6 million cash distribution. Letters of credit At December 31, 2017, we had $2.4 million letters of credit outstanding, all related to operations at our Wyoming properties. Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our Credit Facility was $7.1 million at December 31, 2017. The unamortized deferred financing costs are amortized over the remaining life of our Credit Facility using the straight-line method which generally approximate the effective interest method. At December 31, 2016, there were no remaining unamortized deferred financing costs as approximately $1.3 million in deferred financing fees were written off related to our Predecessor’s 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 a default and event of default and the uncertainty regarding anticipated financial covenant violations at December 31, 2016.

Equity (Deficit)

Equity (Deficit)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Equity (Deficit)	Note 11. Equity (Deficit) Issuance of Common Stock and Cancellation of Units In accordance with the Plan, on the Effective Date: • the Company issued 25,000,000 New Common Shares and Warrants to purchase up to 2,173,913 shares of its common stock; • the Predecessor common units were cancelled; and • each Predecessor common unitholder received its pro rata share of: (i) 2% of the New Common Shares, (ii) the Warrants, and (iii) cash in an aggregate amount of approximately $1.3 million. On the Effective Date, there were 25,000,000 New Common Shares issued and outstanding. Equity Outstanding The following table summarizes the changes in the number of outstanding common units and shares of common stock: Common General Units/Shares Subordinated Partner Balance, December 31, 2014 (Predecessor) 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 (Predecessor) 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 (Predecessor) 83,827,920 — — Restricted common units issued — — — Restricted common units forfeited (12,952 ) — — Restricted common units repurchased (1) (14,681 ) — — Balance, May 4, 2017 (Predecessor) 83,800,287 — — Cancellation of Predecessor common units (83,800,287 ) — — Balance, May 4, 2017 (Predecessor) — — — Issuance of Successor common stock 25,000,000 — — Balance, May 5, 2017 (Successor) 25,000,000 — — Issuance of Successor common stock — — — Balance, December 31, 2017 (Successor) 25,000,000 — — (1) Restricted common units are generally net-settled by our Predecessor unitholders to cover the required withholding tax upon vesting. The Predecessor 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 less than approximately $0.1 million for the period from January 1, 2017 through May 4, 2017 and were $0.6 million and $1.3 million for the years ended December 31, 2016 and 2015, respectively. These net-settlements had the effect of unit repurchases by the Company 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 Company. Warrants On the Effective Date, the Company entered into a warrant agreement with American Stock Transfer & Trust Company, LLC, as warrant agent, pursuant to which the Company issued Warrants to purchase up to 2,173,913 shares of the Company’s common stock (representing 8% of the Company’s outstanding common stock as of the Effective Date including shares of the Company’s common stock issuable upon full exercise of the Warrants, but excluding any common stock issuable under the MIP), exercisable for a five year period commencing on the Effective Date at an exercise price of $42.60 per share. The fair values for the warrants upon issuance on the Effective Date have been estimated using the Black-Scholes option pricing model using the following assumptions: Warrants Issued in Successor Period Risk-free interest rate 2.06 % Dividend yield — Expected life (in years) 5.0 Expected volatility 50.0 % Strike Price $ 42.60 Calculated fair value $ 2.20 Predecessor’s 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 Predecessor’s partnership agreement was amended and restated to convert the 0.1% general partner interest in the Predecessor held by MEMP GP into a non-economic general partner interest. Prior to June 1, 2016, Memorial Resource owned 100% of our Predecessor’s general partner, which owned 50% of our incentive distribution rights. The Funds collectively indirectly owned 50% of our incentive distribution rights. Predecessor Common Units. The common units were a separate class of the limited partner interest in our Predecessor and had limited voting rights as set forth in our Predecessor’s partnership agreement. The holders of units were entitled to participate in partnership distributions as discussed further below under “Predecessor’s Cash Distribution Policy” and exercise the rights or privileges available to limited partners under our Predecessor’s 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. 2015 Purchase of Noncontrolling Interest In connection with the 2015 Beta Acquisition, we purchased the noncontrolling interests in SPBPC. See Note 5 for further information. Predecessor “At-the-Market” Equity Program On May 25, 2016, the Predecessor 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 were 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 Predecessor and a sales agent. During the year ended December 31, 2016, the Predecessor 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 Predecessor used the net proceeds from the sale of common units to repurchase senior notes. 2015 Predecessor Repurchases of Common Units In December 2014, the board of directors of our Predecessor’s 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, our Predecessor repurchased $52.8 million in common units, which represents a repurchase and retirement of 3,547,921 common units under the MEMP Repurchase Program. 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 Predecessor was allocated between our Predecessor’s 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 Predecessor’s 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 Predecessor’s general partner. Subsequent to the MEMP GP Acquisition, net income (loss) attributable to the Predecessor is allocated entirely to the common unit holders. Predecessor’s Cash Distribution Policy In October 2016, the board of directors of our Predecessor’s 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 Predecessor’s revolving credit facility. Additionally, under our Predecessor’s revolving credit facility, we could not pay distributions to unitholders in any such quarter in the event there existed a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we were not in pro forma compliance with our Predecessor’s revolving credit facility after giving effect to such distribution. 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 Predecessor 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 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, 2014 (Predecessor) $ 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 (Predecessor) $ —

Earnings per Share_Unit

Earnings per Share/Unit	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings per Share/Unit	Note 12. Earnings per Share/Unit The following sets forth the calculation of earnings (loss) per share/unit, or EPS/EPU, for the periods indicated (in thousands, except per unit amounts): Successor Predecessor Period from May 5, 2017 Period from through January 1, For the Year Ended December 31, 2017 through December 31, 2017 May 4, 2017 2016 2015 Net income (loss) attributable to Successor/Predecessor $ 1,286 $ (90,955 ) $ (540,398 ) $ (395,877 ) Less: Previous owners interest in net income (loss) — — — (2,268 ) Less: Predecessor's general partner's 0.1% interest in net income (loss) (1) — — (168 ) (412 ) Less: Predecessor's IDRs attributable to corresponding period — — — 112 Less: Net income (loss) allocated to participating restricted stockholders 35 — — — Basic and diluted earnings available to common stockholders/limited partners $ 1,251 $ (90,955 ) $ (540,230 ) $ (393,309 ) Common shares/units: Common shares/units outstanding — basic 25,000 83,807 83,351 82,897 Subordinated units — — — 631 Dilutive effect of potential common shares — — — — Common shares/units outstanding — diluted (2) 25,000 83,807 83,351 83,528 Net earnings per share/unit: Basic $ 0.05 $ (1.09 ) $ (6.48 ) $ (4.71 ) Diluted $ 0.05 $ (1.09 ) $ (6.48 ) $ (4.71 ) Antidilutive stock options (3) 517 — — — Antidilutive warrants (4) 2,174 — — — (1) As a result of repurchases under the MEMP Repurchase Program, our Predecessor’s 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. (3) Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect. (4) Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.

Equity-based Awards

Equity-based Awards	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Equity-based Awards	Note 13. Equity-based Awards On the Effective Date in connection with the Plan, the Company implemented the MIP for selected employees of the Company or its subsidiaries. An aggregate of 2,322,404 shares of the Company’s common stock are reserved for issuance under the MIP. MIP awards are granted in the form of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance awards, stock awards and other incentive awards. To the extent that an award under the MIP is expired, forfeited or cancelled for any reason without having been exercised in full, the unexercised award would then be available again for grant under the MIP. The MIP is administered by the board of directors of the Company. On May 4, 2017, the board of directors approved grants of restricted stock unit awards and restricted stock options (collectively the “Emergence Awards”) to certain of the Company’s employees, including the Company’s executive officers. Emergence Awards will generally vest annually in three equal installments on each of the first three anniversaries of the Effective Date, subject to the grantee’s continued employment through each such vesting date. However, upon a grantee’s termination of employment by the Company without Cause, or due to death or Disability, or the grantee resigns from Service for Good Reason (as such terms are defined in the respective Emergence Award agreement), all unvested restricted stock unit awards shall fully vest upon such termination or resignation date. Moreover, (i) upon a grantee’s termination of employment by the Company without Cause, or due to death or Disability, or the grantee resigns from Service for Good Reason (as such terms are defined in the respective Emergence Award agreement), any portion of the then unvested restricted stock options that would have vested had the grantee continued his or her Service during the 12 months following such termination or resignation shall vest on such termination or resignation date and (ii) upon a grantee’s termination of employment by the Company without Cause or the grantee resigns from Service for Good Reason, in each case, following a Change of Control, all unvested restricted stock options shall fully vest as of such termination or resignation date. Notwithstanding the foregoing, the vesting of such Emergence Awards may be subject to and limited by employment-related agreements by and between the Company and grantee. Restricted Stock Units The restricted stock 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. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with restricted stock unit awards was $7.3 million at December 31, 2017. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.39 years. The following table summarizes information regarding the restricted stock unit awards granted under the MIP for the period presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted stock units outstanding at May 5, 2017 (Successor) 614,754 $ 13.77 Granted (2) 173,070 $ 12.87 Forfeited (105,032 ) $ 13.77 Vested — $ — Restricted stock units outstanding at December 31, 2017 (Successor) 682,792 $ 13.54 (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 stock units issued for the period from May 5, 2017 through December 31, 2017 was $2.2 million based on a grant date market price ranging from $10.00 to $13.77 per share. Restricted Stock Options The fair value for restricted stock options granted during the three months ended June 30, 2017 have been estimated using the Black-Scholes option pricing model using the following assumptions: Awards Issued in Successor Period Risk-free interest rate 2.06 % Dividend yield — Expected life (in years) 6.0 Expected volatility 50.0 % Strike Price $ 21.58 Calculated fair value per stock option $ 5.01 No restricted stock options were granted after June 30, 2017. The restricted stock options 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. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with restricted stock option awards was $2.0 million at December 31, 2017. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.34 years. The following table summarizes information regarding the restricted stock option awards granted under the MIP for the period presented: Weighted- Average Grant Number of Date Fair Value Options per Option (1) Restricted stock options outstanding at May 5, 2017 (Successor) 614,754 $ 5.01 Granted 1,876 $ 5.01 Forfeited (99,232 ) $ 5.01 Vested — $ — Restricted stock options outstanding at December 31, 2017 (Successor) 517,398 $ 5.01 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. 2017 Non-Employee Directors Compensation Plan In June 2017, in connection with the Plan, the Company implemented the 2017 Non-Employee Directors Compensation Plan (“Directors Compensation Plan”) to attract and retain services of experienced non-employee directors of the Company or its subsidiaries. An aggregate of 200,000 shares of the Company’s common stock are reserved for issuance under the Directors Compensation Plan. Directors Compensation Plan awards are granted in the form of nonqualified stock options, restricted stock awards, restricted stock units, and other cash-based awards and stock-based awards. To the extent that an award under the Director Compensation Plan is expired, forfeited or cancelled for any reason without having been exercised in full, the unexercised award would then be available again for grant under the Director Compensation Plan. Awards granted will generally vest annually in three equal installments on each of the first three anniversaries of the grant date, subject to the grantee’s continued employment through each such vesting date. The restricted stock 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. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with restricted stock unit awards was $0.2 million at December 31, 2017. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.45 years. The following table summarizes information regarding the restricted stock awards granted under the Director Compensation Plan for the period presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted stock units outstanding at May 5, 2017 (Successor) — $ — Granted (2) 16,341 $ 13.77 Forfeited — $ — Vested — $ — Restricted stock units outstanding at December 31, 2017 (Successor) 16,341 $ 13.77 (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 stock option awards issued in 2017 was $0.2 million based on grant date market price of $13.77 per share. Predecessor Restricted Common Units In December 2011, the board of directors of our Predecessor’s 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 Predecessor. The LTIP authorized 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 was administered by the board of directors of our Predecessor’s general partner or a committee thereof. During the years ended December 31, 2016 and 2015 there was multiple awards of restricted common units that were granted under the LTIP to executive officers and independent directors of our Predecessor’s 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 vested on the first, second, and third anniversaries of the date of grant. Award recipients had all the rights of a Predecessor unitholder in the partnership with respect to the restricted common units, including the right to receive distributions thereon if and when distributions were made by the Predecessor to its unitholders. The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expired. Based on the market price per unit on the date of grant, the aggregate fair value of the restricted common units awarded to our Predecessor’s general partner’s executive officers and other employees during the years ended December 31, 2016 and 2015 was $0.1 million and $12.3 million, respectively. The restricted common units granted were 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 Predecessor’s general partner were 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. On May 1, 2017, the Company effectively cancelled the unvested restricted common unit awards under the LTIP and recorded $2.3 million in compensation expense. 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, 2014 (Predecessor) 1,093,520 $ 20.93 Granted (2) 827,704 $ 14.90 Forfeited (69,059 ) $ 18.35 Vested (483,627 ) $ 20.37 Restricted common units outstanding at December 31, 2015 (Predecessor) 1,368,538 $ 17.61 Granted (3) 50,000 $ 2.41 Forfeited (27,537 ) $ 16.99 Vested (958,841 ) $ 18.01 Restricted common units outstanding at December 31, 2016 (Predecessor) 432,160 $ 15.00 Granted — $ — Forfeited (12,952 ) $ 9.51 Vested (43,045 ) $ 10.40 Cancelled (376,163 ) $ 15.72 Restricted common units outstanding at May 4, 2017 (Predecessor) — $ — (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 2015 was $12.3 million based on grant date market prices ranging from of $6.20 to $15.45 per unit. (3) 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. On June 1, 2016, in connection with the MEMP GP Acquisition, as discussed in Note 1, the board of directors of our Predecessor’s 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 Predecessor’s 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. Predecessor Phantom Units The following table summarizes information regarding the Predecessor’s phantom unit awards granted under the LTIP: Number of Units Phantom units outstanding at December 31, 2015 (Predecessor) — Granted 6,169,018 Forfeited (188,325 ) Phantom units outstanding at December 31, 2016 (Predecessor) 5,980,693 Granted — Forfeited (132,347 ) Vested (155,601 ) Phantom units outstanding at May 4, 2017 (Predecessor) 5,692,745 Cancelled (5,692,745 ) Phantom units outstanding at December 31, 2017 (Successor) — Phantom units issued to non-employee directors of our Predecessor in January 2016 vested on the first anniversary of the date of grant and were settled in cash for less than $0.1 million. Phantom units issued to certain employees in June 2016 were scheduled to 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 would receive, upon vesting, 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 were scheduled to 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 Predecessor’s general partner, in its discretion, was permitted to 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. Upon emergence from bankruptcy, the remaining awards were settled in cash for less than $0.1 million. 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): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 Equity classified awards Restricted stock units (Successor) $ 1,947 $ — $ — $ — Restricted stock options (Successor) 569 — — — Restricted common units (Predecessor) — 3,713 7,206 10,809 Liability classified awards Phantom units (Predecessor) — (46 ) 322 — $ 2,516 $ 3,667 $ 7,528 $ 10,809

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Note 14. Related Party Transactions On June 1, 2016, Memorial Resource and certain affiliates of NGP became unaffiliated entities after we closed the MEMP GP Acquisition, as discussed in Note 1. NGP Affiliated Companies During the year ended December 31, 2016, we paid less than $0.1 million 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 Predecessor acquired all of the equity interests in our Predecessor’s 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 Predecessor’s 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, and (iii) provide that the limited partners of our Predecessor had the ability to elect the members of MEMP GP’s board of directors. On June 1, 2016, the Predecessor also acquired the remaining 50% of the IDRs of MEMP 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 Predecessor owned the assets for the period after common control commenced through the acquisition date. The Predecessor 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 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 The Predecessor 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. Predecessor Omnibus Agreement Memorial Resource provided management, administrative and operating services to the Predecessor and our Predecessor’s general partner pursuant to our Predecessor’s Omnibus Agreement. Upon completion of the MEMP GP Acquisition, the Predecessor’s Omnibus Agreement was terminated and the Predecessor entered into a transition services agreement with Memorial Resource. The following table summarizes the amount of general and administrative expenses recognized under the Predecessor’s Omnibus Agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 $ — $ — $ 11,867 $ 32,281 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 Predecessor’s Omnibus Agreement as noted above and entered into a transition services agreement with Memorial Resource to manage post-closing separation costs and activities. The Company did not incur any costs under the transition services agreement for the period from May 5, 2017 through December 31, 2017 or for the period from January 1, 2017 through May 4, 2017. During the year ended December 31, 2016, we recorded $1.6 million of general and administrative expense related to the transition services agreement with Memorial Resource. 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 Predecessor in connection with the MEMP GP Acquisition. 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 amended gas gathering agreement which was later terminated in November 2015 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, the Predecessor incurred gathering and salt water disposal fees of approximately $3.2 million from Classic Pipeline, an affiliate.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 15. Commitments and Contingencies Litigation & Environmental As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. On January 13, 2017, the Company received a letter from the Environmental Protection Agency (“EPA”) concerning potential violations of the Clean Air Act (“CAA”) section 112(r) associated with our Bairoil complex in Wyoming. The Company met with the EPA on February 16, 2017 to present relevant information related to the allegations. On September 12, 2017, the EPA filed an Administrative Compliance Order on Consent for which the Company must bring all outstanding issues to closure no later than June 30, 2018. We currently cannot estimate the potential penalties, fines or other expenditures, if any, that may result from any EPA actions relating to the alleged violations and, therefore, we cannot determine if the ultimate outcome of this matter will have a material impact on the Company’s financial position, results of operations or cash flows. Other than the Chapter 11 proceedings and the alleged CAA violations discussed herein, based on facts currently available, we are not aware of any litigation, pending or threatened, that we believe will have a material adverse effect on our financial position, results of operations or cash flows; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved. 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. 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: Successor Predecessor 2017 2016 2015 (In thousands) (In thousands) Balance at beginning of period $ — $ 216 $ 2,092 Charged to costs and expenses — — — Payments — (216 ) (1,876 ) Balance at end of period $ — $ — $ 216 At December 31, 2017 and 2016, we had no environmental reserves recorded. Third-Party Midstream Transaction In October 2017, we recognized an approximately $17.0 million gain in connection with the sale of a third-party midstream entity with whom our natural gas gathering and processing agreements entitled us to a percentage of the proceeds in the event of a sale. Sinking Fund Trust Agreement Beta Operating Company, LLC (formerly 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, 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, 2017, the account balance included in restricted investments was approximately $4.1 million. Supplemental Bond for Decommissioning Liabilities Trust Agreement Beta Operating Company, LLC has an obligation with the BOEM in connection with the 2009 acquisition of the Beta properties. The trust account has the required minimum balance of $152.0 million at December 31, 2017 and is fully cash funded. 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. The implementation of this increase is currently on hold and we do not expect resolution of a negotiated decommissioning estimate until 2018. The gross held-to-maturity investments held in the trust account as of December 31, 2017 for the U.S. Bank money market cash equivalent was $152.3 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 period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the years ended December 31, 2016 and 2015, we recognized $6.3 million, $3.1 million, $10.9 million and $16.9 million of rent expense, respectively. 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 Operating leases Total 2018 2019 2020 2021 2022 Thereafter Operating leases $ 14,433 $ 6,155 $ 2,093 $ 2,131 $ 2,154 $ 260 $ 1,640 Purchase Commitments At December 31, 2017, we had a CO 2 2 2 Payment or Settlement Due by Period Purchase commitment Total 2018 2019 2020 2021 2022 Thereafter CO 2 $ 13,633 $ 4,801 $ 4,659 $ 4,173 $ — $ — $ — Minimum Volume Commitment At December 31, 2017, 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 Minimum volume commitment Total 2018 2019 2020 2021 2022 Thereafter Midstream services $ 15,383 $ 3,075 $ 3,075 $ 3,083 $ 3,075 $ 3,075 $ —

