Pressburg (ROAN) 10-K 27 Feb 18 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Entity Registrant Name	Linn Energy, Inc.
Entity Central Index Key	1,326,428
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 1,100
Entity Common Stock, Shares Outstanding		77,229,257
Common Stock, Par or Stated Value Per Share	$ 0.001
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Successor [Member]
Current assets:
Cash and cash equivalents		$ 464,508
Accounts receivable – trade, net		140,485
Derivative instruments		9,629
Restricted cash		56,445
Other current assets		79,771
Assets held for sale		106,963
Current assets of discontinued operations		0
Total current assets		857,801
Noncurrent assets:
Oil and natural gas properties (successful efforts method)		950,083
Less accumulated depletion and amortization		(49,619)
Oil and natural gas properties, successful efforts method, net		900,464
Other property and equipment		480,729
Less accumulated depreciation		(28,658)
Other property and equipment, net		452,071
Derivative instruments		469
Deferred income taxes		198,417
Equity method investments		464,926
Other noncurrent assets		6,975
Noncurrent assets of discontinued operations		0
Noncurrent assets, excluding property, total		670,787
Total noncurrent assets		2,023,322
Total assets		2,881,123
Current liabilities:
Accounts payable and accrued expenses		253,975
Derivative instruments		10,103
Current portion of long-term debt, net	[1]	0
Other accrued liabilities		58,617
Liabilities held for sale		43,302
Current liabilities of discontinued operations		0
Total current liabilities		365,997
Derivative instruments		2,849
Other noncurrent liabilities		160,720
Noncurrent liabilities of discontinued operations		0
Liabilities subject to compromise		0
Commitments and contingencies (Note 11)
Equity (deficit):
Predecessor units issued and outstanding (no units issued or outstanding at December 31, 2017; 352,792,474 units issued and outstanding at December 31, 2016)		0
Predecessor accumulated deficit		0
Successor preferred stock ($0.001 par value, 30,000,000 shares authorized and no shares issued at December 31, 2017; no shares authorized or issued at December 31, 2016)		0
Successor Class A common stock ($0.001 par value, 270,000,000 shares authorized and 83,582,176 shares issued at December 31, 2017; no shares authorized or issued at December 31, 2016)		84
Successor additional paid-in capital		1,899,642
Successor retained earnings		432,860
Total common stockholders’/unitholders’ equity (deficit)		2,332,586
Noncontrolling interests		18,971
Total equity (deficit)		2,351,557
Total liabilities and equity (deficit)		2,881,123
Predecessor [Member]
Current assets:
Cash and cash equivalents			$ 694,857
Accounts receivable – trade, net			198,064
Derivative instruments			0
Restricted cash			1,602
Other current assets			105,310
Assets held for sale			0
Current assets of discontinued operations			701
Total current assets			1,000,534
Noncurrent assets:
Oil and natural gas properties (successful efforts method)			12,349,117
Less accumulated depletion and amortization			(9,843,908)
Oil and natural gas properties, successful efforts method, net			2,505,209
Other property and equipment			618,262
Less accumulated depreciation			(217,724)
Other property and equipment, net			400,538
Derivative instruments			0
Deferred income taxes			0
Equity method investments			6,200
Other noncurrent assets			7,784
Noncurrent assets of discontinued operations			740,326
Noncurrent assets, excluding property, total			754,310
Total noncurrent assets			3,660,057
Total assets			4,660,591
Current liabilities:
Accounts payable and accrued expenses			295,081
Derivative instruments			82,508
Current portion of long-term debt, net	[1]		1,937,729
Other accrued liabilities			25,979
Liabilities held for sale			0
Current liabilities of discontinued operations			321
Total current liabilities			2,341,618
Derivative instruments			11,349
Other noncurrent liabilities			360,405
Noncurrent liabilities of discontinued operations			39,202
Liabilities subject to compromise			4,305,005
Commitments and contingencies (Note 11)
Equity (deficit):
Predecessor units issued and outstanding (no units issued or outstanding at December 31, 2017; 352,792,474 units issued and outstanding at December 31, 2016)			5,386,885
Predecessor accumulated deficit			(7,783,873)
Successor preferred stock ($0.001 par value, 30,000,000 shares authorized and no shares issued at December 31, 2017; no shares authorized or issued at December 31, 2016)			0
Successor Class A common stock ($0.001 par value, 270,000,000 shares authorized and 83,582,176 shares issued at December 31, 2017; no shares authorized or issued at December 31, 2016)			0
Successor additional paid-in capital			0
Successor retained earnings			0
Total common stockholders’/unitholders’ equity (deficit)			(2,396,988)
Total common stockholders’/unitholders’ equity (deficit)			(2,396,988)
Noncontrolling interests			0
Total equity (deficit)			(2,396,988)
Total liabilities and equity (deficit)			$ 4,660,591
[1]	Due to covenant violations, the Predecessor’s credit facility and term loan were classified as current at December 31, 2016.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Common Stock, Par or Stated Value Per Share	$ 0.001
Successor [Member]
Unitholders' capital: Units issued	0
Unitholders' capital: Units outstanding	0
Common Stock, Par or Stated Value Per Share	$ 0.001
Common Stock, Shares Authorized	270,000,000
Common Stock, Shares, Issued	83,582,176
Preferred Stock, Par or Stated Value Per Share	$ 0.001
Preferred Stock, Shares Authorized	30,000,000
Preferred Stock, Shares Issued	0
Predecessor [Member]
Unitholders' capital: Units issued		352,792,474
Unitholders' capital: Units outstanding		352,792,474
Common Stock, Shares Authorized		0
Common Stock, Shares, Issued		0
Preferred Stock, Shares Authorized		0
Preferred Stock, Shares Issued		0

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Successor [Member]
Revenues and other:
Oil, natural gas and natural gas liquids sales		$ 709,363
Gains (losses) on oil and natural gas derivatives		13,533
Marketing revenues		82,943
Other revenues		20,839
Total revenues		826,678
Expenses:
Lease operating expenses		208,446
Transportation expenses		113,128
Marketing expenses		69,008
General and administrative expenses		117,548
Exploration costs		3,137
Depreciation, depletion and amortization		133,711
Impairment of long-lived assets		0
Taxes, other than income taxes		47,553
(Gains) losses on sale of assets and other, net		(623,072)
Total expenses		69,459
Other income and (expenses):
Interest expense, net of amounts capitalized		(12,361)
Gain on extinguishment of debt		0
Earnings from equity method investments		11,840
Other, net		(6,233)
Total other income and (expenses)		(6,754)
Reorganization items, net		(8,851)
Income (loss) from continuing operations before income taxes		741,614
Income tax expense (benefit)		388,942
Income (loss) from continuing operations		352,672
Income (loss) from discontinued operations, net of income taxes		82,995
Loss from continuing operations		435,667
Net income attributable to noncontrolling interests		2,807
Net income (loss)		$ 432,860
Income (loss) per share/unit attributable to common stockholders/unitholders:
Income (loss) from continuing operations per share/unit – Basic		$ 3.99
Income (loss) from continuing operations per share/unit – Diluted		3.92
Income (loss) from discontinued operations per share/unit – Basic		0.95
Income (loss) from discontinued operations per share/unit – Diluted		0.93
Net income (loss) per share/unit – Basic		4.94
Net income (loss) per share/unit – Diluted		$ 4.85
Weighted average shares/units outstanding – Basic		87,646
Weighted average shares/units outstanding – Diluted		88,719
Predecessor [Member]
Revenues and other:
Oil, natural gas and natural gas liquids sales	$ 188,885		$ 874,161	$ 1,065,795
Gains (losses) on oil and natural gas derivatives	92,691		(164,330)	1,027,014
Marketing revenues	6,636		36,505	43,876
Other revenues	9,915		93,308	97,771
Total revenues	298,127		839,644	2,234,456
Expenses:
Lease operating expenses	49,665		296,891	352,077
Transportation expenses	25,972		161,574	167,023
Marketing expenses	4,820		29,736	35,278
General and administrative expenses	71,745		237,841	285,996
Exploration costs	93		4,080	9,473
Depreciation, depletion and amortization	47,155		342,614	520,219
Impairment of long-lived assets	0		165,044	4,960,144
Taxes, other than income taxes	14,877		67,648	97,685
(Gains) losses on sale of assets and other, net	829		16,257	(194,805)
Total expenses	215,156		1,321,685	6,233,090
Other income and (expenses):
Interest expense, net of amounts capitalized	(16,725)		(184,870)	(456,749)
Gain on extinguishment of debt	0		0	708,050
Earnings from equity method investments	157		699	685
Other, net	(149)		(1,536)	(13,965)
Total other income and (expenses)	(16,717)		(185,707)	238,021
Reorganization items, net	2,331,189		311,599	0
Income (loss) from continuing operations before income taxes	2,397,443		(356,149)	(3,760,613)
Income tax expense (benefit)	(166)		11,194	(6,393)
Income (loss) from continuing operations	2,397,609		(367,343)	(3,754,220)
Income (loss) from discontinued operations, net of income taxes	(548)		(1,804,513)	(1,005,591)
Loss from continuing operations	2,397,061		(2,171,856)	(4,759,811)
Net income attributable to noncontrolling interests	0		0	0
Net income (loss)	$ 2,397,061		$ (2,171,856)	$ (4,759,811)
Income (loss) per share/unit attributable to common stockholders/unitholders:
Income (loss) from continuing operations per share/unit – Basic	$ 6.80		$ (1.04)	$ (10.94)
Income (loss) from continuing operations per share/unit – Diluted	6.80		(1.04)	(10.94)
Income (loss) from discontinued operations per share/unit – Basic	(0.01)		(5.12)	(2.93)
Income (loss) from discontinued operations per share/unit – Diluted	(0.01)		(5.12)	(2.93)
Net income (loss) per share/unit – Basic	6.79		(6.16)	(13.87)
Net income (loss) per share/unit – Diluted	$ 6.79		$ (6.16)	$ (13.87)
Weighted average shares/units outstanding – Basic	352,792		352,653	343,323
Weighted average shares/units outstanding – Diluted	352,792		352,653	343,323

CONSOLIDATED STATEMENT OF EQUIT

CONSOLIDATED STATEMENT OF EQUITY - USD ($) $ in Thousands	Total	Units	Unitholders’ Capital	Accumulated Deficit	Treasury Units (at Cost)	Class A Common Stock	Additional Paid-in Capital	Retained Earnings	Total Common Stockholders’ Equity	Noncontrolling Interests	Emergence date issuances [Member]	Emergence date issuances [Member]Class A Common Stock	Emergence date issuances [Member]Additional Paid-in Capital	Emergence date issuances [Member]Retained Earnings	Emergence date issuances [Member]Total Common Stockholders’ Equity	Emergence date issuances [Member]Noncontrolling Interests
Common Units, Outstanding (in units) (Predecessor [Member]) at Dec. 31, 2014		331,975,000
Balance Beginning (Predecessor [Member]) at Dec. 31, 2014	$ 4,543,605		$ 5,395,811	$ (852,206)	$ 0
Sale of units (in units) | Predecessor [Member]		19,622,000
Sale of units, net of offering costs of $8,762 | Predecessor [Member]	224,665		224,665	0	0
Issuances of successor Class A common stock | Predecessor [Member]	224,665		224,665	0	0
Issuance of units (in units) | Predecessor [Member]		3,611,000
Issuance of units | Predecessor [Member]	0		0	0	0
Cancellation of units (in units) | Predecessor [Member]		(191,000)
Cancellation of units | Predecessor [Member]	0		(672)	0	672
Purchase of units | Predecessor [Member]	(672)		0	0	(672)
Distributions to unitholders | Predecessor [Member]	(323,878)		(323,878)	0	0
Unit-based compensation expenses | Predecessor [Member]	56,136		56,136	0	0
Share-based compensation expenses | Predecessor [Member]	56,136		56,136	0	0
Reclassification of distributions paid on forfeited restricted units | Predecessor [Member]	865		865	0	0
Excess tax benefit from unit-based compensation and other | Predecessor [Member]	(9,811)		(9,811)	0	0
Net loss | Predecessor [Member]	(4,759,811)		0	(4,759,811)	0
Net income attributable to noncontrolling interests | Predecessor [Member]	0
Common Units, Outstanding (in units) (Predecessor [Member]) at Dec. 31, 2015		355,017,000
Balance Ending (Predecessor [Member]) at Dec. 31, 2015	(268,901)		5,343,116	(5,612,017)	0
Issuance of units (in units) | Predecessor [Member]		5,000
Issuance of units | Predecessor [Member]	0		0	0	0
Cancellation of units (in units) | Predecessor [Member]		(2,230,000)
Cancellation of units | Predecessor [Member]	0		0	0	0
Distributions to unitholders | Predecessor [Member]	0
Unit-based compensation expenses | Predecessor [Member]	44,218		44,218	0	0
Share-based compensation expenses | Predecessor [Member]	44,218		44,218	0	0
Other | Predecessor [Member]	449		449	0	0
Net loss | Predecessor [Member]	(2,171,856)		0	(2,171,856)	0
Net income attributable to noncontrolling interests | Predecessor [Member]	$ 0
Common Units, Outstanding (in units) (Predecessor [Member]) at Dec. 31, 2016	352,792,474	352,792,000
Balance Ending (Predecessor [Member]) at Dec. 31, 2016	$ (2,396,988)		5,386,885	(7,783,873)	0
Distributions to unitholders | Predecessor [Member]	0
Other | Predecessor [Member]	(73)		(73)	0	0
Net loss | Predecessor [Member]	2,397,061		0	2,397,061	0
Net income attributable to noncontrolling interests | Predecessor [Member]	0
Plan of reorganization, cancellation of units | Predecessor [Member]		(352,792,000)
Cancellation of the Predecessor’s units issued and outstanding | Predecessor [Member]	$ 0		(5,386,812)	5,386,812	0
Common Stock, Shares, Outstanding (Successor [Member]) at Feb. 28, 2017	89,229,892
Balance Ending (Successor [Member]) at Feb. 28, 2017						$ 89	$ 2,034,892	$ 0	$ 2,034,981
Balance Ending (Successor [Member]) at Feb. 28, 2017										$ 0
Balance Ending (Successor [Member]) at Feb. 28, 2017	$ 2,034,981
Preconfirmation, units outstanding | Predecessor [Member]		352,792,000
Preconfirmation, members' equity | Predecessor [Member]	0		5,386,812	(5,386,812)	0
Postconfirmation, common units oustanding | Predecessor [Member]		0
Postconfirmation, members' equity | Predecessor [Member]	$ 0		$ 0	$ 0	$ 0
Sale of units (in units) | Successor [Member]	42,000										89,230,000
Sale of units, net of offering costs of $8,762 | Successor [Member]	$ 0					0	0	0	0	0	$ 2,021,231	$ 89	$ 2,021,142	$ 0	$ 2,021,231	$ 0
Issuances of successor Class A common stock | Successor [Member]	$ 0					0	0	0	0	0	2,021,231	89	2,021,142	0	2,021,231	0
Cancellation of units (in units) | Successor [Member]	(5,690,000)
Distributions to unitholders | Successor [Member]	$ 0
Unit-based compensation expenses | Successor [Member]	77,790					0	77,790	0	77,790	0	13,750	0	13,750	0	13,750	0
Share-based compensation expenses | Successor [Member]	77,790					0	77,790	0	77,790	0	$ 13,750	$ 0	$ 13,750	$ 0	$ 13,750	$ 0
Other | Successor [Member]	(3,003)					0	(3,003)	0	(3,003)	0
Net loss | Successor [Member]	432,860					0	0	432,860	432,860
Net income attributable to noncontrolling interests | Successor [Member]	2,807									2,807
Net income | Successor [Member]	435,667
Repurchases of successor Class A common stock | Successor [Member]	(198,288)					(5)	(198,283)	0	(198,288)	0
Initial allocation of noncontrolling interests upon conversion of subsidiary units | Successor [Member]	0					0	(17,605)	0	(17,605)	17,605
Distributions to noncontrolling interests | Successor [Member]	(1,596)					0	0	0	0	(1,596)
Subsidiary equity transactions | Successor [Member]	$ 0					0	(155)	0	(155)	155
Common Units, Outstanding (in units) (Successor [Member]) at Dec. 31, 2017	0
Common Stock, Shares, Outstanding (Successor [Member]) at Dec. 31, 2017	83,582,000
Balance Ending (Successor [Member]) at Dec. 31, 2017	$ 2,332,586					$ 84	$ 1,899,642	$ 432,860	$ 2,332,586
Balance Ending (Successor [Member]) at Dec. 31, 2017	18,971									$ 18,971
Balance Ending (Successor [Member]) at Dec. 31, 2017	$ 2,351,557

