Amplify Energy (AMPYW) 10-K 6 Mar 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Feb. 28, 2019	Jun. 29, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
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 Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		22,141,804
Entity Public Float			$ 190.2

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 49,704	$ 6,392
Restricted cash	325	0
Accounts receivable	29,514	36,391
Short-term derivative instruments	18,813	28,546
Prepaid expenses and other current assets	7,241	7,220
Total current assets	105,597	78,549
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	598,331	603,053
Support equipment and facilities	108,760	100,225
Other	6,625	6,133
Accumulated depreciation, depletion and impairment	(85,535)	(35,979)
Property and equipment, net	628,181	673,432
Long-term derivative instruments	2,469	0
Restricted investments	94,467	156,938
Other long-term assets	6,129	8,545
Total assets	836,843	917,464
Current liabilities:
Accounts payable	2,345	1,941
Revenues payable	24,779	22,427
Accrued liabilities (see Note 15)	23,155	18,233
Short-term derivative instruments	139	0
Total current liabilities	50,418	42,601
Long-term debt (see Note 11)	294,000	376,000
Asset retirement obligations	75,867	99,460
Long-term derivative instruments	0	5,470
Total liabilities	420,285	523,531
Commitments and contingencies (see Note 17)
Stockholders' equity:
Preferred stock, $0.0001 par value: 45,000,000 shares authorized; no shares issued and outstanding at December 31, 2018 and 2017, respectively	0	0
Warrants, 2,173,913 warrants issued and outstanding at December 31, 2018 and 2017, respectively	4,788	4,788
Common stock, $0.0001 par value: 300,000,000 shares authorized; 22,181,881 and 25,000,000 shares issued and outstanding at December 31, 2018 and 2017, respectively	3	3
Additional paid-in capital	355,872	387,856
Accumulated earnings (deficit)	55,895	1,286
Total stockholders' equity	416,558	393,933
Total liabilities and equity	$ 836,843	$ 917,464

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.0001	$ 0.0001
Preferred stock, shares authorized	45,000,000	45,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Warrants issued	2,173,913	2,173,913
Warrants outstanding	2,173,913	2,173,913
Common stock, par value	$ 0.0001	$ 0.0001
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares issued	22,181,881	25,000,000
Common stock, shares outstanding	22,181,881	25,000,000

STATEMENTS OF CONSOLIDATED OPER

STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) shares in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Revenues:
Total revenues		$ 205,479,000	$ 340,144,000
Costs and expenses:
Lease operating expense		74,547,000	114,405,000
Exploration		32,000	3,045,000
Taxes other than income		11,101,000	20,364,000
Depreciation, depletion and amortization		35,979,000	52,334,000
Impairment of proved oil and natural gas properties	$ 0	0	0
General and administrative expense		29,506,000	43,129,000
Accretion of asset retirement obligations		4,384,000	5,711,000
(Gain) loss on commodity derivative instruments		31,609,000	(8,155,000)
(Gain) loss on sale of properties		0	3,614,000
Other, net		485,000	943,000
Total costs and expenses		206,295,000	258,621,000
Operating income (loss)		(816,000)	81,523,000
Other income (expense):
Interest expense, net		(15,936,000)	(21,923,000)
Other income (expense)		16,981,000	190,000
Gain (loss) on extinguishment of debt		0	(3,034,000)
Total other income (expense)		1,045,000	(24,767,000)
Income (loss) before reorganization items, net and income taxes		229,000	56,756,000
Reorganization items, net		(1,119,000)	(2,147,000)
Income tax benefit (expense)		2,176,000	0
Net income (loss)		1,286,000	54,609,000
Net income (loss) attributable to common stockholders/limited partners		1,286,000	54,609,000
Successor/Predecessor interest in net income (loss):
Net income (loss) attributable to Successor/Predecessor		1,286,000	54,609,000
Net (income) loss allocated to Predecessor's general partner		0	0
Net (income) loss allocated to participating restricted stockholders		(35,000)	(2,426,000)
Net income (loss) available to common stockholders/limited partners		$ 1,251,000	$ 52,183,000
Earnings per share/unit: (See Note 13)
Basic and diluted earnings per share/unit		$ 0.05	$ 2.09
Weighted average common shares/unit outstanding:
Basic and diluted		25,000	24,959
Oil and Natural Gas Sales [Member]
Revenues:
Total revenues		$ 205,176,000	$ 339,840,000
Other Revenues [Member]
Revenues:
Total revenues		303,000	304,000
Gathering, Processing and Transportation [Member]
Costs and expenses:
Gathering, processing and transportation		$ 18,652,000	$ 23,231,000
Predecessor [Member]
Revenues:
Total revenues	109,201,000			$ 284,580,000
Costs and expenses:
Lease operating expense	35,568,000			126,175,000
Exploration	21,000			981,000
Taxes other than income	5,187,000			15,540,000
Depreciation, depletion and amortization	37,717,000			171,629,000
Impairment of proved oil and natural gas properties	0			183,437,000
General and administrative expense	31,606,000			63,280,000
Accretion of asset retirement obligations	3,407,000			10,231,000
(Gain) loss on commodity derivative instruments	(23,076,000)			117,105,000
(Gain) loss on sale of properties	0			(2,754,000)
Other, net	36,000			516,000
Total costs and expenses	101,238,000			721,119,000
Operating income (loss)	7,963,000			(436,539,000)
Other income (expense):
Interest expense, net	(10,243,000)			(146,031,000)
Other income (expense)	8,000			8,000
Gain (loss) on extinguishment of debt	0			42,337,000
Total other income (expense)	(10,235,000)			(103,686,000)
Income (loss) before reorganization items, net and income taxes	(2,272,000)			(540,225,000)
Reorganization items, net	(88,774,000)			0
Income tax benefit (expense)	91,000			(173,000)
Net income (loss)	(90,955,000)			(540,398,000)
Net income (loss) attributable to common stockholders/limited partners	(90,955,000)			(540,398,000)
Successor/Predecessor interest in net income (loss):
Net income (loss) attributable to Successor/Predecessor	(90,955,000)			(540,398,000)
Net (income) loss allocated to Predecessor's general partner	0			168,000
Net (income) loss allocated to participating restricted stockholders	0			0
Net income (loss) available to common stockholders/limited partners	$ (90,955,000)			$ (540,230,000)
Earnings per share/unit: (See Note 13)
Basic and diluted earnings per share/unit	$ (1.09)			$ (6.48)
Weighted average common shares/unit outstanding:
Basic and diluted	83,807			83,351
Predecessor [Member] | Oil and Natural Gas Sales [Member]
Revenues:
Total revenues	$ 108,970,000			$ 284,051,000
Predecessor [Member] | Other Revenues [Member]
Revenues:
Total revenues	231,000			529,000
Predecessor [Member] | Gathering, Processing and Transportation [Member]
Costs and expenses:
Gathering, processing and transportation	$ 10,772,000			$ 34,979,000

STATEMENTS OF CONSOLIDATED CASH

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($)	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Cash flows from operating activities:
Net income (loss)		$ 1,286,000	$ 54,609,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		35,979,000	52,334,000
Impairment of proved oil and natural gas properties	$ 0	0	0
(Gain) loss on derivative instruments		31,609,000	(8,155,000)
Cash settlements (paid) received on expired derivative instruments		30,446,000	10,087,000
Cash settlements (paid) on terminated derivatives		0	0
Bad debt expense		0	106,000
Deferred income tax expense (benefit)		(2,206,000)	0
Amortization and write-off of deferred financing costs		2,093,000	2,518,000
Amortization and write-off of senior notes discount		0	0
(Gain) loss on extinguishment of debt		0	3,034,000
Accretion of asset retirement obligations		4,384,000	5,711,000
(Gain) loss on sale of properties		0	3,614,000
Share/unit-based compensation (see Note 14)		2,516,000	4,374,000
Settlement of asset retirement obligations		(633,000)	(767,000)
Exploration costs		0	0
Reorganization items, net		0	0
Other		0	0
Changes in operating assets and liabilities:
Accounts receivable		(2,830,000)	5,783,000
Prepaid expenses and other assets		5,578,000	623,000
Payables and accrued liabilities		(13,590,000)	7,925,000
Other		10,000	(15,000)
Net cash provided by operating activities		94,642,000	141,781,000
Cash flows from investing activities:
Additions to oil and gas properties		(52,735,000)	(55,425,000)
Additions to other property and equipment		(127,000)	(492,000)
Additions to restricted investments		(495,000)	(500,000)
Withdrawals of restricted investments		0	62,467,000
Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold		0	17,113,000
Other		0	503,000
Net cash provided by (used in) investing activities		(53,357,000)	23,666,000
Cash flows from financing activities:
Advances on revolving credit facilities		9,000,000	315,000,000
Payments on revolving credit facilities		(63,000,000)	(397,000,000)
Deferred financing costs		(642,000)	(3,451,000)
Payment to holders of the Notes		(8,193,000)	0
Payment to Predecessor common unitholders		(1,250,000)	0
Contribution from management		1,500,000	0
Retirement of common stock under tender offer		0	(35,000,000)
Costs incurred in conjunction with tender offer		0	(521,000)
Repurchase of senior notes		0	0
Contributions related to sale of assets to NGP affiliate		0	0
Transfer of operating subsidiary from Memorial Resource		0	0
Proceeds from the issuance of Predecessor common units		0	0
Costs incurred in conjunction with issuance of Predecessor common units		0	0
Distributions to partners		0	0
Acquisition of Predecessor's general partner (see Note 1)		0	0
Acquisition of incentive distribution rights from NGP (see Note 1)		0	0
Restricted units returned to plan		0	(847,000)
Other		(9,000)	9,000
Net cash (used in) provided by financing activities		(62,594,000)	(121,810,000)
Net change in cash, cash equivalents and restricted cash		(21,309,000)	43,637,000
Cash, cash equivalents and restricted cash, beginning of period		27,701,000	6,392,000
Cash, cash equivalents and restricted cash, end of period	27,701,000	6,392,000	$ 50,029,000
Predecessor [Member]
Cash flows from operating activities:
Net income (loss)	(90,955,000)			$ (540,398,000)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	37,717,000			171,629,000
Impairment of proved oil and natural gas properties	0			183,437,000
(Gain) loss on derivative instruments	(23,076,000)			118,395,000
Cash settlements (paid) received on expired derivative instruments	15,895,000			210,704,000
Cash settlements (paid) on terminated derivatives	94,146,000			228,646,000
Bad debt expense	0			2,050,000
Deferred income tax expense (benefit)	(74,000)			187,000
Amortization and write-off of deferred financing costs	0			22,106,000
Amortization and write-off of senior notes discount	0			13,185,000
(Gain) loss on extinguishment of debt	0			(42,337,000)
Accretion of asset retirement obligations	3,407,000			10,231,000
(Gain) loss on sale of properties	0			(2,754,000)
Share/unit-based compensation (see Note 14)	3,667,000			7,350,000
Settlement of asset retirement obligations	(164,000)			(1,442,000)
Exploration costs	0			792,000
Reorganization items, net	68,356,000			0
Other	56,000			229,000
Changes in operating assets and liabilities:
Accounts receivable	1,024,000			23,928,000
Prepaid expenses and other assets	735,000			(4,088,000)
Payables and accrued liabilities	15,030,000			4,084,000
Other	(266,000)			2,692,000
Net cash provided by operating activities	125,498,000			408,626,000
Cash flows from investing activities:
Additions to oil and gas properties	(6,211,000)			(57,675,000)
Additions to other property and equipment	(76,000)			(7,875,000)
Additions to restricted investments	(209,000)			(8,443,000)
Withdrawals of restricted investments	0			4,840,000
Proceeds from the sale of oil and natural gas properties, net of cash and cash equivalents sold	0			52,711,000
Other	0			0
Net cash provided by (used in) investing activities	(6,496,000)			(16,442,000)
Cash flows from financing activities:
Advances on revolving credit facilities	16,600,000			144,000,000
Payments on revolving credit facilities	(98,252,000)			(468,348,000)
Deferred financing costs	(8,575,000)			(1,350,000)
Payment to holders of the Notes	(16,446,000)			0
Payment to Predecessor common unitholders	0			0
Contribution from management	0			0
Retirement of common stock under tender offer	0			0
Costs incurred in conjunction with tender offer	0			0
Repurchase of senior notes	0			(41,261,000)
Contributions related to sale of assets to NGP affiliate	0			26,000
Transfer of operating subsidiary from Memorial Resource	0			2,363,000
Proceeds from the issuance of Predecessor common units	0			2,385,000
Costs incurred in conjunction with issuance of Predecessor common units	0			(536,000)
Distributions to partners	0			(13,300,000)
Acquisition of Predecessor's general partner (see Note 1)	0			(750,000)
Acquisition of incentive distribution rights from NGP (see Note 1)	0			(50,000)
Restricted units returned to plan	(10,000)			(589,000)
Other	9,000			0
Net cash (used in) provided by financing activities	(106,674,000)			(377,410,000)
Net change in cash, cash equivalents and restricted cash	12,328,000			14,774,000
Cash, cash equivalents and restricted cash, beginning of period	15,373,000	$ 27,701,000		599,000
Cash, cash equivalents and restricted cash, end of period	$ 27,701,000			$ 15,373,000

STATEMENTS OF CONSOLIDATED AND

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY - USD ($) $ in Thousands	Total	Common Stock [Member]	Warrants [Member]	Additional Paid in Capital [Member]	Accumulated Earnings (Deficit)	Limited Partners Common Units [Member]	General Partner [Member]
Balance (Predecessor [Member]) at Dec. 31, 2015	$ 645,492					$ 644,644	$ 848
Net income (loss) | Predecessor [Member]	(540,398)					(540,230)	(168)
Distributions | Predecessor [Member]	(13,300)					(13,289)	(11)
Purchase of equity interest of general partner (see Note 1) | Predecessor [Member]	(750)					(81)	(669)
Acquisition of IDRs from NGP (see Note 1) | Predecessor [Member]	(50)					(50)	0
Net proceeds from issuance of Predecessor common units | Predecessor [Member]	1,849					1,849	0
Cancellation and amortization of unit-based awards | Predecessor [Member]	7,206					7,206	0
Restricted units repurchased and other | Predecessor [Member]	(560)					(560)	0
Balance (Predecessor [Member]) at Dec. 31, 2016	99,489					99,489	0
Net income (loss) | Predecessor [Member]	(90,955)					(90,955)	0
Cancellation and amortization of unit-based awards | Predecessor [Member]	3,713					3,713	0
Restricted units repurchased and other | Predecessor [Member]	(2)					(2)	0
Issuance of common stock to Predecessor common unitholders | Predecessor [Member]	(7,707)					(7,707)	0
Issuance of warrants to Predecessor common unitholders | Predecessor [Member]	(4,788)					(4,788)	0
Contribution from management | Predecessor [Member]	1,500					1,500	0
Settlement with Predecessor common unitholders | Predecessor [Member]	(1,250)					(1,250)	0
Balance (Predecessor [Member]) at May. 04, 2017	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
Net income (loss)	54,609	0	0	0	54,609
Tender offer distribution	(35,520)	0	0	(35,520)	0
Share-based compensation expense	4,374	0	0	4,374	0
Restricted shares repurchased	(847)	0	0	(847)	0
Other	9	0	0	9	0
Balance at Dec. 31, 2018	$ 416,558	$ 3	$ 4,788	$ 355,872	$ 55,895

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
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 located in the Rockies, federal waters offshore Southern California, East Texas / North Louisiana and South Texas. 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” refer 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; and (vii) “NGP” refers to Natural Gas Partners. MEMP GP Acquisition 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 16 for additional information regarding the MEMP GP Acquisition and the transition services agreement. Emergence from Voluntary Reorganization under Chapter 11 On January 16, 2017 (the “Petition Date”), 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’ Chapter 11 proceedings were jointly administered under the caption In re: Memorial Production Partners LP, et al. Management and Board Changes On April 27, 2018, the board of directors appointed Martyn Willsher to serve as Senior Vice President and Chief Financial Officer of the Company, effective April 27, 2018. On May 1, 2018, the Company announced the retirement of William J. Scarff, the Company’s President and Chief Executive Officer and member of the board of directors, which retirement became effective May 14, 2018. Also on May 1, 2018, the Company announced the departure of Christopher S. Cooper, Senior Vice President and Chief Operating Officer, and Robert L. Stillwell, Jr., Senior Vice President and Chief Financial Officer, from their respective positions with the Company, effective April 27, 2018. There were no disagreements between the Company and any of Messrs. Scarff, Cooper or Stillwell (collectively, the “Departing Executives”) which led to their retirement or separation (as applicable) from the Company. On May 4, 2018, the board of directors appointed Kenneth Mariani to serve as President and Chief Executive Officer of the Company, effective May 14, 2018. On May 17, 2018, Mr. Scarff resigned from the board of directors of the Company. There were no disagreements between Mr. Scarff and the Company which led to Mr. Scarff’s resignation from the board of directors. Also on May 17, 2018, the board of directors appointed Mr. Mariani to serve as a director of the Company to fill the vacancy caused by Mr. Scarff’s resignation. On July 25, 2018, the board of directors appointed Denise DuBard to serve as Vice President and Chief Accounting Officer of the Company, effective August 9, 2018. Also on July 25, 2018, Matthew J. Hoss tendered his resignation from his position as Vice President and Chief Accounting Officer of the Company, effective August 9, 2018. There were no disagreements between Mr. Hoss and the Company which led to his separation from the Company. Basis of Presentation Our Consolidated Financial Statements included herein have been prepared pursuant to the rule and guidelines of the Securities and Exchange Commission (the “SEC”). All material intercompany transactions and balances have been eliminated in preparation of our Consolidated Financial Statements. The accompanying Consolidated 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 (loss) on extinguishment of deferred finance cost were previously accounted for as interest expense, net and are now being presented as gain (loss) on extinguishment of debt on our Statement of Consolidated Operations. The Consolidated 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 Operations. The Company adopted the new accounting pronouncement related to the presentation of statement of cash flows — restricted cash in the first quarter of 2018. See Note 4 for additional information. A retrospective change for the period from January 1, 2017 through May 4, 2017 and May 5, 2017 through December 31, 2017 on the Statement of Consolidated Cash Flows as previously presented was required due to adoption. The table below sets forth the retrospective adjustments for the periods presented: Predecessor Previously Period from January 1, 2017 through May 4, 2017 Adjustment Effect As Adjusted Period from January 1, 2017 through May 4, 2017 (In thousands) Changes in operating assets and liabilities: Restricted cash $ (7,561 ) $ 7,561 $ — Net cash provided by operating activities 117,937 7,561 125,498 Net change in cash and cash equivalents 4,767 7,561 12,328 Cash and cash equivalents, end of period 20,140 7,561 27,701 Successor Previously Period from May 5, 2017 through December 31, 2017 Adjustment Effect As Adjusted Period from May 5, 2017 through December 30, 2017 (In thousands) Changes in operating assets and liabilities: Restricted cash $ 7,561 $ (7,561 ) $ — Net cash provided by operating activities 102,203 (7,561 ) 94,642 Net change in cash and cash equivalents (13,748 ) (7,561 ) (21,309 ) Cash and cash equivalents, end of period 6,392 — 6,392 Comparability of Financial Statements to Prior Periods As discussed in further detail in Note 3 below, we 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 Financial Statements and Notes after May 4, 2017, are not comparable to the Consolidated Financial Statements and Notes prior to that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Consolidated 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 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, 2018
Reorganizations [Abstract]
Emergence from Voluntary Reorganization under Chapter 11	Note 2. Emergence from Voluntary Reorganization under Chapter 11 On 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 Plan. On 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 “Emergence Credit Facility”), as further discussed in Note 11. • 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 became 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, 2018
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 reflected 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 17) 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) Reflected 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) Reflected 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 Emergence 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) Reflected the transfer to restricted cash to fund the professional fees escrow account. (4) Reflected the pre-payment of certain professional fees. (5) Reflected the deferred financing costs related to the Emergence Credit Facility. (6) Reflected the recognition of payables for general unsecured claims. (7) Net increase in accrued liabilities reflected 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) Reflected a repayment of $24.8 million on the Predecessor’s revolving credit facility and the reclassification of $430.0 million in borrowings under the Emergence 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) Reflected 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) Reflected the write-off of the deferred rent and loss on sublease liabilities. (13) Reflected a decrease of $62.9 million for asset retirement obligations. The fair value of asset retirement obligations was 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) Reflected 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 Operations (in thousands): Successor Predecessor Period from Period from For the May 5, 2017 January 1, Year Ended through 2017 through December 31, 2018 December 31, 2017 May 4, 2017 Gain on settlement of liabilities subject to compromise $ — $ — $ 758,764 Fresh start valuation adjustments — — (827,120 ) Professional fees (864 ) (724 ) (19,824 ) Other (1,283 ) (395 ) (594 ) Reorganization items, net $ (2,147 ) $ (1,119 ) $ (88,774 )