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax	Note 16. Income Tax Amplify Energy is a corporation and as a result, is subject to U.S. federal, state and local income taxes. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). The provisions of the Tax Act that impact us include, but are not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3) temporary bonus depreciation that will allow for full expensing of qualified property, and (4) limitations on net operating losses (NOLs) generated after December 31, 2017, to 80% of taxable income. In conjunction with the Tax Act, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under Accounting Standards Codification 740 “Income Tax” (“ASC 740”). In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax Act for which the accounting under ASC 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act. In connection with our initial analysis of the impact of the Tax Act, we provisionally decreased our net deferred tax assets by $23.0 million for the reduction in the federal tax rate and correspondingly decreased the associated valuation allowance by $23.0 million. While we have not completed our accounting for the income tax effects of the Tax Act, there were no specific impacts of the Tax Act for which a reasonable estimate could not be made. Based on a continued analysis of the estimates, it is anticipated that additional revisions may occur during the allowable measurement period. The components of income tax benefit (expense) are as follows: Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 (In thousands) (In thousands) Current taxes: Federal $ 4 $ — $ 6 $ (11 ) State (34 ) 17 8 (48 ) Total current income tax benefit (expense) (30 ) 17 14 (59 ) Deferred taxes: Federal 1,933 71 8 1,193 State 273 3 (195 ) 1,041 Total deferred income tax benefit (expense) 2,206 74 (187 ) 2,234 Total income tax benefit (expense) $ 2,176 $ 91 $ (173 ) $ 2,175 The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows: Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 (In thousands) (In thousands) Expected tax benefit (expense) at federal statutory rate $ 310 $ 5,764 $ 191,870 $ 139,183 State income tax benefit (expense), net of federal benefit 240 30 382 645 Non-deductible expenses (187 ) — — — Changes in valuation allowances 24,767 — — — Remeasurement of federal deferred tax assets due rate change (22,958 ) — — — Pass-through entities (1) — (5,686 ) (191,921 ) (137,704 ) Other 4 (17 ) (504 ) 51 Total income tax benefit (expense) $ 2,176 $ 91 $ (173 ) $ 2,175 (1) MEMP, a publicly traded partnership with qualifying income, was a pass-through entity for federal income tax purposes. The Company’s deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities are as follows (in thousands): Successor Predecessor December 31, December 31, 2017 2016 Deferred income tax assets: Property, Plant & Equipment $ 19,423 $ — Derivative instrument 6,251 — Net operating loss carryforward 10,452 9 Asset retirement obligation 1,223 875 Other 779 33 Total deferred income tax assets: 38,128 917 Valuation allowance (38,128 ) (865 ) Net deferred income tax assets — 52 Deferred income tax liabilities: Property, plant and equipment $ — $ 1,522 Derivatives — 770 Other — 40 Total deferred income tax liabilities — 2,332 Net deferred income tax liabilities $ — $ 2,280 As of December 31, 2017, the Company had U.S. federal net operating loss carry forwards of approximately $46.8 million that will expire in years 2035 - 2037 and state net operating loss carry forwards of approximately $8.8 million which will expire in varying amounts beginning in 2035. In assessing deferred tax assets, the Company considers whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Among other items, the Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and available tax planning strategies. As of December 31, 2017, a valuation allowance of $38.1 million had been recorded. 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, 2017. Tax Audits and Settlements. Generally, our income tax years 2014 through 2017 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.

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information (Unaudited)	Note 17. Quarterly Financial Information (Unaudited) The following tables present selected quarterly financial data for the periods indicated. Earnings per share/unit are computed independently for each of the quarters presented and the sum of the quarterly earnings per share/unit may not necessarily equal the total for the year. Predecessor Successor Period from Period from April 1, 2017 May 5, 2017 First through through Third Fourth Quarter May 4, 2017 June 30, 2017 Quarter Quarter (In thousands, except per share/unit amounts) Revenues $ 81,380 $ 27,821 $ 42,395 $ 75,589 $ 87,495 Operating income (loss) (421 ) 8,384 2,654 (6,043 ) 2,573 Net income (loss) (16,377 ) (74,578 ) (906 ) (7,536 ) 9,728 Net income (loss) attributable to Successor/Predecessor (16,377 ) (74,578 ) (906 ) (7,536 ) 9,728 Net income (loss) available to common stockholders/limited partners (16,377 ) (74,578 ) (906 ) (7,536 ) 9,463 Basic and diluted earnings per unit/share (0.20 ) (0.89 ) (0.04 ) (0.30 ) 0.38 Predecessor 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 ) See Notes 4 and 12 for additional information regarding earnings per share/unit.

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Supplemental Oil and Gas Information (Unaudited)	N ote 18. 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. Successor Predecessor December 31, December 31, December 31, 2017 2016 2015 (In thousands) (In thousands) Evaluated oil and natural gas properties $ 603,053 $ 3,115,012 $ 3,616,325 Support equipment and facilities 100,225 199,093 205,876 Accumulated depletion, depreciation, and amortization (34,429 ) (1,743,274 ) (1,878,549 ) Total $ 668,849 $ 1,570,831 $ 1,943,652 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: Successor Predecessor Period from May 5, 2017 Period from through January 1, For the Year Ended December 31, 2017 through December 31, 2017 May 4, 2017 2016 2015 (In thousands) (In thousands) Property acquisition costs, proved $ — $ — $ — $ 77,834 Property acquisition costs, unproved — — — 1,887 Exploration — — 792 2,078 Development 51,925 9,573 54,310 233,241 Total $ 51,925 $ 9,573 $ 55,102 $ 315,040 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 Company’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, 2017. 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: 2017 2016 2015 Oil ($/Bbl): WTI (1) $ 51.34 $ 42.75 $ 46.79 NGL ($/Bbl): WTI (1) $ 51.34 $ 42.75 $ 46.79 Natural Gas ($/MMbtu): Henry Hub (2) $ 2.98 $ 2.48 $ 2.58 (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 for the periods indicated: For the period from May 5, 2017 through December 31, 2017 (Successor) Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of period 80,960 419,472 30,572 1,088,660 Extensions and discoveries 121 4,900 261 7,195 Production (2,380 ) (21,885 ) (1,114 ) (42,850 ) Revision of previous estimates (6,697 ) 4,071 (4,530 ) (63,284 ) End of year 72,004 406,558 25,189 989,721 Proved developed reserves: Beginning of period 57,803 297,101 21,963 775,693 End of year 50,014 299,481 17,982 707,459 Proved undeveloped reserves: Beginning of period 23,157 122,371 8,609 312,967 End of year 21,990 107,077 7,207 282,262 For the period from January 1, 2017 through May 4, 2017 (Predecessor) Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 65,741 371,016 25,184 916,565 Extensions and discoveries 53 45 8 410 Production (1,204 ) (12,411 ) (616 ) (23,336 ) Revision of previous estimates 16,370 60,822 5,996 195,021 End of period 80,960 419,472 30,572 1,088,660 Proved developed reserves: Beginning of year 45,536 280,035 18,923 666,786 End of period 57,803 297,101 21,963 775,693 Proved undeveloped reserves: Beginning of year 20,205 90,981 6,261 249,779 End of period 23,157 122,371 8,609 312,967 Year Ended December 31, 2016 (Predecessor) 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 (Predecessor) 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 Noteworthy amounts included in the categories of proved reserve changes in the above tables include: • The 98.9 Bcfe reduction in reserves for the period from May 5, 2017 through December 31, 2017 is primarily due to a 13.4 Bcfe upward pricing revision and a 76.7 Bcfe downward revision due to updated well performance data and future anticipated development and maintenance cost increases. We added 7.2 Bcfe during the period from May 5, 2017 through December 31, 2017 due to extensions and discoveries. • The 172.1 Bcfe increase in reserves for the January 1, 2017 through May 4, 2017 is primarily due to a 204.6 Bcfe upward pricing revision and a 9.6 Bcfe downward revision due to updated well performance data. Proved undeveloped reserves increased primarily due to upward pricing during the period from January 1, 2017 through May 4, 2017. • 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 an 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. See Note 5 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: Successor Predecessor Period from May 5, 2017 Period from through January 1, For the Year Ended December 31, 2017 through December 31, 2017 May 4, 2017 2016 2015 (In thousands) (In thousands) Future cash inflows $ 5,149,623 $ 5,246,487 $ 3,666,731 $ 5,952,935 Future production costs (2,982,035 ) (3,275,952 ) (2,384,195 ) (3,194,577 ) Future development costs (530,133 ) (492,610 ) (440,496 ) (808,512 ) Future income tax expense — — — — Future net cash flows for estimated timing of cash flows 1,637,455 1,477,925 842,040 1,949,846 10% annual discount for estimated timing of cash flows (869,784 ) (786,836 ) (446,199 ) (1,360,292 ) Standardized measure of discounted future net cash flows $ 767,671 $ 691,089 $ 395,841 $ 589,554 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, 2017: Successor Predecessor Period from May 5, 2017 Period from through January 1, For the Year Ended December 31, 2017 through December 31, 2017 May 4, 2017 2016 2015 (In thousands) (In thousands) Beginning of year $ 691,089 $ 395,841 $ 589,554 $ 2,911,987 Sale of oil and natural gas produced, net of production costs (100,946 ) (57,420 ) (107,357 ) (128,382 ) Purchase of minerals in place — — — 75,998 Sale of minerals in place — — (28,277 ) (45,100 ) Extensions and discoveries 7,187 1,320 2,016 18,582 Changes in income taxes, net — — — 63,180 Changes in prices and costs 161,106 306,375 (404,870 ) (2,764,481 ) Previously estimated development costs incurred 61,851 9,227 89,748 322,446 Net changes in future development costs (31,438 ) (55,333 ) 254,043 448,089 Revisions of previous quantities (27,060 ) 99,591 14,414 (344,775 ) Accretion of discount 46,072 13,195 58,956 297,517 Change in production rates and other (40,190 ) (21,707 ) (72,386 ) (265,507 ) End of year $ 767,671 $ 691,089 $ 395,841 $ 589,554

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Note. 19 Subsequent Events Reduction in Force On February 6, 2018, certain employees were impacted by a workforce reduction resulting in an involuntary termination of 19 employees across the Company. Departure of Certain Directors or Certain Officers On January 9, 2018, Alex Shayevsky resigned from our board of directors. Mr. Shayevsky served on our audit committee and compensation committee. There were no disagreements between Mr. Shayevsky and us which led to Mr. Shayevsky’s resignation from the board.

Organization and Basis of Pre26

Organization and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
General	General When referring to Amplify Energy Corp. (formerly known as Memorial Production Partners LP and also referred to as “Successor,” “Amplify Energy,” or the “Company”), the intent is to refer to Amplify Energy, a newly formed Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Amplify Energy is the successor reporting company of Memorial Production Partners LP (“MEMP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended. When referring to the “Predecessor” or the “Company” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to MEMP, the predecessor that was dissolved following the effective date of the Plan (as defined below) and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. We operate in one reportable segment engaged in the acquisition, development exploitation 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 Company’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 “Predecessor’s general partner” and “MEMP GP” refers to Memorial Production Partners GP LLC, our Predecessor’s general partner, which was dissolved following the effective date of the Plan; (ii) “Memorial Resource” refers to Memorial Resource Development Corp., the former owner of our Predecessor’s 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 controlled MRD Holdco LLC; (v) “OLLC” refers to Amplify Energy Operating LLC, formerly known as Memorial Production Operating LLC, our wholly owned subsidiary through which we operate our properties; (vi) “Finance Corp.” refers to Memorial Production Finance Corporation, our Predecessor’s wholly owned subsidiary, whose activities were limited to co-issuing our debt securities and engaging in other activities incidental thereto and which was dissolved following the effective date of the Plan; (vii) “MRD Holdco” refers to MRD Holdco LLC, which together with a group controlled Memorial Resource and (viii) “NGP” refers to Natural Gas Partners. On April 27, 2016, we entered into an agreement pursuant to which the Predecessor agreed to acquire, among other things, all of the equity interests in our Predecessor’s 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 Predecessor’s partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Predecessor held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Predecessor will have the ability to elect the members of MEMP GP’s board of directors. In addition, we terminated the Predecessor’s Omnibus Agreement under which Memorial Resource provided management, administrative and operations personnel to us and our Predecessor’s general partner, and we entered into a transition services agreement with Memorial Resource to manage certain post-closing separation costs and activities. See Note 14 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 Predecessor 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 Predecessor owned the assets for periods after common control commenced through the acquisition date. See Note 14 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 Beta Operating Company LLC, 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 5 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 was 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.
Bankruptcy Accounting	Bankruptcy Accounting On January 16, 2017, MEMP and certain of its subsidiaries (collectively with MEMP, the “Debtors”) filed voluntary petitions (the cases commenced thereby, the “Chapter 11 proceedings”) under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code” or “Chapter 11”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). The Debtors operated their business as “debtors-in-possession” under the Bankruptcy Code for the period from January 16, 2017 through May 4, 2017. The Consolidated and Combined Financial Statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that were realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s Statement of Consolidated and Combined Operations.
Comparability of Financial Statements to Prior Periods	Comparability of Financial Statements to Prior Periods As discussed in further detail in Note 3 below, we have adopted and applied the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from bankruptcy proceedings (“Fresh Start Accounting”). Accordingly, our Consolidated and Combined Financial Statements and Notes after May 4, 2017, are not comparable to the Consolidated and Combined Financial Statements and Notes prior to that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Consolidated and Combined Financial Statements and Notes as the “Successor” for periods subsequent to May 4, 2017 and “Predecessor” for periods prior to May 5, 2017. Furthermore, our Consolidated and Combined Financial Statements and Notes have been presented with a “black line” division to delineate the lack of comparability between the Predecessor and Successor.
Fresh Start Accounting	Fresh Start Accounting Upon the Effective Date, we adopted fresh start accounting as required by GAAP. We met the requirements of fresh start accounting, which include: (i) the holders of the Predecessor’s voting common units immediately prior to the Effective Date received less than 50% of the voting shares of the Company and (ii) the reorganization value of our assets immediately prior to the Effective Date was less than the post-petition liabilities and allowed claims. Fresh start accounting involved a comprehensive valuation process in which we determined the fair value of all of our assets and liabilities on the Effective Date. See Note 3 for additional information.
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, 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. We recorded $1.9 million as an allowance for doubtful accounts at December 31, 2017 and 2016, respectively. 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, seismic costs and delay rental payments 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 twelve to twenty-four 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, 2017 and 2016.
Oil and Natural Gas Reserves	Oil and Natural 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, 2017. 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 and U.S. Government securities. See Note 9 for additional information.
Debt Issuance Costs	Debt Issuance Costs These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the period from May 5, 2017 through December 31, 2017 and the years ended December 31, 2016 and 2015 was approximately $2.1 million, $22.1 million, and $6.1 million, respectively. No amortization of deferred financing cost was recorded for the period from January 1, 2017 through May 4, 2017 as the unamortized amount of deferred financing cost at December 31, 2016 was written off due to (i) the uncertainty regarding the Predecessor’s ability to cure the default that existed at December 31, 2016, (ii) the Predecessor’s inability to comply with certain financial covenants contained in our Predecessor’s revolving credit facility and (iii) the default or cross default provisions in the indentures governing the 2021 Senior Notes and 2022 Senior Notes.
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. No impairment expense was recorded for the period from May 5, 2017 through December 31, 2017 or the period from January 1, 2017 through May 4, 2017. Impairment expense for the years ended December 31, 2016 and 2015 was approximately $183.4 million and $616.8 million, respectively. Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, the expense is reported in exploration expenses. We did not record any impairments related to unproved properties for the year ended December 31, 2017, 2016 and 2015.
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 8 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, 2017 and 2016. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 through through For the Year Ending December 31, December 31, 2017 May 4, 2017 2016 2015 Major customers: Phillips 66 23% 19% 19% 12% Sinclair Oil & Gas Company 19% 20% 16% 18% CIMA Energy 11% n/a n/a n/a BP America Production Company 10% 10% n/a n/a Royal Dutch Shell plc and subsidiaries n/a n/a 14% 14%
General and Administrative Expense	General and Administrative Expense Prior to June 1, 2016, Memorial Resource provided management, administrative and operating services to the Predecessor and our Predecessor’s general partner pursuant to our Predecessor’s Omnibus Agreement. Upon completion of the MEMP GP Acquisition, the Predecessor’s Omnibus Agreement was terminated on June 1, 2016, and the Predecessor 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 Predecessor’s partnership agreement provided that our Predecessor’s general partner determined in good faith the expenses that were allocated to us, including expenses incurred by our Predecessor’s 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 year ended December 31, 2015 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 Predecessor’s partnership agreement and the Predecessor’s Omnibus Agreement, we reimbursed Memorial Resource for all direct and indirect costs incurred on our behalf. See Note 14 for additional information regarding the Predecessor’s 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) are used to reduce the impact of natural gas and oil price fluctuations. 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 period from May 5, 2017 through December 31, 2017 and the years ended December 31, 2016 and 2015, we had $0.4 million, $0.5 million and $2.1 million in capitalized interest, respectively. No capitalized interest recorded for the period from January 1, 2017 through May 4, 2017.
Income Tax	Income Tax We are a corporation subject to federal and certain state income taxes. Our Predecessor was organized as a pass-through entity for federal and most state income tax purposes. Certain of our consolidated subsidiaries were taxed as corporations for federal and state income tax purposes. We are also subject to the Texas margin tax for 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 Statement of Consolidated and Combined 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 by taxing authorities, 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. Although we believe our assumptions, judgements and estimates are reasonable, changes in tax laws or our interpretation of tax laws and the resolution of any tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). The provisions of the Tax Act that impact us include, but are not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) elimination of the corporate alternative minimum tax (AMT); (3) temporary bonus depreciation that will allow for full expensing of qualified property, and (4) limitations on net operating losses (NOLs) generated after December 31, 2017, to 80 percent of taxable income.
Earnings Per Share/Unit	Earnings Per Share/Unit Basic and diluted earnings per share/unit (“EPS” or “EPU”) is determined by dividing net income or loss available to the common stockholders/limited partners by the weighted average number of outstanding shares/units during the period. Diluted earnings (loss) per common share is calculated under the two-class method and the treasury stock method by dividing net income (loss) available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. Net income or loss available to the Predecessor limited partners was determined by applying the two-class method. The two-class method of computing the Predecessor’s EPU was an earnings allocation formula that determined EPU based on distributions declared. The amount of net income or loss used in the determination of EPU was reduced (or increased) by the amount of available cash that had been distributed to the Predecessor’s limited partners for that corresponding period. The remaining undistributed earnings or excess distributions over earnings were allocated to the Predecessor’s limited partners in accordance with the contractual terms of the Predecessor’s partnership agreement. The total earnings allocated to the Predecessor’s limited partners was 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 participated in distributions. See Note 12 for additional information.
Equity Compensation	Equity Compensation The fair value of equity-classified awards (e.g., restricted common unit awards, restricted stock units or stock options) 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 re-measured 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 13 for further information.
Accrued Liabilities	Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): Successor Predecessor December 31, December 31, 2017 2016 Accrued lease operating expense $ 6,439 $ 10,411 Accrued general and administrative expense 4,412 3,040 Accrued capital expenditures 3,854 1,826 Accrued interest payable 1,309 46,417 Asset retirement obligation 713 789 Accrued ad valorem tax 398 977 Other 1,108 1,775 Accrued liabilities $ 18,233 $ 65,235
Supplemental Cash Flows	Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 12,109 $ 6,598 $ 87,527 $ 107,272 Cash paid for reorganization items, net 7,934 11,999 — $ — Cash paid for taxes — — — 472 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (1,080 ) 3,173 (6,284 ) (27,932 ) (Increase) decrease in accounts receivable related to acquisitions — — — 9,698 (Increase) decrease in accounts receivable/payable related to divestitures — — (289 ) — Assumptions of asset retirement obligations related to acquisitions — — — 23,754 Asset retirement obligation removal related to divestitures — — (19,669 ) —
New Accounting Pronouncements	New Accounting Pronouncements Compensation—Stock Compensation. In May 2017, the FASB issued an accounting standards update to clarify and reduce both (i) diversity in practice and (ii) cost and complexity when applying its guidance in the terms and conditions of a share-based payment award. The new guidance is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s financial statements and related disclosures. Definition of a Business. In January 2017, the FASB issued an accounting standards update to clarify the definition of a business. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The amendments are intended to help companies and other organizations evaluate whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments provide a more robust framework to use in determining when a set of assets and activities is a business. The amendments are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. Early adoption is permitted and the guidance is to be applied on a prospective basis to purchases or disposals of a business or an asset. The Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s financial statements and related disclosures. 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 Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s 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 Company adopted this guidance as of January 1, 2018, noting the impact of adopting this guidance was not material to the Company’s financial statements and related disclosures. Leases. In February 2016, the FASB issued a revision to lease accounting guidance. The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The revised guidance requires lessees to recognize a right-of-use asset and lease liability for all leasing transactions regardless of classification. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The Company 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 15, Commitments and Contingencies. As a result, these new rules will increase reported assets and liabilities. The Company will not early adopt this standard. The Company 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 Company 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 Company’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. 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 Company adopted this guidance as of January 1, 2018 and plans to use the modified retrospective approach, with the cumulative effect of initial application recognized at the date of initial application subject to certain additional disclosures. The Company has performed a detailed review of key contracts and based on that review has concluded the adoption of this new accounting standard will not have a material impact on the consolidated financial statements and related footnote disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Fresh Start Accounting (Tables)