CONSOLIDATED STATEMENT OF EQUI6

CONSOLIDATED STATEMENT OF EQUITY (Parenthetical) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Statement of Stockholders' Equity [Abstract]
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs	$ 8,672

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Successor [Member]
Cash flow from operating activities:
Net income (loss)		$ 435,667
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
(Income) loss from discontinued operations		(82,995)
Depreciation, depletion and amortization		133,711
Impairment of long-lived assets		0
Deferred income taxes		381,313
Total (gains) losses on derivatives, net		(13,533)
Cash settlements on derivatives		26,793
Share-based compensation expenses		41,285
Gain on extinguishment of debt		0
Amortization and write-off of deferred financing fees		3,711
(Gains) losses on sale of assets and other, net		(667,549)
Reorganization items, net		0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		41,094
(Increase) decrease in other assets		4,548
(Increase) decrease in restricted cash		2,151
Increase (decrease) in accounts payable and accrued expenses		(48,963)
Increase (decrease) in other liabilities		7,740
Net cash provided by (used in) operating activities – continuing operations		264,973
Net cash provided by operating activities – discontinued operations		16,191
Net cash provided by (used in) operating activities		281,164
Cash flow from investing activities:
Development of oil and natural gas properties		(171,721)
Purchases of other property and equipment		(88,595)
Deconsolidation of Berry Petroleum Company, LLC cash		0
Investment in discontinued operations		0
Proceeds from sale of properties and equipment and other		1,156,691
Net cash provided by (used in) investing activities – continuing operations		896,375
Net cash provided by (used in) investing activities – discontinued operations		345,643
Net cash provided by (used in) investing activities		1,242,018
Cash flow from financing activities:
Proceeds from rights offerings, net		0
Proceeds from sale of units		0
Repurchases of shares		(198,288)
Proceeds from borrowings		190,000
Repayments of debt		(1,090,000)
Payment to holders of claims under the second lien notes		0
Distributions to unitholders		0
Debt issuance costs paid		(7,729)
Settlement of advance from discontinued operations		0
Excess tax benefit from unit-based compensation		0
Other		(7,012)
Net cash provided by (used in) financing activities – continuing operations		(1,113,029)
Net cash used in financing activities – discontinued operations		0
Net cash provided by (used in) financing activities		(1,113,029)
Net increase (decrease) in cash and cash equivalents		410,153
Cash and cash equivalents:
Beginning		54,355
Ending	$ 54,355	464,508
Less cash and cash equivalents of discontinued operations at end of year		0
Ending – continuing operations		464,508
Predecessor [Member]
Cash flow from operating activities:
Net income (loss)	2,397,061		$ (2,171,856)	$ (4,759,811)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
(Income) loss from discontinued operations	548		1,804,513	1,005,591
Depreciation, depletion and amortization	47,155		342,614	520,219
Impairment of long-lived assets	0		165,044	4,960,144
Deferred income taxes	(166)		11,367	4,606
Total (gains) losses on derivatives, net	(92,691)		164,330	(1,027,014)
Cash settlements on derivatives	(11,572)		860,778	1,135,319
Share-based compensation expenses	50,255		44,218	56,136
Gain on extinguishment of debt	0		0	(708,050)
Amortization and write-off of deferred financing fees	1,338		13,356	30,993
(Gains) losses on sale of assets and other, net	1,069		13,007	(188,200)
Reorganization items, net	(2,359,364)		(365,367)	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	(7,216)		(71,059)	211,884
(Increase) decrease in other assets	402		(17,733)	(9,142)
(Increase) decrease in restricted cash	(80,164)		0	0
Increase (decrease) in accounts payable and accrued expenses	20,949		38,468	(98,223)
Increase (decrease) in other liabilities	2,801		(515)	(51,266)
Net cash provided by (used in) operating activities – continuing operations	(29,595)		831,165	1,083,186
Net cash provided by operating activities – discontinued operations	8,781		49,349	166,271
Net cash provided by (used in) operating activities	(20,814)		880,514	1,249,457
Cash flow from investing activities:
Development of oil and natural gas properties	(50,597)		(172,298)	(550,083)
Purchases of other property and equipment	(7,409)		(43,559)	(48,967)
Deconsolidation of Berry Petroleum Company, LLC cash	0		(28,549)	0
Investment in discontinued operations	0		0	(132,332)
Proceeds from sale of properties and equipment and other	(166)		(4,690)	345,770
Net cash provided by (used in) investing activities – continuing operations	(58,172)		(249,096)	(385,612)
Net cash provided by (used in) investing activities – discontinued operations	(584)		13,256	75,195
Net cash provided by (used in) investing activities	(58,756)		(235,840)	(310,417)
Cash flow from financing activities:
Proceeds from rights offerings, net	514,069		0	0
Proceeds from sale of units	0		0	224,665
Repurchases of shares	0		0	0
Proceeds from borrowings	0		978,500	1,445,000
Repayments of debt	(1,038,986)		(913,209)	(1,828,461)
Payment to holders of claims under the second lien notes	(30,000)		0	0
Distributions to unitholders	0		0	(323,878)
Debt issuance costs paid	0		(752)	(17,916)
Settlement of advance from discontinued operations	0		0	(129,217)
Excess tax benefit from unit-based compensation	0		0	(9,467)
Other	(6,015)		(14,823)	(74,958)
Net cash provided by (used in) financing activities – continuing operations	(560,932)		49,716	(714,232)
Net cash used in financing activities – discontinued operations	0		(1,701)	(224,449)
Net cash provided by (used in) financing activities	(560,932)		48,015	(938,681)
Net increase (decrease) in cash and cash equivalents	(640,502)		692,689	359
Cash and cash equivalents:
Beginning	694,857	$ 54,355	2,168	1,809
Ending	54,355		694,857	2,168
Less cash and cash equivalents of discontinued operations at end of year	0		0	(1,023)
Ending – continuing operations	$ 54,355		$ 694,857	$ 1,145

Basis of Presentation and Signi

Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Significant Accounting Policies	Basis of Presentation and Significant Accounting Policies When referring to Linn Energy, Inc. (formerly known as Linn Energy, LLC) (“Successor,” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a Delaware corporation formed in February 2017, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Linn Energy, Inc. is a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Linn Energy, Inc. is not a successor of Linn Energy, LLC for purposes of Delaware corporate law. When referring to the “Predecessor” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to Linn Energy, LLC, the predecessor that will be dissolved following the effective date of the Plan (as defined below) and resolution of all outstanding claims, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiary of LINN Energy through February 28, 2017. Berry was deconsolidated effective December 3, 2016 (see Note 4). The reference to “LinnCo” herein refers to LinnCo, LLC, which was an affiliate of the Predecessor. Nature of Business LINN Energy is an independent oil and natural gas company that was formed in February 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017. The Company’s properties are currently located in six operating regions in the United States (“U.S.”): Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; TexLa, which includes properties located in east Texas and north Louisiana; Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; Mid-Continent, which includes Oklahoma properties located in the Arkoma basin and the Northwest STACK, as well as waterfloods in the Central Oklahoma Platform; Permian Basin, which includes properties located in west Texas and southeast New Mexico; and Rockies, which includes Utah properties located in Uinta Basin. The Company also owns a 50% equity interest in Roan Resources LLC (“Roan”), which is focused on the accelerated development of the Merge/SCOOP/STACK play in Oklahoma. During 2017, the Company divested of its properties located in previous operating regions California and South Texas. Principles of Consolidation and Reporting The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Noncontrolling interests represent ownership in the net assets of the Company’s consolidated subsidiary, Linn Energy Holdco LLC (“Holdco”), not attributable to LINN Energy, and are presented as a component of equity. Changes in the Company’s ownership interests in Holdco that do not result in deconsolidation are recognized in equity. See Note 14 for additional information about noncontrolling interests. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. See Note 5 for additional information about equity method investments. The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. The Company has also classified the assets and liabilities of its California properties, as well as the results of operations and cash flows of its California properties and Berry, as discontinued operations on its consolidated financial statements. Such reclassifications have no impact on previously reported net income (loss), stockholders’/unitholders’ equity (deficit) or cash flows. See Note 4 for additional information. Bankruptcy Accounting The consolidated financial statements have been prepared as if the Company will continue as 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 are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on the Company’s consolidated balance sheet at December 31, 2016 . These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less. Upon emergence from bankruptcy on February 28, 2017, the Company adopted fresh start accounting which resulted in the Company becoming a new entity for financial reporting purposes. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the consolidated financial statements on or after February 28, 2017, are not comparable with the consolidated financial statements prior to that date. See Note 3 for additional information. Use of Estimates The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, and fair values of commodity derivatives. In addition, as part of fresh start accounting, the Company made estimates and assumptions related to its reorganization value, liabilities subject to compromise, the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting and income taxes. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods. Recently Adopted Accounting Standards In March 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The Company adopted this ASU on January 1, 2017. The adoption of this ASU had no impact on the Company’s historical financial statements or related disclosures. Upon adoption and subsequently this ASU will result in excess tax benefits, which were previously recorded in equity on the balance sheets and classified as financing activities on the statements of cash flows, being recorded in the statements of operations and classified as operating activities on the statements of cash flows. Additionally, the Company elected to begin accounting for forfeitures as they occur. New Accounting Standards Issued But Not Yet Adopted In November 2016, the FASB issued an ASU that is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures. The adoption of this ASU is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the balance sheets to cash, cash equivalents and restricted cash on the statements of cash flows. In February 2016, the FASB issued an ASU that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2018, and interim periods within those years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures. The Company expects the adoption of this ASU to impact its balance sheets resulting from an increase in both assets and liabilities related to the Company’s leasing activities. In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those years. The Company has completed an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. While the Company does not currently expect its net income to be materially impacted, the Company’s gross revenues and expenses are expected to be impacted based on a determination of when control of the commodity is transferred and whether it is acting as a principal or agent in certain transactions. In addition, the Company expects to recognize revenue for commodities received as noncash consideration in exchange for services provided by its midstream business and revenue and associated cost of product for the subsequent sale of those same commodities. This recognition will result in an increase to revenues and expenses with no impact on net income. The Company continues to evaluate the impact of these and other provisions of the ASU on its accounting policies, internal controls and financial statements. The Company will adopt this new standard as of January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings. Cash Equivalents For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows. Accounts Receivable – Trade, Net Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million and $8 million at December 31, 2017 , and December 31, 2016 , respectively. Inventories Materials, supplies and commodity inventories are valued at the lower of average cost and net realizable value. Oil and Natural Gas Properties As a result of the application of fresh start accounting, the Company recorded its oil and natural gas properties at fair value as of the Effective Date. See Note 3 for additional information. Proved Properties The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $158,000 for the ten months ended December 31, 2017 , and approximately $257,000 and $3 million for the years ended December 31, 2016 , and December 31, 2015 , respectively. The Company did not capitalize any interest costs during the two months ended February 28, 2017. The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. 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 New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Based on the analysis described above, the Company recorded the following noncash impairment charges associated with proved oil and natural gas properties: Predecessor Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) Mid-Continent region $ 141,902 $ 405,370 Rockies region 23,142 1,592,256 Hugoton Basin region — 1,667,768 TexLa region — 352,422 Permian Basin region — 71,990 South Texas region — 42,433 $ 165,044 $ 4,132,239 The impairment charges in 2016 and 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. The Company recorded no impairment charges associated with proved properties during the ten months ended December 31, 2017 , or the two months ended February 28, 2017. Unproved Properties Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past. Based on the analysis described above, the Company recorded the following noncash impairment charges associated with unproved oil and natural gas properties: Predecessor Year Ended December 31, 2015 (in thousands) TexLa region $ 416,846 Permian Basin region 226,922 Rockies region 184,137 $ 827,905 The Company recorded no impairment charges associated with unproved properties for the ten months ended December 31, 2017 , the two months ended February 28, 2017, or the year ended December 31, 2016 . The impairment charges in 2015 were based primarily on no future plans to develop properties in certain operating areas as a result of declines in commodity prices. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. Exploration Costs Exploratory geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. Other Property and Equipment Other property and equipment includes natural gas gathering systems, pipelines, furniture and office equipment, buildings, vehicles, information technology equipment, software and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from one to 39 years for the individual asset or group of assets. Accounting for Investment in Roan Resources LLC The Company uses the equity method of accounting for its investment in Roan. The Company’s equity earnings (losses) consists of its share of Roan’s earnings or losses and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets. Impairment testing on the Company’s investment in Roan is performed when events or circumstances warrant such testing and considers whether there is an inability to recover the carrying value of the investment that is other than temporary. See Note 5 for additional details about the Company’s investment in Roan. Derivative Instruments Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials. The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date. Derivative instruments are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads are applied to the Company’s commodity derivatives. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments. Revenue Recognition Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Upon the adoption of fresh start accounting on February 28, 2017, the Company has elected the sales method to account for natural gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. The Predecessor had applied the entitlements method to account for natural gas production imbalances in previous periods. The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses. Share-Based Compensation The Company recognizes expense for share-based compensation over the requisite service period in an amount equal to the fair value of share-based awards granted. The fair value of share-based awards, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. Beginning in 2017, the Company accounts for forfeitures as they occur. See Note 15 for additional details about the Company’s accounting for share-based compensation. Deferred Financing Fees The Company has incurred legal and bank fees related to the issuance of debt. At December 31, 2017 , net deferred financing fees of approximately $4 million are included in “other noncurrent assets” on the consolidated balance sheet. At December 31, 2016 , net deferred financing fees of approximately $17 million are included in “other current assets” and approximately $1 million are included in “current portion of long-term debt, net” on the consolidated balance sheet. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense. For the ten months ended December 31, 2017 , the two months ended February 28, 2017, and the years ended December 31, 2016 , and December 31, 2015 , amortization expense of approximately $1 million , $1 million , $10 million and $20 million , respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations. For the ten months ended December 31, 2017 , and the years ended December 31, 2016 , and December 31, 2015 , approximately $3 million , $1 million and $7 million , respectively, were written off to expense and included in “other, net” on the consolidated statements of operations related to amendments of the Company’s credit facilities. In addition, for the year ended December 31, 2016 , approximately $33 million were written off to expense and included in “reorganization items, net” on the consolidated statement of operations in connection with the filing of the Bankruptcy Petitions. No fees were written off to expense for the two months ended February 28, 2017. Fair Value of Financial Instruments The carrying values of the Company’s receivables, payables an d credit facilities are estimated to be substantially the same as their fair values at December 31, 2017 , and December 31, 2016 . See Note 6 for fair value disclosures related to the Company’s other debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments. Income Taxes The Successor was formed as a C corporation. For federal and state income tax purposes (with the exception of the state of Texas), the Predecessor was a limited liability company treated as a partnership, in which income tax liabilities and/or benefits were passed through to the Predecessor’s unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and tax carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 17 for additional details of the Company’s accounting for income taxes.