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
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 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 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. 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 $1.2 million and $1.9 million as an allowance for doubtful accounts at December 31, 2018 and 2017, 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, 2018 and 2017. Oil and Natural Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the Consolidated 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, 2018. 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 17 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 year ended December 31, 2018, the period from May 5, 2017 through December 31, 2017 and the year ended December 31, 2016 was approximately $2.5 million, $2.1 million, and $22.1 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 year ended December 31, 2018, 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 year ended December 31, 2016 was approximately $183.4 million. 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, 2018, 2017 and 2016. 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 9 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, 2018 and 2017. 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 we expect to be entitled to in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance and requires enhanced disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The standard was effective for the Company starting January 1, 2018, and the Company adopted the standard using a modified retrospective approach. See Note 5 for additional information. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Successor Predecessor For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 Major customers: Phillips 66 27% 23% 19% 19% Sinclair Oil & Gas Company 21% 19% 20% 16% CIMA Energy 10% 11% n/a n/a BP America Production Company n/a 10% 10% n/a Royal Dutch Shell plc and subsidiaries n/a n/a n/a 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 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 16 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, collars and puts) 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 year ended December 31, 2018, the period from May 5, 2017 through December 31, 2017 and the year ended December 31, 2016, we had $0.5 million, $0.4 million, and $0.5 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 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 13 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 awards subject to performance criteria; 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 14 for further information. Recently Adopted Accounting Pronouncements Compensation—Stock Compensation. In May 2017, the FASB issued an accounting standard 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. Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Issues Task Force. In November 2016, the FASB issued an accounting standard 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 and applied the disclosure requirements retrospectively. New Accounting Pronouncements Fair Value Measurement . In August 2018, the FASB issued an amendment to modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement. Certain disclosure requirements were removed, modified and added and primarily relate to Level 3 hierarchy measurements and changes to non-public entities disclosures. The guidance is effective for all entities for fiscal years and interim periods within those fiscal years, beginning after December 15, 2019. The impact of this guidance is not expected to have a material impact on the Company. 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. In July 2018, the FASB issued a revision to lease accounting implementation guidance, targeting improvements to comparative reporting requirements for initial adoption. Previously, the reporting requirements for initial adoption required an entity to initially apply the new leases standard (subject to specific transition requirements and optional practical expedients) at the beginning of the earliest period presented in the financial statements (which is January 1, 2017, for calendar-year-end public business entities that adopt the new leases standard on January 1, 2019). Under this new revision an optional method in addition to the existing method allows entities to initially apply the new leases standard at the adoption date January 1, 2019 for calendar-year-end public business entities and recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. The FASB also issued another update in July on additional codification improvements, primarily corrections and clarifications. The Company will not early adopt this standard. The Company is the lessee under various agreements for office space, compressors, equipment, vehicles and surface rentals (right of use assets) that are currently accounted for as operating leases, see Note 17, for additional information. The Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using the modified retrospective approach with a cumulative impact to retained earnings in that period, and including several optional practical expedients relating to leases commenced before the effective date. The practical expedients the Company will adopt are: 1) the original correct assessment of a contract containing a lease will be accepted without further review on all existing or expired contracts; 2) the original lease classification as an operating lease will convert as an operating lease under the new guidance; 3) initial direct costs for any existing leases will not be reassessed; 4) existing land easements or right of use agreements will continue under current accounting policy and only new agreements will be evaluated in the future and 5) short-term leases for twelve months or less will not be evaluated under the guidance. The adoption of this standard will result in an increase in the assets and liabilities on the Company’s consolidated balance sheets. The Company has completed the review and evaluation of current and potential leases which resulted primarily in our corporate office lease and some minor equipment and vehicle leases qualifying under the new guidance. Based upon this analysis, the impact of the new guidance is expected to establish a liability and the corresponding asset of approximately $5.0 million to $6.0 million at inception related to leases existing as of January 1, 2019. 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.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2018
Revenue From Contract With Customer [Abstract]
Revenue	Revenue from contracts with customers As discussed in Note 4, the Company adopted Accounting Standard Update (ASU) No. 2014-09, revenue from contracts with customers (ASC 606), on January 1, 2018 using the modified retrospective method of adoption. Adoption of the ASU did not require an adjustment to the opening balance of equity and did not materially change the Company's amount and timing of revenues. The Company applied the ASU only to contracts that were not completed as of January 1, 2018. Although the adoption of ASC 606 did not have an impact on the Company’s net income or cash flows, it did result in the reclassification of fees incurred under certain gathering and gas processing agreements. Such reclassification led to an overall decrease in oil and natural gas sales with a corresponding decrease in gathering, processing and transportation as follows: For the Year Ended December 31, 2018 As Reported Previous Revenue Recognition Method Increase/ (Decrease) (in thousands) Revenues: Oil and natural gas sales $ 339,840 $ 342,210 $ (2,370 ) Cost and expenses: Gathering, processing and transportation 23,231 25,601 $ (2,370 ) Net income (loss) $ 54,609 $ 54,609 $ — The reclassification of certain fees between oil and natural gas sales and gathering, processing and transportation is the result of the Company’s assessment of the point in time at which its performance obligations under its commodity sales contracts are satisfied and control of the commodity is transferred to the customer. The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as gathering, processing and transportation and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered. 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, 2018. Disaggregation of Revenue We have identified three material revenue streams in our business: oil, natural gas and NGLs. The following table present our revenues disaggregated by revenue stream. For the Year Ended December 31, 2018 (in thousands) Revenues Oil $ 209,066 NGLs 42,463 Natural gas 88,311 Oil and natural gas sales $ 339,840 Contract Balances Under our sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to our revenue contracts with customers was $25.0 million at December 31, 2018 and $30.1 million at December 31, 2017. Transaction Price Allocated to Remaining Performance Obligations For our contracts that have a contract term greater than one year, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For our contracts that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
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 initial public offering in December 2011, as further discussed in Note 16, directly or indirectly from Memorial Resource and certain affiliates of NGP. Acquisition and Divestiture related expenses Acquisition and divestiture related expenses for 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 For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 $ 205 $ 609 $ — $ 1,451 2018 Acquisitions & Divestitures On May 30, 2018, we closed a transaction to divest certain of our non-core assets located in South Texas (the “South Texas Divestiture”) for total proceeds of approximately $17.1 million, including post-closing adjustments, which includes $18.6 million in cash, $0.5 million in accounts payable and $0.9 million paid in legal and advisor expenses. We recorded a loss on sale of properties of approximately $3.6 million for the year ended December 31, 2018, in “(gain) loss on sale of properties” in the accompanying Statements of Consolidated Operations. The net proceeds from the sale were used to reduce outstanding borrowings under our Emergence Credit Facility (as defined below). This disposition did not qualify as a discontinued operation. There were no material acquisitions for the year ended December 31, 2018. 2017 Acquisitions & Divestitures There were no material acquisitions or divestitures the period from January 1, 2017 through May 4, 2017 or for the period from May 5, 2017 through December 31, 2017. 2016 Acquisitions & 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 final 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 Operations of the Company is as follows (in thousands): Predecessor For the Year Ended December 31, 2016 Permian Divestiture $ 4,297 Rockies Divestiture (7,677 )

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
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, 2018 and December 31, 2017. 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 11 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, 2018 and December 31, 2017 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, 2018 and December 31, 2017 for each of the fair value hierarchy levels: Successor Fair Value Measurements at December 31, 2018 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 $ — $ 25,515 $ — $ 25,515 Liabilities: Commodity derivatives $ — $ 4,372 $ — $ 4,372 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 See Note 8 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. The initial fair value estimates are based on unobservable market data and are classified within Level 3 of the fair value hierarchy. See Note 9 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 were recognized for the year ended December 31, 2018. (ii) No impairments were recognized for the period from May 5, 2017 through December 31, 2017 or the period from January 1, 2017 through May 4, 2017. (iii) During the year ended December 31, 2016, our Predecessor 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.

Risk Management and Derivative

Risk Management and Derivative Instruments	12 Months Ended
	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
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 New 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, 2018, 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 $21.2 million against amounts outstanding under our New Revolving Credit Facility at December 31, 2018. See Note 11 for additional information regarding our New Revolving Credit Facility. Commodity Derivatives A combination of commodity derivatives (e.g., floating-for-fixed swaps, costless collars, call spreads and puts) 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 Oil Price Information Service Mont Belvieu. At December 31, 2018, the Company had the following open commodity positions: 2019 2020 Natural Gas Derivative Contracts: Fixed price swap contracts: Average monthly volume (MMBtu) 1,565,000 — Weighted-average fixed price $ 2.89 $ — Collar contracts: Average monthly volume (MMBtu) — 90,000 Weighted-average floor price — $ 2.60 Weighted-average ceiling price $ — $ 2.85 Crude Oil Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 148,000 — Weighted-average fixed price $ 53.06 $ — Collar contracts: Average monthly volume (Bbls) 38,000 14,300 Weighted-average floor price $ 55.00 $ 55.00 Weighted-average ceiling price $ 63.85 $ 62.10 Purchased put option contracts: Average Monthly Volume (Bbls) — 14,300 Weighted-average strike price $ — $ 55.00 NGL Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 72,000 18,200 Weighted-average fixed price $ 29.96 $ 28.67 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 New Credit Agreement to fixed interest rates. The Company did not have any interest rate swaps at December 31, 2018 and 2017, respectively. 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, 2018 and 2017. 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 New Credit Agreement. Successor Asset Derivatives Liability Derivatives Asset Derivatives Liability Derivatives December 31, December 31, December 31, December 31, Type Balance Sheet Location 2018 2018 2017 2017 (In thousands) Commodity contracts $ 21,217 $ 2,543 $ 37,729 $ 9,183 Gross fair value 21,217 2,543 37,729 9,183 Netting arrangements (2,404 ) (2,404 ) (9,183 ) (9,183 ) Net recorded fair value Short-term derivative instruments $ 18,813 $ 139 $ 28,546 $ — Commodity contracts $ 4,298 $ 1,829 $ 459 $ 5,929 Gross fair value 4,298 1,829 459 5,929 Netting arrangements (1,829 ) (1,829 ) (459 ) (459 ) Net recorded fair value Long-term derivative instruments $ 2,469 $ — $ — $ 5,470 (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 For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended Statements of December 31, through through December 31, Operations Location 2018 December 31, 2017 May 4, 2017 2016 (Gain) loss on commodity derivatives $ (8,155 ) $ 31,609 $ (23,076 ) $ 117,105 Interest expense, net — — — 1,290

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
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 year ended December 31, 2018, the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016 (in thousands): Successor Predecessor For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 Asset retirement obligations at beginning of period $ 100,173 $ 96,127 $ 155,702 $ 164,164 Liabilities added from acquisition or drilling 89 191 6 30 Liabilities removed upon sale of wells (15,702 ) — — (19,669 ) Liabilities settled (767 ) (633 ) (164 ) (1,442 ) Accretion expense 5,711 4,384 3,407 10,231 Revision of estimates (1) (13,160 ) 104 104 2,388 Asset retirement obligation at end of period 76,344 100,173 159,055 155,702 Fresh start adjustment (2) — — (62,928 ) — Less: Current Portion 477 713 941 789 Asset retirement obligations - long-term portion $ 75,867 $ 99,460 $ 95,186 $ 154,913 (1) The decrease in revision of estimates for the year ended December 31, 2018 is primarily due to receiving new cost estimates from third parties regarding the estimated plugging and abandonment costs. (2) 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, 2018
Investments Debt And Equity Securities [Abstract]
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. The components of the restricted investment balances are as follows: Successor December 31, December 31, 2018 2017 (In thousands) BOEM platform abandonment (See Note 17) $ 90,162 $ 152,272 Surety bond cash collateral — 501 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 4,305 4,058 Port of Long Beach pipeline license — 107 Restricted investments $ 94,467 $ 156,938

Debt

Debt	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt	Our consolidated debt obligations consisted of the following at the dates indicated: Successor December 31, December 31, 2018 2017 (In thousands) $425.0 million New Revolving Credit Facility, variable-rate, due November 2023 (1) $ 294,000 $ — $1.0 billion Emergence Credit Facility, variable-rate, due March 2021 (1) — 376,000 Long-term debt $ 294,000 $ 376,000 (1) The carrying amount of our New Revolving Credit Facility and Emergence Credit Facility approximates fair value because the interest rates are variable and reflective of market rates. New Revolving Credit Facility On November 2, 2018, OLLC and Amplify Acquisitionco, Inc. (“Acquisitionco”), our wholly owned subsidiaries, entered into a credit agreement (the “New Credit Agreement”) providing for a new $425.0 million reserve-based revolving credit facility (the “New Revolving Credit Facility”) with Bank of Montreal, as administrative agent (in such capacity, the “Agent”) and an issuer of letters of credit, and the other lenders and agents from time to time party thereto. The New Revolving Credit Facility matures on November 2, 2023. The terms and conditions under the New Revolving Credit Facility include (but are not limited to) the following: • a borrowing base of $425.0 million; • at OLLC’s option, borrowings under the New Credit Agreement will bear interest at the base rate, LIBOR Market Index rate or LIBOR plus an applicable margin. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the federal funds effective rate plus 50 basis points, (ii) the rate of interest in effect for each day as publicly announced from time to time by the Agent as its “prime rate”; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points per annum. The applicable margin for base rate loans ranges from 100 to 200 basis points, and the applicable margin for LIBOR loans and LIBOR Market loans ranges from 200 to 300 basis points, in each case depending on the percentage of the borrowing base utilized; • the obligations under the New Revolving Credit Facility are secured by mortgages on not less than 85% of the PV-9 value of oil and gas properties (and at least 85% of the PV-9 value of the proved, developed and producing oil and gas properties) included in the determination of the borrowing base. OLLC and its other subsidiaries entered into a pledge and security agreement in favor of the Agent for the secured parties, pursuant to which OLLC’s obligations under the New Credit Agreement are secured by a first priority security interest in substantially all of our assets (subject to permitted liens). Additionally, the Company entered into a non-recourse pledge agreement in favor of the Agent for the secured parties, pursuant to which OLLC’s obligations under the New Credit Agreement are secured by a pledge and security interest of 100% of the equity interests held by the Company in Acquisitionco; • certain financial covenants, including the maintenance of (i) • 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. On December 21, 2018, we entered into a letter agreement relating to the New Credit Agreement (the “Letter Agreement”). Pursuant to the Letter Agreement, the parties to the New Credit Agreement agreed, among other things, to: • extend the date by which OLLC was required to show compliance with certain minimum hedging requirements set forth in the New Credit Agreement from December 31, 2018 to February 28, 2019; and • subject to certain conditions, waive the requirement that OLLC deliver to the Agent within 60 days after the closing date of the New Credit Agreement control agreements with respect to certain deposit accounts held or maintained by each Loan Party (as defined in the New Credit Agreement) on the closing date of the New Credit Agreement. Emergence Credit Facility On May 4, 2017, OLLC, as borrower, entered into the Amended and Restated Credit Agreement (the “Emergence Credit Agreement”) among Acquisitionco, as parent guarantor, the lenders from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent. Pursuant to the Emergence Credit Agreement the lenders party thereto agreed to provide OLLC with the Emergence Credit Facility (the loans thereunder, the “Loans”). The aggregate principal amount of Loans outstanding under the Emergence Credit Facility as of the Effective Date was $430.0 million. The terms and conditions under the Emergence Credit Agreement included (but were not limited to) the following: • a borrowing base of approximately $490.0 million; • a maturity date of March 19, 2021 for the Emergence Credit Facility; • 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 Emergence Credit Facility; • the unused commitments under the Emergence Credit Facility accrued a commitment fee of 0.50%, payable quarterly in arrears; • the obligations under the Emergence Credit Agreement were 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; • 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; and • 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 Emergence Credit Facility On November 30, 2017, we entered into the first amendment to the Emergence Credit Agreement. The first amendment, among other things, amended the Emergence Credit Agreement to: • reflect the reduction of the borrowing base under the Emergence 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; • remove the requirement to make mandatory prepayments of borrowings in respect of excess unrestricted cash and cash equivalents greater than $35.0 million; and • 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. Second Amendment to Emergence Credit Facility On May 15, 2018, we entered into the second amendment to the Emergence Credit Agreement, to among other things, (i) reflect the reduction of the borrowing base under the Emergence Credit Agreement from $435.0 million to $430.0 million, effective as of May 15, 2018, with the borrowing base to be further reduced by $15.0 million upon the consummation of the South Texas Divestiture and by $5.0 million each month until the next scheduled redetermination of the borrowing base; and (ii) amend the minimum hedging requirement to disregard the reasonably anticipated production of hydrocarbons from the assets to be sold in the South Texas Divestiture. Extinguishment of Debt On November 2, 2018, in connection with our entrance into the New Revolving Credit Facility, the Emergence Credit Facility was terminated and repaid in full. At December 31, 2018, $3.0 million of deferred financing costs related to the Emergence Credit Facility was written off resulting in a loss on extinguishment of debt. Borrowing Base The borrowing base for our New Revolving Credit Facility was $425.0 million at December 31, 2018. 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 Emergence 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 For the Year Ended May 5, 2017 January 1, 2017 For the Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 New Revolving Credit Facility 4.96% n/a n/a n/a Emergence Credit Facility 5.75% 5.08% n/a n/a Predecessor's revolving credit facility n/a n/a 4.18% 3.28% Senior Notes On April 17, 2013, May 23, 2013 and October 10, 2013, our Predecessor and Finance Corp. (collectively, the “Issuers”) issued $300.0 million, $100.0 million and $300.0 million, respectively, of 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 were 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 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 2022 Senior Notes would have matured on August 1, 2022 with interest accruing at 6.875% per annum and were payable semi-annually in arrears on February 1 and August 1 of each year. 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. 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, 2018, 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 New Revolving Credit Facility was $3.3 million at December 31, 2018. The unamortized deferred financing costs are amortized over the remaining life of our New Revolving Credit Facility using the straight-line method which generally approximate the effective interest method. On November 2, 2018, in connection with our entrance into the New Revolving Credit Facility, the Emergence Credit Facility was terminated and repaid in full. The remaining deferred financing costs of $3.0 million was written off resulting in a loss on extinguishment of debt. 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, 2018
Equity [Abstract]
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 Shares/Units Partner 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 — Issuance of common stock — — Restricted stock units vested 163,700 — Repurchase of common shares (65,152 ) — Restricted common stock repurchased and retired under tender offer (2,916,667 ) — Balance, December 31, 2018 (Successor) 22,181,881 — (1) Restricted common units were 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 for the year ended December 31, 2016. 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 Tender Offer On November 19, 2018, the Company’s board of directors announced the commencement of a tender offer to purchase 2,916,667 shares of the Company’s common stock. On December 19, 2018, upon the terms and subject to the conditions described in the Offer to Purchase dated November 19, 2018, as amended, the Company repurchased an aggregate of 2,916,667 shares of its common stock at a price of $12.00 per share, for a total cost of approximately $35.0 million (excluding fees and expenses relating to the offer). Share Repurchase Program On December 21, 2018, the Company’s board of directors authorized the repurchase of up to $25.0 million of the Company’s outstanding shares of common stock, with repurchases to begin on or after January 9, 2019. Subsequent Event. In January and February 2019, the Company repurchased 42,583 shares of common stock at an average price of $8.63 for a total cost of approximately $0.4 million. At February 28, 2019, approximately $24.6 million remains available for share repurchases under the program. 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. 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. 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 was allocated entirely to the common unit holders, and net income (loss) attributable to the Successor is allocated entirely to the common stockholders. 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 then 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. 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