Fresh Start Accounting (Tables)	12 Months Ended
	Dec. 31, 2017
Fresh Start Accounting [Abstract]
Reconciliation of the Enterprise Value to the Reorganization Value	The following table is a reconciliation of the enterprise value to the reorganization value of the Successor assets at the Effective Date (in thousands): Enterprise value $ 800,000 Plus: Cash and cash equivalents 20,140 Plus: Other working capital liabilities 63,817 Plus: Other long-term liabilities 97,470 Reorganization value of Successor assets $ 981,427
Schedule of Reorganization and Fresh Start Adjustments	The adjustments included in the following condensed consolidated balance sheet reflect the effect of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the fair values and significant assumptions. As of May 4, 2017 Reorganization Fresh Start Predecessor Adjustments (1) Adjustments Successor (In thousands) ASSETS Current assets: Cash and cash equivalents $ 83,050 $ (62,910 ) (2) $ — $ 20,140 Restricted cash — 7,411 (3) — 7,411 Accounts receivable 33,560 — — 33,560 Short-term derivative instruments 51,329 — — 51,329 Prepaid expenses and other current assets 10,229 675 (4) — 10,904 Total current assets 178,168 (54,824 ) — 123,344 Property and equipment, net 1,551,500 — (894,164 ) (11) 657,336 Long-term derivative instruments 33,800 — — 33,800 Restricted investments 156,443 — — 156,443 Other long-term assets 1,929 8,575 (5) — 10,504 Total assets $ 1,921,840 $ (46,249 ) $ (894,164 ) $ 981,427 LIABILITIES AND EQUITY Current liabilities: Accounts payable $ 1,501 $ 1,389 (6) $ — $ 2,890 Revenues payable 22,747 — — 22,747 Accrued liabilities 36,954 2,939 (7) (1,713 ) (12) 38,180 Current portion of long-term debt 454,799 (454,799 ) (8) — — Total current liabilities 516,001 (450,471 ) (1,713 ) 63,817 Liabilities subject to compromise 1,162,437 (1,162,437 ) (9) — — Long-term debt — 430,000 (8) — 430,000 Asset retirement obligations 158,114 — (62,928 ) (13) 95,186 Deferred tax liabilities 2,206 — — 2,206 Other long-term liabilities 2,481 — (2,403 ) (12) 78 Total liabilities 1,841,239 (1,182,908 ) (67,044 ) 591,287 Commitments and contingencies (see Note 14) Stockholders'/partners' equity: Predecessor common units 80,601 (80,601 ) (10) — — Successor warrants — 4,788 (10) — 4,788 Successor common stock — 3 (10) — 3 Successor additional paid-in capital — 1,212,469 (10) (827,120 ) (14) 385,349 Total stockholders'/ partners' equity 80,601 1,136,659 (827,120 ) 390,140 Total liabilities and equity $ 1,921,840 $ (46,249 ) $ (894,164 ) $ 981,427 Reorganization Adjustments (1) Reflects amounts recorded as of the Effective Date for the implementation of the Plan, including among other items, settlement of the Predecessor’s liabilities subject to compromise, cancellation of the Predecessor’s equity, issuance of the Successor New Common Shares and the Warrants, repayment of certain of Predecessor’s debt and settlement with holders of the Notes. (2) Reflects the changes in cash and cash equivalents, including the following (in thousands): Payment on the Predecessor's revolving credit facility $ (24,799 ) Payment to holders of the Notes (1) (16,446 ) Payment of fees related to Credit Facility (8,575 ) Funding of the professional fees escrow account (7,411 ) Payment of professional fees (4,295 ) Other (1,384 ) Changes in cash and cash equivalents $ (62,910 ) (1) The total cash settlement to the holders of the Notes was approximately $24.6 million, of which $16.4 million was paid upon emergence and $8.2 million was paid post-emergence and is reflected in accrued liabilities in the above condensed consolidated balance sheet. (3) Reflects the transfer to restricted cash to fund the professional fees escrow account. (4) Reflects the pre-payment of certain professional fees. (5) Reflects the deferred financing costs related to the Credit Facility. (6) Reflects the recognition of payables for general unsecured claims. (7) Net increase in accrued liabilities reflects the following (in thousands): Recognition of liability for settlement with holders of the Notes $ 8,193 Payment of professional fees (4,295 ) Recognition of contribution from management (1,500 ) Recognition of settlement with Predecessor common unitholders 1,250 Other (709 ) Net increase in accrued liabilities due to reorganization items $ 2,939 (8) Reflects a repayment of $24.8 million on the Predecessor’s revolving credit facility and the reclassification of $430.0 million in borrowings under the Credit Facility to long-term debt. (9) Settlement of liabilities subject to compromise and the resulting net gain were determined as follows (in thousands): Accounts payable $ 1,389 Accrued interest payable 49,796 Debt 1,111,252 Total liabilities subject to compromise of Predecessor 1,162,437 Recognition of payables for general unsecured claims (1,389 ) Recognition of settlement with holders of the Notes (24,639 ) Issuance of common stock to holders of the Notes (377,645 ) Gain on settlement of liabilities subject to compromise $ 758,764 (10) Net increase in our stockholders’/partners’ equity reflects the following (in thousands): Issuance of common stock to holders of the Notes $ 377,645 Issuance of common stock to Predecessor common unitholders 7,707 Cancellation of the Predecessor's units issued and outstanding 80,601 Recognition on gain on settlement of liabilities subject to compromise 758,764 Recognition of issuance of common stock to Predecessor common unitholders (7,707 ) Recognition of issuance of warrants to Predecessor common unitholders (4,788 ) Recognition of contribution from management 1,500 Recognition of settlement with Predecessor common unitholders (1,250 ) Par value of common stock (3 ) Change in Successor additional paid-in capital 1,212,469 Issuance of warrants to Predecessor common unitholders 4,788 Par value of common stock 3 Predecessor units issued and outstanding (80,601 ) Net increase in capital accounts $ 1,136,659 Fresh Start Adjustments (11) Reflects a decrease of property and equipment, net based on the methodology discussed above and the elimination of accumulated depreciation, depletion and impairment. The fresh start adjustments to property and equipment, net are as follow: Predecessor Fresh Start Adjustments Successor (In thousands) Property and equipment at cost: Proved oil and natural gas properties $ 3,124,137 $ (2,615,076 ) $ 509,061 Support equipment and facilities 199,463 (101,883 ) 97,580 Unproved oil and natural gas properties — 44,688 44,688 Other 15,420 (9,413 ) 6,007 Property and equipment 3,339,020 (2,681,684 ) 657,336 Accumulated depreciation, depletion and impairment (1,787,520 ) 1,787,520 — Property and equipment, net $ 1,551,500 $ (894,164 ) $ 657,336 (12) Reflects the write-off of the deferred rent and loss on sublease liabilities. (13) Reflects a decrease of $62.9 million for asset retirement obligations. The fair value of asset retirement obligations were estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plugging and abandonment costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk free rate. (14) Reflects the cumulative impact of our fresh start accounting adjustments discussed above.
Schedule of Reorganization Items, Net	The following table summarizes the components of reorganization items, net included in the accompanying Statements of Consolidated and Combined Operations (in thousands): Successor Predecessor Period from Period from May 5, 2017 January 1, through 2017 through December 31, 2017 May 4, 2017 Gain on settlement of liabilities subject to compromise $ — $ 758,764 Fresh start valuation adjustments — (827,120 ) Professional fees (724 ) (19,824 ) Other (395 ) (594 ) Reorganization items, net $ (1,119 ) $ (88,774 )

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Major Customers	The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 through through For the Year Ending December 31, December 31, 2017 May 4, 2017 2016 2015 Major customers: Phillips 66 23% 19% 19% 12% Sinclair Oil & Gas Company 19% 20% 16% 18% CIMA Energy 11% n/a n/a n/a BP America Production Company 10% 10% n/a n/a Royal Dutch Shell plc and subsidiaries n/a n/a 14% 14%
Summary of Current Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands): Successor Predecessor December 31, December 31, 2017 2016 Accrued lease operating expense $ 6,439 $ 10,411 Accrued general and administrative expense 4,412 3,040 Accrued capital expenditures 3,854 1,826 Accrued interest payable 1,309 46,417 Asset retirement obligation 713 789 Accrued ad valorem tax 398 977 Other 1,108 1,775 Accrued liabilities $ 18,233 $ 65,235
Summary of Supplemental Cash Flow	Supplemental cash flow for the periods presented (in thousands): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 12,109 $ 6,598 $ 87,527 $ 107,272 Cash paid for reorganization items, net 7,934 11,999 — $ — Cash paid for taxes — — — 472 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (1,080 ) 3,173 (6,284 ) (27,932 ) (Increase) decrease in accounts receivable related to acquisitions — — — 9,698 (Increase) decrease in accounts receivable/payable related to divestitures — — (289 ) — Assumptions of asset retirement obligations related to acquisitions — — — 23,754 Asset retirement obligation removal related to divestitures — — (19,669 ) —

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2017
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): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, December 31, 2017 May 4, 2017 2016 2015 $ 609 $ — $ 1,451 $ 1,928
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): Predecessor 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
Supplemental Pro Forma Information	The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2015 as though the 2015 Beta Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Predecessor 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. Predecessor For the Year Ended December 31, 2015 (In thousands, except per unit amounts) Revenues $ 381,495 Net income (loss) (394,756 ) Basic and diluted earnings per unit (4.73 )
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 Statements of Consolidated and Combined Operations of the Company is as follows (in thousands): Predecessor For the Year Ended December 31, 2016 2015 Permian Divestiture $ 4,297 $ (60,875 ) Rockies Divestiture (7,677 ) (56,917 )

Fair Value Measurements of Fi30

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 and December 31, 2016 for each of the fair value hierarchy levels: Successor Fair Value Measurements at December 31, 2017 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 $ — $ 38,188 $ — $ 38,188 Liabilities: Commodity derivatives $ — $ 15,112 $ — $ 15,112 Predecessor 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 Liabilities: Commodity derivatives $ — $ 17,757 $ — $ 17,757

Risk Management and Derivativ31

Risk Management and Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Open Commodity Positions	At December 31, 2017, the Company had the following open commodity positions: 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average monthly volume (MMBtu) 1,102,000 300,000 Weighted-average fixed price $ 3.91 $ 2.91 Crude Oil Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 152,000 110,000 Weighted-average fixed price $ 71.31 $ 51.34 NGL Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 65,700 — Weighted-average fixed price $ 24.13 $ —
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, 2017 and 2016. 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. Successor Predecessor Asset Derivatives Liability Derivatives Asset Derivatives Liability Derivatives December 31, December 31, December 31, December 31, Type Balance Sheet Location 2017 2017 2016 2016 (In thousands) (In thousands) Commodity contracts $ 37,729 $ 9,183 $ 86,335 $ 16,871 Gross fair value 37,729 9,183 86,335 16,871 Netting arrangements (9,183 ) (9,183 ) (16,871 ) (16,871 ) Net recorded fair value Short-term derivative instruments $ 28,546 $ — $ 69,464 $ — Commodity contracts $ 459 $ 5,929 $ 103,515 $ 885 Gross fair value 459 5,929 103,515 885 Netting arrangements (459 ) (459 ) (885 ) (885 ) Net recorded fair value Long-term derivative instruments $ — $ 5,470 $ 102,630 $ —
Unrealized and Realized Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended Statements of through through December 31, Operations Location December 31, 2017 May 4, 2017 2016 2015 (Gain) loss on commodity derivatives $ 31,609 $ (23,076 ) $ 117,105 $ (462,890 ) Interest expense, net — — 1,290 4,674

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The Company’s asset retirement obligations primarily relate to the Company’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 period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the years ended December 31, 2016 and 2015 (in thousands): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 Asset retirement obligations at beginning of period $ 96,127 $ 155,702 $ 164,164 $ 112,702 Liabilities added from acquisition or drilling 191 6 30 26,876 Liabilities removed upon sale of wells — — (19,669 ) (3,412 ) Liabilities settled (633 ) (164 ) (1,442 ) (1,430 ) Accretion expense 4,384 3,407 10,231 7,125 Revision of estimates 104 104 2,388 22,303 Asset retirement obligation at end of period 100,173 159,055 155,702 164,164 Fresh start adjustment (1) — (62,928 ) — — Less: Current Portion 713 941 789 1,175 Asset retirement obligations - long-term portion $ 99,460 $ 95,186 $ 154,913 $ 162,989 (1) As a result of the application of fresh start accounting, the Successor recorded its asset retirement obligation at fair value as of the Effective date.

Restricted Investments (Tables)

Restricted Investments (Tables)	12 Months Ended
	Dec. 31, 2017
Investments Debt And Equity Securities [Abstract]
Restricted Investment Balances	The components of the restricted investment balances are as follows Successor Predecessor December 31, December 31, 2017 2016 (In thousands) BOEM platform abandonment (See Note 15) $ 152,272 $ 152,000 Surety bond cash collateral 501 500 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 4,058 3,627 Port of Long Beach pipeline license 107 107 Restricted investments $ 156,938 $ 156,234

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Consolidated Debt Obligations	Our consolidated debt obligations consisted of the following at the dates indicated: Successor Predecessor December 31, December 31, 2017 2016 (In thousands) Successor $1.0 billion Credit Facility, variable-rate, due March 2021 (1) $ 376,000 $ — Predecessor $2.0 billion revolving credit facility, variable-rate, due March 2018 (1) — 511,652 2021 Senior Notes, fixed-rate, due May 2021 (2) (4) — 646,287 2022 Senior Notes, fixed-rate, due August 2022 (3) (4) — 464,965 Total debt 376,000 1,622,904 Less: current portion of long-term debt (5) — (1,622,904 ) Long-term debt $ 376,000 $ — (1) The carrying amount of our Predecessor’s revolving credit facility and Successor 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 at December 31, 2016. (3) The estimated fair value of our 2022 Senior Notes was $223.2 million at December 31, 2016. (4) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (5) Due to an existing and anticipated financial covenant violations, the Predecessor’s revolving credit facility and senior notes were classified as current at December 31, 2016. There were no existing or anticipated financial covenant violations as of December 31, 2017.
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: Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 Successor Credit Facility 5.08% n/a n/a n/a Predecessor's revolving credit facility n/a 4.18% 3.28% 2.12%

Equity (Deficit) (Tables)

Equity (Deficit) (Tables)	12 Months Ended
	Dec. 31, 2017
Equity and Distributions [Line Items]
Summary of Changes in Number of Outstanding Common Units and Shares of Common Stock	The following table summarizes the changes in the number of outstanding common units and shares of common stock: Common General Units/Shares Subordinated Partner Balance, December 31, 2014 (Predecessor) 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 (Predecessor) 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 (Predecessor) 83,827,920 — — Restricted common units issued — — — Restricted common units forfeited (12,952 ) — — Restricted common units repurchased (1) (14,681 ) — — Balance, May 4, 2017 (Predecessor) 83,800,287 — — Cancellation of Predecessor common units (83,800,287 ) — — Balance, May 4, 2017 (Predecessor) — — — Issuance of Successor common stock 25,000,000 — — Balance, May 5, 2017 (Successor) 25,000,000 — — Issuance of Successor common stock — — — Balance, December 31, 2017 (Successor) 25,000,000 — — (1) Restricted common units are generally net-settled by our Predecessor unitholders to cover the required withholding tax upon vesting. The Predecessor 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 less than approximately $0.1 million for the period from January 1, 2017 through May 4, 2017 and were $0.6 million and $1.3 million for the years ended December 31, 2016 and 2015, respectively. These net-settlements had the effect of unit repurchases by the Company 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 Company.
Predecessor [Member]
Equity and Distributions [Line Items]
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
Predecessor [Member] | Previous Owners [Member]
Equity and Distributions [Line Items]
Summary of Previous Owners' 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, 2014 (Predecessor) $ 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 (Predecessor) $ —
Warrants [Member]
Equity and Distributions [Line Items]
Summary of Assumptions used to Estimate the Fair Value	The fair values for the warrants upon issuance on the Effective Date have been estimated using the Black-Scholes option pricing model using the following assumptions: Warrants Issued in Successor Period Risk-free interest rate 2.06 % Dividend yield — Expected life (in years) 5.0 Expected volatility 50.0 % Strike Price $ 42.60 Calculated fair value $ 2.20

Earnings per Share_Unit (Tables

Earnings per Share/Unit (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Calculation of Earnings (Loss) Per Share/Unit	The following sets forth the calculation of earnings (loss) per share/unit, or EPS/EPU, for the periods indicated (in thousands, except per unit amounts): Successor Predecessor Period from May 5, 2017 Period from through January 1, For the Year Ended December 31, 2017 through December 31, 2017 May 4, 2017 2016 2015 Net income (loss) attributable to Successor/Predecessor $ 1,286 $ (90,955 ) $ (540,398 ) $ (395,877 ) Less: Previous owners interest in net income (loss) — — — (2,268 ) Less: Predecessor's general partner's 0.1% interest in net income (loss) (1) — — (168 ) (412 ) Less: Predecessor's IDRs attributable to corresponding period — — — 112 Less: Net income (loss) allocated to participating restricted stockholders 35 — — — Basic and diluted earnings available to common stockholders/limited partners $ 1,251 $ (90,955 ) $ (540,230 ) $ (393,309 ) Common shares/units: Common shares/units outstanding — basic 25,000 83,807 83,351 82,897 Subordinated units — — — 631 Dilutive effect of potential common shares — — — — Common shares/units outstanding — diluted (2) 25,000 83,807 83,351 83,528 Net earnings per share/unit: Basic $ 0.05 $ (1.09 ) $ (6.48 ) $ (4.71 ) Diluted $ 0.05 $ (1.09 ) $ (6.48 ) $ (4.71 ) Antidilutive stock options (3) 517 — — — Antidilutive warrants (4) 2,174 — — — (1) As a result of repurchases under the MEMP Repurchase Program, our Predecessor’s 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. (3) Amount represents options to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect. (4) Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.