Emergence From Voluntary Reorga

Emergence From Voluntary Reorganization Under Chapter 11	12 Months Ended
	Dec. 31, 2017
Reorganizations [Abstract]
Emergence From Voluntary Reorganization Under Chapter 11	Emergence From Voluntary Reorganization Under Chapter 11 On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. On December 3, 2016, the LINN Debtors filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC (“LAC”) and Berry Petroleum Company, LLC (the “Plan”). The LINN Debtors subsequently filed amended versions of the Plan with the Bankruptcy Court. On December 13, 2016, LAC and Berry filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Berry Plan” and together with the Plan, the “Plans”). LAC and Berry subsequently filed amended versions of the Berry Plan with the Bankruptcy Court. On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plans (the “Confirmation Order”). On February 28, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the respective Plans, the Plans became effective in accordance with their respective terms and LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. Plan of Reorganization In accordance with the Plan, on the Effective Date: • The Predecessor transferred all of its assets, including equity interests in its subsidiaries, other than LAC and Berry, to Linn Energy Holdco II LLC (“Holdco II”), a newly formed wholly owned subsidiary of the Predecessor and the borrower under the Credit Agreement (as amended, the “Successor Credit Facility”) entered into in connection with the reorganization, in exchange for equity interests in Holdco II and the issuance of interests in the Successor Credit Facility to certain of the Predecessor’s creditors in partial satisfaction of their claims (the “Contribution”). Immediately following the Contribution, the Predecessor transferred equity interests in Holdco II to the Successor in exchange for approximately $530 million in cash, an amount of equity securities in the Successor not to exceed 49.90% of the outstanding equity interests of the Successor, which the Predecessor distributed to certain of its creditors in satisfaction of their claims, and the Successor’s agreement to honor certain obligations of the Predecessor under the Plan. In connection with this transfer, certain entities composing the Successor guaranteed the Successor Credit Facility. Contemporaneously with the reorganization transactions and pursuant to the Plan, (i) LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, (ii) all of the equity interests in LAC and the Predecessor were canceled and (iii) LAC and the Predecessor commenced liquidation, which is expected to be completed following the resolution of the respective companies’ outstanding claims. • The holders of claims under the Predecessor’s Sixth Amended and Restated Credit Agreement (“Predecessor Credit Facility”) received a full recovery, consisting of a cash paydown and their pro rata share of the $1.7 billion Successor Credit Facility. As a result, all outstanding obligations under the Predecessor Credit Facility were canceled. • Holdco II, as borrower, entered into the Successor Credit Facility with the holders of claims under the Predecessor Credit Facility, as lenders, and Wells Fargo Bank, National Association, as administrative agent, providing for a new reserve-based revolving loan with up to $1.4 billion in borrowing commitments and a new term loan in an original principal amount of $300 million . For additional information about the Successor Credit Facility, see Note 6. • The holders of the Company’s 12.00% senior secured second lien notes due December 2020 (the “Second Lien Notes”) received their pro rata share of (i) 17,678,889 shares of Class A common stock; (ii) certain rights to purchase shares of Class A common stock in the rights offerings, as described below; and (iii) $30 million in cash. The holders of the Company’s 6.50% senior notes due May 2019, 6.25% senior notes due November 2019, 8.625% senior notes due 2020, 7.75% senior notes due February 2021 and 6.50% senior notes due September 2021 (collectively, the “Unsecured Notes”) received their pro rata share of (i) 26,724,396 shares of Class A common stock; and (ii) certain rights to purchase shares of Class A common stock in the rights offerings, as described below. As a result, all outstanding obligations under the Second Lien Notes and the Unsecured Notes and the indentures governing such obligations were canceled. • The holders of general unsecured claims (other than claims relating to the Second Lien Notes and the Unsecured Notes) against the LINN Debtors (the “LINN Unsecured Claims”) received their pro rata share of cash from two cash distribution pools totaling $40 million , as divided between a $2.3 million cash distribution pool for the payment in full of allowed LINN Unsecured Claims in an amount equal to $2,500 or less (and larger claims for which the holders irrevocably agreed to reduce such claims to $2,500 ), and a $37.7 million cash distribution pool for pro rata distributions to all remaining allowed general LINN Unsecured Claims. As a result, all outstanding LINN Unsecured Claims were fully satisfied, settled, released and discharged as of the Effective Date. • All units of the Predecessor that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery. On the Effective Date, the Successor issued in the aggregate 89,229,892 shares of Class A common stock. No cash was raised from the issuance of the Class A common stock on account of claims held by the Predecessor’s creditors. • The Successor entered into a registration rights agreement with certain parties, pursuant to which the Company agreed to, among other things, file a registration statement with the SEC within 60 days of the Effective Date covering the offer and resale of “Registrable Securities” (as defined therein). • By operation of the Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. The Successor formed a new board of directors, consisting of the Chief Executive Officer of the Predecessor, one director selected by the Successor and five directors selected by a six-person selection committee. Rights Offerings On October 25, 2016, the Company entered into a backstop commitment agreement (“Backstop Commitment Agreement”) with the parties thereto (collectively, the “Backstop Parties”). In accordance with the Plan, the Backstop Commitment Agreement and the rights offerings procedures filed in the Chapter 11 cases and approved by the Bankruptcy Court, the eligible creditors were offered the right to purchase Class A common stock from the Successor in connection with the consummation of the Plan for an aggregate purchase price of $530 million . Under the Backstop Commitment Agreement, certain Backstop Parties agreed to purchase their pro rata share of the shares that were not duly subscribed to pursuant to the offerings at the discounted per share price set forth in the Backstop Commitment Agreement by parties other than Backstop Parties. Pursuant to the Backstop Commitment Agreement, the Backstop Parties were entitled to receive, on the Effective Date, a commitment premium equal to 4.0% of the $530 million committed amount, of which 3.0% was paid in cash and 1.0% was paid in the form of Class A common stock at the discounted per share price set forth in the Backstop Commitment Agreement. On the Effective Date, all conditions to the rights offerings and the Backstop Commitment Agreement were met, and the rights offerings and the related issuances of Class A common stock were completed. Liabilities Subject to Compromise The Predecessor’s consolidated balance sheet as of December 31, 2016 , includes amounts classified as “liabilities subject to compromise,” which represent prepetition liabilities that were allowed, or that the Company estimated would be allowed, as claims in its Chapter 11 cases. The following table summarizes the components of liabilities subject to compromise included on the consolidated balance sheet: Predecessor December 31, 2016 (in thousands) Accounts payable and accrued expenses $ 137,692 Accrued interest payable 144,184 Debt 4,023,129 Liabilities subject to compromise $ 4,305,005 Reorganization Items, Net The Company incurred significant costs and recognized significant gains associated with the reorganization. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments were determined. The following tables summarize the components of reorganization items included on the consolidated statements of operations: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 (in thousands) Gain on settlement of liabilities subject to compromise $ — $ 3,724,750 $ — Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement — (1,000,000 ) — Fresh start valuation adjustments — (591,525 ) — Income tax benefit related to implementation of the Plan — 264,889 — Legal and other professional advisory fees (8,902 ) (46,961 ) (56,656 ) Unamortized deferred financing fees, discounts and premiums — — (52,045 ) Gain related to interest payable on Predecessor’s Second Lien Notes — — 551,000 Terminated contracts — (6,915 ) (66,052 ) Other 51 (13,049 ) (64,648 ) Reorganization items, net $ (8,851 ) $ 2,331,189 $ 311,599