Earnings per Share_Unit

Earnings per Share/Unit	12 Months Ended
	Dec. 31, 2018
Earnings Per Share [Abstract]
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 For the May 5, 2017 Period from For the Year Ended through January 1, Year Ended December 31, December 31, 2017 through December 31, 2018 2017 May 4, 2017 2016 Net income (loss) attributable to Successor/Predecessor $ 54,609 $ 1,286 $ (90,955 ) $ (540,398 ) Less: Predecessor's general partner's 0.1% interest in net income (loss) (1) — — — (168 ) Less: Net income (loss) allocated to participating restricted stockholders 2,426 35 — — Basic and diluted earnings available to common stockholders/limited partners $ 52,183 $ 1,251 $ (90,955 ) $ (540,230 ) Common shares/units: Common shares/units outstanding — basic 24,959 25,000 83,807 83,351 Dilutive effect of potential common shares — — — — Common shares/units outstanding — diluted (2) 24,959 25,000 83,807 83,351 Net earnings per share/unit: Basic $ 2.09 $ 0.05 $ (1.09 ) $ (6.48 ) Diluted $ 2.09 $ 0.05 $ (1.09 ) $ (6.48 ) Antidilutive stock options (3) — 517 — — Antidilutive warrants (4) 2,174 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. (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, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
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 were reserved for issuance under the MIP as of the Effective Date. 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 Restricted Stock Units with Service Vesting Condition The restricted stock units with service vesting conditions (“TSUs”) granted are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with TSUs was $5.6 million at December 31, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.2 years. The following table summarizes information regarding the TSUs granted under the MIP for the period presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) TSUs outstanding at May 5, 2017 (Successor) 614,754 $ 13.77 Granted (2) 173,070 $ 12.87 Forfeited (105,032 ) $ 13.77 Vested — $ — TSUs outstanding at December 31, 2017 (Successor) 682,792 $ 13.54 Granted (3) 437,000 $ 10.51 Forfeited (4) (363,513 ) $ 13.55 Vested (158,255 ) $ 13.44 TSUs outstanding at December 31, 2018 (Successor) 598,024 $ 11.35 (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 TSUs 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. (3) The aggregate grant date fair value of TSUs issued for the year ended December 31, 2018 was $4.6 million based on a grant date market price ranging from $9.30 to $11.00 per share. (4) In connection with the separation and retirement agreements of certain executives as discussed in Note 1, the Departing Executives forfeited 298,354 TSUs during the year ended December 31, 2018. Restricted Stock Units with Market and Service Vesting Conditions The restricted stock units with market and service vesting conditions (“PSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a graded-vesting basis. As such, the Company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. The Company accounts for forfeitures as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost related to the PSUs was $1.8 million at December 31, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.4 years. During the year ended December 31, 2018, the board of directors granted PSUs to certain executives and employees of the Company. The PSUs will vest based on the satisfaction of service and market vesting conditions with market vesting based on the Company’s achievement of certain share price targets. The PSUs are subject to service-based vesting such that 50% of the PSUs service vest on the applicable market vesting date and an additional 25% of the PSUs service vest on each of the first and second anniversaries of the applicable market vesting date. In the event of a qualifying termination, subject to certain conditions, (i) all PSUs that have satisfied the market vesting conditions will fully service vest, upon such termination, and (ii) if the termination occurs between the second and third anniversaries of the grant date, then PSUs that have not market vested as of the termination will market vest to the extent that the share targets (in each case, reduced by $0.25) are achieved as of such termination. Subject to the foregoing, any unvested PSUs will be forfeited upon termination of employment. A Monte Carlo simulation was used to determine the fair value of these awards at the grant date. The assumptions used to estimate the fair value of the PSUs are as follows: Share price targets $ 12.50 $ 15.00 $ 17.50 Risk-free interest rate: Awards Issued on May 14, 2018 2.68 % 2.68 % 2.68 % Awards Issued on July 1, 2018 2.61 % 2.61 % 2.61 % Awards Issued on August 1, 2018 2.76 % 2.76 % 2.76 % Awards Issued on October 1, 2018 2.88 % 2.88 % 2.88 % Awards Issued on November 1, 2018 2.89 % 2.89 % 2.89 % Dividend yield — — — Expected volatility: Awards Issued on May 14, 2018 50.0 % 50.0 % 50.0 % Awards Issued on July 1, 2018 50.0 % 50.0 % 50.0 % Awards Issued on August 1, 2018 55.0 % 55.0 % 55.0 % Awards Issued on October 1, 2018 53.0 % 53.0 % 53.0 % Awards Issued on November 1, 2018 54.0 % 54.0 % 54.0 % Calculated fair value per PSU: Awards Issued on May 14, 2018 $ 9.71 $ 8.52 $ 7.48 Awards Issued on July 1, 2018 $ 9.87 $ 8.72 $ 7.68 Awards Issued on August 1, 2018 $ 9.79 $ 8.66 $ 7.65 Awards Issued on October 1, 2018 $ 8.54 $ 7.57 $ 6.66 Awards Issued on November 1, 2018 $ 7.65 $ 6.72 $ 5.88 The following table summarizes information regarding the PSUs granted under the MIP for the period presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) PSUs outstanding at December 31, 2017 (Successor) — $ — Granted (2) 395,500 $ 8.14 Forfeited (2,000 ) $ 7.59 Vested — $ — PSUs outstanding at December 31, 2018 (Successor) 393,500 $ 8.14 (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 PSUs issued for the year ended December 31, 2018 was $3.2 million based on a calculated fair value price ranging from $5.88 to $9.87 per share. Restricted Stock Options The restricted stock options granted are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The fair value for restricted stock options granted during the year ended December 31, 2017 have been estimated using 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 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 Granted — $ — Forfeited (2) (161,243 ) $ 5.01 Vested (356,155 ) $ 5.01 Restricted stock options outstanding at December 31, 2018 (Successor) — $ — (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) In connection with certain grants awarded in 2018 pursuant to the MIP, all remaining outstanding and unvested restricted stock options were forfeited. Stock Option Modification On April 27, 2018, in connection with the separation and retirement of certain executives as discussed in Note 1, the board of directors of the Company approved the acceleration of the vesting schedule for 298,354 unvested restricted stock option awards with an exercisable period of two years that otherwise would have been forfeited upon an involuntary termination. The acceleration of the restricted stock options 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 $0.3 million was recognized. The modified-date grant fair value was estimated using the Black-Scholes option pricing model using the following assumptions: Awards Issued in Successor Period Risk-free interest rate 2.49 % Dividend yield — Expected life (in years) 2.0 Expected volatility 50.0 % Strike Price $ 21.58 Calculated fair value per stock option $ 0.85 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 were reserved for issuance under the Directors Compensation Plan upon adoption. 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 with a service vesting condition (“Board RSUs”) granted are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with Board RSUs was $0.4 million at December 31, 2018. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.0 years. The following table summarizes information regarding the Board RSUs granted under the Director Compensation Plan for the period presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Board RSUs outstanding at May 5, 2017 (Successor) — $ — Granted (2) 16,341 $ 13.77 Forfeited — $ — Vested — $ — Board RSUs outstanding at December 31, 2017 (Successor) 16,341 $ 13.77 Granted (3) 28,708 $ 10.45 Forfeited — $ — Vested (5,445 ) $ 13.77 Board RSUs outstanding at December 31, 2018 (Successor) 39,604 $ 11.36 (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 Board RSUs issued in 2017 was $0.2 million based on grant date market price of $13.77 per share. (3) The aggregate grant date fair value of Board RSUs issued in 2018 was $0.3 million based on a grant date market price of $10.45 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 limited the number of common units that could be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that were cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations would have been 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 year ended December 31, 2016, there were 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 were 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 Predecessor 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” represented a time-vested unit. Such awards were 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 year ended December 31, 2016 was $0.1 million. The restricted common units granted were accounted for as equity-classified awards. The grant-date fair value was recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures accounted for as they occur. The fair value of the restricted unit awards granted to the independent directors of our Predecessor’s general partner was also recognized as compensation cost on a straight-line basis over the requisite service period. Compensation costs were 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, 2015 (Predecessor) 1,368,538 $ 17.61 Granted (2) 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 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 were 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 For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 Equity classified awards TSUs (Successor) $ 1,445 $ 1,906 $ — $ — PSUs (Successor) 1,404 — — — Board RSUs (Successor) 142 41 — — Restricted stock options (Successor) (214 ) 569 — — Restricted common units (Predecessor) — — 3,713 7,206 Liability classified awards Phantom units (Predecessor) — — (46 ) 322 $ 2,777 $ 2,516 $ 3,667 $ 7,528

Supplemental Disclosures to the

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows	12 Months Ended
	Dec. 31, 2018
Supplemental Disclosures To Condensed Consolidated Statements Of Cash Flows [Abstract]
Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows	Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): Successor December 31, December 31, 2018 2017 Accrued lease operating expense $ 10,469 $ 6,439 Accrued general and administrative expense 4,393 4,412 Accrued capital expenditures 4,349 3,854 Accrued interest payable 2,476 1,309 Accrued ad valorem tax 729 398 Asset retirement obligations 477 713 Other 262 1,108 Accrued liabilities $ 23,155 $ 18,233 Cash and Cash Equivalents Reconciliation The following table provides a reconciliation of cash and cash equivalents on the Consolidated Balance Sheet to cash, cash equivalents and restricted cash on the Statements of Consolidated Cash Flows (in thousands): Successor December 31, December 31, 2018 2017 Cash and cash equivalents $ 49,704 $ 6,392 Restricted cash 325 — Total cash, cash equivalents and restricted cash $ 50,029 $ 6,392 Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): Successor Predecessor Period from Period from For the May 5, 2017 January 1, 2017 For the Year Ended through through Year Ended December 31, 2018 December 31, 2017 May 4, 2017 December 31, 2016 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 17,083 $ 12,109 $ 6,598 $ 87,527 Cash paid for reorganization items, net 2,399 7,934 11,999 $ — Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (156 ) (1,080 ) 3,173 (6,284 ) (Increase) decrease in accounts receivable/payable related to divestiture — — — (289 ) Asset retirement obligation removal related to divestitures (15,702 ) — — (19,669 )

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
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. 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 For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 $ — $ — $ — $ 11,867 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 year ended December 31, 2018, 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
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 was required to bring all outstanding issues to closure no later than June 30, 2018. On June 14, 2018, we sent the EPA a letter informing the EPA that we had completed all remedial action items related to the Administrative Compliance Order on Consent. In September 2018, we came to an agreement regarding the potential violations, noting no 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 2018 2017 2016 (In thousands) (In thousands) Balance at beginning of period $ — $ — $ 216 Charged to costs and expenses — — — Payments — — (216 ) Balance at end of period $ — $ — $ — At December 31, 2018 and 2017, 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. Application for Final Decree On April 30, 2018, the Debtors filed with the Bankruptcy Court a motion for a final decree and entry of an order closing the Chapter 11 cases with respect to each of the Debtors other than (i) San Pedro Bay Pipeline Company, Ch. 11 Case No. 17-30249, (ii) Rise Energy Beta, LLC, Ch. 11 Case No. 17-30250, and (iii) Beta Operating Company, LLC, Ch. 11 Case No. 17-30253, (collectively, the “Closing Debtors”). On May 30, 2018, the Bankruptcy Court entered the final decree closing the Chapter 11 cases of the Closing Debtors. Sinking Fund Trust Agreement Beta Operating Company, LLC (“Beta”) assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of our properties in federal waters offshore California, 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, 2018, the account balance included in restricted investments was approximately $4.3 million. Supplemental Bond for Decommissioning Liabilities Trust Agreement Beta has an obligation with the BOEM in connection with the 2009 acquisition of the Beta properties. On October 5, 2018, the Company received approximately $61.5 million from the trust account (the “Beta Decommissioning Trust Account”). On November 20, 2018, the Company received an additional $1.0 million from the Beta Decommissioning Trust Account that had been withheld from the initial payment on October 5, 2018. The cash released to the Company’s balance sheet was made pursuant to an order of the Bankruptcy Court dated February 9, 2018, which allowed for the release of Beta cash subject to certain conditions that have since been satisfied. Following the cash release, Beta’s decommissioning obligations remain fully supported by A-rated surety bonds and $90.0 million of cash. 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 later in 2019. The gross held-to-maturity investments held in the trust account as of December 31, 2018 for the U.S. Bank money market cash equivalent was $90.2 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. For the year ended December 31, 2018, the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016, we recognized $8.6 million, $6.3 million, $3.1 million, and $10.9 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 2019 2020 2021 2022 2023 Thereafter Operating leases $ 11,846 $ 5,893 $ 2,072 $ 2,109 $ 337 $ 205 $ 1,230 Purchase Commitments At December 31, 2018, we had a CO 2 2 2 Payment or Settlement Due by Period Purchase commitment Total 2019 2020 2021 2022 2023 Thereafter CO 2 $ 8,315 $ 4,306 $ 4,009 $ — $ — $ — $ — Minimum Volume Commitment At December 31, 2018, 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 2019 2020 2021 2022 2023 Thereafter Midstream services $ 12,308 $ 3,075 $ 3,083 $ 3,075 $ 3,075 $ — $ —

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Tax	Note 18. 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. We previously reported provisional amounts resulting from the income tax effects of the Tax Act for which the accounting was incomplete, but a reasonable estimate could be determined. During the year ended December 31, 2018, our accounting for the income tax effects of the Tax Act was completed without material changes to the previously provided estimates. The components of income tax benefit (expense) are as follows: Successor Predecessor Period from Period from For the Year Ended May 5, 2017 January 1, 2017 For the Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 (In thousands) (In thousands) Current taxes: Federal $ — $ 4 $ — $ 6 State — (34 ) 17 8 Total current income tax benefit (expense) — (30 ) 17 14 Deferred taxes: Federal — 1,933 71 8 State — 273 3 (195 ) Total deferred income tax benefit (expense) — 2,206 74 (187 ) Total income tax benefit (expense) $ — $ 2,176 $ 91 $ (173 ) The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 21% in 2018 and 35% in 2017 and 2016 as follows: Successor Predecessor Period from Period from For the Year Ended May 5, 2017 January 1, 2017 For the Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 (In thousands) (In thousands) Expected tax benefit (expense) at federal statutory rate $ 11,468 $ 310 $ 5,764 $ 191,870 State income tax benefit (expense), net of federal benefit 1,108 240 30 382 Non-deductible expenses 1,328 (187 ) — — Changes in valuation allowances (14,194 ) 24,767 — — Remeasurement of federal deferred tax assets due rate change — (22,958 ) — — Pass-through entities (1) — — (5,686 ) (191,921 ) Other 290 4 (17 ) (504 ) Total income tax benefit (expense) $ — $ 2,176 $ 91 $ (173 ) (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 December 31, December 31, 2018 2017 Deferred income tax assets: Property, Plant & Equipment $ 2,208 $ 19,423 Derivative instrument — 6,251 Net operating loss carryforward 19,085 10,452 Asset retirement obligation — 1,223 Interest 5,748 — Accrued liabilities 1,387 — Other 307 779 Total deferred income tax assets: 28,735 38,128 Valuation allowance (23,934 ) (38,128 ) Net deferred income tax assets 4,801 — Deferred income tax liabilities: Property, plant and equipment $ — $ — Derivatives 4,801 — Other — — Total deferred income tax liabilities 4,801 — Net deferred income tax liabilities $ — $ — As of December 31, 2018, the Company had approximately $86.0 million of federal net operating loss carryovers of which $41.0 million federal net operating loss forwards have no expiration date and the remaining will expire in years 2035 – 2037. As of December 31, 2018, the Company had approximately $14.8 million of state net operating loss carryovers. The state net operating loss carryforwards 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, 2018, a valuation allowance of $23.9 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, 2018. Tax Audits and Settlements. Generally, our income tax years 2015 through 2018 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, 2018
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information (Unaudited)	Note 19. 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. Successor First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per share amounts) Revenues $ 87,932 $ 90,988 $ 85,522 $ 75,702 Operating income (loss) 9,529 (18,226 ) 3,206 87,014 Net income (loss) 3,239 (25,279 ) (2,598 ) 79,247 Net income (loss) attributable to Successor 3,239 (25,279 ) (2,598 ) 79,247 Net income (loss) available to common stockholders 3,156 (25,279 ) (2,598 ) 75,727 Basic and diluted earnings per share $ 0.13 $ (1.01 ) $ (0.10 ) $ 3.06 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 See Notes 4 and 13 for additional information regarding earnings per share/unit.

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2018
Extractive Industries [Abstract]
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 December 31, December 31, 2018 2017 (In thousands) Evaluated oil and natural gas properties $ 598,331 $ 603,053 Support equipment and facilities 108,760 100,225 Accumulated depletion, depreciation, and amortization (82,389 ) (34,429 ) Total $ 624,702 $ 668,849 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 For the May 5, 2017 Period from For the Year Ended through January 1, Year Ended December 31, December 31, 2017 through December 31, 2018 2017 May 4, 2017 2016 (In thousands) (In thousands) Property acquisition costs, proved $ — $ — $ — $ — Property acquisition costs, unproved — — — — Exploration — — — 792 Development 42,878 51,925 9,573 54,310 Total $ 42,878 $ 51,925 $ 9,573 $ 55,102 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, 2018. 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: 2018 2017 2016 Oil ($/Bbl): WTI (1) $ 65.56 $ 51.34 $ 42.75 NGL ($/Bbl): WTI (1) $ 65.56 $ 51.34 $ 42.75 Natural Gas ($/MMbtu): Henry Hub (2) $ 3.10 $ 2.98 $ 2.48 (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: Year Ended December 31, 2018 (Successor) Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 72,004 406,558 25,189 989,721 Extensions and discoveries 1,207 2,910 231 11,541 Production (3,335 ) (29,176 ) (1,496 ) (58,166 ) Sale of minerals in place (159 ) (56,328 ) (1,469 ) (66,095 ) Revision of previous estimates (93 ) (30,005 ) (883 ) (35,864 ) End of year 69,624 293,959 21,572 841,137 Proved developed reserves: Beginning of year 50,014 299,481 17,982 707,459 End of year 54,147 232,110 17,324 660,937 Proved undeveloped reserves: Beginning of year 21,990 107,077 7,207 282,262 End of year 15,477 61,849 4,248 180,200 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 period 72,004 406,558 25,189 989,721 Proved developed reserves: Beginning of period 57,803 297,101 21,963 775,693 End of period 50,014 299,481 17,982 707,459 Proved undeveloped reserves: Beginning of period 23,157 122,371 8,609 312,967 End of period 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 period 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 period 45,536 280,035 18,923 666,786 End of period 57,803 297,101 21,963 775,693 Proved undeveloped reserves: Beginning of period 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 Noteworthy amounts included in the categories of proved reserve changes in the above tables include: • The 148.6 Bcfe reduction in reserves for the year ended December 31, 2018 is primarily due to a 27.6 Bcfe upward pricing revision and a 63.5 Bcfe downward revision due to updated well performance data and future anticipated development and maintenance cost increases. We divested 66.1 Bcfe during the year ended December 31, 2018. We added 11.5 Bcfe during the year ended December 31, 2018 due to extensions and discoveries. • 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. See Note 6 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 For the May 5, 2017 Period from For the Year Ended through January 1, Year Ended December 31, December 31, 2017 through December 31, 2018 2017 May 4, 2017 2016 (In thousands) (In thousands) Future cash inflows $ 6,000,268 $ 5,149,623 $ 5,246,487 $ 3,666,731 Future production costs (3,280,778 ) (2,982,035 ) (3,275,952 ) (2,384,195 ) Future development costs (474,413 ) (530,133 ) (492,610 ) (440,496 ) Future income tax expense — — — — Future net cash flows for estimated timing of cash flows 2,245,077 1,637,455 1,477,925 842,040 10% annual discount for estimated timing of cash flows (1,132,048 ) (869,784 ) (786,836 ) (446,199 ) Standardized measure of discounted future net cash flows $ 1,113,029 $ 767,671 $ 691,089 $ 395,841 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, 2018: Successor Predecessor Period from For the May 5, 2017 Period from For the Year Ended through January 1, Year Ended December 31, December 31, 2017 through December 31, 2018 2017 May 4, 2017 2016 (In thousands) (In thousands) Beginning of year $ 767,671 $ 691,089 $ 395,841 $ 589,554 Sale of oil and natural gas produced, net of production costs (181,841 ) (100,946 ) (57,420 ) (107,357 ) Sale of minerals in place (29,036 ) — — (28,277 ) Extensions and discoveries 27,157 7,187 1,320 2,016 Changes in prices and costs 507,888 161,106 306,375 (404,870 ) Previously estimated development costs incurred 73,761 61,851 9,227 89,748 Net changes in future development costs 24,396 (31,438 ) (55,333 ) 254,043 Revisions of previous quantities (86,812 ) (27,060 ) 99,591 14,414 Accretion of discount 51,769 46,072 13,195 58,956 Change in production rates and other (41,924 ) (40,190 ) (21,707 ) (72,386 ) End of year $ 1,113,029 $ 767,671 $ 691,089 $ 395,841

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Share Repurchase Program See Note 12 for additional information regarding the share repurchase program.