Equity-based Awards (Tables)

Equity-based Awards (Tables)	12 Months Ended
	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Summary of Information Regarding Restricted Stock 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, 2014 (Predecessor) 1,093,520 $ 20.93 Granted (2) 827,704 $ 14.90 Forfeited (69,059 ) $ 18.35 Vested (483,627 ) $ 20.37 Restricted common units outstanding at December 31, 2015 (Predecessor) 1,368,538 $ 17.61 Granted (3) 50,000 $ 2.41 Forfeited (27,537 ) $ 16.99 Vested (958,841 ) $ 18.01 Restricted common units outstanding at December 31, 2016 (Predecessor) 432,160 $ 15.00 Granted — $ — Forfeited (12,952 ) $ 9.51 Vested (43,045 ) $ 10.40 Cancelled (376,163 ) $ 15.72 Restricted common units outstanding at May 4, 2017 (Predecessor) — $ — (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 2015 was $12.3 million based on grant date market prices ranging from of $6.20 to $15.45 per unit. (3) 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 Fair Value Assumptions	The fair value for restricted stock options granted during the three months ended June 30, 2017 have been estimated using the Black-Scholes option pricing model using the following assumptions: Awards Issued in Successor Period Risk-free interest rate 2.06 % Dividend yield — Expected life (in years) 6.0 Expected volatility 50.0 % Strike Price $ 21.58 Calculated fair value per stock option $ 5.01
Summary of Stock Option Awards	The following table summarizes information regarding the restricted stock option awards granted under the MIP for the period presented: Weighted- Average Grant Number of Date Fair Value Options per Option (1) Restricted stock options outstanding at May 5, 2017 (Successor) 614,754 $ 5.01 Granted 1,876 $ 5.01 Forfeited (99,232 ) $ 5.01 Vested — $ — Restricted stock options outstanding at December 31, 2017 (Successor) 517,398 $ 5.01
Summary of Information Regarding Phantom Unit Awards	The following table summarizes information regarding the Predecessor’s phantom unit awards granted under the LTIP: Number of Units Phantom units outstanding at December 31, 2015 (Predecessor) — Granted 6,169,018 Forfeited (188,325 ) Phantom units outstanding at December 31, 2016 (Predecessor) 5,980,693 Granted — Forfeited (132,347 ) Vested (155,601 ) Phantom units outstanding at May 4, 2017 (Predecessor) 5,692,745 Cancelled (5,692,745 ) Phantom units outstanding at December 31, 2017 (Successor) —
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): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 Equity classified awards Restricted stock units (Successor) $ 1,947 $ — $ — $ — Restricted stock options (Successor) 569 — — — Restricted common units (Predecessor) — 3,713 7,206 10,809 Liability classified awards Phantom units (Predecessor) — (46 ) 322 — $ 2,516 $ 3,667 $ 7,528 $ 10,809
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Summary of Information Regarding Restricted Stock Unit Awards	The following table summarizes information regarding the restricted stock unit awards granted under the MIP for the period presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted stock units outstanding at May 5, 2017 (Successor) 614,754 $ 13.77 Granted (2) 173,070 $ 12.87 Forfeited (105,032 ) $ 13.77 Vested — $ — Restricted stock units outstanding at December 31, 2017 (Successor) 682,792 $ 13.54 (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 stock units issued for the period from May 5, 2017 through December 31, 2017 was $2.2 million based on a grant date market price ranging from $10.00 to $13.77 per share.
Restricted Stock Units [Member] | 2017 Non-Employee Directors Compensation Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Summary of Information Regarding Restricted Stock Unit Awards	The following table summarizes information regarding the restricted stock awards granted under the Director Compensation Plan for the period presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Restricted stock units outstanding at May 5, 2017 (Successor) — $ — Granted (2) 16,341 $ 13.77 Forfeited — $ — Vested — $ — Restricted stock units outstanding at December 31, 2017 (Successor) 16,341 $ 13.77 (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 stock option awards issued in 2017 was $0.2 million based on grant date market price of $13.77 per share.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
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 Predecessor’s Omnibus Agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands): Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 $ — $ — $ 11,867 $ 32,281
Predecessor [Member] | February 2015 Acquisition [Member]
Related Party Transaction [Line Items]
Schedule of Net Assets Recorded by Predecessor	The Predecessor 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

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Environmental Reserves	The following table presents the activity of our environmental reserves for the periods presented: Successor Predecessor 2017 2016 2015 (In thousands) (In thousands) Balance at beginning of period $ — $ 216 $ 2,092 Charged to costs and expenses — — — Payments — (216 ) (1,876 ) Balance at end of period $ — $ — $ 216
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 Operating leases Total 2018 2019 2020 2021 2022 Thereafter Operating leases $ 14,433 $ 6,155 $ 2,093 $ 2,131 $ 2,154 $ 260 $ 1,640
Purchase Commitments Under the Contracts	At December 31, 2017, we had a CO 2 2 2 Payment or Settlement Due by Period Purchase commitment Total 2018 2019 2020 2021 2022 Thereafter CO 2 $ 13,633 $ 4,801 $ 4,659 $ 4,173 $ — $ — $ — At December 31, 2017, 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 Minimum volume commitment Total 2018 2019 2020 2021 2022 Thereafter Midstream services $ 15,383 $ 3,075 $ 3,075 $ 3,083 $ 3,075 $ 3,075 $ —

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Components of Income Tax Expense (Benefit)	The components of income tax benefit (expense) are as follows: Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 (In thousands) (In thousands) Current taxes: Federal $ 4 $ — $ 6 $ (11 ) State (34 ) 17 8 (48 ) Total current income tax benefit (expense) (30 ) 17 14 (59 ) Deferred taxes: Federal 1,933 71 8 1,193 State 273 3 (195 ) 1,041 Total deferred income tax benefit (expense) 2,206 74 (187 ) 2,234 Total income tax benefit (expense) $ 2,176 $ 91 $ (173 ) $ 2,175
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: Successor Predecessor Period from Period from May 5, 2017 January 1, 2017 For the Year Ended through through December 31, December 31, 2017 May 4, 2017 2016 2015 (In thousands) (In thousands) Expected tax benefit (expense) at federal statutory rate $ 310 $ 5,764 $ 191,870 $ 139,183 State income tax benefit (expense), net of federal benefit 240 30 382 645 Non-deductible expenses (187 ) — — — Changes in valuation allowances 24,767 — — — Remeasurement of federal deferred tax assets due rate change (22,958 ) — — — Pass-through entities (1) — (5,686 ) (191,921 ) (137,704 ) Other 4 (17 ) (504 ) 51 Total income tax benefit (expense) $ 2,176 $ 91 $ (173 ) $ 2,175 (1) MEMP, a publicly traded partnership with qualifying income, was a pass-through entity for federal income tax purposes.
Components of Net Deferred Income Tax Liabilities	The Company’s deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities are as follows (in thousands): Successor Predecessor December 31, December 31, 2017 2016 Deferred income tax assets: Property, Plant & Equipment $ 19,423 $ — Derivative instrument 6,251 — Net operating loss carryforward 10,452 9 Asset retirement obligation 1,223 875 Other 779 33 Total deferred income tax assets: 38,128 917 Valuation allowance (38,128 ) (865 ) Net deferred income tax assets — 52 Deferred income tax liabilities: Property, plant and equipment $ — $ 1,522 Derivatives — 770 Other — 40 Total deferred income tax liabilities — 2,332 Net deferred income tax liabilities $ — $ 2,280

Quarterly Financial Informati41

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data	The following tables present selected quarterly financial data for the periods indicated. Earnings per share/unit are computed independently for each of the quarters presented and the sum of the quarterly earnings per share/unit may not necessarily equal the total for the year. Predecessor Successor Period from Period from April 1, 2017 May 5, 2017 First through through Third Fourth Quarter May 4, 2017 June 30, 2017 Quarter Quarter (In thousands, except per share/unit amounts) Revenues $ 81,380 $ 27,821 $ 42,395 $ 75,589 $ 87,495 Operating income (loss) (421 ) 8,384 2,654 (6,043 ) 2,573 Net income (loss) (16,377 ) (74,578 ) (906 ) (7,536 ) 9,728 Net income (loss) attributable to Successor/Predecessor (16,377 ) (74,578 ) (906 ) (7,536 ) 9,728 Net income (loss) available to common stockholders/limited partners (16,377 ) (74,578 ) (906 ) (7,536 ) 9,463 Basic and diluted earnings per unit/share (0.20 ) (0.89 ) (0.04 ) (0.30 ) 0.38 Predecessor 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 )

Supplemental Oil and Gas Info42

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
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. Successor Predecessor December 31, December 31, December 31, 2017 2016 2015 (In thousands) (In thousands) Evaluated oil and natural gas properties $ 603,053 $ 3,115,012 $ 3,616,325 Support equipment and facilities 100,225 199,093 205,876 Accumulated depletion, depreciation, and amortization (34,429 ) (1,743,274 ) (1,878,549 ) Total $ 668,849 $ 1,570,831 $ 1,943,652
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: Successor Predecessor Period from May 5, 2017 Period from through January 1, For the Year Ended December 31, 2017 through December 31, 2017 May 4, 2017 2016 2015 (In thousands) (In thousands) Property acquisition costs, proved $ — $ — $ — $ 77,834 Property acquisition costs, unproved — — — 1,887 Exploration — — 792 2,078 Development 51,925 9,573 54,310 233,241 Total $ 51,925 $ 9,573 $ 55,102 $ 315,040
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: 2017 2016 2015 Oil ($/Bbl): WTI (1) $ 51.34 $ 42.75 $ 46.79 NGL ($/Bbl): WTI (1) $ 51.34 $ 42.75 $ 46.79 Natural Gas ($/MMbtu): Henry Hub (2) $ 2.98 $ 2.48 $ 2.58 (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 for the periods indicated: For the period from May 5, 2017 through December 31, 2017 (Successor) Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of period 80,960 419,472 30,572 1,088,660 Extensions and discoveries 121 4,900 261 7,195 Production (2,380 ) (21,885 ) (1,114 ) (42,850 ) Revision of previous estimates (6,697 ) 4,071 (4,530 ) (63,284 ) End of year 72,004 406,558 25,189 989,721 Proved developed reserves: Beginning of period 57,803 297,101 21,963 775,693 End of year 50,014 299,481 17,982 707,459 Proved undeveloped reserves: Beginning of period 23,157 122,371 8,609 312,967 End of year 21,990 107,077 7,207 282,262 For the period from January 1, 2017 through May 4, 2017 (Predecessor) Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 65,741 371,016 25,184 916,565 Extensions and discoveries 53 45 8 410 Production (1,204 ) (12,411 ) (616 ) (23,336 ) Revision of previous estimates 16,370 60,822 5,996 195,021 End of period 80,960 419,472 30,572 1,088,660 Proved developed reserves: Beginning of year 45,536 280,035 18,923 666,786 End of period 57,803 297,101 21,963 775,693 Proved undeveloped reserves: Beginning of year 20,205 90,981 6,261 249,779 End of period 23,157 122,371 8,609 312,967 Year Ended December 31, 2016 (Predecessor) 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 (Predecessor) 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
Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows is as follows: Successor Predecessor Period from May 5, 2017 Period from through January 1, For the Year Ended December 31, 2017 through December 31, 2017 May 4, 2017 2016 2015 (In thousands) (In thousands) Future cash inflows $ 5,149,623 $ 5,246,487 $ 3,666,731 $ 5,952,935 Future production costs (2,982,035 ) (3,275,952 ) (2,384,195 ) (3,194,577 ) Future development costs (530,133 ) (492,610 ) (440,496 ) (808,512 ) Future income tax expense — — — — Future net cash flows for estimated timing of cash flows 1,637,455 1,477,925 842,040 1,949,846 10% annual discount for estimated timing of cash flows (869,784 ) (786,836 ) (446,199 ) (1,360,292 ) Standardized measure of discounted future net cash flows $ 767,671 $ 691,089 $ 395,841 $ 589,554
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, 2017: Successor Predecessor Period from May 5, 2017 Period from through January 1, For the Year Ended December 31, 2017 through December 31, 2017 May 4, 2017 2016 2015 (In thousands) (In thousands) Beginning of year $ 691,089 $ 395,841 $ 589,554 $ 2,911,987 Sale of oil and natural gas produced, net of production costs (100,946 ) (57,420 ) (107,357 ) (128,382 ) Purchase of minerals in place — — — 75,998 Sale of minerals in place — — (28,277 ) (45,100 ) Extensions and discoveries 7,187 1,320 2,016 18,582 Changes in income taxes, net — — — 63,180 Changes in prices and costs 161,106 306,375 (404,870 ) (2,764,481 ) Previously estimated development costs incurred 61,851 9,227 89,748 322,446 Net changes in future development costs (31,438 ) (55,333 ) 254,043 448,089 Revisions of previous quantities (27,060 ) 99,591 14,414 (344,775 ) Accretion of discount 46,072 13,195 58,956 297,517 Change in production rates and other (40,190 ) (21,707 ) (72,386 ) (265,507 ) End of year $ 767,671 $ 691,089 $ 395,841 $ 589,554

Organization and Basis of Pre43

Organization and Basis of Presentation - Additional Information (Detail)	Apr. 27, 2016USD ($)	Nov. 03, 2015USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017Segment
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments | Segment				1
Acquisitions of oil and natural gas properties			$ 0
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 Predecessor’s partnership agreement was amended and restated to, among other things, (i) convert the 0.1% general partner interest in the Predecessor held by MEMP GP into a non-economic general partner interest, (ii) cancel the IDRs, and (iii) provide that the limited partners of the Predecessor will have the ability to elect the members of MEMP GP’s board of directors.
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%

Emergence from Voluntary Reor44

Emergence from Voluntary Reorganization under Chapter 11 - Additional Information (Detail) - USD ($)	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016
Reorganizations [Line Items]
Common stock, par value		$ 0.0001
Warrant issued during period		2,173,913	0
Percentage of new common shares issued to predecessor	2.00%
Aggregate cash amount to predecessor	$ 1,300,000
Common Stock [Member]
Reorganizations [Line Items]
Stock issued during period	25,000,000	0
Warrants [Member]
Reorganizations [Line Items]
Warrant life period	5 years
Percentage of common shares to be issued upon exercise of warrants	8.00%
Warrant exercise price	$ 42.60
Plan of Reorganization [Member]
Reorganizations [Line Items]
Warrant life period	5 years
Percentage of common shares to be issued upon exercise of warrants	8.00%
Common stock, par value	$ 0.0001
Percentage of new common shares issued to predecessor	2.00%
Aggregate cash amount to predecessor	$ 1,300,000
Plan of Reorganization [Member] | Management Incentive Plan [Member]
Reorganizations [Line Items]
Aggregate shares of common stock available for grants	2,322,404
Plan of Reorganization [Member] | Credit Facility [Member]
Reorganizations [Line Items]
Revolving credit facility	$ 1,000,000,000
Plan of Reorganization [Member] | Common Stock [Member]
Reorganizations [Line Items]
Stock issued during period	25,000,000
Plan of Reorganization [Member] | Warrants [Member]
Reorganizations [Line Items]
Warrant issued during period	2,173,913
Warrant exercise price	$ 42.60
Noteholder Plan Support Agreement [Member]
Reorganizations [Line Items]
Percentage of new common shares issued	98.00%
Unsecured noteholders to receive pro rata share of cash distribution	$ 24,600,000

Fresh Start Accounting - Additi

Fresh Start Accounting - Additional Information (Detail) - USD ($)	May 04, 2017	Dec. 31, 2017
Fresh Start Adjustment [Line Items]
Enterprise value	$ 800,000,000
Repayment of predecessor’s revolving credit facility		$ 63,000,000
Reorganization Adjustments [Member]
Fresh Start Adjustment [Line Items]
Repayment of predecessor’s revolving credit facility	24,800,000
Reclassification of borrowings under the credit facility to long-term debt	430,000,000
Fresh Start Adjustments [Member]
Fresh Start Adjustment [Line Items]
Decrease in asset retirement obligations	62,900,000
Maximum [Member]
Fresh Start Adjustment [Line Items]
Percentage of voting shares to be received by voting share holders		50.00%
Enterprise value	900,000,000
Minimum
Fresh Start Adjustment [Line Items]
Enterprise value	$ 700,000,000