Fresh Start Accounting

Fresh Start Accounting	12 Months Ended
	Dec. 31, 2017
Fresh Start Accounting [Abstract]
Fresh Start Accounting	Fresh Start Accounting Upon the Company’s emergence from Chapter 11 bankruptcy, it adopted fresh start accounting in accordance with the provisions of ASC 852 which resulted in the Company becoming a new entity for financial reporting purposes. In accordance with ASC 852, the Company was required to adopt fresh start accounting upon its emergence from Chapter 11 because (i) the holders of existing voting ownership interests of the Predecessor received less than 50% of the voting shares of the Successor and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims. Upon adoption of fresh start accounting, the reorganization value derived from the enterprise value as disclosed in the Plan was allocated to the Company’s assets and liabilities based on their fair values (except for deferred income taxes) in accordance with ASC 805 “Business Combinations” (“ASC 805”). The amount of deferred income taxes recorded was determined in accordance with ASC 740 “Income Taxes” (“ASC 740”). The Effective Date fair values of the Company’s assets and liabilities differed materially from their recorded values as reflected on the historical balance sheet. The effects of the Plan and the application of fresh start accounting were reflected on the consolidated balance sheet as of February 28, 2017, and the related adjustments thereto were recorded on the consolidated statement of operations for the two months ended February 28, 2017. As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the Company’s consolidated financial statements subsequent to February 28, 2017, are not comparable to its consolidated financial statements prior to February 28, 2017. References to “Successor” relate to the financial position and results of operations of the reorganized Company as of and subsequent to February 28, 2017. References to “Predecessor” relate to the financial position of the Company prior to, and results of operations through and including, February 28, 2017. The Company’s consolidated financial statements and related footnotes are presented with a black line division, which delineates the lack of comparability between amounts presented after February 28, 2017, and amounts presented on or prior to February 28, 2017. The Company’s financial results for future periods following the application of fresh start accounting will be different from historical trends and the differences may be material. Reorganization Value Under ASC 852, the Successor determined a value to be assigned to the equity of the emerging entity as of the date of adoption of fresh start accounting. The Plan confirmed by the Bankruptcy Court estimated an enterprise value of $2.35 billion . The Plan enterprise value was prepared using an asset based methodology, as discussed further below. The enterprise value was then adjusted to determine the equity value of the Successor of approximately $2.03 billion . Adjustments to determine the equity value are presented below (in thousands): Plan confirmed enterprise value $ 2,350,000 Fair value of debt (900,000 ) Fair value of subsequently determined tax attributes 621,486 Fair value of vested Class B units (36,505 ) Value of Successor’s stockholders’ equity $ 2,034,981 The subsequently determined tax attributes were primarily the result of the conversion from a limited liability company to a C corporation and differences in the accounting basis and tax basis of the Company’s oil and natural gas properties as of the Effective Date. The Class B units are incentive interest awards that were granted on the Effective Date by Holdco to certain members of its management (see Note 15), and the associated fair value was recorded as a liability of approximately $7 million in “other accrued liabilities” and temporary equity of approximately $29 million in “redeemable noncontrolling interests” on the consolidated balance sheet at February 28, 2017. The Company’s principal assets are its oil and natural gas properties. The fair values of oil and natural gas properties were estimated using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. 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 New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. See below under “Fresh Start Adjustments” for additional information regarding assumptions used in the valuation of the Company’s various other significant assets and liabilities. Consolidated Balance Sheet The adjustments included in the following fresh start consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and executed by the Company on the Effective Date (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 February 28, 2017 Predecessor Reorganization Adjustments (1) Fresh Start Adjustments Successor (in thousands) ASSETS Current assets: Cash and cash equivalents $ 734,166 $ (679,811 ) (2) $ — $ 54,355 Accounts receivable – trade, net 212,099 — (7,808 ) (16) 204,291 Derivative instruments 15,391 — — 15,391 Restricted cash 1,602 80,164 (3) — 81,766 Other current assets 106,426 (15,983 ) (4) 1,780 (17) 92,223 Total current assets 1,069,684 (615,630 ) (6,028 ) 448,026 Noncurrent assets: Oil and natural gas properties (successful efforts method) 13,269,035 — (11,082,258 ) (18) 2,186,777 Less accumulated depletion and amortization (10,044,240 ) — 10,044,240 (18) — 3,224,795 — (1,038,018 ) 2,186,777 Other property and equipment 641,586 — (197,653 ) (19) 443,933 Less accumulated depreciation (230,952 ) — 230,952 (19) — 410,634 — 33,299 443,933 Derivative instruments 4,492 — — 4,492 Deferred income taxes — 264,889 (5) 356,597 (5) 621,486 Other noncurrent assets 15,003 151 (6) 8,139 (20) 23,293 19,495 265,040 364,736 649,271 Total noncurrent assets 3,654,924 265,040 (639,983 ) 3,279,981 Total assets $ 4,724,608 $ (350,590 ) $ (646,011 ) $ 3,728,007 LIABILITIES AND EQUITY (DEFICIT) Current liabilities: Accounts payable and accrued expenses $ 324,585 $ 41,266 (7) $ (2,351 ) (21) $ 363,500 Derivative instruments 7,361 — — 7,361 Current portion of long-term debt, net 1,937,822 (1,912,822 ) (8) — 25,000 Other accrued liabilities 41,251 (1,026 ) (9) 1,104 (22) 41,329 Total current liabilities 2,311,019 (1,872,582 ) (1,247 ) 437,190 Derivative instruments 2,116 — — 2,116 Long-term debt — 875,000 (10) — 875,000 Other noncurrent liabilities 402,776 (167 ) (11) (53,239 ) (23) 349,370 Liabilities subject to compromise 4,301,912 (4,301,912 ) (12) — — Temporary equity: Redeemable noncontrolling interests — 29,350 (13) — 29,350 As of February 28, 2017 Predecessor Reorganization Adjustments (1) Fresh Start Adjustments Successor Stockholders’/unitholders’ equity (deficit): Predecessor units issued and outstanding 5,386,812 (5,386,812 ) (14) — — Predecessor accumulated deficit (7,680,027 ) 2,884,740 (15) 4,795,287 (24) — Successor Class A common stock — 89 (14) — 89 Successor additional paid-in capital — 7,421,704 (14) (5,386,812 ) (24) 2,034,892 Successor retained earnings — — — — Total stockholders’/unitholders’ equity (deficit) (2,293,215 ) 4,919,721 (591,525 ) 2,034,981 Total liabilities and equity (deficit) $ 4,724,608 $ (350,590 ) $ (646,011 ) $ 3,728,007 Reorganization Adjustments: 1) Represent 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, repayment of certain of the Predecessor’s debt, cancellation of the Predecessor’s equity, issuances of the Successor’s Class A common stock, proceeds received from the Successor’s rights offerings and issuance of the Successor’s debt. 2) Changes in cash and cash equivalents included the following: (in thousands) Borrowings under the Successor’s revolving loan $ 600,000 Borrowings under the Successor’s term loan 300,000 Proceeds from rights offerings 530,019 Removal of restriction on cash balance 1,602 Payment to holders of claims under the Predecessor Credit Facility (1,947,357 ) Payment to holders of claims under the Second Lien Notes (30,000 ) Payment of Berry’s ad valorem taxes (23,366 ) Payment of the rights offerings backstop commitment premium (15,900 ) Payment of professional fees (13,043 ) Funding of the professional fees escrow account (41,766 ) Funding of the general unsecured claims cash distribution pool (40,000 ) Changes in cash and cash equivalents $ (679,811 ) 3) Primarily reflects the transfer to restricted cash to fund the Predecessor’s professional fees escrow account and general unsecured claims cash distribution pool. 4) Primarily reflects the write-off of the Predecessor’s deferred financing fees. 5) Reflects deferred tax assets recorded as of the Effective Date as determined in accordance with ASC 740. The deferred tax assets were primarily the result of the conversion from a limited liability company to a C corporation and differences in the accounting basis and tax basis of the Company’s oil and natural gas properties as of the Effective Date. 6) Reflects the capitalization of deferred financing fees related to the Successor’s revolving loan. 7) Net increase in accounts payable and accrued expenses reflects: (in thousands) Recognition of payables for the professional fees escrow account $ 41,766 Recognition of payables for the general unsecured claims cash distribution pool 40,000 Payment of professional fees (17,130 ) Payment of Berry’s ad valorem taxes (23,366 ) Other (4 ) Net increase in accounts payable and accrued expenses $ 41,266 8) Reflects the settlement of the Predecessor Credit Facility through repayment of approximately $1.9 billion , net of the write-off of deferred financing fees and an increase of $25 million for the current portion of the Successor’s term loan. 9) Reflects a decrease of approximately $8 million for the payment of accrued interest on the Predecessor Credit Facility partially offset by an increase of approximately $7 million related to noncash share-based compensation classified as a liability related to the incentive interest awards issued by Holdco to certain members of its management (see Note 15). 10) Reflects borrowings of $900 million under the Successor Credit Facility, which includes a $600 million revolving loan and a $300 million term loan, net of $25 million for the current portion of the Successor’s term loan. 11) Reflects a reduction in deferred tax liabilities as determined in accordance with ASC 740. 12) Settlement of liabilities subject to compromise and the resulting net gain were determined as follows: (in thousands) Accounts payable and accrued expenses $ 134,599 Accrued interest payable 144,184 Debt 4,023,129 Total liabilities subject to compromise 4,301,912 Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement 1,000,000 Funding of the general unsecured claims cash distribution pool (40,000 ) Payment to holders of claims under the Second Lien Notes (30,000 ) Issuance of Class A common stock to creditors (1,507,162 ) Gain on settlement of liabilities subject to compromise $ 3,724,750 13) Reflects redeemable noncontrolling interests classified as temporary equity related to the incentive interest awards issued by Holdco to certain members of its management. See Note 15 for additional information. 14) Net increase in capital accounts reflects: (in thousands) Issuance of Class A common stock to creditors $ 1,507,162 Issuance of Class A common stock pursuant to the rights offerings 530,019 Payment of the rights offerings backstop commitment premium (15,900 ) Payment of issuance costs (50 ) Share-based compensation expenses 13,750 Cancellation of the Predecessor’s units issued and outstanding 5,386,812 Par value of Class A common stock (89 ) Change in additional paid-in capital 7,421,704 Par value of Class A common stock 89 Predecessor’s units issued and outstanding (5,386,812 ) Net increase in capital accounts $ 2,034,981 See Note 13 for additional information on the issuances of the Successor’s equity. 15) Net decrease in accumulated deficit reflects: (in thousands) Recognition of gain on settlement of liabilities subject to compromise $ 3,724,750 Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement (1,000,000 ) Recognition of professional fees (37,680 ) Write-off of deferred financing fees (16,728 ) Recognition of deferred income taxes 264,889 Total reorganization items, net 2,935,231 Share-based compensation expenses (50,255 ) Other (236 ) Net decrease in accumulated deficit $ 2,884,740 Fresh Start Adjustments: 16) Reflects a change in accounting policy from the entitlements method to the sales method for natural gas production imbalances. 17) Reflects the recognition of intangible assets for the current portion of favorable leases, partially offset by decreases for well equipment inventory and the write-off of historical intangible assets. 18) Reflects a decrease of oil and natural gas properties, based on the methodology discussed above, and the elimination of accumulated depletion and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date: Successor Predecessor Fair Value Historical Book Value (in thousands) Proved properties $ 1,727,834 $ 12,258,835 Unproved properties 458,943 1,010,200 2,186,777 13,269,035 Less accumulated depletion and amortization — (10,044,240 ) $ 2,186,777 $ 3,224,795 19) Reflects a decrease of other property and equipment and the elimination of accumulated depreciation. The following table summarizes the components of other property and equipment as of the Effective Date: Successor Predecessor Fair Value Historical Book Value (in thousands) Natural gas plants and pipelines $ 342,924 $ 426,914 Office equipment and furniture 39,211 106,059 Buildings and leasehold improvements 32,817 66,023 Vehicles 16,980 30,760 Land 7,747 3,727 Drilling and other equipment 4,254 8,103 443,933 641,586 Less accumulated depreciation — (230,952 ) $ 443,933 $ 410,634 In estimating the fair value of other property and equipment, the Company used a combination of cost and market approaches. A cost approach was used to value the Company’s natural gas plants and pipelines and other operating assets, 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. A market approach was used to value the Company’s vehicles and land, using recent transactions of similar assets to determine the fair value from a market participant perspective. 20) Reflects the recognition of intangible assets for the noncurrent portion of favorable leases, as well as increases in equity method investments and carbon credit allowances. Assets and liabilities for out-of-market contracts were valued based on market terms as of February 28, 2017, and will be amortized over the remaining life of the respective lease. The Company’s equity method investments were valued based on a market approach using a market EBITDA multiple. Carbon credit allowances were valued using a market approach based on trading prices for carbon credits on February 28, 2017. 21) Primarily reflects the write-off of deferred rent partially offset by an increase in carbon emissions liabilities. 22) Reflects an increase of the current portion of asset retirement obligations. 23) Primarily reflects a decrease of approximately $49 million for asset retirement obligations and approximately $5 million for deferred rent, partially offset by an increase of approximately $1 million for carbon emissions liabilities. The fair value of asset retirement obligations were estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. Carbon emissions liabilities were valued using a market approach based on trading prices for carbon credits on February 28, 2017. 24) Reflects the cumulative impact of the fresh start accounting adjustments discussed above and the elimination of the Predecessor’s accumulated deficit.