Organization and Basis of Pre_2

Organization and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2018
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 located in the Rockies, federal waters offshore Southern California, East Texas / North Louisiana and South Texas. 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” refer 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; and (vii) “NGP” refers to Natural Gas Partners.
MEMP GP Acquisition	MEMP GP Acquisition 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 16 for additional information regarding the MEMP GP Acquisition and the transition services agreement.
Emergence from Voluntary Reorganization under Chapter 11	Emergence from Voluntary Reorganization under Chapter 11 On January 16, 2017 (the “Petition Date”), 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’ Chapter 11 proceedings were jointly administered under the caption In re: Memorial Production Partners LP, et al.
Management Changes	Management and Board Changes On April 27, 2018, the board of directors appointed Martyn Willsher to serve as Senior Vice President and Chief Financial Officer of the Company, effective April 27, 2018. On May 1, 2018, the Company announced the retirement of William J. Scarff, the Company’s President and Chief Executive Officer and member of the board of directors, which retirement became effective May 14, 2018. Also on May 1, 2018, the Company announced the departure of Christopher S. Cooper, Senior Vice President and Chief Operating Officer, and Robert L. Stillwell, Jr., Senior Vice President and Chief Financial Officer, from their respective positions with the Company, effective April 27, 2018. There were no disagreements between the Company and any of Messrs. Scarff, Cooper or Stillwell (collectively, the “Departing Executives”) which led to their retirement or separation (as applicable) from the Company. On May 4, 2018, the board of directors appointed Kenneth Mariani to serve as President and Chief Executive Officer of the Company, effective May 14, 2018. On May 17, 2018, Mr. Scarff resigned from the board of directors of the Company. There were no disagreements between Mr. Scarff and the Company which led to Mr. Scarff’s resignation from the board of directors. Also on May 17, 2018, the board of directors appointed Mr. Mariani to serve as a director of the Company to fill the vacancy caused by Mr. Scarff’s resignation. On July 25, 2018, the board of directors appointed Denise DuBard to serve as Vice President and Chief Accounting Officer of the Company, effective August 9, 2018. Also on July 25, 2018, Matthew J. Hoss tendered his resignation from his position as Vice President and Chief Accounting Officer of the Company, effective August 9, 2018. There were no disagreements between Mr. Hoss and the Company which led to his separation from the Company.
Basis of Presentation	Basis of Presentation Our Consolidated Financial Statements included herein have been prepared pursuant to the rule and guidelines of the Securities and Exchange Commission (the “SEC”). All material intercompany transactions and balances have been eliminated in preparation of our Consolidated Financial Statements. The accompanying Consolidated 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 (loss) on extinguishment of deferred finance cost were previously accounted for as interest expense, net and are now being presented as gain (loss) on extinguishment of debt on our Statement of Consolidated Operations. The Consolidated 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 Operations. The Company adopted the new accounting pronouncement related to the presentation of statement of cash flows — restricted cash in the first quarter of 2018. See Note 4 for additional information. A retrospective change for the period from January 1, 2017 through May 4, 2017 and May 5, 2017 through December 31, 2017 on the Statement of Consolidated Cash Flows as previously presented was required due to adoption. The table below sets forth the retrospective adjustments for the periods presented: Predecessor Previously Period from January 1, 2017 through May 4, 2017 Adjustment Effect As Adjusted Period from January 1, 2017 through May 4, 2017 (In thousands) Changes in operating assets and liabilities: Restricted cash $ (7,561 ) $ 7,561 $ — Net cash provided by operating activities 117,937 7,561 125,498 Net change in cash and cash equivalents 4,767 7,561 12,328 Cash and cash equivalents, end of period 20,140 7,561 27,701 Successor Previously Period from May 5, 2017 through December 31, 2017 Adjustment Effect As Adjusted Period from May 5, 2017 through December 30, 2017 (In thousands) Changes in operating assets and liabilities: Restricted cash $ 7,561 $ (7,561 ) $ — Net cash provided by operating activities 102,203 (7,561 ) 94,642 Net change in cash and cash equivalents (13,748 ) (7,561 ) (21,309 ) Cash and cash equivalents, end of period 6,392 — 6,392
Comparability of Financial Statements to Prior Periods	Comparability of Financial Statements to Prior Periods As discussed in further detail in Note 3 below, we 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 Financial Statements and Notes after May 4, 2017, are not comparable to the Consolidated Financial Statements and Notes prior to that date. To facilitate our financial statement presentations, we refer to the reorganized company in these Consolidated 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 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 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 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.
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 $1.2 million and $1.9 million as an allowance for doubtful accounts at December 31, 2018 and 2017, 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, 2018 and 2017.
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 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, 2018. 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 17 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 year ended December 31, 2018, the period from May 5, 2017 through December 31, 2017 and the year ended December 31, 2016 was approximately $2.5 million, $2.1 million, and $22.1 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 year ended December 31, 2018, 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 year ended December 31, 2016 was approximately $183.4 million. 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, 2018, 2017 and 2016.
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 9 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, 2018 and 2017. 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 we expect to be entitled to in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance and requires enhanced disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The standard was effective for the Company starting January 1, 2018, and the Company adopted the standard using a modified retrospective approach. See Note 5 for additional information. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Successor Predecessor For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 Major customers: Phillips 66 27% 23% 19% 19% Sinclair Oil & Gas Company 21% 19% 20% 16% CIMA Energy 10% 11% n/a n/a BP America Production Company n/a 10% 10% n/a Royal Dutch Shell plc and subsidiaries n/a n/a n/a 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 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 16 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, collars and puts) 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 year ended December 31, 2018, the period from May 5, 2017 through December 31, 2017 and the year ended December 31, 2016, we had $0.5 million, $0.4 million, and $0.5 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 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 13 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 awards subject to performance criteria; 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 14 for further information.
Recently Adopted Accounting Pronouncements	Recently Adopted Accounting Pronouncements Compensation—Stock Compensation. In May 2017, the FASB issued an accounting standard 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. Statement of Cash Flows – Restricted Cash a consensus of the FASB Emerging Issues Task Force. In November 2016, the FASB issued an accounting standard 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 and applied the disclosure requirements retrospectively.
New Accounting Pronouncements	New Accounting Pronouncements Fair Value Measurement . In August 2018, the FASB issued an amendment to modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement. Certain disclosure requirements were removed, modified and added and primarily relate to Level 3 hierarchy measurements and changes to non-public entities disclosures. The guidance is effective for all entities for fiscal years and interim periods within those fiscal years, beginning after December 15, 2019. The impact of this guidance is not expected to have a material impact on the Company. 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. In July 2018, the FASB issued a revision to lease accounting implementation guidance, targeting improvements to comparative reporting requirements for initial adoption. Previously, the reporting requirements for initial adoption required an entity to initially apply the new leases standard (subject to specific transition requirements and optional practical expedients) at the beginning of the earliest period presented in the financial statements (which is January 1, 2017, for calendar-year-end public business entities that adopt the new leases standard on January 1, 2019). Under this new revision an optional method in addition to the existing method allows entities to initially apply the new leases standard at the adoption date January 1, 2019 for calendar-year-end public business entities and recognize a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption. The FASB also issued another update in July on additional codification improvements, primarily corrections and clarifications. The Company will not early adopt this standard. The Company is the lessee under various agreements for office space, compressors, equipment, vehicles and surface rentals (right of use assets) that are currently accounted for as operating leases, see Note 17, for additional information. The Company will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019 using the modified retrospective approach with a cumulative impact to retained earnings in that period, and including several optional practical expedients relating to leases commenced before the effective date. The practical expedients the Company will adopt are: 1) the original correct assessment of a contract containing a lease will be accepted without further review on all existing or expired contracts; 2) the original lease classification as an operating lease will convert as an operating lease under the new guidance; 3) initial direct costs for any existing leases will not be reassessed; 4) existing land easements or right of use agreements will continue under current accounting policy and only new agreements will be evaluated in the future and 5) short-term leases for twelve months or less will not be evaluated under the guidance. The adoption of this standard will result in an increase in the assets and liabilities on the Company’s consolidated balance sheets. The Company has completed the review and evaluation of current and potential leases which resulted primarily in our corporate office lease and some minor equipment and vehicle leases qualifying under the new guidance. Based upon this analysis, the impact of the new guidance is expected to establish a liability and the corresponding asset of approximately $5.0 million to $6.0 million at inception related to leases existing as of January 1, 2019. 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.

Organization and Basis of Pre_3

Organization and Basis of Presentation (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Summary of Prior Period Adjustments in Cash Flows	The table below sets forth the retrospective adjustments for the periods presented: Predecessor Previously Period from January 1, 2017 through May 4, 2017 Adjustment Effect As Adjusted Period from January 1, 2017 through May 4, 2017 (In thousands) Changes in operating assets and liabilities: Restricted cash $ (7,561 ) $ 7,561 $ — Net cash provided by operating activities 117,937 7,561 125,498 Net change in cash and cash equivalents 4,767 7,561 12,328 Cash and cash equivalents, end of period 20,140 7,561 27,701 Successor Previously Period from May 5, 2017 through December 31, 2017 Adjustment Effect As Adjusted Period from May 5, 2017 through December 30, 2017 (In thousands) Changes in operating assets and liabilities: Restricted cash $ 7,561 $ (7,561 ) $ — Net cash provided by operating activities 102,203 (7,561 ) 94,642 Net change in cash and cash equivalents (13,748 ) (7,561 ) (21,309 ) Cash and cash equivalents, end of period 6,392 — 6,392

Fresh Start Accounting (Tables)

Fresh Start Accounting (Tables)	12 Months Ended
	Dec. 31, 2018
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 reflected 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 17) 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) Reflected 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) Reflected 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 Emergence 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) Reflected the transfer to restricted cash to fund the professional fees escrow account. (4) Reflected the pre-payment of certain professional fees. (5) Reflected the deferred financing costs related to the Emergence Credit Facility. (6) Reflected the recognition of payables for general unsecured claims. (7) Net increase in accrued liabilities reflected 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) Reflected a repayment of $24.8 million on the Predecessor’s revolving credit facility and the reclassification of $430.0 million in borrowings under the Emergence 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) Reflected 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) Reflected the write-off of the deferred rent and loss on sublease liabilities. (13) Reflected a decrease of $62.9 million for asset retirement obligations. The fair value of asset retirement obligations was 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) Reflected 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 Operations (in thousands): Successor Predecessor Period from Period from For the May 5, 2017 January 1, Year Ended through 2017 through December 31, 2018 December 31, 2017 May 4, 2017 Gain on settlement of liabilities subject to compromise $ — $ — $ 758,764 Fresh start valuation adjustments — — (827,120 ) Professional fees (864 ) (724 ) (19,824 ) Other (1,283 ) (395 ) (594 ) Reorganization items, net $ (2,147 ) $ (1,119 ) $ (88,774 )

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
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 For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 Major customers: Phillips 66 27% 23% 19% 19% Sinclair Oil & Gas Company 21% 19% 20% 16% CIMA Energy 10% 11% n/a n/a BP America Production Company n/a 10% 10% n/a Royal Dutch Shell plc and subsidiaries n/a n/a n/a 14%

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2018
Summary of Revenues Disaggregated	We have identified three material revenue streams in our business: oil, natural gas and NGLs. The following table present our revenues disaggregated by revenue stream. For the Year Ended December 31, 2018 (in thousands) Revenues Oil $ 209,066 NGLs 42,463 Natural gas 88,311 Oil and natural gas sales $ 339,840
ASC 606 [Member]
Summary of Oil and Gas Operating Income (Loss)	Although the adoption of ASC 606 did not have an impact on the Company’s net income or cash flows, it did result in the reclassification of fees incurred under certain gathering and gas processing agreements. Such reclassification led to an overall decrease in oil and natural gas sales with a corresponding decrease in gathering, processing and transportation as follows: For the Year Ended December 31, 2018 As Reported Previous Revenue Recognition Method Increase/ (Decrease) (in thousands) Revenues: Oil and natural gas sales $ 339,840 $ 342,210 $ (2,370 ) Cost and expenses: Gathering, processing and transportation 23,231 25,601 $ (2,370 ) Net income (loss) $ 54,609 $ 54,609 $ —

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Acquisition and Divestiture Related Expenses	Acquisition and divestiture related expenses for 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 For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 $ 205 $ 609 $ — $ 1,451
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 Operations of the Company is as follows (in thousands): Predecessor For the Year Ended December 31, 2016 Permian Divestiture $ 4,297 Rockies Divestiture (7,677 )

Fair Value Measurements of Fi_2

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and December 31, 2017 for each of the fair value hierarchy levels: Successor Fair Value Measurements at December 31, 2018 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 $ — $ 25,515 $ — $ 25,515 Liabilities: Commodity derivatives $ — $ 4,372 $ — $ 4,372 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

Risk Management and Derivativ_2

Risk Management and Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Open Commodity Positions	At December 31, 2018, the Company had the following open commodity positions: 2019 2020 Natural Gas Derivative Contracts: Fixed price swap contracts: Average monthly volume (MMBtu) 1,565,000 — Weighted-average fixed price $ 2.89 $ — Collar contracts: Average monthly volume (MMBtu) — 90,000 Weighted-average floor price — $ 2.60 Weighted-average ceiling price $ — $ 2.85 Crude Oil Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 148,000 — Weighted-average fixed price $ 53.06 $ — Collar contracts: Average monthly volume (Bbls) 38,000 14,300 Weighted-average floor price $ 55.00 $ 55.00 Weighted-average ceiling price $ 63.85 $ 62.10 Purchased put option contracts: Average Monthly Volume (Bbls) — 14,300 Weighted-average strike price $ — $ 55.00 NGL Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 72,000 18,200 Weighted-average fixed price $ 29.96 $ 28.67
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, 2018 and 2017. 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 New Credit Agreement. Successor Asset Derivatives Liability Derivatives Asset Derivatives Liability Derivatives December 31, December 31, December 31, December 31, Type Balance Sheet Location 2018 2018 2017 2017 (In thousands) Commodity contracts $ 21,217 $ 2,543 $ 37,729 $ 9,183 Gross fair value 21,217 2,543 37,729 9,183 Netting arrangements (2,404 ) (2,404 ) (9,183 ) (9,183 ) Net recorded fair value Short-term derivative instruments $ 18,813 $ 139 $ 28,546 $ — Commodity contracts $ 4,298 $ 1,829 $ 459 $ 5,929 Gross fair value 4,298 1,829 459 5,929 Netting arrangements (1,829 ) (1,829 ) (459 ) (459 ) Net recorded fair value Long-term derivative instruments $ 2,469 $ — $ — $ 5,470
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 For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended Statements of December 31, through through December 31, Operations Location 2018 December 31, 2017 May 4, 2017 2016 (Gain) loss on commodity derivatives $ (8,155 ) $ 31,609 $ (23,076 ) $ 117,105 Interest expense, net — — — 1,290

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
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 year ended December 31, 2018, the period from May 5, 2017 through December 31, 2017, the period from January 1, 2017 through May 4, 2017 and the year ended December 31, 2016 (in thousands): Successor Predecessor For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 Asset retirement obligations at beginning of period $ 100,173 $ 96,127 $ 155,702 $ 164,164 Liabilities added from acquisition or drilling 89 191 6 30 Liabilities removed upon sale of wells (15,702 ) — — (19,669 ) Liabilities settled (767 ) (633 ) (164 ) (1,442 ) Accretion expense 5,711 4,384 3,407 10,231 Revision of estimates (1) (13,160 ) 104 104 2,388 Asset retirement obligation at end of period 76,344 100,173 159,055 155,702 Fresh start adjustment (2) — — (62,928 ) — Less: Current Portion 477 713 941 789 Asset retirement obligations - long-term portion $ 75,867 $ 99,460 $ 95,186 $ 154,913 (1) The decrease in revision of estimates for the year ended December 31, 2018 is primarily due to receiving new cost estimates from third parties regarding the estimated plugging and abandonment costs. (2) 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, 2018
Investments Debt And Equity Securities [Abstract]
Restricted Investment Balances	The components of the restricted investment balances are as follows Successor December 31, December 31, 2018 2017 (In thousands) BOEM platform abandonment (See Note 17) $ 90,162 $ 152,272 Surety bond cash collateral — 501 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 4,305 4,058 Port of Long Beach pipeline license — 107 Restricted investments $ 94,467 $ 156,938

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Consolidated Debt Obligations	Our consolidated debt obligations consisted of the following at the dates indicated: Successor December 31, December 31, 2018 2017 (In thousands) $425.0 million New Revolving Credit Facility, variable-rate, due November 2023 (1) $ 294,000 $ — $1.0 billion Emergence Credit Facility, variable-rate, due March 2021 (1) — 376,000 Long-term debt $ 294,000 $ 376,000 (1) The carrying amount of our New Revolving Credit Facility and Emergence Credit Facility approximates fair value because the interest rates are variable and reflective of market rates.
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 For the Year Ended May 5, 2017 January 1, 2017 For the Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 New Revolving Credit Facility 4.96% n/a n/a n/a Emergence Credit Facility 5.75% 5.08% n/a n/a Predecessor's revolving credit facility n/a n/a 4.18% 3.28%

Equity (Deficit) (Tables)