Fresh Start Accounting - Reconc

Fresh Start Accounting - Reconciliation of the Enterprise Value to the Reorganization Value (Detail) $ in Thousands	May 04, 2017USD ($)
Reorganizations [Abstract]
Enterprise value	$ 800,000
Plus: Cash and cash equivalents	20,140
Plus: Other working capital liabilities	63,817
Plus: Other long-term liabilities	97,470
Reorganization value of Successor assets	$ 981,427

Fresh Start Accounting - Applic

Fresh Start Accounting - Application of Fresh Start Accounting to Balance Sheet (Detail) - USD ($) $ in Thousands		Dec. 31, 2017		May 04, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents		$ 6,392		$ 20,140
Restricted cash				7,411
Accounts receivable		36,391		33,560
Short-term derivative instruments		28,546		51,329
Prepaid expenses and other current assets		7,220		10,904
Total current assets		78,549		123,344
Property and equipment, net		673,432		657,336
Long-term derivative instruments		0		33,800
Restricted investments		156,938		156,443
Other long-term assets		8,545		10,504
Total assets		917,464		981,427
Current liabilities:
Accounts payable		1,941		2,890
Revenues payable		22,427		22,747
Accrued liabilities		18,233		38,180
Current portion of long-term debt		0	[1]	0
Total current liabilities		42,601		63,817
Liabilities subject to compromise				0
Long-term debt		376,000		430,000
Asset retirement obligations		99,460		95,186
Deferred tax liabilities		0		2,206
Other long-term liabilities		0		78
Total liabilities		523,531		591,287
Commitments and contingencies (see Note 14)				0
Stockholders'/ partners' equity:
Predecessor common units				0
Successor warrants		4,788		4,788
Successor common stock		3		3
Successor additional paid-in capital		387,856		385,349
Total stockholders' equity		393,933		390,140
Total liabilities and equity		$ 917,464		981,427
Reorganization Adjustments [Member]
Current assets:
Cash and cash equivalents				(62,910)
Restricted cash				7,411
Accounts receivable				0
Short-term derivative instruments				0
Prepaid expenses and other current assets				675
Total current assets				(54,824)
Property and equipment, net				0
Long-term derivative instruments				0
Restricted investments				0
Other long-term assets				8,575
Total assets				(46,249)
Current liabilities:
Accounts payable				1,389
Revenues payable				0
Accrued liabilities				2,939
Current portion of long-term debt				(454,799)
Total current liabilities				(450,471)
Liabilities subject to compromise				(1,162,437)
Long-term debt				430,000
Asset retirement obligations				0
Deferred tax liabilities				0
Other long-term liabilities				0
Total liabilities				(1,182,908)
Commitments and contingencies (see Note 14)				0
Stockholders'/ partners' equity:
Predecessor common units				(80,601)
Successor warrants				4,788
Successor common stock				3
Successor additional paid-in capital				1,212,469
Total partners' equity				1,136,659
Total liabilities and equity				(46,249)
Fresh Start Adjustments [Member]
Current assets:
Cash and cash equivalents				0
Restricted cash				0
Accounts receivable				0
Short-term derivative instruments				0
Prepaid expenses and other current assets				0
Total current assets				0
Property and equipment, net				(894,164)
Long-term derivative instruments				0
Restricted investments				0
Other long-term assets				0
Total assets				(894,164)
Current liabilities:
Accounts payable				0
Revenues payable				0
Accrued liabilities				(1,713)
Current portion of long-term debt				0
Total current liabilities				(1,713)
Liabilities subject to compromise				0
Long-term debt				0
Asset retirement obligations				(62,928)
Deferred tax liabilities				0
Other long-term liabilities				(2,403)
Total liabilities				(67,044)
Commitments and contingencies (see Note 14)				0
Stockholders'/ partners' equity:
Predecessor common units				0
Successor warrants				0
Successor common stock				0
Successor additional paid-in capital				(827,120)
Total partners' equity				(827,120)
Total liabilities and equity				(894,164)
Predecessor [Member]
Current assets:
Cash and cash equivalents				20,140	$ 15,373	$ 599	$ 970
Accounts receivable					34,584
Short-term derivative instruments					69,464
Prepaid expenses and other current assets					13,163
Total current assets					132,584
Property and equipment, net				1,551,500	1,579,702
Long-term derivative instruments					102,630
Restricted investments					156,234
Other long-term assets					2,104
Total assets					1,973,254
Current liabilities:
Accounts payable					4,353
Revenues payable					21,285
Accrued liabilities					65,235
Current portion of long-term debt	[1]				1,622,904
Total current liabilities					1,713,777
Long-term debt					0
Asset retirement obligations				95,186	154,913	162,989
Deferred tax liabilities					2,280
Other long-term liabilities					2,795
Total liabilities					1,873,765
Commitments and contingencies (see Note 14)
Stockholders'/ partners' equity:
Successor warrants					0
Successor common stock					0
Successor additional paid-in capital					0
Total partners' equity				0	99,489	$ 645,492	$ 1,296,314
Total liabilities and equity					$ 1,973,254
Predecessor [Member] | Balances Prior to Reorganization and Fresh Start Adjustments [Member]
Current assets:
Cash and cash equivalents				83,050
Restricted cash				0
Accounts receivable				33,560
Short-term derivative instruments				51,329
Prepaid expenses and other current assets				10,229
Total current assets				178,168
Property and equipment, net				1,551,500
Long-term derivative instruments				33,800
Restricted investments				156,443
Other long-term assets				1,929
Total assets				1,921,840
Current liabilities:
Accounts payable				1,501
Revenues payable				22,747
Accrued liabilities				36,954
Current portion of long-term debt				454,799
Total current liabilities				516,001
Liabilities subject to compromise				1,162,437
Long-term debt				0
Asset retirement obligations				158,114
Deferred tax liabilities				2,206
Other long-term liabilities				2,481
Total liabilities				1,841,239
Commitments and contingencies (see Note 14)				0
Stockholders'/ partners' equity:
Predecessor common units				80,601
Successor warrants				0
Successor common stock				0
Successor additional paid-in capital				0
Total partners' equity				80,601
Total liabilities and equity				1,921,840
Predecessor [Member] | Reorganization Adjustments [Member]
Current liabilities:
Liabilities subject to compromise				$ 1,162,437
[1]	Due to an existing and anticipated financial covenant violations, the Predecessor’s revolving credit facility and senior notes were classified as current at December 31, 2016. There were no existing or anticipated financial covenant violations as of December 31, 2017.

Fresh Start Accounting - Summar

Fresh Start Accounting - Summary of Changes in Cash and Cash Equivalents (Details) - USD ($) $ in Thousands		May 04, 2017	Dec. 31, 2017
Payment to holders of the Notes			$ (8,193)
Net change in cash and cash equivalents			$ (13,748)
Reorganization Adjustments [Member]
Payment on the Predecessor's revolving credit facility		$ (24,799)
Payment to holders of the Notes	[1]	(16,446)
Payment of fees related to Credit Facility		(8,575)
Funding of the professional fees escrow account		(7,411)
Payment of professional fees		(4,295)
Other		(1,384)
Net change in cash and cash equivalents		$ (62,910)
[1]	The total cash settlement to the holders of the Notes was approximately $24.6 million, of which $16.4 million was paid upon emergence and $8.2 million was paid post-emergence and is reflected in accrued liabilities in the above condensed consolidated balance sheet.

Fresh Start Accounting - Summ49

Fresh Start Accounting - Summary of Changes in Cash and Cash Equivalents (Parenthetical) (Details) - USD ($) $ in Thousands		May 04, 2017	Dec. 31, 2017
Total cash settlement to the holders of the notes			$ 8,193
Reorganization Adjustments [Member]
Total cash settlement to the holders of the notes	[1]	$ 16,446
Reorganization Adjustments [Member] | Paid Upon Emergence [Member]
Total cash settlement to the holders of the notes		16,400
Reorganization Adjustments [Member] | Paid Post-emergence [Member] | Accrued Liabilities [Member]
Total cash settlement to the holders of the notes		8,200
Reorganization Adjustments [Member] | Notes [Member]
Total cash settlement to the holders of the notes		$ 24,600
[1]	The total cash settlement to the holders of the Notes was approximately $24.6 million, of which $16.4 million was paid upon emergence and $8.2 million was paid post-emergence and is reflected in accrued liabilities in the above condensed consolidated balance sheet.

Fresh Start Accounting - Summ50

Fresh Start Accounting - Summary of Net Increase in Accrued liabilities (Details) - Reorganization Adjustments [Member] $ in Thousands	May 04, 2017USD ($)
Net Increase in Accrued Liabilities [Abstract]
Recognition of liability for settlement with holders of the Notes	$ 8,193
Payment of professional fees	(4,295)
Recognition of contribution from management	(1,500)
Recognition of settlement with Predecessor common unitholders	1,250
Other	(709)
Net increase in accrued liabilities due to reorganization items	$ 2,939

Fresh Start Accounting - Schedu

Fresh Start Accounting - Schedule of Settlement of Liabilities Subject to Compromise and Resulting Net Gain (Detail) - USD ($) $ in Thousands	May 04, 2017	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fresh Start Adjustment [Line Items]
Total liabilities subject to compromise of Predecessor	$ 0	$ 0
Payment to holders of the Notes			$ (8,193)
Gain on settlement of liabilities subject to compromise			$ 0
Predecessor [Member]
Fresh Start Adjustment [Line Items]
Payment to holders of the Notes		(16,446)		$ 0	$ 0
Gain on settlement of liabilities subject to compromise		758,764
Reorganization Adjustments [Member]
Fresh Start Adjustment [Line Items]
Total liabilities subject to compromise of Predecessor	(1,162,437)	(1,162,437)
Recognition of payables for general unsecured claims	(1,389)
Payment to holders of the Notes	(24,639)
Issuance of common stock to holders of the Notes	(377,645)
Gain on settlement of liabilities subject to compromise	758,764
Reorganization Adjustments [Member] | Predecessor [Member]
Fresh Start Adjustment [Line Items]
Accounts payable	1,389	1,389
Accrued interest payable	49,796	49,796
Debt	1,111,252	1,111,252
Total liabilities subject to compromise of Predecessor	$ 1,162,437	$ 1,162,437

Fresh Start Accounting - Sche52

Fresh Start Accounting - Schedule of Net Increase in Stockholders'/Partners' Equity (Detail) - USD ($) $ in Thousands	May 04, 2017	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016
Fresh Start Adjustment [Line Items]
Recognition on gain on settlement of liabilities subject to compromise			$ 0
Par value of common stock		$ (377,645)
Successor common stock	$ 3	3	$ 3
Predecessor [Member]
Fresh Start Adjustment [Line Items]
Recognition on gain on settlement of liabilities subject to compromise		758,764
Contribution from management		1,500
Recognition of settlement with Predecessor common unitholders		1,250
Successor common stock				$ 0
Reorganization Adjustments [Member]
Fresh Start Adjustment [Line Items]
Issuance of common stock	377,645
Recognition on gain on settlement of liabilities subject to compromise	758,764
Contribution from management	1,500
Par value of common stock	(3)
Change in Successor additional paid-in capital	1,212,469	1,212,469
Successor common stock	3	3
Net increase in capital accounts	1,136,659
Reorganization Adjustments [Member] | Predecessor [Member]
Fresh Start Adjustment [Line Items]
Issuance of common stock	7,707
Cancellation of the Predecessor's units issued and outstanding	80,601
Recognition of issuance of common stock to Predecessor common unitholders	(7,707)
Recognition of issuance of warrants to Predecessor common unitholders	(4,788)
Recognition of settlement with Predecessor common unitholders	(1,250)
Issuance of warrants to Predecessor common unitholders	4,788
Predecessor units issued and outstanding	$ (80,601)	$ (80,601)

Fresh Start Accounting - Sche53

Fresh Start Accounting - Schedule of Fresh Start Adjustments to Property and Equipment, Net (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	May 04, 2017	Dec. 31, 2016
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	$ 603,053	$ 657,336
Support equipment and facilities	100,225
Other	6,133	6,007
Accumulated depreciation, depletion and impairment	(35,979)	0
Property and equipment, net	$ 673,432	657,336
Support Equipment and Facilities [Member]
Property and equipment, at cost:
Support equipment and facilities		97,580
Fresh Start Adjustments [Member]
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		(2,681,684)
Other		(9,413)
Accumulated depreciation, depletion and impairment		1,787,520
Property and equipment, net		(894,164)
Fresh Start Adjustments [Member] | Support Equipment and Facilities [Member]
Property and equipment, at cost:
Support equipment and facilities		(101,883)
Proved Oil and Natural Gas Properties [Member]
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		509,061
Proved Oil and Natural Gas Properties [Member] | Fresh Start Adjustments [Member]
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		(2,615,076)
Unproved Oil and Natural Gas Properties [Member]
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		44,688
Unproved Oil and Natural Gas Properties [Member] | Fresh Start Adjustments [Member]
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		44,688
Predecessor [Member]
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		3,339,020	$ 3,115,012
Support equipment and facilities			199,093
Other		15,420	15,344
Accumulated depreciation, depletion and impairment		(1,787,520)	(1,749,747)
Property and equipment, net		1,551,500	$ 1,579,702
Predecessor [Member] | Support Equipment and Facilities [Member]
Property and equipment, at cost:
Support equipment and facilities		199,463
Predecessor [Member] | Proved Oil and Natural Gas Properties [Member]
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		3,124,137
Predecessor [Member] | Unproved Oil and Natural Gas Properties [Member]
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		$ 0

Fresh Start Accounting - Sche54

Fresh Start Accounting - Schedule of Reorganization Items, net (Detail) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fresh Start Adjustment [Line Items]
Gain on settlement of liabilities subject to compromise		$ 0
Fresh start valuation adjustments		0
Professional fees		(724)
Other		(395)
Reorganization items, net		$ (1,119)
Predecessor [Member]
Fresh Start Adjustment [Line Items]
Gain on settlement of liabilities subject to compromise	$ 758,764
Fresh start valuation adjustments	(827,120)
Professional fees	(19,824)
Other	(594)
Reorganization items, net	$ (88,774)		$ 0	$ 0

Summary of Significant Accoun55

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary Of Significant Accounting Policies [Line Items]
Allowance for doubtful accounts		$ 1,900,000		$ 1,900,000	$ 1,900,000
Capitalized exploratory drilling costs pending evaluation				$ 0	0
Amortization expense including write-off of debt issuance costs	$ 0	2,100,000			22,100,000	$ 6,100,000
Impairment expense	0	0			183,400,000	616,800,000
Capitalized interest	$ 0	$ 400,000			$ 500,000	$ 2,100,000
Chance of tax benefit likely to be realized				greater than 50%
Federal corporate tax rate				35.00%
Tax cuts and jobs act of 2017, limitations on NOLs percentage of taxable income				80.00%
Scenario, Plan [Member]
Summary Of Significant Accounting Policies [Line Items]
Federal corporate tax rate			21.00%
Customer Concentration Risk [Member] | Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of total revenue				10.00%
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of voting shares to be received by voting share holders		50.00%		50.00%
Maximum [Member] | Other Property & Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives				7 years
Maximum [Member] | Support Equipment and Facilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives				24 years
Minimum [Member] | Other Property & Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives				3 years
Minimum [Member] | Support Equipment and Facilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives				12 years

Summary of Significant Accoun56

Summary of Significant Accounting Policies - Major Customers (Detail) - Customer Concentration Risk [Member] - Revenues [Member]	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Significant Accounting Policies [Line Items]
Total Reported Revenues			10.00%
Phillips 66 [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		23.00%
Sinclair Oil & Gas Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		19.00%
BP America Production Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		10.00%
Royal Dutch Shell plc and subsidiaries [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		0.00%
CIMA Energy [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		11.00%
Predecessor [Member] | Phillips 66 [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	19.00%			19.00%	12.00%
Predecessor [Member] | Sinclair Oil & Gas Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	20.00%			16.00%	18.00%
Predecessor [Member] | BP America Production Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	10.00%			0.00%	0.00%
Predecessor [Member] | Royal Dutch Shell plc and subsidiaries [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	0.00%			14.00%	14.00%
Predecessor [Member] | CIMA Energy [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	0.00%			0.00%	0.00%

Summary of Significant Accoun57

Summary of Significant Accounting Policies - Summary of Current Accrued Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	May 04, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Accrued Liabilities [Line Items]
Accrued lease operating expense	$ 6,439
Accrued general and administrative expense	4,412
Accrued capital expenditures	3,854
Accrued interest payable	1,309
Asset retirement obligation	713
Accrued ad valorem tax	398
Other	1,108
Accrued liabilities	$ 18,233	$ 38,180
Predecessor [Member]
Schedule Of Accrued Liabilities [Line Items]
Accrued lease operating expense			$ 10,411
Accrued general and administrative expense			3,040
Accrued capital expenditures			1,826
Accrued interest payable			46,417
Asset retirement obligation		$ 941	789	$ 1,175
Accrued ad valorem tax			977
Other			1,775
Accrued liabilities			$ 65,235

Summary of Significant Accoun58

Summary of Significant Accounting Policies - Summary of Supplemental Cash Flow (Detail) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized		$ 12,109
Cash paid for reorganization items, net		7,934
Cash paid for taxes		0
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		(1,080)
(Increase) decrease in accounts receivable related to acquisitions		0
(Increase) decrease in accounts receivable/payable related to divestitures		0
Assumptions of asset retirement obligations related to acquisitions		0
Asset retirement obligation removal related to divestitures		$ 0
Predecessor [Member]
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$ 6,598		$ 87,527	$ 107,272
Cash paid for reorganization items, net	11,999		0	0
Cash paid for taxes	0		0	472
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	3,173		(6,284)	(27,932)
(Increase) decrease in accounts receivable related to acquisitions	0		0	9,698
(Increase) decrease in accounts receivable/payable related to divestitures	0		(289)	0
Assumptions of asset retirement obligations related to acquisitions	0		0	23,754
Asset retirement obligation removal related to divestitures	$ 0		$ (19,669)	$ 0

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisition and Divestiture Related Expenses (Detail) - General and Administrative Expense [Member] - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs		$ 609
Predecessor [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs	$ 0		$ 1,451	$ 1,928

Acquisitions and Divestitures60

Acquisitions and Divestitures - Additional Information (Detail) - USD ($)	Jul. 14, 2016	Jun. 14, 2016	Nov. 03, 2015	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition And Divestiture [Line Items]
Acquisitions of oil and natural gas properties					$ 0
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
Predecessor [Member]
Business Acquisition And Divestiture [Line Items]
Acquisitions of oil and natural gas properties				$ 0		$ 0	100,730,000
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] | Predecessor [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)

Acquisitions and Divestitures61

Acquisitions and Divestitures - Summary of Fair Value of Assets Acquired and Liabilities Assumed (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	May 04, 2017	Dec. 31, 2016	Nov. 03, 2015
Business Acquisition [Line Items]
Revenues payable	$ (22,427)	$ (22,747)
Predecessor [Member]
Business Acquisition [Line Items]
Revenues payable			$ (21,285)
2015 Beta Acquisition [Member] | Predecessor [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 Divestitures62