Discontinued Operations, Other

Discontinued Operations, Other Divestitures and Roan Contribution	12 Months Ended
	Dec. 31, 2017
Acquisitions and divestitures [Abstract]
Discontinued Operations, Other Divestitures and Roan Contribution	Discontinued Operations, Other Divestitures and Roan Contribution Discontinued Operations On July 31, 2017, the Company completed the sale of its interest in properties located in the San Joaquin Basin in California (the “San Joaquin Basin Sale”). Cash proceeds received from the sale of these properties were approximately $253 million , net of costs to sell of approximately $4 million , and the Company recognized a net gain of approximately $120 million . The gain is included in “income (loss) from discontinued operations, net of income taxes” on the consolidated statements of operations. On July 21, 2017, the Company completed the sale of its interest in properties located in the Los Angeles Basin in California (the “Los Angeles Basin Sale”). Cash proceeds received from the sale of these properties were approximately $93 million , net of costs to sell of approximately $2 million , and the Company recognized a net gain of approximately $2 million . The gain is included in “income (loss) from discontinued operations, net of income taxes” on the consolidated statements of operations. The Company will receive an additional $7 million contingent payment if certain operational requirements are satisfied within one year from the date of sale. As a result of the Company’s strategic exit from California (completed by the San Joaquin Basin Sale and Los Angeles Basin Sale), the Company classified the assets and liabilities, results of operations and cash flows of its California properties as discontinued operations on its consolidated financial statements. On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry (see Note 2). As a result of its loss of control of Berry, LINN Energy concluded that it was appropriate to deconsolidate Berry effective on the aforementioned date and classified it as discontinued operations. The following table presents carrying amounts of the assets and liabilities of the Company’s California properties classified as discontinued operations on the consolidated balance sheet: Predecessor December 31, 2016 (in thousands) Assets: Oil and natural gas properties $ 728,190 Other property and equipment 11,402 Other 1,435 Total assets of discontinued operations $ 741,027 Liabilities: Asset retirement obligations $ 38,042 Other 1,481 Total liabilities of discontinued operations $ 39,523 All balances of discontinued operations on the consolidated balance sheet relate to the Company’s California properties, as Berry was deconsolidated effective December 3, 2016. The following tables present summarized financial results of the Company’s California properties and Berry classified as discontinued operations on the consolidated statements of operations: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) Revenues and other $ 34,096 $ 14,891 $ 465,775 $ 727,211 Expenses 19,479 13,758 1,612,727 1,651,114 Other income and (expenses) (3,541 ) (1,681 ) (65,022 ) (81,756 ) Reorganization items, net — — (46,127 ) — Income (loss) from discontinued operations before income taxes 11,076 (548 ) (1,258,101 ) (1,005,659 ) Income tax expense (benefit) 4,165 — 196 (68 ) Income (loss) from discontinued operations, net of income taxes $ 6,911 $ (548 ) $ (1,258,297 ) $ (1,005,591 ) In addition, for the ten months ended December 31, 2017 , the Successor recognized a net gain on the sale of the California properties of approximately $76 million (net of income tax expense of approximately $46 million ), and for the year ended December 31, 2016 , the Predecessor recognized a net loss on the deconsolidation of Berry of approximately $546 million . Results of operations of Berry are only included for the period from January 1, 2016 through December 3, 2016, and the year ended December 31, 2015 , as Berry was deconsolidated effective December 3, 2016. Other income and (expenses) include an allocation of interest expense for the California properties of approximately $4 million , $2 million , $8 million and $4 million for the ten months ended December 31, 2017 , the two months ended February 28, 2017, and the years ended December 31, 2016 , and December 31, 2015 , respectively, which represents interest on debt that was required to be repaid as a result of the sales. Berry Transition Services and Separation Agreement On the Effective Date, Berry entered into a Transition Services and Separation Agreement (the “TSSA”) with LINN Energy and certain of its subsidiaries to facilitate the separation of Berry’s operations from LINN Energy’s operations. Pursuant to the TSSA, LINN Energy continued to provide, or caused to be provided, certain administrative, management, operating, and other services and support to Berry during a transitional period following the Effective Date (the “Transition Services”). Under the TSSA, Berry reimbursed LINN Energy for any and all reasonable, third-party out-of-pocket costs and expenses, without markup, actually incurred by LINN Energy, to the extent documented, in connection with providing the Transition Services. Additionally, Berry paid to LINN Energy a management fee of $6 million per month, prorated for partial months, during the period from the Effective Date through the last day of the second full calendar month after the Effective Date (the “Transition Period”) and paid $2.7 million per month, prorated for partial months, from the first day following the Transition Period through the last day of the second full calendar month thereafter (the “Accounting Period”). During the Accounting Period, the scope of the Transition Services was reduced to specified accounting and administrative functions. The Transition Period ended April 30, 2017, and the Accounting Period ended June 30, 2017. Other Divestitures On November 30, 2017, the Company completed the sale of its interest in properties located in the Williston Basin (the “Williston Assets Sale”). Cash proceeds received from the sale of these properties were approximately $255 million , net of costs to sell of approximately $3 million , and the Company recognized a net gain of approximately $116 million . On November 30, 2017, the Company completed the sale of its interest in properties located in Wyoming (the “Washakie Assets Sale”). Cash proceeds received from the sale of these properties were approximately $193 million , net of costs to sell of approximately $2 million , and the Company recognized a net gain of approximately $175 million . On September 12, 2017, August 1, 2017, and July 31, 2017, the Company completed the sales of its interest in certain properties located in south Texas (the “South Texas Assets Sales”). Combined cash proceeds received from the sale of these properties were approximately $48 million , net of costs to sell of approximately $1 million , and the Company recognized a combined net gain of approximately $14 million . On August 23, 2017, July 28, 2017, and May 9, 2017, the Company completed the sales of its interest in certain properties located in Texas and New Mexico (the “Permian Assets Sales”). Combined cash proceeds received from the sale of these properties were approximately $31 million and the Company recognized a combined net gain of approximately $29 million . On June 30, 2017, the Company completed the sale of its interest in properties located in the Salt Creek Field in Wyoming (the “Salt Creek Assets Sale”). Cash proceeds received from the sale of these properties were approximately $73 million , net of costs to sell of approximately $1 million , and the Company recognized a net gain of approximately $30 million . On May 31, 2017, the Company completed the sale of its interest in properties located in western Wyoming (the “Jonah Assets Sale”). Cash proceeds received from the sale of these properties were approximately $559 million , net of costs to sell of approximately $6 million , and the Company recognized a net gain of approximately $277 million . The divestitures discussed above are not presented as discontinued operations because they do not represent a strategic shift that will have a major effect on the Company’s operations and financial results. The gains on these divestitures are included in “gains (losses) on sale of assets and other, net” on the consolidated statements of operations. Divestitures – Pending On February 13, 2018, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in conventional properties located in west Texas for a contract price of $119.5 million , subject to closing adjustments. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. On January 15, 2018, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its interest in properties located in the Altamont Bluebell Field in Utah for a contract price of $132 million, subject to closing adjustments. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. On December 18, 2017, the Company, through certain of its subsidiaries, entered into a definitive purchase and sale agreement to sell its Oklahoma waterflood and Texas Panhandle properties for a contract price of $122 million , subject to closing adjustments. The sale is anticipated to close in the first quarter of 2018, subject to closing conditions. There can be no assurance that all of the conditions to closing will be satisfied. The assets and liabilities associated with the pending divestiture of Oklahoma waterflood and Texas Panhandle properties are classified as “held for sale” on the consolidated balance sheet. At December 31, 2017 , the Company’s consolidated balance sheet included current assets of approximately $107 million included in “assets held for sale” and current liabilities of approximately $43 million included in “liabilities held for sale” related to this transaction. The following table presents carrying amounts of the assets and liabilities of the Company’s properties classified as held for sale on the consolidated balance sheet: Successor December 31, 2017 (in thousands) Assets: Oil and natural gas properties $ 92,245 Other property and equipment 12,983 Other 1,735 Total assets held for sale $ 106,963 Liabilities: Asset retirement obligations $ 42,001 Other 1,301 Total liabilities held for sale $ 43,302 Other assets primarily include inventories and other liabilities primarily include accounts payable. Roan Contribution On August 31, 2017, the Company, through certain of its subsidiaries, completed the transaction in which LINN Energy and Citizen Energy II, LLC (“Citizen”) each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan Resources LLC (the contribution, the “Roan Contribution”), focused on the accelerated development of the Merge/SCOOP/STACK play. In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan, subject to customary post-closing adjustments. As of August 31, 2017, the date of the Roan Contribution, the Company recognized its equity investment at carryover basis of approximately $452 million . In connection with the Roan Contribution, the Company paid approximately $17 million in advisory fees, which are included in “gains (losses) on sale of assets and other, net” on the consolidated statements of operations. See Note 5 for additional information about the Company’s equity method investment in Roan. Divestiture – 2015 On August 31, 2015, the Company completed the sale of its remaining position in Howard County in the Permian Basin (the “Howard County Assets Sale”). Cash proceeds received from the sale of these properties were approximately $276 million , net of costs to sell of approximately $1 million , and the Company recognized a net gain of approximately $177 million . The gain is included in “(gains) losses on sale of assets and other, net” on the consolidated statement of operations.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Equity Method Investments On August 31, 2017, the Company completed the transaction in which LINN Energy and Citizen each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan, focused on the accelerated development of the Merge/SCOOP/STACK play. See Note 4 for additional information. The Company uses the equity method of accounting for its investment in Roan. The Company’s equity earnings (losses) consists of its share of Roan’s earnings or losses and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets. At both December 31, 2017 , and August 31, 2017 (the date of the Roan Contribution), the Company owned 50% of Roan’s outstanding units. The percentage ownership in Roan is subject to customary post-closing adjustments. At December 31, 2017 , the carrying amount of the Company’s investment in Roan of approximately $458 million was less than the Company’s ownership interest in Roan’s underlying net assets by approximately $346 million . The difference is attributable to proved and unproved oil and natural gas properties and is amortized over the lives of the related assets. Such amortization is included in the equity earnings (losses) from the Company’s investment in Roan. Impairment testing on the Company’s investment in Roan is performed when events or circumstances warrant such testing and considers whether there is an inability to recover the carrying value of the investment that is other than temporary. No impairments occurred with respect to the Company’s investment in Roan for the four months ended December 31, 2017 . Following are summarized statement of operations and balance sheet information for Roan. Summarized Roan Resources LLC Statement of Operations Information Four Months Ended December 31, 2017 (in thousands) Revenues and other $ 75,461 Expenses 61,790 Other income and (expenses) (1,180 ) Net income $ 12,491 Summarized Roan Resources LLC Balance Sheet Information December 31, 2017 (in thousands) Current assets $ 27,465 Noncurrent assets 1,826,741 1,854,206 Current liabilities 149,409 Noncurrent liabilities 97,480 Members’ equity $ 1,607,317

Debt

Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt	Debt The following summarizes the Company’s outstanding debt: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands, except percentages) Revolving credit facility $ — $ — Predecessor credit facility (1) — 1,654,745 Predecessor term loan (1) — 284,241 6.50% senior notes due May 2019 — 562,234 6.25% senior notes due November 2019 — 581,402 8.625% senior notes due April 2020 — 718,596 12.00% senior secured second lien notes due December 2020 — 1,000,000 7.75% senior notes due February 2021 — 779,474 6.50% senior notes due September 2021 — 381,423 Net unamortized deferred financing fees — (1,257 ) Total debt, net — 5,960,858 Less current portion, net (2) — (1,937,729 ) Less liabilities subject to compromise (3) — (4,023,129 ) Long-term debt $ — $ — (1) Variable interest rate of 5.50% at December 31, 2016 . (2) Due to covenant violations, the Predecessor’s credit facility and term loan were classified as current at December 31, 2016 . (3) The Predecessor’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016 . On the Effective Date, pursuant to the terms of the Plan, all outstanding amounts under these debt instruments were canceled. Fair Value The Company’s debt is recorded at the carrying amount on the consolidated balance sheets. The carrying amounts of the credit facilities and term loans approximate fair value because the interest rates are variable and reflective of market rates. The Company used a market approach to determine the fair value of the Predecessor’s Second Lien Notes and senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement. Predecessor December 31, 2016 Carrying Value Fair Value (in thousands) Senior secured second lien notes $ 1,000,000 $ 863,750 Senior notes, net 3,023,129 1,179,224 Revolving Credit Facility On August 4, 2017, the Company entered into a credit agreement with Holdco II, as borrower, Royal Bank of Canada, as administrative agent, and the lenders and agents party thereto, providing for a new senior secured reserve-based revolving loan facility (the “Revolving Credit Facility”) with $500 million in borrowing commitments and an initial borrowing base of $500 million . The maximum commitment amount was $425 million at December 31, 2017 . As of December 31, 2017 , there were no borrowings outstanding under the Revolving Credit Facility and there was approximately $381 million of available borrowing capacity (which includes a $44 million reduction for outstanding letters of credit). The maturity date is August 4, 2020. Redetermination of the borrowing base under the Revolving Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October, with the first scheduled borrowing base redetermination to occur on March 15, 2018. At the Company’s election, interest on borrowings under the Revolving Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin ranging from 2.50% to 3.50% per annum or the alternate base rate (“ABR”) plus an applicable margin ranging from 1.50% to 2.50% per annum, depending on utilization of the borrowing base. Interest is generally payable in arrears quarterly for loans bearing interest based at the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR, or if such interest period is longer than three months, at the end of the three month intervals during such interest period. The Company is required to pay a commitment fee to the lenders under the Revolving Credit Facility, which accrues at a rate per annum of 0.50% on the average daily unused amount of the available revolving loan commitments of the lenders. The obligations under the Revolving Credit Facility are secured by mortgages covering approximately 85% of the total value of the proved reserves of the oil and natural gas properties of the Company and certain of its subsidiaries, along with liens on substantially all personal property of the Company and certain of its subsidiaries, and are guaranteed by the Company, Holdco and certain of Holdco II’s subsidiaries, subject to customary exceptions. Under the Revolving Credit Facility, the Company is required to maintain (i) a maximum total net debt to last twelve months EBITDA ratio of 4.0 to 1.0 , and (ii) a minimum adjusted current ratio of 1.0 to 1.0 . The Revolving Credit Facility also contains affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, mergers, consolidations and sales of assets, paying dividends or other distributions in respect of, or repurchasing or redeeming, the Company’s capital stock, making certain investments and transactions with affiliates. The Revolving Credit Facility contains events of default and remedies customary for credit facilities of this nature. Failure to comply with the financial and other covenants in the Revolving Credit Facility would allow the lenders, subject to customary cure rights, to require immediate payment of all amounts outstanding under the Revolving Credit Facility. In September 2017, the Company entered into an amendment to the Revolving Credit Facility to provide for, among other things, an increase in the size of the letter of credit subfacility from $25 million to $50 million . Successor Credit Facility On the Effective Date, pursuant to the terms of the Plan, the Company entered into the Successor Credit Facility with Holdco II as borrower and Wells Fargo Bank, National Association, as administrative agent, providing for: 1) a reserve-based revolving loan with an initial borrowing base of $1.4 billion and 2) a term loan in an original principal amount of $300 million . On May 31, 2017, the Company entered into the First Amendment and Consent to Credit Agreement, pursuant to which among other modifications: 1) the term loan was paid in full and terminated using cash proceeds from the Jonah Assets Sale, and 2) the borrowing base for the revolving loan was reduced to $1 billion with additional agreed upon reductions for the Company’s other announced sales. In connection with the entry into the Revolving Credit Facility, the Successor Credit Facility was terminated and repaid in full. Predecessor’s Credit Facility, Second Lien Notes and Senior Notes On the Effective Date, pursuant to the terms of the Plan, all outstanding obligations under the Predecessor’s credit facility, Second Lien Notes and senior notes were canceled. See Note 2 for additional information. Predecessor Covenant Violations The Company’s filing of the Bankruptcy Petitions described in Note 2 constituted an event of default that accelerated the obligations under the Predecessor’s credit facility, Second Lien Notes and senior notes. For the two months ended February 28, 2017, contractual interest, which was not recorded, on the Second Lien Notes and senior notes was approximately $57 million . Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of an event of default. Predecessor’s Senior Secured Second Lien Notes Due December 2020 On November 20, 2015, the Company issued $1.0 billion in aggregate principal amount of 12.00% senior secured second lien notes due December 2020 (“Second Lien Notes”) in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes as follows: Par Value of Senior Notes Exchanged (in thousands) 6.50% senior notes due May 2019 $ 584,422 6.25% senior notes due November 2019 824,348 8.625% senior notes due April 2020 286,344 7.75% senior notes due February 2021 184,300 6.50% senior notes due September 2021 120,586 $ 2,000,000 The exchanges were accounted for as a troubled debt restructuring (“TDR”). Since the total future cash payments of the new debt were less than the carrying amount of the previous debt, a gain of approximately $352 million , or $1.03 per unit, was recognized for the year ended December 31, 2015, and included in “gain on extinguishment of debt” on the consolidated statement of operations. TDR accounting requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. Predecessor Repurchases of Senior Notes During the year ended December 31, 2015 , the Predecessor repurchased, through privately negotiated transactions and on the open market, approximately $927 million of its outstanding senior notes as follows: • 6.50% senior notes due May 2019 – $53 million ; • 6.25% senior notes due November 2019 – $395 million ; • 8.625% senior notes due April 2020 – $295 million ; • 7.75% senior notes due February 2021 – $36 million ; and • 6.50% senior notes due September 2021 – $148 million . In connection with the repurchases, the Predecessor paid approximately $553 million in cash and recorded a gain on extinguishment of debt of approximately $356 million for the year ended December 31, 2015 .