Equity (Deficit) (Tables)	12 Months Ended
	Dec. 31, 2018
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 Shares/Units Partner 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 — Issuance of common stock — — Restricted stock units vested 163,700 — Repurchase of common shares (65,152 ) — Restricted common stock repurchased and retired under tender offer (2,916,667 ) — Balance, December 31, 2018 (Successor) 22,181,881 — (1) Restricted common units were 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 for the year ended December 31, 2016. 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
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, 2018
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 For the May 5, 2017 Period from For the Year Ended through January 1, Year Ended December 31, December 31, 2017 through December 31, 2018 2017 May 4, 2017 2016 Net income (loss) attributable to Successor/Predecessor $ 54,609 $ 1,286 $ (90,955 ) $ (540,398 ) Less: Predecessor's general partner's 0.1% interest in net income (loss) (1) — — — (168 ) Less: Net income (loss) allocated to participating restricted stockholders 2,426 35 — — Basic and diluted earnings available to common stockholders/limited partners $ 52,183 $ 1,251 $ (90,955 ) $ (540,230 ) Common shares/units: Common shares/units outstanding — basic 24,959 25,000 83,807 83,351 Dilutive effect of potential common shares — — — — Common shares/units outstanding — diluted (2) 24,959 25,000 83,807 83,351 Net earnings per share/unit: Basic $ 2.09 $ 0.05 $ (1.09 ) $ (6.48 ) Diluted $ 2.09 $ 0.05 $ (1.09 ) $ (6.48 ) Antidilutive stock options (3) — 517 — — Antidilutive warrants (4) 2,174 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. (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, 2018
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, 2015 (Predecessor) 1,368,538 $ 17.61 Granted (2) 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 2016 was $0.1 million based on grant date market price of $2.41 per unit.
Summary of Modified-Date Grant Fair Value Estimated Using Black-Scholes Option Pricing Model	The fair value for restricted stock options granted during the year ended December 31, 2017 have been estimated using 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 The modified-date grant fair value was estimated using the Black-Scholes option pricing model using the following assumptions: Awards Issued in Successor Period Risk-free interest rate 2.49 % Dividend yield — Expected life (in years) 2.0 Expected volatility 50.0 % Strike Price $ 21.58 Calculated fair value per stock option $ 0.85
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 Granted — $ — Forfeited (2) (161,243 ) $ 5.01 Vested (356,155 ) $ 5.01 Restricted stock options outstanding at December 31, 2018 (Successor) — $ — (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) In connection with certain grants awarded in 2018 pursuant to the MIP, all remaining outstanding and unvested restricted stock options were forfeited.
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 For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 Equity classified awards TSUs (Successor) $ 1,445 $ 1,906 $ — $ — PSUs (Successor) 1,404 — — — Board RSUs (Successor) 142 41 — — Restricted stock options (Successor) (214 ) 569 — — Restricted common units (Predecessor) — — 3,713 7,206 Liability classified awards Phantom units (Predecessor) — — (46 ) 322 $ 2,777 $ 2,516 $ 3,667 $ 7,528
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 Board RSUs granted under the Director Compensation Plan for the period presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) Board RSUs outstanding at May 5, 2017 (Successor) — $ — Granted (2) 16,341 $ 13.77 Forfeited — $ — Vested — $ — Board RSUs outstanding at December 31, 2017 (Successor) 16,341 $ 13.77 Granted (3) 28,708 $ 10.45 Forfeited — $ — Vested (5,445 ) $ 13.77 Board RSUs outstanding at December 31, 2018 (Successor) 39,604 $ 11.36 (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 Board RSUs issued in 2017 was $0.2 million based on grant date market price of $13.77 per share. (3) The aggregate grant date fair value of Board RSUs issued in 2018 was $0.3 million based on a grant date market price of $10.45 per share.
TSUs [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 TSUs granted under the MIP for the period presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) TSUs outstanding at May 5, 2017 (Successor) 614,754 $ 13.77 Granted (2) 173,070 $ 12.87 Forfeited (105,032 ) $ 13.77 Vested — $ — TSUs outstanding at December 31, 2017 (Successor) 682,792 $ 13.54 Granted (3) 437,000 $ 10.51 Forfeited (4) (363,513 ) $ 13.55 Vested (158,255 ) $ 13.44 TSUs outstanding at December 31, 2018 (Successor) 598,024 $ 11.35 (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 TSUs 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. (3) The aggregate grant date fair value of TSUs issued for the year ended December 31, 2018 was $4.6 million based on a grant date market price ranging from $9.30 to $11.00 per share. (4) In connection with the separation and retirement agreements of certain executives as discussed in Note 1, the Departing Executives forfeited 298,354 TSUs during the year ended December 31, 2018.
PSUs [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 PSUs granted under the MIP for the period presented: Weighted- Average Grant Number of Date Fair Value Units per Unit (1) PSUs outstanding at December 31, 2017 (Successor) — $ — Granted (2) 395,500 $ 8.14 Forfeited (2,000 ) $ 7.59 Vested — $ — PSUs outstanding at December 31, 2018 (Successor) 393,500 $ 8.14 (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 PSUs issued for the year ended December 31, 2018 was $3.2 million based on a calculated fair value price ranging from $5.88 to $9.87 per share.
Schedule of Fair Value Assumptions for PSUs	A Monte Carlo simulation was used to determine the fair value of these awards at the grant date. The assumptions used to estimate the fair value of the PSUs are as follows: Share price targets $ 12.50 $ 15.00 $ 17.50 Risk-free interest rate: Awards Issued on May 14, 2018 2.68 % 2.68 % 2.68 % Awards Issued on July 1, 2018 2.61 % 2.61 % 2.61 % Awards Issued on August 1, 2018 2.76 % 2.76 % 2.76 % Awards Issued on October 1, 2018 2.88 % 2.88 % 2.88 % Awards Issued on November 1, 2018 2.89 % 2.89 % 2.89 % Dividend yield — — — Expected volatility: Awards Issued on May 14, 2018 50.0 % 50.0 % 50.0 % Awards Issued on July 1, 2018 50.0 % 50.0 % 50.0 % Awards Issued on August 1, 2018 55.0 % 55.0 % 55.0 % Awards Issued on October 1, 2018 53.0 % 53.0 % 53.0 % Awards Issued on November 1, 2018 54.0 % 54.0 % 54.0 % Calculated fair value per PSU: Awards Issued on May 14, 2018 $ 9.71 $ 8.52 $ 7.48 Awards Issued on July 1, 2018 $ 9.87 $ 8.72 $ 7.68 Awards Issued on August 1, 2018 $ 9.79 $ 8.66 $ 7.65 Awards Issued on October 1, 2018 $ 8.54 $ 7.57 $ 6.66 Awards Issued on November 1, 2018 $ 7.65 $ 6.72 $ 5.88

Supplemental Disclosures to t_2

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Summary of Current Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands): Successor December 31, December 31, 2018 2017 Accrued lease operating expense $ 10,469 $ 6,439 Accrued general and administrative expense 4,393 4,412 Accrued capital expenditures 4,349 3,854 Accrued interest payable 2,476 1,309 Accrued ad valorem tax 729 398 Asset retirement obligations 477 713 Other 262 1,108 Accrued liabilities $ 23,155 $ 18,233
Summary of Cash and Cash Equivalents Reconciliation	The following table provides a reconciliation of cash and cash equivalents on the Consolidated Balance Sheet to cash, cash equivalents and restricted cash on the Statements of Consolidated Cash Flows (in thousands): Successor December 31, December 31, 2018 2017 Cash and cash equivalents $ 49,704 $ 6,392 Restricted cash 325 — Total cash, cash equivalents and restricted cash $ 50,029 $ 6,392
Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands): Successor Predecessor Period from Period from For the May 5, 2017 January 1, 2017 For the Year Ended through through Year Ended December 31, 2018 December 31, 2017 May 4, 2017 December 31, 2016 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 17,083 $ 12,109 $ 6,598 $ 87,527 Cash paid for reorganization items, net 2,399 7,934 11,999 $ — Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (156 ) (1,080 ) 3,173 (6,284 ) (Increase) decrease in accounts receivable/payable related to divestiture — — — (289 ) Asset retirement obligation removal related to divestitures (15,702 ) — — (19,669 )

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2018
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 For the Period from Period from For the Year Ended May 5, 2017 January 1, 2017 Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 $ — $ — $ — $ 11,867

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Environmental Reserves	The following table presents the activity of our environmental reserves for the periods presented: Successor Predecessor 2018 2017 2016 (In thousands) (In thousands) Balance at beginning of period $ — $ — $ 216 Charged to costs and expenses — — — Payments — — (216 ) Balance at end of period $ — $ — $ —
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 2019 2020 2021 2022 2023 Thereafter Operating leases $ 11,846 $ 5,893 $ 2,072 $ 2,109 $ 337 $ 205 $ 1,230
Purchase Commitments Under the Contracts	At December 31, 2018, we had a CO 2 2 2 Payment or Settlement Due by Period Purchase commitment Total 2019 2020 2021 2022 2023 Thereafter CO 2 $ 8,315 $ 4,306 $ 4,009 $ — $ — $ — $ — At December 31, 2018, 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 2019 2020 2021 2022 2023 Thereafter Midstream services $ 12,308 $ 3,075 $ 3,083 $ 3,075 $ 3,075 $ — $ —

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
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 For the Year Ended May 5, 2017 January 1, 2017 For the Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 (In thousands) (In thousands) Current taxes: Federal $ — $ 4 $ — $ 6 State — (34 ) 17 8 Total current income tax benefit (expense) — (30 ) 17 14 Deferred taxes: Federal — 1,933 71 8 State — 273 3 (195 ) Total deferred income tax benefit (expense) — 2,206 74 (187 ) Total income tax benefit (expense) $ — $ 2,176 $ 91 $ (173 )
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 21% in 2018 and 35% in 2017 and 2016 as follows: Successor Predecessor Period from Period from For the Year Ended May 5, 2017 January 1, 2017 For the Year Ended December 31, through through December 31, 2018 December 31, 2017 May 4, 2017 2016 (In thousands) (In thousands) Expected tax benefit (expense) at federal statutory rate $ 11,468 $ 310 $ 5,764 $ 191,870 State income tax benefit (expense), net of federal benefit 1,108 240 30 382 Non-deductible expenses 1,328 (187 ) — — Changes in valuation allowances (14,194 ) 24,767 — — Remeasurement of federal deferred tax assets due rate change — (22,958 ) — — Pass-through entities (1) — — (5,686 ) (191,921 ) Other 290 4 (17 ) (504 ) Total income tax benefit (expense) $ — $ 2,176 $ 91 $ (173 ) (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 December 31, December 31, 2018 2017 Deferred income tax assets: Property, Plant & Equipment $ 2,208 $ 19,423 Derivative instrument — 6,251 Net operating loss carryforward 19,085 10,452 Asset retirement obligation — 1,223 Interest 5,748 — Accrued liabilities 1,387 — Other 307 779 Total deferred income tax assets: 28,735 38,128 Valuation allowance (23,934 ) (38,128 ) Net deferred income tax assets 4,801 — Deferred income tax liabilities: Property, plant and equipment $ — $ — Derivatives 4,801 — Other — — Total deferred income tax liabilities 4,801 — Net deferred income tax liabilities $ — $ —

Quarterly Financial Informati_2

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
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. Successor First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per share amounts) Revenues $ 87,932 $ 90,988 $ 85,522 $ 75,702 Operating income (loss) 9,529 (18,226 ) 3,206 87,014 Net income (loss) 3,239 (25,279 ) (2,598 ) 79,247 Net income (loss) attributable to Successor 3,239 (25,279 ) (2,598 ) 79,247 Net income (loss) available to common stockholders 3,156 (25,279 ) (2,598 ) 75,727 Basic and diluted earnings per share $ 0.13 $ (1.01 ) $ (0.10 ) $ 3.06 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

Supplemental Oil and Gas Info_2

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
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 December 31, December 31, 2018 2017 (In thousands) Evaluated oil and natural gas properties $ 598,331 $ 603,053 Support equipment and facilities 108,760 100,225 Accumulated depletion, depreciation, and amortization (82,389 ) (34,429 ) Total $ 624,702 $ 668,849
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 For the May 5, 2017 Period from For the Year Ended through January 1, Year Ended December 31, December 31, 2017 through December 31, 2018 2017 May 4, 2017 2016 (In thousands) (In thousands) Property acquisition costs, proved $ — $ — $ — $ — Property acquisition costs, unproved — — — — Exploration — — — 792 Development 42,878 51,925 9,573 54,310 Total $ 42,878 $ 51,925 $ 9,573 $ 55,102
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: 2018 2017 2016 Oil ($/Bbl): WTI (1) $ 65.56 $ 51.34 $ 42.75 NGL ($/Bbl): WTI (1) $ 65.56 $ 51.34 $ 42.75 Natural Gas ($/MMbtu): Henry Hub (2) $ 3.10 $ 2.98 $ 2.48 (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: Year Ended December 31, 2018 (Successor) Oil Gas NGLs Equivalent (MBbls) (MMcf) (MBbls) (MMcfe) Proved developed and undeveloped reserves: Beginning of year 72,004 406,558 25,189 989,721 Extensions and discoveries 1,207 2,910 231 11,541 Production (3,335 ) (29,176 ) (1,496 ) (58,166 ) Sale of minerals in place (159 ) (56,328 ) (1,469 ) (66,095 ) Revision of previous estimates (93 ) (30,005 ) (883 ) (35,864 ) End of year 69,624 293,959 21,572 841,137 Proved developed reserves: Beginning of year 50,014 299,481 17,982 707,459 End of year 54,147 232,110 17,324 660,937 Proved undeveloped reserves: Beginning of year 21,990 107,077 7,207 282,262 End of year 15,477 61,849 4,248 180,200 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 period 72,004 406,558 25,189 989,721 Proved developed reserves: Beginning of period 57,803 297,101 21,963 775,693 End of period 50,014 299,481 17,982 707,459 Proved undeveloped reserves: Beginning of period 23,157 122,371 8,609 312,967 End of period 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 period 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 period 45,536 280,035 18,923 666,786 End of period 57,803 297,101 21,963 775,693 Proved undeveloped reserves: Beginning of period 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
Standardized Measure of Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows is as follows: Successor Predecessor Period from For the May 5, 2017 Period from For the Year Ended through January 1, Year Ended December 31, December 31, 2017 through December 31, 2018 2017 May 4, 2017 2016 (In thousands) (In thousands) Future cash inflows $ 6,000,268 $ 5,149,623 $ 5,246,487 $ 3,666,731 Future production costs (3,280,778 ) (2,982,035 ) (3,275,952 ) (2,384,195 ) Future development costs (474,413 ) (530,133 ) (492,610 ) (440,496 ) Future income tax expense — — — — Future net cash flows for estimated timing of cash flows 2,245,077 1,637,455 1,477,925 842,040 10% annual discount for estimated timing of cash flows (1,132,048 ) (869,784 ) (786,836 ) (446,199 ) Standardized measure of discounted future net cash flows $ 1,113,029 $ 767,671 $ 691,089 $ 395,841
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, 2018: Successor Predecessor Period from For the May 5, 2017 Period from For the Year Ended through January 1, Year Ended December 31, December 31, 2017 through December 31, 2018 2017 May 4, 2017 2016 (In thousands) (In thousands) Beginning of year $ 767,671 $ 691,089 $ 395,841 $ 589,554 Sale of oil and natural gas produced, net of production costs (181,841 ) (100,946 ) (57,420 ) (107,357 ) Sale of minerals in place (29,036 ) — — (28,277 ) Extensions and discoveries 27,157 7,187 1,320 2,016 Changes in prices and costs 507,888 161,106 306,375 (404,870 ) Previously estimated development costs incurred 73,761 61,851 9,227 89,748 Net changes in future development costs 24,396 (31,438 ) (55,333 ) 254,043 Revisions of previous quantities (86,812 ) (27,060 ) 99,591 14,414 Accretion of discount 51,769 46,072 13,195 58,956 Change in production rates and other (41,924 ) (40,190 ) (21,707 ) (72,386 ) End of year $ 1,113,029 $ 767,671 $ 691,089 $ 395,841

Organization and Basis of Pre_4

Organization and Basis of Presentation - Additional Information (Detail)	Apr. 27, 2016USD ($)	Dec. 31, 2018Segment
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments | Segment		1
MEMP GP [Member]
Consolidation And Basis Of Presentation [Line Items]
Acquisition purchase price	$ 800,000
Partnership ownership percentage	0.10%
Gain (loss) on acquisition	$ 0
Related party transaction, description of transaction		In connection with the closing of the transactions on June 1, 2016, our 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] | NGP IDR [Member] | MEMP GP [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage	50.00%
Natural Gas Partners [Member] | NGP IDR [Member]
Consolidation And Basis Of Presentation [Line Items]
Agreed ownership interest percentage to acquire	50.00%

Organization and Basis of Pre_5

Organization and Basis of Presentation - Summary of Prior Period Adjustments in Cash Flows (Details) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Restricted cash		$ 0
Net cash provided by operating activities		94,642	$ 141,781
Net change in cash and cash equivalents		(21,309)
Cash and cash equivalents	$ 20,140	6,392	$ 49,704
Previously Reported [Member]
Restricted cash		7,561
Net cash provided by operating activities		102,203
Net change in cash and cash equivalents		(13,748)
Cash and cash equivalents		6,392
Adjustment Effect [Member]
Restricted cash		(7,561)
Net cash provided by operating activities		(7,561)
Net change in cash and cash equivalents		(7,561)
Cash and cash equivalents		$ 0
Predecessor [Member]
Restricted cash	0
Net cash provided by operating activities	125,498			$ 408,626
Net change in cash and cash equivalents	12,328
Cash and cash equivalents	27,701
Predecessor [Member] | Previously Reported [Member]
Restricted cash	(7,561)
Net cash provided by operating activities	117,937
Net change in cash and cash equivalents	4,767
Cash and cash equivalents	20,140
Predecessor [Member] | Adjustment Effect [Member]
Restricted cash	7,561
Net cash provided by operating activities	7,561
Net change in cash and cash equivalents	7,561
Cash and cash equivalents	$ 7,561

Emergence from Voluntary Reor_2

Emergence from Voluntary Reorganization under Chapter 11 - Additional Information (Detail) - USD ($)	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018
Reorganizations [Line Items]
Common stock, par value		$ 0.0001	$ 0.0001
Warrant issued during period		2,173,913	2,173,913
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	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	Dec. 31, 2018
Fresh Start Adjustment [Line Items]
Enterprise value	$ 800,000,000
Repayment of predecessor's revolving credit facility		$ 63,000,000	$ 397,000,000
Reorganization Adjustments [Member]
Fresh Start Adjustment [Line Items]
Repayment of predecessor's revolving credit facility	24,800,000
Reclassification of borrowings under the emergence 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 [Member]
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, 2018	Dec. 31, 2017	May 04, 2017	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 49,704	$ 6,392	$ 20,140
Restricted cash	325	0	7,411
Accounts receivable	29,514	36,391	33,560
Short-term derivative instruments	18,813	28,546	51,329
Prepaid expenses and other current assets	7,241	7,220	10,904
Total current assets	105,597	78,549	123,344
Property and equipment, net	628,181	673,432	657,336
Long-term derivative instruments	2,469	0	33,800
Restricted investments	94,467	156,938	156,443
Other long-term assets	6,129	8,545	10,504
Total assets	836,843	917,464	981,427
Current liabilities:
Accounts payable	2,345	1,941	2,890
Revenues payable	24,779	22,427	22,747
Accrued liabilities	23,155	18,233	38,180
Current portion of long-term debt			0
Total current liabilities	50,418	42,601	63,817
Liabilities subject to compromise			0
Long-term debt	294,000	376,000	430,000
Asset retirement obligations	75,867	99,460	95,186
Deferred tax liabilities	0	0	2,206
Other long-term liabilities			78
Total liabilities	420,285	523,531	591,287
Commitments and contingencies (see Note 17)			0
Stockholders' equity:
Predecessor common units			0
Successor warrants	4,788	4,788	4,788
Successor common stock	3	3	3
Additional paid-in capital	355,872	387,856	385,349
Total stockholders' equity	416,558	393,933	390,140
Total liabilities and equity	$ 836,843	$ 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 17)			0
Stockholders' equity:
Predecessor common units			(80,601)
Successor warrants			4,788
Successor common stock			3
Additional paid-in capital			1,212,469
Total stockholders'/ 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 17)			0
Stockholders' equity:
Predecessor common units			0
Successor warrants			0
Successor common stock			0
Additional paid-in capital			(827,120)
Total stockholders'/ partners' equity			(827,120)
Total liabilities and equity			(894,164)
Predecessor [Member]
Current assets:
Cash and cash equivalents			27,701
Property and equipment, net			1,551,500
Current liabilities:
Asset retirement obligations			95,186	$ 154,913
Stockholders' equity:
Total stockholders'/ partners' equity			0	$ 99,489	$ 645,492
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 17)			0
Stockholders' equity:
Predecessor common units			80,601
Successor warrants			0
Successor common stock			0
Additional paid-in capital			0
Total stockholders'/ 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

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	Dec. 31, 2018
Payment to holders of the Notes			$ (8,193)	$ 0
Changes in cash and cash equivalents			$ (21,309)
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 Emergence 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.