Acquisitions and Divestitures - Supplemental Pro Forma Information (Detail) - 2015 Beta Acquisition [Member] - Predecessor [Member] $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / shares
Business Acquisition [Line Items]
Revenues	$ 381,495
Net income (loss)	$ (394,756)
Basic and diluted earnings per unit | $ / shares	$ (4.73)

Acquisitions and Divestitures63

Acquisitions and Divestitures - Schedule of Income (Loss) before Income Taxes Including (Gain) Loss on Divestiture (Detail) - Predecessor [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Permian Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Income (loss) before income taxes	$ 4,297	$ (60,875)
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Income (loss) before income taxes	$ (7,677)	$ (56,917)

Fair Value Measurements of Fi64

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value [Member] - Commodity derivatives [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	$ 38,188
Liabilities	15,112
Predecessor [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets		$ 189,851
Liabilities		17,757
Quoted Prices in Active Market (Level 1) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0
Liabilities	0
Quoted Prices in Active Market (Level 1) [Member] | Predecessor [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets		0
Liabilities		0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	38,188
Liabilities	15,112
Significant Other Observable Inputs (Level 2) [Member] | Predecessor [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets		189,851
Liabilities		17,757
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0
Liabilities	$ 0
Significant Unobservable Inputs (Level 3) [Member] | Predecessor [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets		0
Liabilities		$ 0

Fair Value Measurements of Fi65

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($)	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	$ 0	$ 0	$ 183,400,000	$ 616,800,000
Predecessor [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	$ 0		183,437,000	616,784,000
East Texas [Member] | Predecessor [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties			183,400,000
Carrying value of properties after impairment charges			$ 156,200,000
East Texas, Wyoming and Colorado [Member] | Predecessor [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties				616,800,000
Carrying value of properties after impairment charges				$ 408,600,000

Risk Management and Derivativ66

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	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments Gain Loss [Line Items]
Counterparty exposure				$ 0
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk				$ 26.5
Cash settlement receipt			$ 39.3
Commodity derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Cash settlement receipt	$ 94.1	$ 191.4
Interest Rate Swaps [Member]
Derivative Instruments Gain Loss [Line Items]
Cash settlements paid on terminated interest rate derivative					$ 2.1

Risk Management and Derivativ67

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	12 Months Ended
	Dec. 31, 2017MMBTU$ / MMBTU$ / bblbbl
Natural Gas Derivative Contracts Fixed Price Swap 2018 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	1,102,000
Weighted-average fixed price | $ / MMBTU	3.91
Crude Oil Derivative Contracts Fixed Price Swap 2018 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	152,000
Weighted-average fixed price | $ / bbl	71.31
NGL Derivative Contracts Fixed Price Swap 2018 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	65,700
Weighted-average fixed price | $ / bbl	24.13
Natural Gas Derivative Contracts Fixed Price Swap 2019 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	300,000
Weighted-average fixed price | $ / MMBTU	2.91
Crude Oil Derivative Contracts Fixed Price Swap 2019 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	110,000
Weighted-average fixed price | $ / bbl	51.34
NGL Derivative Contracts Fixed Price Swap Contracts 2019 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	0
Weighted-average fixed price | $ / bbl	0

Risk Management and Derivativ68

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	May 04, 2017	Dec. 31, 2016
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 28,546	$ 51,329
Asset Derivatives, Net recorded fair value	0	$ 33,800
Liability Derivatives, Net recorded fair value	5,470
Predecessor [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value			$ 69,464
Asset Derivatives, Net recorded fair value			102,630
Liability Derivatives, Net recorded fair value			0
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	37,729
Asset Derivatives, Netting arrangements	(9,183)
Asset Derivatives, Net recorded fair value	28,546
Liability Derivatives, Gross fair value	9,183
Liability Derivatives, Netting arrangements	(9,183)
Liability Derivatives, Net recorded fair value	0
Short-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	37,729
Liability Derivatives, Gross fair value	9,183
Short-Term Derivative Instruments [Member] | Predecessor [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value			86,335
Asset Derivatives, Netting arrangements			(16,871)
Asset Derivatives, Net recorded fair value			69,464
Liability Derivatives, Gross fair value			16,871
Liability Derivatives, Netting arrangements			(16,871)
Liability Derivatives, Net recorded fair value			0
Short-Term Derivative Instruments [Member] | Predecessor [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value			86,335
Liability Derivatives, Gross fair value			16,871
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	459
Asset Derivatives, Netting arrangements	(459)
Asset Derivatives, Net recorded fair value	0
Liability Derivatives, Gross fair value	5,929
Liability Derivatives, Netting arrangements	(459)
Liability Derivatives, Net recorded fair value	5,470
Long-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	459
Liability Derivatives, Gross fair value	$ 5,929
Long-Term Derivative Instruments [Member] | Predecessor [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value			103,515
Asset Derivatives, Netting arrangements			(885)
Asset Derivatives, Net recorded fair value			102,630
Liability Derivatives, Gross fair value			885
Liability Derivatives, Netting arrangements			(885)
Liability Derivatives, Net recorded fair value			0
Long-Term Derivative Instruments [Member] | Predecessor [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value			103,515
Liability Derivatives, Gross fair value			$ 885

Risk Management and Derivativ69

Risk Management and Derivative Instruments - Unrealized and Realized Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments		$ 31,609
Interest expense, net		(15,936)
Predecessor [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	$ (23,076)		$ 117,105	$ (462,890)
Interest expense, net	(10,243)		(146,031)	(115,154)
Commodity derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments		31,609
Commodity derivatives [Member] | Predecessor [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	(23,076)		117,105	(462,890)
Interest rate derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net		$ 0
Interest rate derivatives [Member] | Predecessor [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net	$ 0		$ 1,290	$ 4,674

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands		4 Months Ended	8 Months Ended	12 Months Ended
		May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations [Line Items]
Asset retirement obligations at beginning of period			$ 96,127
Liabilities added from acquisition or drilling			191
Liabilities removed upon sale of wells			0
Liabilities settled			(633)
Accretion expense			4,384
Revision of estimates			104
Asset retirement obligation at end of period		$ 96,127	100,173
Fresh start adjustment	[1]		0
Asset retirement obligation			713
Asset retirement obligations - long-term portion		95,186	99,460
Predecessor [Member]
Asset Retirement Obligations [Line Items]
Asset retirement obligations at beginning of period		155,702	$ 159,055	$ 164,164	$ 112,702
Liabilities added from acquisition or drilling		6		30	26,876
Liabilities removed upon sale of wells		0		(19,669)	(3,412)
Liabilities settled		(164)		(1,442)	(1,430)
Accretion expense		3,407		10,231	7,125
Revision of estimates		104		2,388	22,303
Asset retirement obligation at end of period		159,055		155,702	164,164
Fresh start adjustment	[1]	(62,928)		0	0
Asset retirement obligation		941		789	1,175
Asset retirement obligations - long-term portion		$ 95,186		$ 154,913	$ 162,989
[1]	As a result of the application of fresh start accounting, the Successor recorded its asset retirement obligation at fair value as of the Effective date.

Restricted Investments - Restri

Restricted Investments - Restricted Investment Balances (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	May 04, 2017	Dec. 31, 2016
Schedule Of Investments [Line Items]
Restricted investments	$ 156,938	$ 156,443
Predecessor [Member]
Schedule Of Investments [Line Items]
Restricted investments			$ 156,234
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	152,272
BOEM platform abandonment [Member] | Predecessor [Member]
Schedule Of Investments [Line Items]
Restricted investments			152,000
Surety bond cash collateral [Member]
Schedule Of Investments [Line Items]
Restricted investments	501
Surety bond cash collateral [Member] | Predecessor [Member]
Schedule Of Investments [Line Items]
Restricted investments			500
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	4,058
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member] | Predecessor [Member]
Schedule Of Investments [Line Items]
Restricted investments			3,627
SPBPC Collateral Port of Long Beach pipeline license [Member]
Schedule Of Investments [Line Items]
Restricted investments	$ 107
SPBPC Collateral Port of Long Beach pipeline license [Member] | Predecessor [Member]
Schedule Of Investments [Line Items]
Restricted investments			$ 107

Debt - Consolidated Debt Obliga

Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Dec. 31, 2017		May 04, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Total debt		$ 376,000
Less: current portion of long-term debt		0	[1]	$ 0
Long-term debt		376,000		$ 430,000
Predecessor [Member]
Debt Instrument [Line Items]
Total debt					$ 1,622,904
Less: current portion of long-term debt	[1]				(1,622,904)
Long-term debt					0
Successor $1.0 billion Credit Facility, variable-rate, due March 2021
Debt Instrument [Line Items]
Aggregate principal outstanding	[2]	$ 376,000
Predecessor $2.0 billion revolving credit facility, variable-rate, due March 2018 [Member] | Predecessor [Member]
Debt Instrument [Line Items]
Aggregate principal outstanding	[2]				511,652
2021 Senior Notes, fixed-rate, due May 2021 [Member] | Predecessor [Member]
Debt Instrument [Line Items]
Senior Notes, fixed-rate	[3],[4]				646,287
2022 Senior Notes, fixed-rate, due August 2022 [Member] | Predecessor [Member]
Debt Instrument [Line Items]
Senior Notes, fixed-rate	[3],[5]				$ 464,965
[1]	Due to an existing and anticipated financial covenant violations, the Predecessor’s revolving credit facility and senior notes were classified as current at December 31, 2016. There were no existing or anticipated financial covenant violations as of December 31, 2017.
[2]	The carrying amount of our Predecessor’s revolving credit facility and Successor Credit Facility approximates fair value because the interest rates are variable and reflective of market rates.
[3]	The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy
[4]	The estimated fair value of our 2021 Senior Notes was $314.3 million at December 31, 2016.
[5]	The estimated fair value of our 2022 Senior Notes was $223.2 million at December 31, 2016.

Debt - Consolidated Debt Obli73

Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Successor $1.0 billion Credit Facility, variable-rate, due March 2021
Debt Instrument [Line Items]
Revolving credit facility	$ 1,000,000,000
Maturity date	Mar. 19, 2021
Predecessor $2.0 billion revolving credit facility, variable-rate, due March 2018 [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 2,000,000,000
Maturity date	Mar. 19, 2018
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
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

Debt - Credit Facility - Additi

Debt - Credit Facility - Additional Information (Detail) - USD ($)	Nov. 30, 2017	May 04, 2017	Dec. 31, 2017	Nov. 29, 2017
Line of Credit Facility [Line Items]
Repayment of predecessor’s revolving credit facility			$ 63,000,000
Letters of credit outstanding			2,400,000
Predecessor $2.0 billion revolving credit facility, variable-rate, due March 2018 [Member]
Line of Credit Facility [Line Items]
Revolving credit facility, maximum borrowing capacity			2,000,000,000
Repayment of predecessor’s revolving credit facility		$ 24,800,000
Credit Facility [Member] | Amplify Energy Operating LLC
Line of Credit Facility [Line Items]
Aggregate principal outstanding		430,000,000
Borrowing base	$ 450,000,000	490,000,000	$ 447,500,000	$ 475,000,000
Amortization of deferred charges	2,500,000	$ 2,500,000
Maturity date		Mar. 19, 2021
Percentage of revolving unused commitment fee		0.50%
Minimum Percentage of Oil and Gas Properties mortgage as collateral security for the obligations		95.00%
Interest coverage ratio maximum		250.00%
Current ratio		100.00%
Total leverage ratio maximum		400.00%
Debt covenant, minimum aggregate amount of unrestricted cash or cash equivalents to prepay loans and cash collateralize letter of credit exposure	$ 35,000,000
Credit Facility [Member] | Amplify Energy Operating LLC | Minimum
Line of Credit Facility [Line Items]
Percentage of hedging requirement	50.00%
Credit Facility [Member] | Amplify Energy Operating LLC | Minimum | Alternative Base Rate [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage		2.00%
Credit Facility [Member] | Amplify Energy Operating LLC | Minimum | LIBOR/Eurodollar [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage		3.00%
Credit Facility [Member] | Amplify Energy Operating LLC | Maximum [Member]
Line of Credit Facility [Line Items]
Percentage of hedging requirement	75.00%
Credit Facility [Member] | Amplify Energy Operating LLC | Maximum [Member] | Alternative Base Rate [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage		3.00%
Credit Facility [Member] | Amplify Energy Operating LLC | Maximum [Member] | LIBOR/Eurodollar [Member]
Line of Credit Facility [Line Items]
Base rate borrowing percentage		4.00%

Debt - Summary of Weighted-Aver

Debt - Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations (Detail)	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Successor Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates		5.08%
Predecessor's Revolving Credit Facility [Member] | Predecessor [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates	4.18%		3.28%	2.12%

Debt - Senior Notes - Additiona

Debt - Senior Notes - Additional Information (Detail) - USD ($) $ in Thousands	May 04, 2017	May 04, 2017	May 04, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jul. 17, 2014	Oct. 10, 2013	May 23, 2013	Apr. 17, 2013
Debt Instrument [Line Items]
Repurchase of senior notes				$ 0
Gain on extinguishment of debt				$ 0
Noteholder Plan Support Agreement [Member]
Debt Instrument [Line Items]
Unsecured noteholders to receive pro rata share of cash distribution	$ 24,600
Predecessor [Member]
Debt Instrument [Line Items]
Repurchase of senior notes		$ 0				$ 41,261	$ 2,914
Gain on extinguishment of debt		$ 0				42,337	422
Senior Notes [Member]
Debt Instrument [Line Items]
Unrecorded contractual interest			$ 24,200
2021 Senior Notes [Member]
Debt Instrument [Line Items]
Senior notes				7.625%	7.625%
Maturity date					May 1, 2021
2021 Senior Notes [Member] | Predecessor [Member]
Debt Instrument [Line Items]
Repurchase of debt						53,700
Repurchase of senior notes						26,400
Gain on extinguishment of debt						27,500
2021 Senior Notes [Member] | Private Placement of Debt [Member]
Debt Instrument [Line Items]
Face amount of senior notes at time of issuance									$ 300,000	$ 100,000	$ 300,000
2022 Senior Notes [Member]
Debt Instrument [Line Items]
Maturity date					Aug. 1, 2022
2022 Senior Notes [Member] | Predecessor [Member]
Debt Instrument [Line Items]
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] | Private Placement of Debt [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%

Debt - Unamortized Deferred Fin

Debt - Unamortized Deferred Financing Costs - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017
Predecessor's Revolving Credit Facility [Member]
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
Successor Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs		$ 7.1

Equity (Deficit)- Additional In

Equity (Deficit)- Additional Information (Detail)	May 04, 2017USD ($)$ / sharesshares	Apr. 27, 2016USD ($)	Feb. 13, 2015shares	May 04, 2017USD ($)$ / shares$ / Partnershipshares	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares	Jun. 01, 2016	May 31, 2016	May 25, 2016USD ($)	Dec. 31, 2014USD ($)
Equity and Distributions [Line Items]
Percentage of new common shares issued to predecessor	2.00%			2.00%
Aggregate cash amount to predecessor	$ 1,300,000
Common stock, shares issued | shares	25,000,000			25,000,000	25,000,000	0
Common stock, shares outstanding | shares	25,000,000			25,000,000	25,000,000
Proceeds from sale of common units, net					$ 0
Fees on sale of common unit					$ 0
MEMP GP [Member]
Equity and Distributions [Line Items]
Acquisition purchase price		$ 800,000
Partnership ownership percentage		0.10%
Gain (loss) on acquisition		$ 0
Natural Gas Partners [Member] | Incentive Distribution Rights ("IDRs") [Member]
Equity and Distributions [Line Items]
Agreed ownership interest percentage to acquire		50.00%
Predecessor [Member]
Equity and Distributions [Line Items]
Proceeds from sale of common units, net				$ 0		$ 2,385,000	$ 0
Fees on sale of common unit				$ 0		536,000	0
Common units amount repurchased under repurchase program							52,813,000
Minimum Quarterly Distribution amount per common unit | $ / Partnership				0.4750
Predecessor [Member] | MEMP Repurchase Program [Member]
Equity and Distributions [Line Items]
Stock repurchase program, authorized amount											$ 150,000,000
Common units amount repurchased under repurchase program							$ 52,800,000
Common units repurchased under repurchase program | shares							3,547,921
Predecessor [Member] | ATM Program [Member]
Equity and Distributions [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
Predecessor [Member] | MEMP GP [Member]
Equity and Distributions [Line Items]
Acquisition purchase price		$ 800,000
Gain (loss) on acquisition		$ 0
Predecessor [Member] | Incentive Distribution Rights ("IDRs") [Member] | MEMP GP [Member]
Equity and Distributions [Line Items]
Partnership ownership percentage		50.00%
Predecessor [Member] | Memorial Resource [Member] | MEMP GP [Member]
Equity and Distributions [Line Items]
Partnership ownership percentage									100.00%
Predecessor [Member] | MEMP GP [Member] | Incentive Distribution Rights ("IDRs") [Member]
Equity and Distributions [Line Items]
Percentage of economic interest in incentive distribution rights									50.00%
Predecessor [Member] | The Funds [Member] | Incentive Distribution Rights ("IDRs") [Member]
Equity and Distributions [Line Items]
Percentage of economic interest in incentive distribution rights									50.00%
Predecessor [Member] | Natural Gas Partners [Member] | Incentive Distribution Rights ("IDRs") [Member]
Equity and Distributions [Line Items]
Agreed ownership interest percentage to acquire		50.00%						50.00%
Predecessor [Member] | General Partner and Affiliates [Member] | MEMP GP [Member]
Equity and Distributions [Line Items]
Partnership ownership percentage		0.10%
Predecessor [Member] | Subordinated Units [Member]
Equity and Distributions [Line Items]
Subordinated units converted to common units | shares							(5,360,912)
Common unit, issued | shares						0
Common units repurchased under repurchase program | shares							0
Predecessor [Member] | Subordinated Units [Member] | MRD Holdco [Member]
Equity and Distributions [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.
Predecessor [Member] | Limited Partners Common Units [Member]
Equity and Distributions [Line Items]
Subordinated units converted to common units | shares							5,360,912
Common unit, issued | shares						1,178,102
Common units amount repurchased under repurchase program							$ 52,813,000
Common units repurchased under repurchase program | shares							3,547,921
Common Stock [Member]
Equity and Distributions [Line Items]
Stock issued during period | shares	25,000,000				0
Common stock, shares outstanding | shares	25,000,000			25,000,000	25,000,000
Warrants [Member]
Equity and Distributions [Line Items]
Warrant issued during period | shares	2,173,913			2,173,913
Warrant life period	5 years
Percentage of common shares to be issued upon exercise of warrants	8.00%			8.00%
Warrant exercise price | $ / shares	$ 42.60			$ 42.60

Equity (Deficit) - Summary of C

Equity (Deficit) - Summary of Changes in Number of Outstanding Common Units and Shares of Common Stock (Detail) - shares		May 04, 2017	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary of Changes in Number of Outstanding Units/Shares [Line Item]
Beginning balance				25,000,000
Ending balance		25,000,000	25,000,000	25,000,000
Common Shares [Member]
Summary of Changes in Number of Outstanding Units/Shares [Line Item]
Beginning balance				25,000,000
Stock issued during period		25,000,000		0
Ending balance		25,000,000	25,000,000	25,000,000
Limited Partners Common Units [Member] | Predecessor [Member]
Summary of Changes in Number of Outstanding Units/Shares [Line Item]
Beginning balance			83,827,920	0	82,906,400	80,421,992
Common units issued					1,178,102
Restricted common units issued			0		50,000	827,704
Restricted common units/shares forfeited			(12,952)		(27,537)	(69,059)
Restricted common units/shares repurchased	[1]		(14,681)		(279,045)	(87,228)
Common units repurchased under repurchase program						(3,547,921)
Subordinated units converted to common units						5,360,912
Cancellation of general partner units					0
Ending balance before cancellation		83,800,287	83,800,287
Cancellation of Predecessor common units			(83,800,287)
Ending balance		0	0	0	83,827,920	82,906,400
Subordinated Units [Member] | Predecessor [Member]
Summary of Changes in Number of Outstanding Units/Shares [Line Item]
Beginning balance			0	0	0	5,360,912
Common units issued					0
Restricted common units issued			0		0	0
Restricted common units/shares forfeited			0		0	0
Restricted common units/shares repurchased	[1]		0		0	0
Common units repurchased under repurchase program						0
Subordinated units converted to common units						(5,360,912)
Cancellation of general partner units					0
Ending balance before cancellation		0	0
Cancellation of Predecessor common units			0
Ending balance		0	0		0	0
General Partner [Member] | Predecessor [Member]
Summary of Changes in Number of Outstanding Units/Shares [Line Item]
Beginning balance			0	0	86,797	86,797
Common units issued					0
Restricted common units issued			0		0	0
Restricted common units/shares forfeited			0		0	0
Restricted common units/shares repurchased	[1]		0		0	0
Common units repurchased under repurchase program						0
Subordinated units converted to common units						0
Cancellation of general partner units					(86,797)
Cancellation of Predecessor common units			0
Ending balance		0	0		0	86,797
[1]	Restricted common units are generally net-settled by our Predecessor unitholders to cover the required withholding tax upon vesting. The Predecessor 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 less than approximately $0.1 million for the period from January 1, 2017 through May 4, 2017 and were $0.6 million and $1.3 million for the years ended December 31, 2016 and 2015, respectively. These net-settlements had the effect of unit repurchases by the Company 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 Company.