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives Commodity Derivatives Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials. The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives. The following table presents derivative positions for the periods indicated as of December 31, 2017 : 2018 2019 Natural gas positions: Fixed price swaps (NYMEX Henry Hub): Hedged volume (MMMBtu) 69,715 11,315 Average price ($/MMBtu) $ 3.02 $ 2.97 Oil positions: Fixed price swaps (NYMEX WTI): Hedged volume (MBbls) 548 — Average price ($/Bbl) $ 54.07 $ — Collars (NYMEX WTI): Hedged volume (MBbls) 1,825 1,825 Average floor price ($/Bbl) $ 50.00 $ 50.00 Average ceiling price ($/Bbl) $ 55.50 $ 55.50 During the ten months ended December 31, 2017 , the Company entered into commodity derivative contracts consisting of oil swaps for January 2018 through December 2018 and natural gas swaps for January 2018 through December 2019. The Company did not enter into any commodity derivative contracts during the two months ended February 28, 2017. In accordance with a Bankruptcy Court order dated August 16, 2016, the Company was authorized to enter into postpetition hedging arrangements. During the year ended December 31, 2016 , LINN Energy entered into commodity derivative contracts consisting of natural gas swaps for October 2016 through December 2019, oil swaps for November 2016 through December 2017, and oil collars for January 2018 through December 2019. In April 2016 and May 2016, in connection with the Company’s restructuring efforts, LINN Energy canceled (prior to the contract settlement dates) all of its then-outstanding derivative contracts for net proceeds of approximately $1.2 billion . The net proceeds were used to make permanent repayments of a portion of the borrowings outstanding under the LINN Credit Facility. The natural gas derivatives are settled based on the closing price of NYMEX Henry Hub natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX WTI crude oil for each day of the delivery month. Balance Sheet Presentation The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. The following table summarizes the fair value of derivatives outstanding on a gross basis: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) Assets: Commodity derivatives $ 22,589 $ 19,369 Liabilities: Commodity derivatives $ 25,443 $ 113,226 By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the Revolving Credit Facility. The Revolving Credit Facility is secured by certain of the Company’s and its subsidiaries’ oil, natural gas and NGL reserves and personal property; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $23 million at December 31, 2017 . The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated. Gains and Losses on Derivatives Gains and losses on derivatives were net gains of approximately $14 million and $93 million for the ten months ended December 31, 2017 , and the two months ended February 28, 2017, respectively. Gains and losses on derivatives were net losses of approximately $164 million for the year ended December 31, 2016 , and net gains of approximately $1.0 billion for the year ended December 31, 2015 . Gains and losses on derivatives are reported on the consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.” The Company received net cash settlements of approximately $27 million for the ten months ended December 31, 2017 , and paid net cash settlements of approximately $12 million for the two months ended February 28, 2017. The Company received net cash settlements of approximately $861 million and $1.1 billion for the years ended December 31, 2016 , and December 31, 2015 , respectively. In addition, during the year ended December 31, 2016 , approximately $841 million in settlements (primarily in connection with the April 2016 and May 2016 commodity derivative cancellations) were paid directly by the counterparties to the lenders under the Predecessor Credit Facility as repayments of a portion of the borrowings outstanding.

Fair Value Measurements on a Re

Fair Value Measurements on a Recurring Basis	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements on a Recurring Basis	Fair Value Measurements on a Recurring Basis The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads, are applied to the Company’s commodity derivatives. Fair Value Hierarchy In accordance with applicable accounting standards, the Company has categorized its financial instruments into a three-level fair value hierarchy based on the priority of inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Financial assets and liabilities recorded in the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows: Level 1 Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Level 2 Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives). Level 3 Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis: Successor December 31, 2017 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 22,589 $ (12,491 ) $ 10,098 Liabilities: Commodity derivatives $ 25,443 $ (12,491 ) $ 12,952 Predecessor December 31, 2016 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 19,369 $ (19,369 ) $ — Liabilities: Commodity derivatives $ 113,226 $ (19,369 ) $ 93,857 (1) Represents counterparty netting under agreements governing such derivatives.

Other Property and Equipment

Other Property and Equipment	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Other Property and Equipment	Other Property and Equipment Other property and equipment consists of the following: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) Natural gas plant and pipeline $ 392,999 $ 421,806 Furniture and office equipment 39,551 105,353 Buildings and leasehold improvements 27,301 66,014 Vehicles 10,811 31,496 Land 6,776 3,736 Drilling and other equipment 3,291 8,082 480,729 636,487 Less accumulated depreciation (28,658 ) (224,547 ) Less other property and equipment, net – discontinued operations — (11,402 ) $ 452,071 $ 400,538

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other noncurrent liabilities” on the consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. 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 following table presents a reconciliation of the Company’s asset retirement obligations: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 (in thousands) Asset retirement obligations at beginning of period $ 357,397 $ 402,162 $ 523,541 Liabilities added from drilling 551 146 546 Liabilities added from acquisitions — — 1,416 Liabilities associated with assets divested (158,228 ) — — Liabilities associated with assets held for sale (42,001 ) — — Deconsolidation of Berry Petroleum Company, LLC asset retirement obligations — — (141,612 ) Current year accretion expense 14,995 4,024 30,498 Settlements (8,189 ) (618 ) (12,823 ) Revision of estimates 28 — 596 Fresh start adjustment (1) — (48,317 ) — 164,553 357,397 402,162 Less asset retirement obligations – discontinued operations — (26,978 ) (38,042 ) Asset retirement obligations at end of period $ 164,553 $ 330,419 $ 364,120 (1) As a result of the application of fresh start accounting, the Successor recorded its asset retirement obligations at fair value as of the Effective Date.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies On May 11, 2016, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. On January 27, 2017, the Bankruptcy Court entered the Confirmation Order. Consummation of the Plan was subject to certain conditions set forth in the Plan. On the Effective Date, all of the conditions were satisfied or waived and the Plan became effective and was implemented in accordance with its terms. The LINN Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims. The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates. However, the Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings. In March 2017, Wells Fargo Bank, National Association (“Wells Fargo”), the administrative agent under the Predecessor Credit Facility, filed a motion in the Bankruptcy Court seeking payment of post-petition default interest of approximately $31 million . The Company has vigorously disputed that Wells Fargo is entitled to any default interest based on the plain language of the Plan and Confirmation Order. A hearing was held on April 27, 2017, and on November 13, 2017, the Bankruptcy Court ruled that the secured lenders are not entitled to payment of post-petition default interest. The ruling has been appealed by Wells Fargo and that appeal is pending. The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved. Except for in connection with its Chapter 11 proceedings, the Company made no significant payments to settle any legal, environmental or tax proceedings during the years ended December 31, 2017 , December 31, 2016 , and December 31, 2015 . See Note 3 for additional information about payments made upon the Company’s emergence from Chapter 11 bankruptcy. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Operating Leases

Operating Leases	12 Months Ended
	Dec. 31, 2016
Leases, Operating [Abstract]
Operating Leases	Operating Leases The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2021 . The Company recognized expense under operating leases of approximately $6 million , $1 million , $9 million and $15 million for the ten months ended December 31, 2017 , the two months ended February 28, 2017, and the years ended December 31, 2016 , and December 31, 2015 , respectively. As of December 31, 2017 , future minimum lease payments were as follows (in thousands): 2018 $ 2,812 2019 2,005 2020 463 2021 12 2022 — Thereafter — $ 5,292

Equity (Deficit)

Equity (Deficit)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Equity (Deficit)	Equity (Deficit) Successor Equity Shares Issued and Outstanding As of December 31, 2017 , there were 83,582,176 shares of Class A common stock issued and outstanding. An additional 609,905 vested but not issued restricted stock units and 2,960,304 unvested restricted stock units were outstanding under the Company’s Omnibus Incentive Plan. As of December 31, 2017 , the Company’s consolidated subsidiary, Holdco, had 768,787 vested Class A-2 units and 2,306,361 unvested Class A-2 units, which may be converted into shares of Class A common stock pursuant to the terms of the Limited Liability Company Operating Agreement of Holdco (the “Holdco LLC Agreement”). See Note 15 for additional information related to the restricted stock units and Class A-2 units. As of January 31, 2018, there were 77,229,257 shares of Class A common stock issued and outstanding, an additional 2,953,294 unvested restricted stock units (of which 1,165,134 are scheduled to vest on or before March 1, 2018) were outstanding under the Company’s Omnibus Incentive Plan and 2,820,804 Class A‑2 units of Holdco (of which 1,410,402 are vested or will be vested by March 1, 2018) were outstanding. Cancellation of Units and Issuance of Class A Common Stock In accordance with the Plan, on the Effective Date: • All units in the Predecessor that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery; • 17,678,889 shares of Class A common stock were issued pro rata to holders of the Second Lien Notes with claims allowed under the Plan; • 26,724,396 shares of Class A common stock were issued pro rata to holders of Unsecured Notes with claims allowed under the Plan; • 471,110 shares of Class A common stock were issued to commitment parties under the Backstop Commitment Agreement in respect of the premium due thereunder; • 2,995,691 shares of Class A common stock were issued to commitment parties under the Backstop Commitment Agreement in connection with their backstop obligation thereunder; and • 41,359,806 shares of Class A common stock were issued to participants in the rights offerings extended by the Company to certain holders of claims arising under the Second Lien Notes and the Unsecured Notes (including, in each case, certain of the commitment parties party to the Backstop Commitment Agreement). With the exception of shares of Class A common stock issued to commitment parties pursuant to their obligations under the Backstop Commitment Agreement, shares of Class A common stock were issued under the Plan pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), under Section 1145 of the Bankruptcy Code. Shares of Class A common stock issued to commitment parties pursuant to their obligations under the Backstop Commitment Agreement were issued pursuant to an exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) thereof. As of the Effective Date, there were 89,229,892 shares of Class A common stock, par value $0.001 per share, issued and outstanding. Share Repurchase Program On June 1, 2017, the Company’s Board of Directors announced that it had authorized the repurchase of up to $75 million of the Company’s outstanding shares of Class A common stock. On June 28, 2017, the Company’s Board of Directors announced that it had authorized an increase in the previously announced share repurchase program to up to a total of $200 million of the Company’s outstanding shares of Class A common stock. On October 4, 2017, the Company’s Board of Directors announced that it had authorized an additional increase in the previously announced share repurchase program to up to a total of $400 million of the Company’s outstanding shares of Class A common stock. Any share repurchases are subject to restrictions in the Revolving Credit Facility. During the period from June 2017 through December 2017, the Company repurchased an aggregate of 5,690,192 shares of Class A common stock at an average price of $34.85 per share for a total cost of approximately $198 million . Tender Offer – Subsequent Event On December 14, 2017, the Company’s Board of Directors announced the intention to commence a tender offer to purchase at least $250 million of the Company’s Class A common stock. In January 2018, upon the terms and subject to the conditions described in the Offer to Purchase dated December 20, 2017, as amended, the Company repurchased an aggregate of 6,770,833 shares of Class A common stock at a fixed price of $48.00 per share for a total cost of approximately $325 million (excluding expenses of the tender offer). Dividends The Successor is not currently paying a cash dividend; however, the Board of Directors periodically reviews the Company’s liquidity position to evaluate whether or not to pay a cash dividend. Any future payment of cash dividends would be subject to the restrictions in the Revolving Credit Facility. Predecessor Equity Cancellation of Awards In December 2016, the Predecessor canceled all of its then-outstanding nonvested restricted units without consideration given to the employees, decreasing the Predecessor’s units issued and outstanding by 2,230,182 . At-the-Market Offering Program The Predecessor’s Board of Directors had authorized the sale of up to $500 million of units under an at-the-market offering program, with sales of units, if any, to be made under an equity distribution agreement. No sales were made under the equity distribution agreement during the year ended December 31, 2016 . During the year ended December 31, 2015 , the Company, under its equity distribution agreement, sold 3,621,983 units representing limited liability company interests at an average price of $12.37 per unit for net proceeds of approximately $44 million (net of approximately $448,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional services expenses of approximately $459,000 . The Company used the net proceeds for general corporate purposes, including the open market repurchases of a portion of its senior notes (see Note 6). Public Offering of Units In May 2015, the Predecessor sold 16,000,000 units representing limited liability company interests in an underwritten public offering at $11.79 per unit ( $11.32 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering costs of approximately $8 million ). The Predecessor used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under the Predecessor Credit Facility. Forfeiture of Units in Exchange for Cash In August 2015, in accordance with terms of the separation agreement between the Company and Kolja Rockov, former Chief Financial Officer, dated August 31, 2015, Mr. Rockov agreed to forfeit 191,446 units issued to him under the Company’s equity compensation plan in exchange for a cash payment of approximately $672,000 . Distributions Under the Predecessor’s limited liability company agreement, unitholders were entitled to receive a distribution of available cash, which included cash on hand plus borrowings less any reserves established by the Predecessor’s Board of Directors to provide for the proper conduct of the Predecessor’s business (including reserves for future capital expenditures, acquisitions and anticipated future credit needs) or to fund distributions, if any, over the next four quarters. Monthly distributions were paid by the Company through September 2015. Distributions paid by the Company during 2015 are presented on the consolidated statements of unitholders’ capital (deficit) and the consolidated statements of cash flows. In October 2015, the Predecessor’s Board of Directors determined to suspend payment of the Predecessor’s distribution.

Noncontrolling Interests

Noncontrolling Interests	12 Months Ended
	Dec. 31, 2017
Noncontrolling Interest [Abstract]
Noncontrolling Interests	Noncontrolling Interests Noncontrolling interests represent ownership in the net assets of the Company’s consolidated subsidiary, Holdco, not attributable to LINN Energy. On the Effective Date, Holdco granted incentive interest awards to certain members of its management in the form of Class B units (see Note 15). In accordance with the terms of the Holdco LLC Agreement, on July 31, 2017, all of the Class B units were converted to Class A-2 units of Holdco. At both December 31, 2017 , and July 31, 2017 (the date of the conversion), the noncontrolling Class A-2 units represented approximately 0.88% of Holdco’s total outstanding units.