Fresh Start Accounting - Summ_2

Fresh Start Accounting - Summary of Changes in Cash and Cash Equivalents (Parenthetical) (Details) - USD ($) $ in Thousands		May 04, 2017	Dec. 31, 2017	Dec. 31, 2018
Total cash settlement to the holders of the notes			$ 8,193	$ 0
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 - Summ_3

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, 2018	Dec. 31, 2016
Fresh Start Adjustment [Line Items]
Total liabilities subject to compromise of Predecessor	$ 0	$ 0
Payment to holders of the Notes			$ (8,193)	$ 0
Gain on settlement of liabilities subject to compromise			$ 0	$ 0
Predecessor [Member]
Fresh Start Adjustment [Line Items]
Payment to holders of the Notes		(16,446)			$ 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 - Sche_2

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, 2018
Fresh Start Adjustment [Line Items]
Recognition on gain on settlement of liabilities subject to compromise			$ 0	$ 0
Par value of common stock		$ (377,645)
Par value of common stock	$ 3	3	$ 3	$ 3
Predecessor [Member]
Fresh Start Adjustment [Line Items]
Recognition on gain on settlement of liabilities subject to compromise		758,764
Recognition of contribution from management		1,500
Recognition of settlement with Predecessor common unitholders		1,250
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
Recognition of contribution from management	1,500
Par value of common stock	(3)
Change in Successor additional paid-in capital	1,212,469	1,212,469
Par value of 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 - Sche_3

Fresh Start Accounting - Schedule of Fresh Start Adjustments to Property and Equipment, Net (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	May 04, 2017
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	$ 598,331	$ 603,053	$ 657,336
Support equipment and facilities	108,760	100,225
Other	6,625	6,133	6,007
Accumulated depreciation, depletion and impairment	(85,535)	(35,979)	0
Property and equipment, net	$ 628,181	$ 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
Other			15,420
Accumulated depreciation, depletion and impairment			(1,787,520)
Property and equipment, net			1,551,500
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 - Sche_4

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, 2018	Dec. 31, 2016
Fresh Start Adjustment [Line Items]
Gain on settlement of liabilities subject to compromise		$ 0	$ 0
Fresh start valuation adjustments		0	0
Professional fees		(724)	(864)
Other		(395)	(1,283)
Reorganization items, net		$ (1,119)	$ (2,147)
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

Summary of Significant Accoun_3

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	Jan. 01, 2019
Summary Of Significant Accounting Policies [Line Items]
Allowance for doubtful accounts		$ 1,900,000	$ 1,200,000	$ 1,900,000
Capitalized exploratory drilling costs pending evaluation			0	$ 0
Amortization expense including write-off of debt issuance costs	$ 0	2,100,000	2,500,000		$ 22,100,000
Impairment expense	0	0	0
Capitalized interest	0	$ 400,000	$ 500,000		$ 500,000
Chance of tax benefit likely to be realized			greater than 50%
Federal corporate tax rate			21.00%	35.00%	35.00%
Tax cuts and jobs act of 2017, limitations on NOLs percentage of taxable income			80.00%	80.00%
Customer Concentration Risk [Member] | Revenues [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of total revenue			10.00%
Predecessor [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment expense	$ 0				$ 183,437,000
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Percentage of voting shares to be received by voting share holders			50.00%
Maximum [Member] | ASU 2016-02 [Member] | Subsequent Event [Member]
Summary Of Significant Accounting Policies [Line Items]
Operating lease, assets and liabilities						$ 6,000,000
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] | ASU 2016-02 [Member] | Subsequent Event [Member]
Summary Of Significant Accounting Policies [Line Items]
Operating lease, assets and liabilities						$ 5,000,000
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 Accoun_4

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, 2018	Dec. 31, 2016
Significant Accounting Policies [Line Items]
Total Reported Revenues			10.00%
Phillips 66 [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		23.00%	27.00%
Sinclair Oil & Gas Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		19.00%	21.00%
BP America Production Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		10.00%	0.00%
Royal Dutch Shell plc and subsidiaries [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		0.00%	0.00%
CIMA Energy [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		11.00%	10.00%
Predecessor [Member] | Phillips 66 [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	19.00%			19.00%
Predecessor [Member] | Sinclair Oil & Gas Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	20.00%			16.00%
Predecessor [Member] | BP America Production Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	10.00%			0.00%
Predecessor [Member] | Royal Dutch Shell plc and subsidiaries [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	0.00%			14.00%
Predecessor [Member] | CIMA Energy [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	0.00%			0.00%

Revenue - Summary of Impact of

Revenue - Summary of Impact of Adoption of ASC 606 (Detail) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended						8 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2018
Revenues:
Oil and natural gas sales	$ 42,395	$ 75,702	$ 85,522	$ 90,988	$ 87,932	$ 87,495	$ 75,589	$ 205,479	$ 340,144
Costs and expenses:
Net income (loss)	$ (906)	$ 79,247	$ (2,598)	$ (25,279)	$ 3,239	$ 9,728	$ (7,536)	1,286	54,609
ASC 606 [Member] | Previous Revenue Recognition Method [Member]
Costs and expenses:
Net income (loss)									54,609
ASC 606 [Member] | Increase/ (Decrease) Due to ASC 606 [Member]
Costs and expenses:
Net income (loss)									0
Oil and Natural Gas Sales [Member]
Revenues:
Oil and natural gas sales								205,176	339,840
Oil and Natural Gas Sales [Member] | ASC 606 [Member] | Previous Revenue Recognition Method [Member]
Revenues:
Oil and natural gas sales									342,210
Oil and Natural Gas Sales [Member] | ASC 606 [Member] | Increase/ (Decrease) Due to ASC 606 [Member]
Revenues:
Oil and natural gas sales									(2,370)
Gathering, Processing and Transportation [Member]
Costs and expenses:
Gathering, processing and transportation								$ 18,652	23,231
Gathering, Processing and Transportation [Member] | ASC 606 [Member] | Previous Revenue Recognition Method [Member]
Costs and expenses:
Gathering, processing and transportation									25,601
Gathering, Processing and Transportation [Member] | ASC 606 [Member] | Increase/ (Decrease) Due to ASC 606 [Member]
Costs and expenses:
Gathering, processing and transportation									$ (2,370)

Revenue - Summary of Revenues D

Revenue - Summary of Revenues Disaggregated (Detail) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended						8 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2018
Revenues:
Oil and natural gas sales	$ 42,395	$ 75,702	$ 85,522	$ 90,988	$ 87,932	$ 87,495	$ 75,589	$ 205,479	$ 340,144
Oil and Natural Gas Sales [Member]
Revenues:
Oil and natural gas sales								$ 205,176	339,840
Oil [Member]
Revenues:
Oil and natural gas sales									209,066
NGLs [Member]
Revenues:
Oil and natural gas sales									42,463
Natural Gas [Member]
Revenues:
Oil and natural gas sales									$ 88,311

Revenue - Additional Informatio

Revenue - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Revenue From Contract With Customer [Abstract]
Accounts receivable attributable to revenue contracts with customers	$ 25	$ 30.1

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, 2018	Dec. 31, 2016
Business Acquisition [Line Items]
Business Acquisition and Divestiture, Related Expenses		$ 609	$ 205
Predecessor [Member]
Business Acquisition [Line Items]
Business Acquisition and Divestiture, Related Expenses	$ 0			$ 1,451

Acquisitions and Divestitures_2

Acquisitions and Divestitures - Additional Information (Detail) - USD ($)	May 30, 2018	Jul. 14, 2016	Jun. 14, 2016	Dec. 31, 2018	Dec. 31, 2016	Dec. 31, 2017	May 04, 2017
Business Acquisition And Divestiture [Line Items]
Accounts payable				$ 2,345,000		$ 1,941,000	$ 2,890,000
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
(Gain) loss on sale of properties		$ 4,200,000
Permian Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
(Gain) loss on sale of properties			$ (6,100,000)
Immaterial Divestitures [Member]
Business Acquisition And Divestiture [Line Items]
(Gain) loss on sale of 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]
Business Acquisition And Divestiture [Line Items]
(Gain) loss on sale of properties				3,600,000
Disposal Group Not Discontinued Operation [Member] | South Texas Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Total net proceeds from divestitures	$ 17,100,000
Proceeds from divestitures	18,600,000
Accounts payable	500,000
Legal and advisor expenses	$ 900,000			$ 0
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

Acquisitions and Divestitures_3

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

Fair Value Measurements of Fi_3

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, 2018	Dec. 31, 2017
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	$ 25,515	$ 38,188
Liabilities	4,372	15,112
Quoted Prices in Active Market (Level 1) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0	0
Liabilities	0	0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	25,515	38,188
Liabilities	4,372	15,112
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Assets	0	0
Liabilities	$ 0	$ 0

Fair Value Measurements of Fi_4

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, 2018	Dec. 31, 2016
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	$ 0	$ 0	$ 0
Predecessor [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment of proved oil and natural gas properties	$ 0			$ 183,437,000
Predecessor [Member] | East Texas [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

Risk Management and Derivativ_3

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, 2018	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				$ 21.2
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 Derivativ_4

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	12 Months Ended
	Dec. 31, 2018MMBTU$ / MMBTU$ / bblbbl
Natural Gas Derivative Contracts Fixed Price Swap 2018 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	0
Weighted-average fixed price | $ / MMBTU	0
Natural Gas Derivative Collar Contracts 2020 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	90,000
Weighted-average floor price	2.60
Weighted-average ceiling price	2.85
Crude Oil Derivative Contracts Fixed Price Swap 2020 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	0
Weighted-average fixed price	0
Crude Oil Derivative Collar Contracts 2020 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	14,300
Weighted-average floor price	55
Weighted-average ceiling price	62.10
NGL Derivative Contracts Fixed Price Swap 2020 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	18,200
Weighted-average fixed price	28.67
Crude Oil Derivative Purchased Put Option 2020 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	14,300
Weighted-average strike price	55
Natural Gas Derivative Contracts Fixed Price Swap 2019 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	1,565,000
Weighted-average fixed price | $ / MMBTU	2.89
Natural Gas Derivative Collar Contracts 2019 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	0
Weighted-average floor price	0
Weighted-average ceiling price	0
Crude Oil Derivative Contracts Fixed Price Swap 2019 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	148,000
Weighted-average fixed price	53.06
Crude Oil Derivative Collar Contracts 2019 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	38,000
Weighted-average floor price	55
Weighted-average ceiling price	63.85
Crude Oil Derivative Purchased Put Option 2019 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	0
Weighted-average strike price	0
NGL Derivative Contracts Fixed Price Swap Contracts 2019 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	72,000
Weighted-average fixed price	29.96

Risk Management and Derivativ_5

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	May 04, 2017
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 18,813	$ 28,546	$ 51,329
Asset Derivatives, Net recorded fair value	2,469	0	$ 33,800
Liability Derivatives, Net recorded fair value	139	0
Liability Derivatives, Net recorded fair value	0	5,470
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	21,217	37,729
Asset Derivatives, Netting arrangements	(2,404)	(9,183)
Asset Derivatives, Net recorded fair value	18,813	28,546
Liability Derivatives, Gross fair value	2,543	9,183
Liability Derivatives, Netting arrangements	(2,404)	(9,183)
Liability Derivatives, Net recorded fair value	139	0
Short-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	21,217	37,729
Liability Derivatives, Gross fair value	2,543	9,183
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	4,298	459
Asset Derivatives, Netting arrangements	(1,829)	(459)
Asset Derivatives, Net recorded fair value	2,469	0
Liability Derivatives, Gross fair value	1,829	5,929
Liability Derivatives, Netting arrangements	(1,829)	(459)
Liability Derivatives, Net recorded fair value	0	5,470
Long-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	4,298	459
Liability Derivatives, Gross fair value	$ 1,829	$ 5,929

Risk Management and Derivativ_6

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, 2018	Dec. 31, 2016
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments		$ 31,609	$ (8,155)
Interest expense, net		(15,936)	(21,923)
Predecessor [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	$ (23,076)			$ 117,105
Interest expense, net	(10,243)			(146,031)
Commodity derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments		31,609	(8,155)
Commodity derivatives [Member] | Predecessor [Member]
Derivative Instruments Gain Loss [Line Items]
(Gain) loss on commodity derivative instruments	(23,076)			117,105
Interest rate derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net		$ 0	$ 0
Interest rate derivatives [Member] | Predecessor [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net	$ 0			$ 1,290

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, 2018	Dec. 31, 2016
Asset Retirement Obligations [Line Items]
Asset retirement obligations at beginning of period			$ 96,127	$ 100,173
Liabilities added from acquisition or drilling			191	89
Liabilities removed upon sale of wells			0	(15,702)
Liabilities settled			(633)	(767)
Accretion expense			4,384	5,711
Revision of estimates	[1]		104	(13,160)
Asset retirement obligation at end of period		$ 96,127	100,173	76,344
Fresh start adjustment	[2]		0	0
Less: Current Portion			713	477
Asset retirement obligations - long-term portion		95,186	99,460	$ 75,867
Predecessor [Member]
Asset Retirement Obligations [Line Items]
Asset retirement obligations at beginning of period		155,702	$ 159,055		$ 164,164
Liabilities added from acquisition or drilling		6			30
Liabilities removed upon sale of wells		0			(19,669)
Liabilities settled		(164)			(1,442)
Accretion expense		3,407			10,231
Revision of estimates	[1]	104			2,388
Asset retirement obligation at end of period		159,055			155,702
Fresh start adjustment	[2]	(62,928)			0
Less: Current Portion		941			789
Asset retirement obligations - long-term portion		$ 95,186			$ 154,913
[1]	The decrease in revision of estimates for the year ended December 31, 2018 is primarily due to receiving new cost estimates from third parties regarding the estimated plugging and abandonment costs.
[2]	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, 2018	Dec. 31, 2017	May 04, 2017
Schedule Of Investments [Line Items]
Restricted investments	$ 94,467	$ 156,938	$ 156,443
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	90,162	152,272
Surety bond cash collateral [Member]
Schedule Of Investments [Line Items]
Restricted investments	0	501
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	4,305	4,058
SPBPC Collateral Port of Long Beach pipeline license [Member]
Schedule Of Investments [Line Items]
Restricted investments	$ 0	$ 107

Debt - Consolidated Debt Obliga

Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	May 04, 2017
Debt Instrument [Line Items]
Long-term debt	$ 294,000	$ 376,000	$ 430,000
$425.0 million New Revolving Credit Facility, variable-rate, due November 2023 [Member]
Debt Instrument [Line Items]
Aggregate principal outstanding	294,000	0
$1.0 billion Emergence Credit Facility, variable-rate, due March 2021 [Member]
Debt Instrument [Line Items]
Aggregate principal outstanding	$ 0	$ 376,000

Debt - Consolidated Debt Obli_2

Debt - Consolidated Debt Obligations (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2018USD ($)
$1.0 billion Emergence Credit Facility, variable-rate, due March 2021 [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 1,000,000,000
Maturity date	Mar. 31, 2021
$425.0 million New Revolving Credit Facility, variable-rate, due November 2023 [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 425,000,000
Maturity date	Nov. 2, 2023

Debt - Credit Facility - Additi

Debt - Credit Facility - Additional Information (Detail) - USD ($)	Nov. 02, 2018	May 15, 2018	Nov. 30, 2017	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018	May 14, 2018	Nov. 29, 2017
Line Of Credit Facility [Line Items]
Borrowing base		$ 430,000,000					$ 435,000,000
Amortization of deferred charges		15,000,000
Amortization of interest in properties		$ 5,000,000
Gain (loss) on extinguishment of debt	$ 3,000,000				$ 0	$ (3,034,000)
Repayment of predecessor's revolving credit facility					$ 63,000,000	397,000,000
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						2,000,000,000
Revolving credit facility, maximum borrowing capacity						$ 2,000,000,000
Repayment of predecessor's revolving credit facility				$ 24,800,000
New Credit Agreement [Member]
Line Of Credit Facility [Line Items]
Extended hedging requirements						Extend the date by which OLLC was required to show compliance with certain minimum hedging requirements set forth in the New Credit Agreement from December 31, 2018 to February 28, 2019
Extended date after the closing date						60 days
New Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$ 425,000,000
Revolving credit facility, expiration date	Nov. 2, 2023
LIBOR rate interest period	1 month
Revolving credit facility, maximum borrowing capacity	$ 425,000,000
New Revolving Credit Facility [Member] | Amplify Acquisitionco Inc
Line Of Credit Facility [Line Items]
Pledge and security interest	100.00%
New Revolving Credit Facility [Member] | Minimum [Member]
Line Of Credit Facility [Line Items]
Current ratio	1.00%
New Revolving Credit Facility [Member] | Minimum [Member] | Oil and Gas Properties [Member]
Line Of Credit Facility [Line Items]
Secured by percentage of mortgages	85.00%
New Revolving Credit Facility [Member] | Minimum [Member] | Proved Developed and Producing Oil and Gas Properties [Member]
Line Of Credit Facility [Line Items]
Secured by percentage of mortgages	85.00%
New Revolving Credit Facility [Member] | Maximum [Member]
Line Of Credit Facility [Line Items]
Total debt to EBITDAX	4.00%
New Revolving Credit Facility [Member] | Federal Funds Effective Rate [Member]
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate	0.50%
New Revolving Credit Facility [Member] | LIBOR [Member]
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate	1.00%
New Revolving Credit Facility [Member] | LIBOR [Member] | Minimum [Member]
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate	2.00%
New Revolving Credit Facility [Member] | LIBOR [Member] | Maximum [Member]
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate	3.00%
New Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate	1.00%
New Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate	2.00%
Emergence Credit Facility [Member]
Line Of Credit Facility [Line Items]
Gain (loss) on extinguishment of debt	$ 3,000,000
Emergence Credit Facility [Member] | Amplify Energy Operating LLC
Line Of Credit Facility [Line Items]
Revolving credit facility, expiration date				Mar. 19, 2021
Aggregate principal outstanding				$ 430,000,000
Borrowing base			$ 450,000,000	$ 490,000,000				$ 475,000,000
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%
Amortization of deferred charges			2,500,000
Debt covenant, minimum aggregate amount of unrestricted cash or cash equivalents to prepay loans and cash collateralize letter of credit exposure			$ 35,000,000
Emergence Credit Facility [Member] | Minimum [Member] | Amplify Energy Operating LLC
Line Of Credit Facility [Line Items]
Percentage of hedging requirement			50.00%
Emergence Credit Facility [Member] | Maximum [Member] | Amplify Energy Operating LLC
Line Of Credit Facility [Line Items]
Percentage of hedging requirement			75.00%
Emergence Credit Facility [Member] | Alternative Base Rate [Member] | Minimum [Member] | Amplify Energy Operating LLC
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate				2.00%
Emergence Credit Facility [Member] | Alternative Base Rate [Member] | Maximum [Member] | Amplify Energy Operating LLC
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate				3.00%
Emergence Credit Facility [Member] | LIBOR/Eurodollar [Member] | Minimum [Member] | Amplify Energy Operating LLC
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate				3.00%
Emergence Credit Facility [Member] | LIBOR/Eurodollar [Member] | Maximum [Member] | Amplify Energy Operating LLC
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate				4.00%
Credit Facility [Member] | Amplify Energy Operating LLC
Line Of Credit Facility [Line Items]
Borrowing base						$ 425,000,000