Equity (Deficit) - Summary of80

Equity (Deficit) - Summary of Changes in Number of Outstanding Common Units and Shares of Common Stock (Parenthetical) (Detail) - Limited Partners Common Units [Member] - Predecessor [Member] - USD ($) $ in Millions	4 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary of Changes in Number of Outstanding Units/Shares [Line Item]
Withholding tax withheld and paid related to vesting of restricted common units		$ 0.6	$ 1.3
Maximum [Member]
Summary of Changes in Number of Outstanding Units/Shares [Line Item]
Withholding tax withheld and paid related to vesting of restricted common units	$ 0.1

Equity (Deficit) - Summary of A

Equity (Deficit) - Summary of Assumptions used to Estimate the Fair Value (Detail) - Warrants [Member]	May 04, 2017$ / shares
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk-free interest rate	2.06%
Dividend yield	0.00%
Expected life (in years)	5 years
Expected volatility	50.00%
Strike Price	$ 42.60
Calculated fair value	$ 2.20

Equity (Deficit) - Summary of Q

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

Equity (Deficit) - Summary of P

Equity (Deficit) - Summary of Previous Owners' Equity Transactions Related to Property Swap (Detail) - USD ($) $ in Thousands

1 Months Ended

2 Months Ended

3 Months Ended

4 Months Ended

8 Months Ended

12 Months Ended

May 04, 2017

Jun. 30, 2017

Dec. 31, 2017

Sep. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

May 04, 2017

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Equity Structure And Transactions [Line Items]

Net income (loss)

$ (906)

$ 9,728

$ (7,536)

$ 1,286

Predecessor [Member]

Equity Structure And Transactions [Line Items]

Net income (loss)

$ (74,578)

$ (16,377)

$ (321,885)

$ (32,866)

$ (147,550)

$ (38,097)

$ (90,955)

$ (540,398)

$ (395,491)

Contributions

4,877

Deferred tax liability retained by previous owner

28,020

Previous Owners [Member] | Predecessor [Member]

Equity Structure And Transactions [Line Items]

Balance

$ 0

$ 0

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

$ 0

Earnings Per Share_Unit - Calcu

Earnings Per Share/Unit - Calculation of Earnings (Loss) Per Share/Unit (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended							4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Jun. 30, 2017	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share/Unit [Line Items]
Net income (loss) attributable to Successor/Predecessor		$ (906)	$ 9,728	$ (7,536)							$ 1,286
Less: Previous owners interest in net income (loss)											0
Less: Predecessor's general partner's 0.1% interest in net income (loss)											0
Less: Predecessor's IDRs attributable to corresponding period											0
Less: Net income (loss) allocated to participating restricted stockholders											35
Basic and diluted earnings available to common stockholders/limited partners											$ 1,251
Common shares/units:
Common shares/units outstanding — basic											25,000
Dilutive effect of potential common shares											0
Common shares/units outstanding — diluted											25,000
Net earnings per share/unit:
Basic											$ 0.05
Diluted											$ 0.05
Antidilutive stock options or warrants												3,325,318
Subordinated Units [Member]
Common shares/units:
Subordinated units											0
Stock Options [Member]
Net earnings per share/unit:
Antidilutive stock options or warrants											517
Warrants [Member]
Net earnings per share/unit:
Antidilutive stock options or warrants											2,174
Predecessor [Member]
Earnings Per Share/Unit [Line Items]
Net income (loss) attributable to Successor/Predecessor	$ (74,578)				$ (16,377)	$ (321,885)	$ (32,866)	$ (147,550)	$ (38,097)	$ (90,955)		$ (540,398)	$ (395,877)
Less: Previous owners interest in net income (loss)										0		0	(2,268)
Less: Predecessor's general partner's 0.1% interest in net income (loss)										0		(168)	(412)
Less: Predecessor's IDRs attributable to corresponding period										0		0	112
Less: Net income (loss) allocated to participating restricted stockholders										0		0	0
Basic and diluted earnings available to common stockholders/limited partners										$ (90,955)		$ (540,230)	$ (393,309)
Common shares/units:
Common shares/units outstanding — basic										83,807		83,351	82,897
Dilutive effect of potential common shares										0		0	0
Common shares/units outstanding — diluted										83,807		83,351	83,528
Net earnings per share/unit:
Basic										$ (1.09)		$ (6.48)	$ (4.71)
Diluted										$ (1.09)		$ (6.48)	$ (4.71)
Predecessor [Member] | Subordinated Units [Member]
Common shares/units:
Subordinated units										0		0	631
Predecessor [Member] | Stock Options [Member]
Net earnings per share/unit:
Antidilutive stock options or warrants										0		0	0
Predecessor [Member] | Warrants [Member]
Net earnings per share/unit:
Antidilutive stock options or warrants										0		0	0

Earnings Per Share_Unit - Cal85

Earnings Per Share/Unit - Calculation of Earnings (Loss) Per Share/Unit (Parenthetical) (Detail) - shares shares in Thousands	5 Months Ended	12 Months Ended
	May 31, 2016	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share/Unit [Line Items]
Phantom units excluded from computation of diluted earnings per unit		3,325,318
Predecessor [Member]
Earnings Per Share/Unit [Line Items]
General partner's interest in net income, percentage		0.10%	0.10%
Average [Member] | Predecessor [Member]
Earnings Per Share/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)	Jul. 01, 2017shares	May 01, 2017USD ($)	Jun. 01, 2016USD ($)	Mar. 09, 2016USD ($)	Jun. 30, 2016	May 04, 2017USD ($)shares	Dec. 31, 2017USD ($)shares	Dec. 31, 2017USD ($)Installmentshares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Jun. 30, 2017shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of vesting annually equal installments | Installment								3
Vesting date description								Emergence Awards will generally vest annually in three equal installments on each of the first three anniversaries of the Effective Date, subject to the grantee’s continued employment through each such vesting date.
Share/unit-based compensation (see Note 13)							$ 2,516,000
Phantom Units [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Phantom units settled in cash							100,000
Restricted Stock Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost							$ 7,300,000	$ 7,300,000
Weighted-average period of unrecognized compensation cost								2 years 4 months 20 days
Restricted Stock Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Weighted-average period of unrecognized compensation cost								2 years 4 months 2 days
Number of restricted stock options granted | shares	0						1,876
Unrecognized compensation cost							$ 2,000,000	$ 2,000,000
Predecessor [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share/unit-based compensation (see Note 13)						$ 3,667,000			$ 7,350,000	$ 10,809,000
Reversed share based compensation				$ 500,000
Fair value of compensation cost recognized on the date of plan modification				$ 300,000
Predecessor [Member] | MEMP GP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Reversed share based compensation			$ 100,000
Fair value of compensation cost recognized on the date of plan modification			$ 500,000
Non-Employee Directors [Member] | Predecessor [Member] | Phantom Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period date								2016-01
Non-Employee Directors [Member] | Predecessor [Member] | First Anniversary Of Grant Date [Member] | Phantom Units [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Phantom units settled in cash									100,000
Certain Employee [Member] | Predecessor [Member] | First Anniversary Of Grant Date [Member] | Phantom Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage from the date of grant					33.33%
Certain Employee [Member] | Predecessor [Member] | Second Anniversary Of Grant Date [Member] | Phantom Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage from the date of grant					33.33%
Certain Employee [Member] | Predecessor [Member] | Third Anniversary Of Grant Date [Member] | Phantom Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage from the date of grant					33.33%
Management Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate shares of common stock reserved for issuance | shares						2,322,404
2017 Non-Employee Directors Compensation Plan [Member] | Restricted Stock Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate shares of common stock reserved for issuance | shares											200,000
Number of vesting annually equal installments | Installment								3
Vesting date description								Awards granted will generally vest annually in three equal installments on each of the first three anniversaries of the grant date, subject to the grantee’s continued employment through each such vesting date.
Weighted-average period of unrecognized compensation cost								2 years 5 months 12 days
Unrecognized compensation cost							$ 200,000	$ 200,000
Long Term Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of common units for awards authorized | shares							2,142,221	2,142,221
Share/unit-based compensation (see Note 13)		$ 2,300,000
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									$ 100,000	$ 12,300,000

Equity-based Awards - Summary o

Equity-based Awards - Summary of Information Regarding Restricted Stock Unit Awards (Detail) - Restricted Stock Units [Member]	8 Months Ended
	Dec. 31, 2017$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance | shares	614,754
Granted, Number of Units | shares	173,070
Forfeited, Number of Units | shares	(105,032)
Vested, Number of Units | shares	0
Outstanding, Number of Units, Ending Balance | shares	682,792
Outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance | $ / shares	$ 13.77
Granted, Weighted-Average Grant Date Fair Value per Unit | $ / shares	12.87
Forfeited, Weighted-Average Grant Date Fair Value per Unit | $ / shares	13.77
Vested, Weighted-Average Grant Date Fair Value per Unit | $ / shares	0
Outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance | $ / shares	$ 13.54

Equity-based Awards - Summary88

Equity-based Awards - Summary of Information Regarding Restricted Stock Unit Awards (Parenthetical) (Detail) - Restricted Stock Units [Member] $ / shares in Units, $ in Millions	Dec. 31, 2017USD ($)$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted stock units issued | $	$ 2.2
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	$ 10
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price	$ 13.77

Equity-based Awards - Summary89

Equity-based Awards - Summary of Fair Value Assumptions (Detail) - Restricted Stock Options [Member]	3 Months Ended
	Jun. 30, 2017$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate	2.06%
Dividend yield	0.00%
Expected life (in years)	6 years
Expected volatility	50.00%
Strike Price	$ 21.58
Calculated fair value per stock option	$ 5.01

Equity-based Awards - Summary90

Equity-based Awards - Summary of Restricted Stock Option Awards (Detail) - Restricted Stock Options [Member] - $ / shares	Jul. 01, 2017	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Options, Beginning Balance		614,754
Granted, Number of Options	0	1,876
Forfeited, Number of Options		(99,232)
Vested, Number of Options		0
Outstanding, Number of Options, Ending Balance		517,398
Outstanding, Weighted Average Grant Date Fair Value per Option, Beginning balance		$ 5.01
Granted, Weighted-Average Grant Date Fair Value per Option		5.01
Forfeited, Weighted-Average Grant Date Fair Value per Option		5.01
Vested, Weighted-Average Grant Date Fair Value per Option		0
Outstanding, Weighted Average Grant Date Fair Value per Option, Ending balance		$ 5.01

Equity-based Awards - Summary91

Equity-based Awards - Summary of Information Regarding Restricted Stock Awards (Detail) - Restricted Stock Units [Member]	8 Months Ended
	Dec. 31, 2017$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance | shares	614,754
Granted, Number of Units | shares	173,070
Forfeited, Number of Units | shares	(105,032)
Vested, Number of Units | shares	0
Outstanding, Number of Units, Ending Balance | shares	682,792
Outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance | $ / shares	$ 13.77
Granted, Weighted-Average Grant Date Fair Value per Unit | $ / shares	12.87
Forfeited, Weighted-Average Grant Date Fair Value per Unit | $ / shares	13.77
Vested, Weighted-Average Grant Date Fair Value per Unit | $ / shares	0
Outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance | $ / shares	$ 13.54
2017 Non-Employee Directors Compensation Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance | shares	0
Granted, Number of Units | shares	16,341
Forfeited, Number of Units | shares	0
Vested, Number of Units | shares	0
Outstanding, Number of Units, Ending Balance | shares	16,341
Outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance | $ / shares	$ 0
Granted, Weighted-Average Grant Date Fair Value per Unit | $ / shares	13.77
Forfeited, Weighted-Average Grant Date Fair Value per Unit | $ / shares	0
Vested, Weighted-Average Grant Date Fair Value per Unit | $ / shares	0
Outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance | $ / shares	$ 13.77

Equity-based Awards - Summary92

Equity-based Awards - Summary of Information Regarding Restricted Stock Awards (Parenthetical) (Detail) - Restricted Stock Units [Member] $ / shares in Units, $ in Millions	Dec. 31, 2017USD ($)$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted stock units issued	$ 2.2
2017 Non-Employee Directors Compensation Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted stock units issued	$ 0.2
Grant date market price | $ / shares	$ 13.77

Equity-based Awards - Summary93

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Detail) - Restricted Common Units [Member] - Predecessor [Member] - $ / shares	4 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	432,160	1,368,538	1,093,520
Granted, Number of Units	0	50,000	827,704
Forfeited, Number of Units	(12,952)	(27,537)	(69,059)
Vested, Number of Units	(43,045)	(958,841)	(483,627)
Cancellation of Predecessor common units	(376,163)
Outstanding, Number of Units, Ending Balance	0	432,160	1,368,538
Outstanding, Weighted Average Grant Date Fair Value per unit, Beginning balance	$ 15	$ 17.61	$ 20.93
Granted, Weighted-Average Grant Date Fair Value per Unit	0	2.41	14.90
Forfeited, Weighted-Average Grant Date Fair Value per Unit	9.51	16.99	18.35
Vested, Weighted-Average Grant Date Fair Value per Unit	10.40	18.01	20.37
Cancelled, Weighted-Average Grant Date Fair Value per Unit	15.72		0
Outstanding, Weighted Average Grant Date Fair Value per unit, Ending balance	$ 0	$ 15	$ 17.61

Equity-based Awards - Summary94

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
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
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
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant date market price		$ 15.45

Equity-based Awards - Summary95

Equity-based Awards - Summary of Information Regarding Predecessor's Phantom Unit Awards (Detail) - Phantom Units [Member] - shares	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Ending Balance		0
Predecessor [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	5,980,693	5,692,745	0
Granted, Number of Units	0		6,169,018
Restricted common units/shares forfeited	(132,347)		(188,325)
Vested, Number of Units	(155,601)
Cancelled		(5,692,745)
Outstanding, Number of Units, Ending Balance	5,692,745		5,980,693

Equity-based Awards - Summary96

Equity-based Awards - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		$ 2,516
Restricted Stock Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		1,947
Restricted Stock Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		569
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		0
Phantom Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		$ 0
Predecessor [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	$ 3,667		$ 7,528	$ 10,809
Predecessor [Member] | Restricted Stock Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	0		0	0
Predecessor [Member] | Restricted Stock Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	0		0	0
Predecessor [Member] | Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	3,713		7,206	10,809
Predecessor [Member] | Phantom Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	$ (46)		$ 322	$ 0

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail)

May 04, 2017USD ($)

Jun. 01, 2016USD ($)

Nov. 02, 2015USD ($)

Jul. 01, 2015$ / bbl

Nov. 30, 2015USD ($)

May 31, 2014$ / MMBTU$ / bbl

Nov. 30, 2011MMBTU

May 04, 2017USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2017

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Apr. 27, 2016

Nov. 01, 2015USD ($)

Feb. 23, 2015USD ($)

Related Party Transaction [Line Items]

Interest sold in oil and gas properties

$ 0

General and administrative expense

29,506,000

Transition Services Agreement [Member]

Related Party Transaction [Line Items]

Transition service agreement cost

$ 0

0

$ 0

General and administrative expense

0

$ 0

1,600,000

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

Related Party Transaction [Line Items]

Maximum dedication of natural gas produced per day | 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. 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.

Base gas gathering fee per MMBtu | $ / MMBTU

0.30

Base stage of compression fee per MMBtu | $ / MMBTU

0.07

Annual inflationary escalation percentage

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

Maximum [Member]

Related Party Transaction [Line Items]

Amount of related party transaction

$ 120,000

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

Related Party Transaction [Line Items]

Drilling and completion expenses

100,000

Natural Gas Partners [Member] | Incentive Distribution Rights ("IDRs") [Member]

Related Party Transaction [Line Items]

Agreed ownership interest percentage to acquire

50.00%

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

Related Party Transaction [Line Items]

Common Control Acquisition Purchase Price

$ 78,400,000

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

Predecessor [Member]

Related Party Transaction [Line Items]

Interest sold in oil and gas properties

0

52,711,000

580,000

General and administrative expense

$ 31,606,000

$ 63,280,000

$ 56,671,000

Predecessor [Member] | 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 Predecessor’s 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, and (iii) provide that the limited partners of our Predecessor had the ability to elect the members of MEMP GP’s board of directors. On June 1, 2016, the Predecessor also acquired the remaining 50% of the IDRs of MEMP owned by an NGP affiliate.