Share-Based Compensation and Ot

Share-Based Compensation and Other Benefits	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation and Other Benefits	Share-Based Compensation and Other Benefits The Company had no equity awards outstanding as of December 31, 2016 . In accordance with the Plan, in February 2017, the Company implemented the Linn Energy, Inc. 2017 Omnibus Incentive Plan (the “Omnibus Incentive Plan”) pursuant to which employees and consultants of the Company and its affiliates are eligible to receive stock options, restricted stock, performance awards, other stock-based awards and other cash-based awards. The Committee (as defined in the Omnibus Incentive Plan) has broad authority under the Omnibus Incentive Plan to, among other things: (i) select participants; (ii) determine the types of awards that participants receive and the number of shares that are subject to such awards; and (iii) establish the terms and conditions of awards, including the price (if any) to be paid for the shares or the award. As of the Effective Date, an aggregate of 6,444,381 shares of Class A common stock were reserved for issuance under the Omnibus Incentive Plan (the “Share Reserve”). Additional shares of Class A common stock may be issued in excess of the Share Reserve for the sole purpose of satisfying any conversion of Class A‑2 units of Holdco into shares of Class A common stock pursuant to the Holdco LLC Agreement, and the conversion procedures set forth therein. If any stock option or other stock-based award granted under the Omnibus Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of Class A common stock underlying any unexercised award shall again be available for the purpose of awards under the Omnibus Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Class A common stock awarded under the Omnibus Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for the purpose of awards under the Omnibus Incentive Plan. Any award under the Omnibus Incentive Plan settled in cash shall not be counted against the maximum share limitation. As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the Omnibus Incentive Plan and any outstanding awards, as well as the exercise or purchase prices of awards, and performance targets under certain types of performance-based awards, are subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Company’s stockholders. Securities Authorized for Issuance Under the Omnibus Incentive Plan As of December 31, 2017 , approximately 6.6 million shares were issuable under the Omnibus Incentive Plan pursuant to outstanding award or other agreements, including approximately 3.5 million shares related to restricted stock units and approximately 3.1 million shares related to Class A‑2 units of Holdco. As of December 31, 2017 , approximately 2.8 million additional shares were reserved for future issuance under the Plan. The Compensation Committee of the Board of Directors of the Company (the “Compensation Committee”) generally has discretion regarding the timing, size and terms of future awards; however, the Omnibus Incentive Plan requires that 1) the portion of the Share Reserve that does not constitute the Emergence Awards, plus any subsequent awards forfeited before vesting (the “Remaining Share Reserve”), will be fully granted within the 36-month period immediately following the Effective Date (with such 36-month anniversary, the “Final Allocation Date”) and 2) if a Change in Control (as defined in the Omnibus Incentive Plan) occurs before the Final Allocation Date, the entire Remaining Share Reserve will be allocated on a fully-vested basis to actively employed employees (pro-rata based upon each such employee’s relative awards) upon the consummation of the Change in Control. In January and February 2018, certain participants in the Omnibus Incentive Plan agreed to waive any rights they may have to future awards under this provision in consideration for the ability to participate in the Liquidity Program described below. Accounting for Share-Based Compensation The Company recognizes expense for share-based compensation over the requisite service period in an amount equal to the fair value of share-based awards granted. The fair value of share-based awards, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company had no outstanding liability awards as of December 31, 2017 . The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. Beginning in 2017, the Company accounts for forfeitures as they occur. The Company’s restricted stock units are equity-classified on the consolidated balance sheet. The Company’s incentive interest awards in the form of Class B units were liability-classified on the consolidated balance sheet through July 31, 2017 (the date of the conversion to Class A-2 units) and are subsequently equity-classified. The fair value of the Company’s restricted stock units was determined based on the fair value of the Company’s shares on the date of grant and the fair value of the incentive interest awards in the form of Class B units (Class A-2 units upon conversion) was initially determined based on the estimated amount to settle the awards and the fair value of the awards at the date of the conversion became the measurement basis from that point forward. A summary of share-based compensation expenses included on the consolidated statements of operations is presented below: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) General and administrative expenses $ 41,285 $ 50,255 $ 34,268 $ 47,312 Lease operating expenses — — 9,950 8,824 Total share-based compensation expenses $ 41,285 $ 50,255 $ 44,218 $ 56,136 Income tax benefit $ 9,861 $ 5,170 $ 16,339 $ 20,742 Restricted Stock Units On the Effective Date, the Company granted to certain employees 2,478,606 restricted stock units (the “Emergence Awards”). During the ten months ended December 31, 2017 , the Company granted to certain employees 1,340,350 restricted stock units from the Remaining Share Reserve. The restricted stock units vest over three years. Upon a participant’s termination of employment and/or service (as applicable), the Company has the right (but not the obligation) to repurchase all or any portion of the shares of Class A common stock acquired pursuant to an award at a price equal to the fair market value (as determined under the Omnibus Incentive Plan) of the shares of Class A common stock to be repurchased, measured as of the date of the Company’s repurchase notice. In addition, in January 2018, the Compensation Committee approved a one-time liquidity program under which the Company has agreed to 1) settle all or a portion of an eligible participant’s restricted stock units vesting on or before March 1, 2018 in cash and/or 2) repurchase all or a portion of any shares of Class A common stock held by an eligible participant as a result of a prior vesting of restricted stock units, in each case at an agreed upon price (the “Liquidity Program”). Only those participants that executed the waiver of certain rights under the Omnibus Incentive Plan described above are eligible to participate in the Liquidity Program. The following summarizes the Company’s restricted stock units activity: Number of Nonvested Units Weighted Average Grant-Date Fair Value Per Unit Nonvested units at February 28, 2017 (Predecessor) — $ — Granted 2,478,606 $ 22.19 Vested (619,665 ) $ 22.19 Nonvested units at February 28, 2017 (Successor) 1,858,941 $ 22.19 Granted 1,340,350 $ 29.29 Vested (51,839 ) $ 27.86 Forfeited (187,148 ) $ 28.38 Nonvested units at December 31, 2017 (Successor) 2,960,304 $ 24.92 The total fair value of restricted stock units that vested was approximately $2 million and $14 million for the ten months ended December 31, 2017 , and on February 28, 2017, respectively. As of December 31, 2017 , there was approximately $49 million of unrecognized compensation cost related to nonvested restricted stock units. The cost is expected to be recognized over a weighted average period of approximately 2.16 years. Holdco Incentive Interest Plan On the Effective Date, Holdco granted incentive interest awards to certain members of its management in the form of 3,470,051 Class B units, which are intended to qualify as “profits interests” for U.S. income tax purposes. The Class B units vested 25% on the Effective Date and the remaining amount vest ratably over the following three years. In accordance with the terms of the Holdco LLC Agreement, on July 31, 2017, all of the Class B units were converted to Class A-2 units of Holdco. The Class A-2 units will continue to vest over three years. The total fair value of Class B units that vested was approximately $28 million on February 28, 2017. As of December 31, 2017 , there was approximately $61 million of unrecognized compensation cost related to nonvested Class A-2 units of Holdco. The cost is expected to be recognized over a weighted average period of approximately 2.16 years. Predecessor’s Incentive Plan Summary The Predecessor’s Amended and Restated Long-Term Incentive Plan, as amended (the “LTIP”), was effective from December 2005 through February 28, 2017. The LTIP permitted grants of unrestricted units, restricted units, stock options and performance awards to employees, consultants and nonemployee directors. In December 2016, the Company canceled all of its then-outstanding nonvested restricted units, phantom units and performance unit awards, as well as its then-outstanding unit options, without consideration given to the employees. As a result, the Company recognized unit-based compensation expenses of approximately $14 million for the year ended December 31, 2016 , associated with previously unrecognized compensation costs for awards that were canceled before the completion of the requisite service period. Defined Contribution Plan The Company sponsors a 401(k) defined contribution plan for eligible employees. For 2017, Company contributions to the 401(k) plan consisted of a discretionary matching contribution equal to 100% of the first 4% of eligible compensation contributed by the employee on a before-tax basis. For the years 2016 and 2015, Company contributions to the 401(k) plan consisted of a discretionary matching contribution equal to 100% of the first 6% of eligible compensation contributed by the employee on a before-tax basis. The Company contributed approximately $3 million , $812,000 , $9 million and $11 million during the ten months ended December 31, 2017 , the two months ended February 28, 2017, and the years ended December 31, 2016 , and December 31, 2015 , respectively, to the 401(k) plan’s trustee account. The 401(k) plan funds are held in a trustee account on behalf of the plan participants.

Earnings Per Share_Unit

Earnings Per Share/Unit	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings Per Share/Unit	Earnings Per Share/Unit Basic earnings per share/unit is computed by dividing net earnings attributable to common stockholders/unitholders by the weighted average number of shares/units outstanding during the period. Diluted earnings per share/unit is computed by adjusting the average number of shares/units outstanding for the dilutive effect, if any, of potential common shares/units. The following tables provide a reconciliation of the numerators and denominators of the basic and diluted per share/unit computations for net income (loss): Successor Ten Months Ended December 31, 2017 Income Shares Per Share (in thousands, except per share data) Basic: Income from continuing operations $ 349,865 87,646 $ 3.99 Income from discontinued operations, net of income taxes 82,995 87,646 0.95 Net income attributable to common stockholders $ 432,860 87,646 $ 4.94 Effect of Dilutive Securities: Dilutive effect of restricted stock units $ — 1,073 Dilutive effect of unvested Class A-2 units of Holdco $ (2,180 ) — Diluted: Income from continuing operations $ 347,685 88,719 $ 3.92 Income from discontinued operations 82,995 88,719 0.93 Net income attributable to common stockholders $ 430,680 88,719 $ 4.85 Predecessor Two Months Ended February 28, 2017 Income (Loss) Units Per Unit (in thousands, except per unit data) Basic and Diluted: Income from continuing operations $ 2,397,609 352,792 $ 6.80 Loss from discontinued operations, net of income taxes (548 ) 352,792 (0.01 ) Net income attributable to common unitholders $ 2,397,061 352,792 $ 6.79 Predecessor Year Ended December 31, 2016 Loss Units Per Unit (in thousands, except per unit data) Basic and Diluted: Loss from continuing operations $ (367,343 ) 352,653 $ (1.04 ) Loss from discontinued operations, net of income taxes (1,804,513 ) 352,653 (5.12 ) Net loss attributable to common unitholders $ (2,171,856 ) 352,653 $ (6.16 ) Predecessor Year Ended December 31, 2015 Loss Units Per Unit (in thousands, except per unit data) Basic and Diluted: Loss from continuing operations $ (3,754,220 ) Allocated to participating securities (3,039 ) (3,757,259 ) 343,323 $ (10.94 ) Loss from discontinued operations, net of income taxes (1,005,591 ) 343,323 (2.93 ) Net loss attributable to common unitholders $ (4,762,850 ) 343,323 $ (13.87 ) There were no anti-dilutive restrictive stock units for the ten months ended December 31, 2017 . The diluted earnings per unit calculation excludes approximately 1 million and 4 million unit options and warrants that were anti-dilutive for the years ended December 31, 2016 , and December 31, 2015 , respectively. There were no potential common units outstanding during the two months ended February 28, 2017.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Successor was formed as a C corporation. For federal and state income tax purposes (with the exception of the state of Texas), the Predecessor was a limited liability company treated as a partnership, in which income tax liabilities and/or benefits were passed through to the Predecessor’s unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor. The deferred tax effects of the Company’s change to a C corporation are included in income from continuing operations for the two months ended February 28, 2017. Amounts recognized as income taxes are included in “income tax expense (benefit),” as well as discontinued operations, on the consolidated statements of operations. On December 22, 2017, H.R. 1 (the “Tax Cuts and Jobs Act”) was signed into law. The Company conducted an assessment of the impact of the Tax Cuts and Jobs Act and concluded that a noncash charge of approximately $106 million for the ten months ended December 31, 2017 , against net deferred income taxes was necessary due to the decrease in the statutory federal income tax rate from 35% to 21% . This charge is included in “income tax expense (benefit)” on the consolidated statement of operations and resulted in a 14.3% increase in the Company’s effective tax rate for the ten months ended December 31, 2017 . Income tax expense (benefit) consisted of the following: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) Current taxes: Federal $ 7,140 $ — $ (494 ) $ (12,021 ) State 489 — 321 1,022 Deferred taxes: Federal 366,243 — 11,582 8,237 State 15,070 (166 ) (215 ) (3,631 ) $ 388,942 $ (166 ) $ 11,194 $ (6,393 ) As of December 31, 2017 , the Company had approximately $60 million of net operating loss carryforwards for federal income tax purposes which will begin expiring in 2038 . A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % 35.0 % Federal statutory rate change 14.3 — — — State, net of federal tax benefit 2.6 — 0.7 0.1 Loss excluded from nontaxable entities — (35.0 ) (24.7 ) (34.7 ) Other 0.5 — (14.1 ) (0.2 ) Effective rate 52.4 % — % (3.1 )% 0.2 % Significant components of the deferred tax assets and liabilities were as follows: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) Deferred tax assets: Net operating loss carryforwards $ 14,615 $ 1,730 Reorganization items — 14,932 Investment in Linn Energy Holdco LLC 176,662 — Valuation allowance — (19,558 ) Other 7,140 10,030 Total deferred tax assets 198,417 7,134 Deferred tax liabilities: Property and equipment principally due to differences in depreciation — (7,021 ) Other — (279 ) Total deferred tax liabilities — (7,300 ) Net deferred tax assets (liabilities) $ 198,417 $ (166 ) The net deferred tax assets are recorded in “deferred income taxes” and the net deferred tax liabilities are recorded in “other noncurrent liabilities” on the consolidated balance sheets at December 31, 2017 , and December 31, 2016 , respectively. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2017 , based upon the projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences. In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2017 , or December 31, 2016 . The tax years 2016 and 2017 remain open to examination for federal and state income tax purposes.

Supplemental Disclosures to the

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows	12 Months Ended
	Dec. 31, 2017
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows	Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows “Other current assets” reported on the consolidated balance sheets include the following: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) Prepaids $ 46,238 $ 70,116 Receivable from related party 23,163 — Inventories 7,667 15,097 Deferred financing fees — 16,809 Other 2,703 3,288 Other current assets $ 79,771 $ 105,310 “Other accrued liabilities” reported on the consolidated balance sheets include the following: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) Accrued compensation $ 29,089 $ 16,443 Asset retirement obligations (current portion) 3,926 9,361 Deposits 15,349 — Income taxes payable 7,496 — Other 2,757 175 Other accrued liabilities $ 58,617 $ 25,979 Supplemental disclosures to the consolidated statements of cash flows are presented below: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) Cash payments for interest, net of amounts capitalized $ 15,165 $ 17,651 $ 143,305 $ 476,077 Cash payments for income taxes $ 275 $ — $ 4,427 $ 643 Cash payments for reorganization items, net $ 11,889 $ 21,571 $ 37,748 $ — Noncash investing activities: Accrued capital expenditures $ 31,447 $ 22,191 $ 31,128 $ 71,105 For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At December 31, 2017 , “restricted cash” on the consolidated balance sheet consists of approximately $36 million that will be used to settle certain claims in accordance with the Plan (which is the remainder of approximately $80 million transferred to restricted cash in February 2017 to fund such items), approximately $15 million related to deposits and approximately $5 million for other items. At December 31, 2016 , “restricted cash” on the consolidated balance sheet represents amounts restricted related to utility services providers. In addition, restricted cash of approximately $8 million is included in “other noncurrent assets” on the consolidated balance sheet at December 31, 2016 , and represents cash deposited by the Company into a separate account designated for asset retirement obligations in accordance with contractual agreements. At December 31, 2016 , net outstanding checks of approximately $6 million were reclassified and included in “accounts payable and accrued expenses” on the consolidated balance sheet. The change in net outstanding checks is presented as cash flows from financing activities and included in “other” on the consolidated statements of cash flows. In November 2015, the Company issued $1.0 billion in aggregate principal amount of Second Lien Notes in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes (see Note 6). In addition, during the year ended December 31, 2016 , approximately $841 million in commodity derivative settlements (primarily in connection with the April 2016 and May 2016 commodity derivative cancellations) were paid directly by the counterparties to the lenders under the Predecessor Credit Facility as repayments of a portion of the borrowings outstanding, and are reflected as noncash transactions by the Company.