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, 2018	Dec. 31, 2016
$425.0 million New Revolving Credit Facility, variable-rate, due November 2023 [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates			4.96%
$1.0 billion Emergence Credit Facility, variable-rate, due March 2021 [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates		5.08%	5.75%
Predecessor's Revolving Credit Facility [Member] | Predecessor [Member]
Debt Instrument [Line Items]
Revolving credit facility, weighted-average interest rates	4.18%			3.28%

Debt - Senior Notes - Additiona

Debt - Senior Notes - Additional Information (Detail) - USD ($) $ in Thousands	Nov. 02, 2018	May 04, 2017	May 04, 2017	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016	Jul. 17, 2014	Oct. 10, 2013	May 23, 2013	Apr. 17, 2013
Debt Instrument [Line Items]
Repurchase of senior notes					$ 0	$ 0
Gain on extinguishment of debt	$ 3,000				$ 0	$ (3,034)
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
Gain on extinguishment of debt				$ 0			42,337
Senior Notes [Member]
Debt Instrument [Line Items]
Unrecorded contractual interest			$ 24,200
2021 Senior Notes [Member]
Debt Instrument [Line Items]
Senior notes						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
Repurchase of senior notes							14,900
Gain on extinguishment of debt							$ 14,800
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 Thousands	Nov. 02, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt	$ 3,000	$ 0	$ (3,034)
Predecessor's Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Deferred financing fees				$ 1,300
2021 Senior Notes, fixed-rate, due May 2021 [Member]
Debt Instrument [Line Items]
Deferred financing fees				8,500
2022 Senior Notes, fixed-rate, due August 2022 [Member]
Debt Instrument [Line Items]
Deferred financing fees				$ 5,700
Successor Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs			$ 3,300

Equity (Deficit)- Additional In

Equity (Deficit)- Additional Information (Detail) - USD ($)	Dec. 19, 2018	Nov. 19, 2018	May 04, 2017	Apr. 27, 2016	Feb. 28, 2019	Jan. 31, 2019	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016	Dec. 21, 2018	Jun. 01, 2016	May 31, 2016	May 25, 2016
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			25,000,000				25,000,000	25,000,000	22,181,881
Common stock, shares outstanding			25,000,000				25,000,000	25,000,000	22,181,881
Proceeds from sale of common units, net								$ 0	$ 0
Fees on sale of common unit								$ 0	$ 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
Fees on sale of common unit							$ 0			$ 536,000
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] | Limited Partners Common Units [Member]
Equity and Distributions [Line Items]
Common unit, issued										1,178,102
ATM Program [Member] | Predecessor [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
Common Stock [Member]
Equity and Distributions [Line Items]
Stock issued during period			25,000,000					0	0
Common stock, shares outstanding			25,000,000				25,000,000	25,000,000	22,181,881
Stock repurchase authorized amount											$ 25,000,000
Common Stock [Member] | Subsequent Event [Member]
Equity and Distributions [Line Items]
Shares repurchased during period					42,583	42,583
Total cost excluding fees and expenses relating to the offer					$ 400,000	$ 400,000
Average common stock price					$ 8.63	$ 8.63
Stock Repurchase Program, Remaining Authorized Repurchase Amount					$ 24,600,000
Common Stock [Member] | Tender Offer [Member]
Equity and Distributions [Line Items]
Tender offer commencement date									Nov. 19, 2018
Tender offer to purchase common stock shares		2,916,667
Shares repurchased during period	2,916,667
Price of common stock	$ 12
Total cost excluding fees and expenses relating to the offer	$ 35,000,000
Warrants [Member]
Equity and Distributions [Line Items]
Warrant issued during period			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			$ 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, 2018	Dec. 31, 2016
Summary of Changes in Number of Outstanding Units/Shares [Line Item]
Beginning balance				25,000,000	25,000,000
Ending balance		25,000,000	25,000,000	25,000,000	22,181,881
Common Shares/Units [Member]
Summary of Changes in Number of Outstanding Units/Shares [Line Item]
Beginning balance				25,000,000	25,000,000
Issuance of common stock		25,000,000		0	0
Restricted stock units vested					163,700
Repurchase of common shares					(65,152)
Restricted Common Stock Repurchased and Retired Under Tender Offer					(2,916,667)
Ending balance		25,000,000	25,000,000	25,000,000	22,181,881
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
Common units issued						1,178,102
Restricted common units issued			0			50,000
Restricted common units/shares forfeited			(12,952)			(27,537)
Restricted common units/shares repurchased	[1]		(14,681)			(279,045)
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			83,827,920
General Partner [Member] | Predecessor [Member]
Summary of Changes in Number of Outstanding Units/Shares [Line Item]
Beginning balance			0	0		86,797
Common units issued						0
Restricted common units issued			0			0
Restricted common units/shares forfeited			0			0
Restricted common units/shares repurchased	[1]		0			0
Cancellation of general partner units						(86,797)
Cancellation of Predecessor common units			0
Ending balance		0	0			0
[1]	Restricted common units were 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 for the year ended December 31, 2016. 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 of_2

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
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
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]
Calculated fair value	$ 2.20
Risk-free Interest Rate [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair values of warrants, measurement input	0.0206
Dividend Yield [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair values of warrants, measurement input	0
Expected Life [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair values of warrants, measurement input	5 years
Expected Volatility [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair values of warrants, measurement input	0.500
Strike Price [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair values of warrants, measurement input	42.60

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
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
Distribution made to member or limited partner, date of record	Aug. 5, 2016	May 6, 2016	Feb. 5, 2016
Distribution made to member or limited partner, date of distribution	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016
Distribution per unit	$ 0.0300	$ 0.0300	$ 0.1000
Aggregate Distribution	$ 2,500,000	$ 2,500,000	$ 8,300,000
Maximum [Member]
Limited Partners Capital Account [Line Items]
Distribution Received by Affiliates	$ 100,000	$ 100,000	$ 100,000

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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Earnings Per Share/Unit [Line Items]
Net income (loss) attributable to Successor/Predecessor			$ (906)	$ 79,247	$ (2,598)	$ (25,279)	$ 3,239	$ 9,728	$ (7,536)			$ 1,286	$ 54,609
Less: Predecessor's general partner's 0.1% interest in net income (loss)	[1]											0	0
Less: Net income (loss) allocated to participating restricted stockholders												35	2,426
Basic and diluted earnings available to common stockholders/limited partners												$ 1,251	$ 52,183
Common shares/units:
Common shares/units outstanding — basic												25,000	24,959
Dilutive effect of potential common shares												0	0
Common shares/units outstanding — diluted	[2]											25,000	24,959
Net earnings per share/unit:
Basic												$ 0.05	$ 2.09
Diluted												$ 0.05	$ 2.09
Antidilutive stock options or warrants														3,325,318
Stock Options [Member]
Net earnings per share/unit:
Antidilutive stock options or warrants	[3]											517	0
Warrants [Member]
Net earnings per share/unit:
Antidilutive stock options or warrants	[4]											2,174	2,174
Predecessor [Member]
Earnings Per Share/Unit [Line Items]
Net income (loss) attributable to Successor/Predecessor		$ (74,578)								$ (16,377)	$ (90,955)			$ (540,398)
Less: Predecessor's general partner's 0.1% interest in net income (loss)	[1]										0			(168)
Less: Net income (loss) allocated to participating restricted stockholders											0			0
Basic and diluted earnings available to common stockholders/limited partners											$ (90,955)			$ (540,230)
Common shares/units:
Common shares/units outstanding — basic											83,807			83,351
Dilutive effect of potential common shares											0			0
Common shares/units outstanding — diluted	[2]										83,807			83,351
Net earnings per share/unit:
Basic											$ (1.09)			$ (6.48)
Diluted											$ (1.09)			$ (6.48)
Predecessor [Member] | Stock Options [Member]
Net earnings per share/unit:
Antidilutive stock options or warrants	[3]										0			0
Predecessor [Member] | Warrants [Member]
Net earnings per share/unit:
Antidilutive stock options or warrants	[4]										0			0
[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.
[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.

Earnings Per Share_Unit - Cal_2

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
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%
Average [Member] | Predecessor [Member]
Earnings Per Share/Unit [Line Items]
General partner's interest in net income, percentage	0.105%

Equity-based Awards - Additiona

Equity-based Awards - Additional Information (Detail)

Apr. 27, 2018shares

May 01, 2017USD ($)

Jun. 01, 2016USD ($)

Mar. 09, 2016USD ($)

Jun. 30, 2016

May 04, 2017USD ($)shares

Dec. 31, 2017USD ($)shares

Dec. 31, 2018USD ($)Installment$ / sharesshares

Dec. 31, 2017shares

Dec. 31, 2016USD ($)shares

Jun. 30, 2017shares

Dec. 31, 2015shares

Dec. 31, 2014shares

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.

Grant-date fair value compensation

$ 500,000

Modified-date grant fair value compensation cost recognized

300,000

Share/unit-based compensation (see Note 14)

$ 2,516,000

$ 4,374,000

Predecessor [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Grant-date fair value compensation

$ 500,000

Share/unit-based compensation (see Note 14)

$ 3,667,000

$ 7,350,000

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]

Grant-date fair value compensation

$ 100,000

Fair value of compensation cost recognized on the date of plan modification

$ 500,000

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

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

Share/unit-based compensation (see Note 14)

$ 2,300,000

Restricted Stock Options [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Number of restricted stock options granted | shares

1,876

0

Unvested restricted stock option awards | shares

298,354

Expected life (in years)

2 years

2 years

6 years

Phantom Units [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Unvested restricted stock option awards | shares

0

0

Phantom Units [Member] | Maximum [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Phantom units settled in cash

$ 100,000

Phantom Units [Member] | Predecessor [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Unvested restricted stock option awards | shares

5,692,745

5,980,693

0

Phantom Units [Member] | Non-Employee Directors [Member] | Predecessor [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Vesting period date

2016-01

Phantom Units [Member] | Non-Employee Directors [Member] | Predecessor [Member] | First Anniversary Of Grant Date [Member] | Maximum [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Phantom units settled in cash

$ 100,000

Phantom Units [Member] | Certain Employee [Member] | Predecessor [Member] | First Anniversary Of Grant Date [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Stock units vesting percentage

33.33%

Phantom Units [Member] | Certain Employee [Member] | Predecessor [Member] | Second Anniversary Market-Vesting Date [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Stock units vesting percentage

33.33%

Phantom Units [Member] | Certain Employee [Member] | Predecessor [Member] | Third Anniversary Of Grant Date [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Stock units vesting percentage

33.33%

TSUs [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Unrecognized compensation cost

$ 5,600,000

Weighted-average period of unrecognized compensation cost

2 years 2 months 12 days

TSUs [Member] | Management Incentive Plan [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Unvested restricted stock option awards | shares

614,754

682,792

598,024

682,792

PSUs [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Unrecognized compensation cost

$ 1,800,000

Weighted-average period of unrecognized compensation cost

1 year 4 months 24 days

Decrease in share targets | $ / shares

$ 0.25

PSUs [Member] | First Anniversary Of Grant Date [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Stock units vesting percentage

25.00%

PSUs [Member] | Market Vesting Date [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Stock units vesting percentage

50.00%

PSUs [Member] | Second Anniversary Market-Vesting Date [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Stock units vesting percentage

25.00%

PSUs [Member] | Management Incentive Plan [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Unvested restricted stock option awards | shares

0

393,500

0

Restricted Stock Units (RSUs) | 2017 Non-Employee Directors Compensation Plan [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

Unrecognized compensation cost

$ 400,000

Restricted Common Units [Member] | Predecessor [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Unvested restricted stock option awards | shares

0

432,160

1,368,538

Restricted Common Units [Member] | Long Term Incentive Plan [Member] | Executive officers and employees [Member]

Share Based Compensation Arrangement By Share Based Payment Award [Line Items]

Fair value of the restricted common units

$ 100,000

Equity-based Awards - Summary o

Equity-based Awards - Summary of Information Regarding Restricted Stock Unit Awards (Detail) - Management Incentive Plan [Member] - $ / shares		8 Months Ended		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2018
TSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance		614,754		682,792
Granted, Number of Units		173,070	[1]	437,000	[2]
Forfeited, Number of Units		(105,032)		(363,513)	[3]
Vested, Number of Units		0		(158,255)
Outstanding, Number of Units, Ending Balance		682,792		598,024
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance	[4]	$ 13.77		$ 13.54
Granted, Weighted-Average Grant Date Fair Value per Unit	[4]	12.87		10.51
Forfeited, Weighted-Average Grant Date Fair Value per Unit	[4]	13.77		13.55
Vested, Weighted-Average Grant Date Fair Value per Unit	[4]	0		13.44
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance	[4]	$ 13.54		$ 11.35
PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance				0
Granted, Number of Units	[5]			395,500
Forfeited, Number of Units				(2,000)
Vested, Number of Units				0
Outstanding, Number of Units, Ending Balance		0		393,500
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance	[6]			$ 0
Granted, Weighted-Average Grant Date Fair Value per Unit	[6]			8.14
Forfeited, Weighted-Average Grant Date Fair Value per Unit	[6]			7.59
Vested, Weighted-Average Grant Date Fair Value per Unit	[6]			0
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance	[6]	$ 0		$ 8.14
[1]	The aggregate grant date fair value of TSUs 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.
[2]	The aggregate grant date fair value of TSUs issued for the year ended December 31, 2018 was $4.6 million based on a grant date market price ranging from $9.30 to $11.00 per share.
[3]	In connection with the separation and retirement agreements of certain executives as discussed in Note 1, the Departing Executives forfeited 298,354 TSUs during the year ended December 31, 2018.
[4]	Determined by dividing the aggregate grant date fair value of awards by the number of awards issued
[5]	The aggregate grant date fair value of PSUs issued for the year ended December 31, 2018 was $3.2 million based on a calculated fair value price ranging from $5.88 to $9.87 per share.
[6]	Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

Equity-based Awards - Summary_2

Equity-based Awards - Summary of Information Regarding Restricted Stock Unit Awards (Parenthetical) (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
TSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted stock units issued	$ 4.6	$ 2.2
TSUs [Member] | Departing Executives [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Forfeited, Number of Units	298,354
TSUs [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant Date Market Price	$ 9.30	$ 10
TSUs [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant Date Market Price	$ 11	$ 13.77
PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted stock units issued	$ 3.2
PSUs [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Calculated fair value price	$ 5.88
PSUs [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Calculated fair value price	$ 9.87

Equity-based Awards - Summary_3

Equity-based Awards - Summary of Fair Value Assumptions (Detail) - PSUs [Member] - $ / shares	Nov. 01, 2018	Oct. 01, 2018	Aug. 01, 2018	Jul. 01, 2018	May 14, 2018	Dec. 31, 2018
Share Price Target 12.50 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share price targets						$ 12.50
Risk-free interest rate	2.89%	2.88%	2.76%	2.61%	2.68%
Expected volatility	54.00%	53.00%	55.00%	50.00%	50.00%
Calculated fair value per PSU	$ 7.65	$ 8.54	$ 9.79	$ 9.87	$ 9.71
Share Price Target 15.00 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share price targets						15
Risk-free interest rate	2.89%	2.88%	2.76%	2.61%	2.68%
Expected volatility	54.00%	53.00%	55.00%	50.00%	50.00%
Calculated fair value per PSU	$ 6.72	$ 7.57	$ 8.66	$ 8.72	$ 8.52
Share Price Target 17.50 [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share price targets						$ 17.50
Risk-free interest rate	2.89%	2.88%	2.76%	2.61%	2.68%
Expected volatility	54.00%	53.00%	55.00%	50.00%	50.00%
Calculated fair value per PSU	$ 5.88	$ 6.66	$ 7.65	$ 7.68	$ 7.48

Equity-based Awards - Summary_4

Equity-based Awards - Summary of Modified-Date Grant Fair Value Estimated Using Black-Scholes Option Pricing Model (Detail) - Restricted Stock Options [Member] - $ / shares	Apr. 27, 2018	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Risk-free interest rate		2.49%	2.06%
Dividend yield		0.00%	0.00%
Expected life (in years)	2 years	2 years	6 years
Expected volatility		50.00%	50.00%
Strike Price		$ 21.58	$ 21.58
Calculated fair value per stock option		$ 0.85	$ 5.01

Equity-based Awards - Summary_5

Equity-based Awards - Summary of Restricted Stock Option Awards (Detail) - Restricted Stock Options [Member] - $ / shares	8 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Options, Beginning Balance	614,754	517,398
Granted, Number of Options	1,876	0
Forfeited, Number of Options	(99,232)	(161,243)
Vested, Number of Options	0	(356,155)
Outstanding, Number of Options, Ending Balance	517,398	0
Outstanding, Weighted Average Grant Date Fair Value per Option, Beginning balance	$ 5.01	$ 5.01
Granted, Weighted-Average Grant Date Fair Value per Option	5.01	0
Forfeited, Weighted-Average Grant Date Fair Value per Option	5.01	5.01
Vested, Weighted-Average Grant Date Fair Value per Option	0	5.01
Outstanding, Weighted Average Grant Date Fair Value per Option, Ending balance	$ 5.01	$ 0

Equity-based Awards - Summary_6

Equity-based Awards - Summary of Information Regarding Restricted Stock Awards (Detail) - Restricted Stock Units [Member] - 2017 Non-Employee Directors Compensation Plan [Member] - $ / shares	8 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance	0	16,341
Granted, Number of Units	16,341	28,708
Forfeited, Number of Units	0	0
Vested, Number of Units	0	(5,445)
Outstanding, Number of Units, Ending Balance	16,341	39,604
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance	$ 0	$ 13.77
Granted, Weighted-Average Grant Date Fair Value per Unit	13.77	10.45
Forfeited, Weighted-Average Grant Date Fair Value per Unit	0	0
Vested, Weighted-Average Grant Date Fair Value per Unit	0	13.77
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance	$ 13.77	$ 11.36

Equity-based Awards - Summary_7

Equity-based Awards - Summary of Information Regarding Restricted Stock Awards (Parenthetical) (Detail) - Restricted Stock Units [Member] - 2017 Non-Employee Directors Compensation Plan [Member] - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted stock units issued	$ 0.3	$ 0.2
Grant Date Market Price	$ 10.45	$ 13.77

Equity-based Awards - Summary_8

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
Granted, Number of Units		0	50,000
Forfeited, Number of Units		(12,952)	(27,537)
Vested, Number of Units		(43,045)	(958,841)
Cancelled, Number of Units	(376,163)
Outstanding, Number of Units, Ending Balance	0		432,160
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance		$ 15	$ 17.61
Granted, Weighted-Average Grant Date Fair Value per Unit		0	2.41
Forfeited, Weighted-Average Grant Date Fair Value per Unit		9.51	16.99
Vested, Weighted-Average Grant Date Fair Value per Unit		$ 10.40	18.01
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

Equity-based Awards - Summary_9

Equity-based Awards - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Common Units [Member] $ / shares in Units, $ in Millions	Dec. 31, 2016USD ($)$ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted common unit awards issued | $	$ 0.1
Grant Date Market Price | $ / shares	$ 2.41