Predecessor [Member] | 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%

Related Party Transactions - Sc

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

Related Party Transactions - 99

Related Party Transactions - Schedule of Amount of General and Administrative Costs and Expenses Recognized (Detail) - Omnibus Agreement [Member] - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
General and administrative costs and expenses under omnibus agreement		$ 0
Predecessor [Member]
Related Party Transaction [Line Items]
General and administrative costs and expenses under omnibus agreement	$ 0		$ 11,867	$ 32,281

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)	Sep. 12, 2017	Oct. 31, 2017USD ($)	May 04, 2017USD ($)	Dec. 31, 2017USD ($)$ / bbl	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Commitments and Contingencies Additional Textual [Abstract]
Remaining environmental accrued liability recorded				$ 0	$ 0
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				6,300,000
Predecessor [Member]
Commitments and Contingencies Additional Textual [Abstract]
Rent expense			$ 3,100,000		$ 10,900,000	$ 16,900,000
U S Bank Money Market [Member]
Commitments and Contingencies Additional Textual [Abstract]
Held-to-maturity investment, amortized cost				152,300,000
Minimum [Member]
Commitments and Contingencies Additional Textual [Abstract]
Minimum balance attributable to Beta Operating net working interest				152,000,000
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Commitments and Contingencies Additional Textual [Abstract]
Restricted Investment - decommissioning of offshore production facilities				$ 4,100,000
Third-Party Midstream Transaction [Member]
Commitments and Contingencies Additional Textual [Abstract]
Proceeds from divestitures		$ 17,000,000
Environmental Protection Agency [Member]
Commitments and Contingencies Additional Textual [Abstract]
Final date to close outstanding environmental related issues	Jun. 30, 2018

Commitments and Contingencie101

Commitments and Contingencies - Environmental Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies [Line Items]
Balance at beginning of period	$ 0
Charged to costs and expenses	0
Payments	0
Balance at end of period	0	$ 0
Predecessor [Member]
Commitments and Contingencies [Line Items]
Balance at beginning of period	$ 0	216	$ 2,092
Charged to costs and expenses		0	0
Payments		(216)	(1,876)
Balance at end of period		$ 0	$ 216

Commitments and Contingencie102

Commitments and Contingencies - Lease Obligations (Detail) $ in Thousands	Dec. 31, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
Total	$ 14,433
2,018	6,155
2,019	2,093
2,020	2,131
2,021	2,154
2,022	260
Thereafter	$ 1,640

Commitments and Contingencie103

Commitments and Contingencies - Purchase Commitments Under the Contracts (Detail) $ in Thousands	Dec. 31, 2017USD ($)
CO2 Minimum Purchase Commitment [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Total	$ 13,633
2,018	4,801
2,019	4,659
2,020	4,173
2,021	0
2,022	0
Thereafter	0
Midstream services [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Total	15,383
2,018	3,075
2,019	3,075
2,020	3,083
2,021	3,075
2,022	3,075
Thereafter	$ 0

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	8 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Line Items]
Federal corporate tax rate			35.00%
Tax cuts and jobs act of 2017, limitations on NOLs percentage of taxable income			80.00%
Maximum measurement period for income tax accounting implications of tax cuts and jobs act			1 year
Decrease in net deferred tax assets			$ (23,000,000)
Federal deferred tax assets due rate change	$ 22,958,000		23,000,000
Valuation Allowance	38,128,000		38,128,000
Unrecognized Tax Benefits	0		$ 0
United States [Member] | Earliest Tax Year [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforwards expiration year			2,035
United States [Member] | Latest Tax Year [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforwards expiration year			2,037
State [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforwards expiration year			2,035
Maximum [Member] | United States [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	46,800,000		$ 46,800,000
Maximum [Member] | State [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	$ 8,800,000		$ 8,800,000
Scenario, Plan [Member]
Income Tax Disclosure [Line Items]
Federal corporate tax rate		21.00%

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Detail) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current taxes:
Federal		$ 4
State		(34)
Total current income tax benefit (expense)		(30)
Deferred taxes:
Federal		1,933
State		273
Total deferred income tax benefit (expense)		2,206
Total income tax benefit (expense)		$ 2,176
Predecessor [Member]
Current taxes:
Federal	$ 0		$ 6	$ (11)
State	17		8	(48)
Total current income tax benefit (expense)	17		14	(59)
Deferred taxes:
Federal	71		8	1,193
State	3		(195)	1,041
Total deferred income tax benefit (expense)	74		(187)	2,234
Total income tax benefit (expense)	$ 91		$ (173)	$ 2,175

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Income Tax Benefit (Provision) (Detail) - USD ($) $ in Thousands		4 Months Ended	8 Months Ended	12 Months Ended
		May 04, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Expected tax benefit (expense) at federal statutory rate			$ 310
State income tax benefit (expense), net of federal benefit			240
Non-deductible expenses			(187)
Changes in valuation allowances			24,767
Remeasurement of federal deferred tax assets due rate change			(22,958)	$ (23,000)
Pass-through entities	[1]		0
Other			4
Total income tax benefit (expense)			$ 2,176
Predecessor [Member]
Income Tax Contingency [Line Items]
Expected tax benefit (expense) at federal statutory rate		$ 5,764			$ 191,870	$ 139,183
State income tax benefit (expense), net of federal benefit		30			382	645
Non-deductible expenses		0			0	0
Changes in valuation allowances		0			0	0
Remeasurement of federal deferred tax assets due rate change		0			0	0
Pass-through entities	[1]	(5,686)			(191,921)	(137,704)
Other		(17)			(504)	51
Total income tax benefit (expense)		$ 91			$ (173)	$ 2,175
[1]	MEMP, a publicly traded partnership with qualifying income, was 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, 2017	May 04, 2017	Dec. 31, 2016
Deferred income tax assets:
Property, Plant & Equipment	$ 19,423
Derivative instrument	6,251
Net operating loss carryforward	10,452
Asset retirement obligation	1,223
Other	779
Total deferred income tax assets:	38,128
Valuation allowance	(38,128)
Net deferred income tax assets	0
Deferred income tax liabilities:
Property, plant and equipment	0
Derivatives	0
Other	0
Total deferred income tax liabilities	0
Net deferred income tax liabilities	$ 0	$ 2,206
Predecessor [Member]
Deferred income tax assets:
Property, Plant & Equipment			$ 0
Derivative instrument			0
Net operating loss carryforward			9
Asset retirement obligation			875
Other			33
Total deferred income tax assets:			917
Valuation allowance			(865)
Net deferred income tax assets			52
Deferred income tax liabilities:
Property, plant and equipment			1,522
Derivatives			770
Other			40
Total deferred income tax liabilities			2,332
Net deferred income tax liabilities			$ 2,280

Quarterly Financial Informat108

Quarterly Financial Information (Unaudited) - Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended							4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Jun. 30, 2017	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule Of Quarterly Financial Information Disclosure [Line Items]
Revenues		$ 42,395	$ 87,495	$ 75,589							$ 205,479
Operating income (loss)		2,654	2,573	(6,043)							(816)
Net income (loss)		(906)	9,728	(7,536)							1,286
Net income (loss) attributable to Successor/Predecessor		(906)	9,728	(7,536)							1,286
Net income (loss) available to common stockholders/limited partners		$ (906)	$ 9,463	$ (7,536)							$ 1,251
Basic and diluted earnings per share/unit		$ (0.04)	$ 0.38	$ (0.30)							$ 0.05
Predecessor [Member]
Schedule Of Quarterly Financial Information Disclosure [Line Items]
Revenues	$ 27,821				$ 81,380	$ 81,426	$ 74,222	$ 68,066	$ 60,866	$ 109,201		$ 284,580	$ 358,147
Operating income (loss)	8,384				(421)	(267,783)	(6,336)	(156,971)	(5,449)	7,963		(436,539)	(282,977)
Net income (loss)	(74,578)				(16,377)	(321,885)	(32,866)	(147,550)	(38,097)	(90,955)		(540,398)	(395,491)
Net income (loss) attributable to Successor/Predecessor	(74,578)				(16,377)	(321,885)	(32,866)	(147,550)	(38,097)	(90,955)		(540,398)	(395,877)
Net income (loss) available to common stockholders/limited partners	$ (74,578)				$ (16,377)					$ (90,955)		$ (540,230)	$ (393,365)
Limited partners’ interest in net income (loss)						$ (321,885)	$ (32,866)	$ (147,422)	$ (38,057)
Basic and diluted earnings per share/unit	$ (0.89)				$ (0.20)	$ (3.85)	$ (0.39)	$ (1.78)	$ (0.46)	$ (1.09)		$ (6.48)	$ (4.71)

Supplemental Oil and Gas Inf109

Supplemental Oil and Gas Information (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Evaluated oil and natural gas properties	$ 603,053
Support equipment and facilities	100,225
Accumulated depletion, depreciation, and amortization	(34,429)
Total	$ 668,849
Predecessor [Member]
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Evaluated oil and natural gas properties		$ 3,115,012	$ 3,616,325
Support equipment and facilities		199,093	205,876
Accumulated depletion, depreciation, and amortization		(1,743,274)	(1,878,549)
Total		$ 1,570,831	$ 1,943,652

Supplemental Oil and Gas Inf110

Supplemental Oil and Gas Information (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Detail) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Property acquisition costs, proved		$ 0
Property acquisition costs, unproved		0
Exploration		0
Development		51,925
Total		$ 51,925
Predecessor [Member]
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Property acquisition costs, proved	$ 0		$ 0	$ 77,834
Property acquisition costs, unproved	0		0	1,887
Exploration	0		792	2,078
Development	9,573		54,310	233,241
Total	$ 9,573		$ 55,102	$ 315,040

Supplemental Oil and Gas Inf111

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Detail) - Bcfe	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Oil And Gas Reserve Information [Line Items]
Percent of discount factor to proved reserves			10.00%
Increase (reduction) in reserves	172.1	(98.9)		(351)	(415.4)
Upward price revisions in proved reserve	204.6	13.4
Downward revisions due to updated well performance data and increase in anticipated development and maintenance cost		76.7
Extensions and discoveries		7.2
Downward revisions due to updated well performance data	9.6			87.9	13
Downward price revisions in proved reserve				148.3	413
Divestiture of oil and gas properties				35.3
Multiple acquisitions					97.1
2015 Beta Acquisition [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Multiple acquisitions, Largest acquisition					58.5

Supplemental Oil and Gas Inf112

Supplemental Oil and Gas Information (Unaudited) - Schedule of Product Prices Used for Valuing the Reserves (Detail)	12 Months Ended
	Dec. 31, 2017$ / MMBTU$ / bbl	Dec. 31, 2016$ / MMBTU$ / bbl	Dec. 31, 2015$ / MMBTU$ / bbl
Oil [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	51.34	42.75	46.79
NGL [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	51.34	42.75	46.79
Natural Gas [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves | $ / MMBTU	2.98	2.48	2.58

Supplemental Oil and Gas Inf113

Supplemental Oil and Gas Information (Unaudited) - Schedule of Net Reserves (Detail)	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017MMcfebblMMcf	Dec. 31, 2017MMcfeBcfebblMMcf	Dec. 31, 2016MMcfebblMMcf	Dec. 31, 2015MMcfebblMMcf
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries | Bcfe		7.2
Oil [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of period		80,960
Extensions and discoveries		121
Production		(2,380)
Sale of minerals in place		0
Revision of previous estimates		(6,697)
Proved developed and undeveloped reserves, End of year	80,960	72,004
Proved developed reserves, Beginning of period		57,803
Proved developed reserves, End of year	57,803	50,014
Proved undeveloped reserves, Beginning of period		23,157
Proved undeveloped reserves, End of year	23,157	21,990
Oil [Member] | Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of period	65,741	80,960	90,945	100,258
Extensions and discoveries	53		297	2,319
Purchase of minerals in place				10,132
Production	(1,204)		(3,883)	(4,087)
Sale of minerals in place			(3,228)	(380)
Revision of previous estimates	16,370		(18,390)	(17,297)
Proved developed and undeveloped reserves, End of year	80,960		65,741	90,945
Proved developed reserves, Beginning of period	45,536	57,803	50,817	54,723
Proved developed reserves, End of year	57,803		45,536	50,817
Proved undeveloped reserves, Beginning of period	20,205	23,157	40,128	45,535
Proved undeveloped reserves, End of year	23,157		20,205	40,128
Natural Gas [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of period | MMcf		419,472
Extensions and discoveries | MMcf		4,900
Production | MMcf		(21,885)
Sale of minerals in place | MMcf		0
Revision of previous estimates | MMcf		4,071
Proved developed and undeveloped reserves, End of year | MMcf	419,472	406,558
Proved developed reserves, Beginning of period | MMcf		297,101
Proved developed reserves, End of year | MMcf	297,101	299,481
Proved undeveloped reserves, Beginning of period | MMcf		122,371
Proved undeveloped reserves, End of year | MMcf	122,371	107,077
Natural Gas [Member] | Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of period | MMcf	371,016	419,472	461,526	727,216
Extensions and discoveries | MMcf	45		288	8,686
Purchase of minerals in place | MMcf				34,128
Production | MMcf	(12,411)		(44,776)	(50,875)
Sale of minerals in place | MMcf			(15,227)	(13,731)
Revision of previous estimates | MMcf	60,822		(30,795)	(243,898)
Proved developed and undeveloped reserves, End of year | MMcf	419,472		371,016	461,526
Proved developed reserves, Beginning of period | MMcf	280,035	297,101	311,147	417,247
Proved developed reserves, End of year | MMcf	297,101		280,035	311,147
Proved undeveloped reserves, Beginning of period | MMcf	90,981	122,371	150,379	309,969
Proved undeveloped reserves, End of year | MMcf	122,371		90,981	150,379
NGL [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of period		30,572
Extensions and discoveries		261
Production		(1,114)
Sale of minerals in place		0
Revision of previous estimates		(4,530)
Proved developed and undeveloped reserves, End of year	30,572	25,189
Proved developed reserves, Beginning of period		21,963
Proved developed reserves, End of year	21,963	17,982
Proved undeveloped reserves, Beginning of period		8,609
Proved undeveloped reserves, End of year	8,609	7,207
NGL [Member] | Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of period	25,184	30,572	43,395	59,034
Extensions and discoveries	8		42	558
Purchase of minerals in place				367
Production	(616)		(2,283)	(2,820)
Sale of minerals in place			(123)	(758)
Revision of previous estimates	5,996		(15,847)	(12,986)
Proved developed and undeveloped reserves, End of year	30,572		25,184	43,395
Proved developed reserves, Beginning of period	18,923	21,963	30,315	37,260
Proved developed reserves, End of year	21,963		18,923	30,315
Proved undeveloped reserves, Beginning of period	6,261	8,609	13,080	21,774
Proved undeveloped reserves, End of year	8,609		6,261	13,080
Equivalent [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of period | MMcfe		1,088,660
Extensions and discoveries | MMcfe		7,195
Production | MMcfe		(42,850)
Sale of minerals in place | MMcfe		0
Revision of previous estimates | MMcfe		(63,284)
Proved developed and undeveloped reserves, End of year | MMcfe	1,088,660	989,721
Proved developed reserves, Beginning of period | MMcfe		775,693
Proved developed reserves, End of year | MMcfe	775,693	707,459
Proved undeveloped reserves, Beginning of period | MMcfe		312,967
Proved undeveloped reserves, End of year | MMcfe	312,967	282,262
Equivalent [Member] | Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of period | MMcfe	916,565	1,088,660	1,267,571	1,682,960
Extensions and discoveries | MMcfe	410		2,320	25,950
Purchase of minerals in place | MMcfe				97,122
Production | MMcfe	(23,336)		(81,773)	(92,315)
Sale of minerals in place | MMcfe			(35,328)	(20,559)
Revision of previous estimates | MMcfe	195,021		(236,225)	(425,587)
Proved developed and undeveloped reserves, End of year | MMcfe	1,088,660		916,565	1,267,571
Proved developed reserves, Beginning of period | MMcfe	666,786	775,693	797,936	969,141
Proved developed reserves, End of year | MMcfe	775,693		666,786	797,936
Proved undeveloped reserves, Beginning of period | MMcfe	249,779	312,967	469,635	713,819
Proved undeveloped reserves, End of year | MMcfe	312,967		249,779	469,635

Supplemental Oil and Gas Inf114

Supplemental Oil and Gas Information (Unaudited) -Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	May 04, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil And Gas Reserve Information [Line Items]
Future cash inflows	$ 5,149,623
Future production costs	(2,982,035)
Future development costs	(530,133)
Future income tax expense	0
Future net cash flows for estimated timing of cash flows	1,637,455
10% annual discount for estimated timing of cash flows	(869,784)
Standardized measure of discounted future net cash flows	$ 767,671	$ 691,089
Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Future cash inflows		5,246,487	$ 3,666,731	$ 5,952,935
Future production costs		(3,275,952)	(2,384,195)	(3,194,577)
Future development costs		(492,610)	(440,496)	(808,512)
Future income tax expense		0	0	0
Future net cash flows for estimated timing of cash flows		1,477,925	842,040	1,949,846
10% annual discount for estimated timing of cash flows		(786,836)	(446,199)	(1,360,292)
Standardized measure of discounted future net cash flows		$ 691,089	$ 395,841	$ 589,554	$ 2,911,987

Supplemental Oil and Gas Inf115

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	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Oil And Gas Reserve Information [Line Items]
Beginning of year		$ 691,089
Sale of oil and natural gas produced, net of production costs		(100,946)
Purchase of minerals in place		0
Sale of minerals in place		0
Extensions and discoveries		7,187
Changes in income taxes, net		0
Changes in prices and costs		161,106
Previously estimated development costs incurred		61,851
Net changes in future development costs		(31,438)
Revisions of previous quantities		(27,060)
Accretion of discount		46,072
Change in production rates and other		(40,190)
End of year	$ 691,089	767,671
Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Beginning of year	395,841	$ 691,089	$ 589,554	$ 2,911,987
Sale of oil and natural gas produced, net of production costs	(57,420)		(107,357)	(128,382)
Purchase of minerals in place	0		0	75,998
Sale of minerals in place	0		(28,277)	(45,100)
Extensions and discoveries	1,320		2,016	18,582
Changes in income taxes, net	0		0	63,180
Changes in prices and costs	306,375		(404,870)	(2,764,481)
Previously estimated development costs incurred	9,227		89,748	322,446
Net changes in future development costs	(55,333)		254,043	448,089
Revisions of previous quantities	99,591		14,414	(344,775)
Accretion of discount	13,195		58,956	297,517
Change in production rates and other	(21,707)		(72,386)	(265,507)
End of year	$ 691,089		$ 395,841	$ 589,554

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail)	Feb. 06, 2018Employee
Subsequent Event [Member]
Subsequent Event [Line Items]
Workforce reduction resulting in an involuntary termination of employees	19