Equity-based Awards - Summar_10

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, Beginning Balance
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
Forfeited, Number of Units	(132,347)		(188,325)
Vested, Number of Units	(155,601)
Cancellation of Predecessor common units		(5,692,745)
Outstanding, Number of Units, Ending Balance	5,692,745		5,980,693

Equity-based Awards - Summar_11

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, 2018	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		$ 2,516	$ 2,777
TSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		1,906	1,445
PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		0	1,404
Restricted Stock Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		569	(214)
Board RSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		41	142
Restricted Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		0	0
Phantom Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)		$ 0	$ 0
Predecessor [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	$ 3,667			$ 7,528
Predecessor [Member] | TSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	0			0
Predecessor [Member] | PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	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
Predecessor [Member] | Board RSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	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
Predecessor [Member] | Phantom Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	$ (46)			$ 322

Supplemental Disclosures to t_3

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows - Summary of Current Accrued Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	May 04, 2017
Accrued Liabilities Current [Abstract]
Accrued lease operating expense	$ 10,469	$ 6,439
Accrued general and administrative expense	4,393	4,412
Accrued capital expenditures	4,349	3,854
Accrued interest payable	2,476	1,309
Accrued ad valorem tax	729	398
Asset retirement obligations	477	713
Other	262	1,108
Accrued liabilities	$ 23,155	$ 18,233	$ 38,180

Supplemental Disclosures to t_4

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows - Summary of Cash and Cash Equivalents Reconciliation (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	May 04, 2017
Cash And Cash Equivalents [Abstract]
Cash and cash equivalents	$ 49,704	$ 6,392	$ 20,140
Restricted cash	325	0
Total cash, cash equivalents and restricted cash	$ 50,029	$ 6,392	$ 27,701

Supplemental Disclosures to t_5

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows - Summary of Supplemental Cash Flows (Detail) - USD ($) $ in Thousands	4 Months Ended	8 Months Ended	12 Months Ended
	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized		$ 12,109	$ 17,083
Cash paid for reorganization items, net		7,934	2,399
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		(1,080)	(156)
(Increase) decrease in accounts receivable/payable related to divestiture		0	0
Asset retirement obligation removal related to divestitures		$ 0	$ (15,702)
Predecessor [Member]
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$ 6,598			$ 87,527
Cash paid for reorganization items, net	11,999			0
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	3,173			(6,284)
(Increase) decrease in accounts receivable/payable related to divestiture	0			(289)
Asset retirement obligation removal related to divestitures	$ 0			$ (19,669)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($)	May 04, 2017	Jun. 01, 2016	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016	Apr. 27, 2016
Related Party Transaction [Line Items]
General and administrative expense				$ 29,506,000	$ 43,129,000
Transition Services Agreement [Member]
Related Party Transaction [Line Items]
Transition service agreement cost			$ 0	0	0	$ 0
General and administrative expense			0	$ 0	$ 0	1,600,000
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%
Predecessor [Member]
Related Party Transaction [Line Items]
General and administrative expense			$ 31,606,000			$ 63,280,000
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 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, 2018	Dec. 31, 2016
Related Party Transaction [Line Items]
General and administrative costs and expenses under omnibus agreement		$ 0	$ 0
Predecessor [Member]
Related Party Transaction [Line Items]
General and administrative costs and expenses under omnibus agreement	$ 0			$ 11,867

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)	Nov. 20, 2018USD ($)	Oct. 05, 2018USD ($)	Sep. 12, 2017	Oct. 31, 2017USD ($)	May 04, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2018USD ($)$ / bbl	Dec. 31, 2016USD ($)
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
Proceeds from Beta Decommissioning Trust account	$ 1,000,000	$ 61,500,000
Beta's decommissioning obligations, cash		$ 90,000,000
Rent expense						$ 6,300,000	8,600,000
Predecessor [Member]
Commitments and Contingencies Additional Textual [Abstract]
Rent expense					$ 3,100,000			$ 10,900,000
U S Bank Money Market [Member]
Commitments and Contingencies Additional Textual [Abstract]
Held-to-maturity investment, amortized cost							90,200,000
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Commitments and Contingencies Additional Textual [Abstract]
Restricted Investment - decommissioning of offshore production facilities							$ 4,300,000
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 Contingencies_2

Commitments and Contingencies - Environmental Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies [Line Items]
Balance at beginning of period	$ 0	$ 0
Charged to costs and expenses	0	0
Payments	0	0
Balance at end of period	$ 0	0	$ 0
Predecessor [Member]
Commitments and Contingencies [Line Items]
Balance at beginning of period		$ 0	216
Charged to costs and expenses			0
Payments			(216)
Balance at end of period			$ 0

Commitments and Contingencies_3

Commitments and Contingencies - Lease Obligations (Detail) $ in Thousands	Dec. 31, 2018USD ($)
Commitments And Contingencies Disclosure [Abstract]
Total	$ 11,846
2,019	5,893
2,020	2,072
2,021	2,109
2,022	337
2,023	205
Thereafter	$ 1,230

Commitments and Contingencies_4

Commitments and Contingencies - Purchase Commitments Under the Contracts (Detail) $ in Thousands	Dec. 31, 2018USD ($)
CO2 Minimum Purchase Commitment [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Total	$ 8,315
2,019	4,306
2,020	4,009
2,021	0
2,022	0
2,023	0
Thereafter	0
Midstream services [Member]
Recorded Unconditional Purchase Obligation [Line Items]
Total	12,308
2,019	3,075
2,020	3,083
2,021	3,075
2,022	3,075
2,023	0
Thereafter	$ 0

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Line Items]
Statutory tax rate	21.00%	35.00%	35.00%
Operating loss carryforwards, limitations on use	limitations on net operating losses (NOLs) generated after December 31, 2017, to 80% of taxable income
Tax cuts and jobs act of 2017, limitations on NOLs percentage of taxable income	80.00%	80.00%
Maximum measurement period for income tax accounting implications of tax cuts and jobs act	1 year
Valuation Allowance	$ 23,934,000	$ 38,128,000
Unrecognized Tax Benefits		$ 0
United States [Member]
Income Tax Disclosure [Line Items]
Operating Loss carryforwards not subject to expiration	$ 41,000,000
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	$ 86,000,000
Maximum [Member] | State [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	$ 14,800,000

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, 2018	Dec. 31, 2016
Current taxes:
Federal		$ 4	$ 0
State		(34)	0
Total current income tax benefit (expense)		(30)	0
Deferred taxes:
Federal		1,933	0
State		273	0
Total deferred income tax benefit (expense)		2,206	0
Total income tax benefit (expense)		$ 2,176	$ 0
Predecessor [Member]
Current taxes:
Federal	$ 0			$ 6
State	17			8
Total current income tax benefit (expense)	17			14
Deferred taxes:
Federal	71			8
State	3			(195)
Total deferred income tax benefit (expense)	74			(187)
Total income tax benefit (expense)	$ 91			$ (173)

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, 2018	Dec. 31, 2016
Income Tax Contingency [Line Items]
Expected tax benefit (expense) at federal statutory rate			$ 310	$ 11,468
State income tax benefit (expense), net of federal benefit			240	1,108
Non-deductible expenses			(187)	1,328
Changes in valuation allowances			24,767	(14,194)
Remeasurement of federal deferred tax assets due rate change			(22,958)	0
Pass-through entities	[1]		0	0
Other			4	290
Total income tax benefit (expense)			$ 2,176	$ 0
Predecessor [Member]
Income Tax Contingency [Line Items]
Expected tax benefit (expense) at federal statutory rate		$ 5,764			$ 191,870
State income tax benefit (expense), net of federal benefit		30			382
Non-deductible expenses		0			0
Changes in valuation allowances		0			0
Remeasurement of federal deferred tax assets due rate change		0			0
Pass-through entities	[1]	(5,686)			(191,921)
Other		(17)			(504)
Total income tax benefit (expense)		$ 91			$ (173)
[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, 2018	Dec. 31, 2017	May 04, 2017
Deferred income tax assets:
Property, Plant & Equipment	$ 2,208	$ 19,423
Derivative instrument	0	6,251
Net operating loss carryforward	19,085	10,452
Asset retirement obligation	0	1,223
Interest	5,748	0
Accrued liabilities	1,387	0
Other	307	779
Total deferred income tax assets:	28,735	38,128
Valuation allowance	(23,934)	(38,128)
Net deferred income tax assets	4,801	0
Deferred income tax liabilities:
Property, plant and equipment	0	0
Derivatives	4,801	0
Other	0	0
Total deferred income tax liabilities	4,801	0
Net deferred income tax liabilities	$ 0	$ 0	$ 2,206

Quarterly Financial Informati_3

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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	May 04, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2016
Schedule Of Quarterly Financial Information Disclosure [Line Items]
Revenues		$ 42,395	$ 75,702	$ 85,522	$ 90,988	$ 87,932	$ 87,495	$ 75,589			$ 205,479	$ 340,144
Operating income (loss)		2,654	87,014	3,206	(18,226)	9,529	2,573	(6,043)			(816)	81,523
Net income (loss)		(906)	79,247	(2,598)	(25,279)	3,239	9,728	(7,536)			1,286	54,609
Net income (loss) attributable to Successor/Predecessor		(906)	79,247	(2,598)	(25,279)	3,239	9,728	(7,536)			1,286	54,609
Net income (loss) available to common stockholders/limited partners		$ (906)	$ 75,727	$ (2,598)	$ (25,279)	$ 3,156	$ 9,463	$ (7,536)			$ 1,251	$ 52,183
Basic and diluted earnings per unit/share		$ (0.04)	$ 3.06	$ (0.10)	$ (1.01)	$ 0.13	$ 0.38	$ (0.30)			$ 0.05	$ 2.09
Predecessor [Member]
Schedule Of Quarterly Financial Information Disclosure [Line Items]
Revenues	$ 27,821								$ 81,380	$ 109,201			$ 284,580
Operating income (loss)	8,384								(421)	7,963			(436,539)
Net income (loss)	(74,578)								(16,377)	(90,955)			(540,398)
Net income (loss) attributable to Successor/Predecessor	(74,578)								(16,377)	(90,955)			(540,398)
Net income (loss) available to common stockholders/limited partners	$ (74,578)								$ (16,377)	$ (90,955)			$ (540,230)
Basic and diluted earnings per unit/share	$ (0.89)								$ (0.20)	$ (1.09)			$ (6.48)

Supplemental Oil and Gas Info_3

Supplemental Oil and Gas Information (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Extractive Industries [Abstract]
Evaluated oil and natural gas properties	$ 598,331	$ 603,053
Support equipment and facilities	108,760	100,225
Accumulated depletion, depreciation, and amortization	(82,389)	(34,429)
Total	$ 624,702	$ 668,849

Supplemental Oil and Gas Info_4

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, 2018	Dec. 31, 2016
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Property acquisition costs, proved		$ 0	$ 0
Property acquisition costs, unproved		0	0
Exploration		0	0
Development		51,925	42,878
Total		$ 51,925	$ 42,878
Predecessor [Member]
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Property acquisition costs, proved	$ 0			$ 0
Property acquisition costs, unproved	0			0
Exploration	0			792
Development	9,573			54,310
Total	$ 9,573			$ 55,102

Supplemental Oil and Gas Info_5

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, 2018	Dec. 31, 2016
Extractive Industries [Abstract]
Percent of discount factor to proved reserves			10.00%
Increase (reduction) in reserves	172.1	(98.9)	(148.6)	(351)
Upward price revisions in proved reserve	204.6	13.4	27.6
Downward revisions due to updated well performance data and increase in anticipated development and maintenance cost		76.7	63.5
Extensions and discoveries		7.2	11.5
Divestiture of oil and gas properties			66.1	35.3
Downward revisions due to updated well performance data	9.6			87.9
Downward price revisions in proved reserve				148.3

Supplemental Oil and Gas Info_6

Supplemental Oil and Gas Information (Unaudited) - Schedule of Product Prices Used for Valuing the Reserves (Detail)	12 Months Ended
	Dec. 31, 2018$ / MMBTU$ / bbl	Dec. 31, 2017$ / MMBTU$ / bbl	Dec. 31, 2016$ / MMBTU$ / bbl
Oil [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	65.56	51.34	42.75
NGL [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	65.56	51.34	42.75
Natural Gas [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves | $ / MMBTU	3.10	2.98	2.48

Supplemental Oil and Gas Info_7

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, 2018MMcfeBcfebblMMcf	Dec. 31, 2016MMcfebblMMcf
Supplemental Oil And Gas Reserve Information [Line Items]
Extensions and discoveries | Bcfe		7.2	11.5
Oil [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year		80,960	72,004
Extensions and discoveries		121	1,207
Production		(2,380)	(3,335)
Sale of minerals in place			(159)
Revision of previous estimates		(6,697)	(93)
Proved developed and undeveloped reserves, End of year	80,960	72,004	69,624
Proved developed reserves, Beginning of year		57,803	50,014
Proved developed reserves, End of year	57,803	50,014	54,147
Proved undeveloped reserves, Beginning of year		23,157	21,990
Proved undeveloped reserves, End of year	23,157	21,990	15,477
Oil [Member] | Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	65,741	80,960		90,945
Extensions and discoveries	53			297
Production	(1,204)			(3,883)
Sale of minerals in place				(3,228)
Revision of previous estimates	16,370			(18,390)
Proved developed and undeveloped reserves, End of year	80,960			65,741
Proved developed reserves, Beginning of year	45,536	57,803		50,817
Proved developed reserves, End of year	57,803			45,536
Proved undeveloped reserves, Beginning of year	20,205	23,157		40,128
Proved undeveloped reserves, End of year	23,157			20,205
Natural Gas [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MMcf		419,472	406,558
Extensions and discoveries | MMcf		4,900	2,910
Production | MMcf		(21,885)	(29,176)
Sale of minerals in place | MMcf			(56,328)
Revision of previous estimates | MMcf		4,071	(30,005)
Proved developed and undeveloped reserves, End of year | MMcf	419,472	406,558	293,959
Proved developed reserves, Beginning of year | MMcf		297,101	299,481
Proved developed reserves, End of year | MMcf	297,101	299,481	232,110
Proved undeveloped reserves, Beginning of year | MMcf		122,371	107,077
Proved undeveloped reserves, End of year | MMcf	122,371	107,077	61,849
Natural Gas [Member] | Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MMcf	371,016	419,472		461,526
Extensions and discoveries | MMcf	45			288
Production | MMcf	(12,411)			(44,776)
Sale of minerals in place | MMcf				(15,227)
Revision of previous estimates | MMcf	60,822			(30,795)
Proved developed and undeveloped reserves, End of year | MMcf	419,472			371,016
Proved developed reserves, Beginning of year | MMcf	280,035	297,101		311,147
Proved developed reserves, End of year | MMcf	297,101			280,035
Proved undeveloped reserves, Beginning of year | MMcf	90,981	122,371		150,379
Proved undeveloped reserves, End of year | MMcf	122,371			90,981
NGLs [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year		30,572	25,189
Extensions and discoveries		261	231
Production		(1,114)	(1,496)
Sale of minerals in place			(1,469)
Revision of previous estimates		(4,530)	(883)
Proved developed and undeveloped reserves, End of year	30,572	25,189	21,572
Proved developed reserves, Beginning of year		21,963	17,982
Proved developed reserves, End of year	21,963	17,982	17,324
Proved undeveloped reserves, Beginning of year		8,609	7,207
Proved undeveloped reserves, End of year	8,609	7,207	4,248
NGLs [Member] | Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	25,184	30,572		43,395
Extensions and discoveries	8			42
Production	(616)			(2,283)
Sale of minerals in place				(123)
Revision of previous estimates	5,996			(15,847)
Proved developed and undeveloped reserves, End of year	30,572			25,184
Proved developed reserves, Beginning of year	18,923	21,963		30,315
Proved developed reserves, End of year	21,963			18,923
Proved undeveloped reserves, Beginning of year	6,261	8,609		13,080
Proved undeveloped reserves, End of year	8,609			6,261
Natural Gas Equivalent
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MMcfe		1,088,660	989,721
Extensions and discoveries | MMcfe		7,195	11,541
Production | MMcfe		(42,850)	(58,166)
Sale of minerals in place | MMcfe			(66,095)
Revision of previous estimates | MMcfe		(63,284)	(35,864)
Proved developed and undeveloped reserves, End of year | MMcfe	1,088,660	989,721	841,137
Proved developed reserves, Beginning of year | MMcfe		775,693	707,459
Proved developed reserves, End of year | MMcfe	775,693	707,459	660,937
Proved undeveloped reserves, Beginning of year | MMcfe		312,967	282,262
Proved undeveloped reserves, End of year | MMcfe	312,967	282,262	180,200
Natural Gas Equivalent | Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MMcfe	916,565	1,088,660		1,267,571
Extensions and discoveries | MMcfe	410			2,320
Production | MMcfe	(23,336)			(81,773)
Sale of minerals in place | MMcfe				(35,328)
Revision of previous estimates | MMcfe	195,021			(236,225)
Proved developed and undeveloped reserves, End of year | MMcfe	1,088,660			916,565
Proved developed reserves, Beginning of year | MMcfe	666,786	775,693		797,936
Proved developed reserves, End of year | MMcfe	775,693			666,786
Proved undeveloped reserves, Beginning of year | MMcfe	249,779	312,967		469,635
Proved undeveloped reserves, End of year | MMcfe	312,967			249,779

Supplemental Oil and Gas Info_8

Supplemental Oil and Gas Information (Unaudited) -Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	May 04, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Oil And Gas Reserve Information [Line Items]
Future cash inflows	$ 6,000,268	$ 5,149,623
Future production costs	(3,280,778)	(2,982,035)
Future development costs	(474,413)	(530,133)
Future income tax expense	0	0
Future net cash flows for estimated timing of cash flows	2,245,077	1,637,455
10% annual discount for estimated timing of cash flows	(1,132,048)	(869,784)
Standardized measure of discounted future net cash flows	$ 1,113,029	$ 767,671	$ 691,089
Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Future cash inflows			5,246,487	$ 3,666,731
Future production costs			(3,275,952)	(2,384,195)
Future development costs			(492,610)	(440,496)
Future income tax expense			0	0
Future net cash flows for estimated timing of cash flows			1,477,925	842,040
10% annual discount for estimated timing of cash flows			(786,836)	(446,199)
Standardized measure of discounted future net cash flows			$ 691,089	$ 395,841	$ 589,554

Supplemental Oil and Gas Info_9

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, 2018	Dec. 31, 2016
Supplemental Oil And Gas Reserve Information [Line Items]
Beginning of year		$ 691,089	$ 767,671
Sale of oil and natural gas produced, net of production costs		(100,946)	(181,841)
Sale of minerals in place		0	(29,036)
Extensions and discoveries		7,187	27,157
Changes in prices and costs		161,106	507,888
Previously estimated development costs incurred		61,851	73,761
Net changes in future development costs		(31,438)	24,396
Revisions of previous quantities		(27,060)	(86,812)
Accretion of discount		46,072	51,769
Change in production rates and other		(40,190)	(41,924)
End of year	$ 691,089	767,671	$ 1,113,029
Predecessor [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Beginning of year	395,841	$ 691,089		$ 589,554
Sale of oil and natural gas produced, net of production costs	(57,420)			(107,357)
Sale of minerals in place	0			(28,277)
Extensions and discoveries	1,320			2,016
Changes in prices and costs	306,375			(404,870)
Previously estimated development costs incurred	9,227			89,748
Net changes in future development costs	(55,333)			254,043
Revisions of previous quantities	99,591			14,414
Accretion of discount	13,195			58,956
Change in production rates and other	(21,707)			(72,386)
End of year	$ 691,089			$ 395,841