Significant Customers

Significant Customers	12 Months Ended
	Dec. 31, 2016
Risks and Uncertainties [Abstract]
Significant Customers	Significant Customers The Company has a concentration of customers who are engaged in oil and natural gas purchasing, transportation and/or refining within the U.S. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company’s customers consist primarily of major oil and natural gas purchasers and the Company generally does not require collateral since it has not experienced significant credit losses on such sales. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectibility (see Note 1). For the ten months ended December 31, 2017 , the two months ended February 28, 2017, and the years ended December 31, 2016 , and December 31, 2015 , no individual customer exceeded 10% of the Company’s sales. At December 31, 2017 , and December 31, 2016 , no individual customer exceeded 10% of the Company’s receivables.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Roan Resources LLC On August 31, 2017, the Company completed the transaction in which LINN Energy and Citizen each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan. In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan, subject to customary post-closing adjustments. See Note 4 for additional information. Also on such date, Roan entered into a Master Services Agreement (the “MSA”) with Linn Operating, LLC (“Linn Operating”), a subsidiary of LINN Energy, pursuant to which Linn Operating will provide certain operating, administrative and other services in respect of the assets contributed to Roan during a transitional period. Under the MSA, Roan will reimburse Linn Operating for certain costs and expenses incurred by Linn Operating in connection with providing the services, and Roan will pay to Linn Operating a service fee of $1.25 million per month, prorated for partial months. The termination of the MSA will be the earliest of: (a) mutual agreement of the parties; (b) upon 30 days’ prior written notice from Roan to Linn Operating; (c) upon five days’ prior written notice from Linn Operating to Roan of a material default by Roan under the MSA, provided Linn Operating must have provided prior written notice to Roan of such material default providing Roan 10 days to cure such material default and such material default has not been cured by the end of the 10 day time period; and (d) eight months from the date of the MSA. In addition, the Company’s subsidiary, Blue Mountain Midstream LLC, has an agreement in place with Roan for the processing of natural gas from certain of Roan’s properties. For the four months ended December 31, 2017 , the Company recognized service fees of approximately $5 million as a reduction to general and administrative expenses. The Company had approximately $23 million due from Roan, primarily associated with capital spending, included in “other current assets” and approximately $18 million due to Roan, primarily associated with joint interest billings and natural gas purchases, included in “accounts payable and accrued expenses” on the consolidated balance sheet at December 31, 2017 . Berry Petroleum Company, LLC Berry, a former subsidiary of the Predecessor, was deconsolidated effective December 31, 2016 (see Note 4). The employees of Linn Operating, Inc. (“LOI”), a subsidiary of the Predecessor, provided services and support to Berry in accordance with an agency agreement and power of attorney between Berry and LOI. Upon deconsolidation, transactions between the Predecessor and Berry were no longer eliminated in consolidation and were treated as related party transactions. These transactions include, but are not limited to, management fees paid to the Company by Berry. On the Effective Date, Berry emerged from bankruptcy as a stand-alone, unaffiliated entity. For the two months ended February 28, 2017, and years ended December 31, 2016 , and December 31, 2015 , Berry incurred management fees of approximately $6 million , $69 million and $78 million , respectively, for services provided by LOI. The Predecessor also had accounts payable due to Berry of approximately $3 million included in “accounts payable and accrued expenses” on the consolidated balance sheet at December 31, 2016 . In addition, $25 million due to Berry was included in “liabilities subject to compromise” on the Predecessor’s consolidated balance sheet at December 31, 2016 . The Company made no capital contributions to Berry during the year ended December 31, 2016 . During the year ended December 31, 2015 , the Company made capital contributions of approximately $471 million to Berry, including $250 million which was deposited on Berry’s behalf and posted as restricted cash with Berry’s lenders in connection with the reduction of its borrowing base in May 2015. The Company received no cash distributions from Berry during the year ended December 31, 2016 . During the year ended December 31, 2015 , the Company received cash distributions of approximately $89 million from Berry. In addition, in 2014, Berry advanced approximately $352 million to the Company. The Company was required to use the cash from the advance on capital expenditures in respect of Berry’s operations, to repay Berry’s indebtedness or as otherwise permitted under the terms of Berry’s indentures and credit facility. During the twelve months ended September 30, 2015, the Company spent approximately $223 million , including approximately $58 million in 2014, on capital expenditures in respect of Berry’s operations. On September 30, 2015, the Company repaid in full the remaining advance of approximately $129 million to Berry. LinnCo, LLC LinnCo, an affiliate of the Predecessor, was formed on April 30, 2012. All of LinnCo’s common shares were held by the public. As of December 31, 2016 , LinnCo had no significant assets or operations other than those related to its interest in the Predecessor and owned approximately 71% of the Predecessor’s then outstanding units. In accordance with the Plan, LinnCo will be dissolved following the resolution of all outstanding claims. The Predecessor had agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any financial, legal, accounting, tax advisory, financial advisory and engineering fees, and other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity. These expenses include costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees. In addition, the Predecessor had agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities. All expenses and costs paid by the Predecessor on LinnCo’s behalf were expensed by the Predecessor. For the two months ended February 28, 2017, LinnCo incurred total general and administrative expenses of approximately $287,000 , including approximately $240,000 related to services provided by the Predecessor. All of the expenses incurred during the two months ended February 28, 2017, had been paid by the Predecessor on LinnCo’s behalf as of February 28, 2017. For the year ended December 31, 2016 , LinnCo incurred total general and administrative expenses, reorganization expenses and offering costs of approximately $6.1 million , including approximately $2.4 million related to services provided by LINN Energy. Of the expenses and costs incurred during 2016, approximately $5.9 million had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2016 . For the year ended December 31, 2015 , LinnCo incurred total general and administrative expenses and certain offering costs of approximately $3.4 million , including approximately $2.0 million related to services provided by LINN Energy. All of the expenses and costs incurred during 2015 had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2015 . The Company did not pay any distributions to LinnCo during the year ended December 31, 2016 . During the year ended December 31, 2015 , the Company paid approximately $121 million in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy. Other One of the Predecessor’s former directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the years ended December 31, 2016 , and December 31, 2015 , the Company incurred expenditures of approximately $5 million and $8 million , respectively, related to services rendered by Superior and its subsidiaries.

Supplemental Oil and Natural Ga

Supplemental Oil and Natural Gas Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Natural Gas Data (Unaudited)	The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.” Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) LINN Energy: Property acquisition costs: Proved $ — $ — $ — $ — Unproved — — — — Exploration costs 103,689 15,153 40,074 19,929 Development costs 96,178 24,256 86,053 264,227 Asset retirement costs 376 312 112 3,331 Total costs incurred – continuing operations $ 200,243 $ 39,721 $ 126,239 $ 287,487 Total costs incurred – discontinued operations $ 1,313 $ 269 $ 11,453 $ 167,049 Four Months Ended December 31, 2017 (in thousands) Equity method investments (1) Property acquisition costs: Proved $ — Unproved 6,851 Exploration costs 3,626 Development costs 89,585 Total costs incurred $ 100,062 (1) Represents the Company’s 50% equity interest in Roan. Costs incurred of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017 . Oil and Natural Gas Capitalized Costs Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) LINN Energy: Proved properties $ 904,390 $ 12,234,099 Unproved properties 45,693 998,860 950,083 13,232,959 Less accumulated depletion and amortization (49,619 ) (9,999,560 ) 900,464 3,233,399 Less oil and natural gas capitalized costs, net – discontinued operations — (728,190 ) $ 900,464 $ 2,505,209 December 31, 2017 (in thousands) Equity Method Investments: (1) Proved properties $ 400,682 Unproved properties 538,703 939,385 Less accumulated depletion and amortization (28,441 ) $ 910,944 (1) Represents the Company’s 50% equity interest in Roan. Results of Oil and Natural Gas Producing Activities The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs): Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) LINN Energy: Revenues and other: Oil, natural gas and natural gas liquids sales $ 709,363 $ 188,885 $ 874,161 $ 1,065,795 Gains (losses) on oil and natural gas derivatives 13,533 92,691 (164,330 ) 1,027,014 722,896 281,576 709,831 2,092,809 Production costs: Lease operating expenses 208,446 49,665 296,891 352,077 Transportation expenses 113,128 25,972 161,574 167,023 Severance taxes, ad valorem taxes and California carbon allowances 47,411 14,851 66,616 97,732 368,985 90,488 525,081 616,832 Other costs: Exploration costs 3,137 93 4,080 9,473 Depletion and amortization 101,360 39,689 295,889 471,046 Impairment of long-lived assets — — 165,044 4,960,144 (Gains) losses on sale of assets and other, net (678,200 ) 18 417 (199,296 ) Income tax benefit (4,640 ) (166 ) (649 ) (2,721 ) (578,343 ) 39,634 464,781 5,238,646 Results of operations – continuing operations $ 932,254 $ 151,454 $ (280,031 ) $ (3,762,669 ) Results of operations – discontinued operations $ 142,175 $ 1,246 $ (1,076,407 ) $ (844,754 ) There is no federal tax provision included in the Predecessor’s results above because the Predecessor’s subsidiaries subject to federal income taxes did not own any of the Predecessor’s oil and natural gas interests. Limited liability companies are subject to Texas margin tax. See Note 17 for additional information about income taxes. Four Months Ended December 31, 2017 (in thousands) Equity Method Investments: (1) Revenues and other: Oil, natural gas and natural gas liquids sales $ 42,322 Losses on oil and natural gas derivatives (4,591 ) 37,731 Production costs: Lease operating expenses 4,102 Transportation expenses 4,576 Severance taxes and ad valorem taxes 1,026 9,704 Other costs: Exploration costs 3,626 Depletion and amortization 11,371 14,997 Results of operations $ 13,030 (1) Represents the Company’s 50% equity interest in Roan. Results of oil and natural gas producing activities of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017 . There is no tax provision included in Roan’s results above because Roan is not subject to federal income taxes. Proved Oil, Natural Gas and NGL Reserves The proved reserves of oil, natural gas and NGL of the Company have been prepared by the independent engineering firm, DeGolyer and MacNaughton. In accordance with Securities and Exchange Commission (“SEC”) regulations, reserves at December 31, 2017 , December 31, 2016 , and December 31, 2015 , were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below: Successor Year Ended December 31, 2017 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) LINN Energy: Proved developed and undeveloped reserves: Beginning of year 2,290 72.6 104.1 3,350 170 3,520 Revisions of previous estimates (102 ) (5.6 ) 9.7 (78 ) — (78 ) Sales of minerals in place (754 ) (37.0 ) (39.6 ) (1,213 ) (164 ) (1,377 ) Extensions and discoveries 90 3.7 4.9 142 — 142 Production (147 ) (6.6 ) (7.6 ) (233 ) (6 ) (239 ) End of year 1,377 27.1 71.5 1,968 — 1,968 Proved developed reserves: Beginning of year 2,118 66.7 94.4 3,084 170 3,254 End of year 1,323 27.0 70.5 1,908 — 1,908 Proved undeveloped reserves: Beginning of year 172 5.9 9.7 266 — 266 End of year 54 0.1 1.0 60 — 60 Four Months Ended December 31, 2017 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total (Bcfe) Equity Method Investments: (1) Proved developed and undeveloped reserves: Beginning of period 173 10.3 17.8 342 Revisions of previous estimates (14 ) (2.6 ) (1.9 ) (42 ) Extensions and discoveries 189 11.4 24.3 403 Production (5 ) (0.4 ) (0.4 ) (9 ) End of year 343 18.7 39.8 694 Proved developed reserves: Beginning of year 95 4.5 7.9 169 End of year 130 6.2 12.0 239 Proved undeveloped reserves: Beginning of year 78 5.8 9.9 173 End of year 213 12.5 27.8 455 (1) Represents the Company’s 50% equity interest in Roan. Predecessor Year Ended December 31, 2016 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) LINN Energy: Proved developed and undeveloped reserves: Beginning of year 2,212 74.3 97.0 3,240 1,248 4,488 Revisions of previous estimates — (3.8 ) 1.2 (16 ) (192 ) (208 ) Extensions and discoveries 265 10.1 15.2 417 11 428 Production (187 ) (8.0 ) (9.3 ) (291 ) (93 ) (384 ) Deconsolidation of Berry Petroleum, LLC proved reserves — — — — (804 ) (804 ) End of year 2,290 72.6 104.1 3,350 170 3,520 Proved developed reserves: Beginning of year 2,212 74.3 97.0 3,240 1,248 4,488 End of year 2,118 66.7 94.4 3,084 170 3,254 Proved undeveloped reserves: Beginning of year — — — — — — End of year 172 5.9 9.7 266 — 266 Predecessor Year Ended December 31, 2015 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) LINN Energy: Proved developed and undeveloped reserves: Beginning of year 3,552 147.8 146.3 5,318 1,986 7,304 Revisions of previous estimates (1,137 ) (62.4 ) (38.7 ) (1,743 ) (636 ) (2,379 ) Sales of minerals in place (13 ) (4.1 ) (2.0 ) (50 ) — (50 ) Extensions and discoveries 10 3.0 0.8 32 15 47 Production (200 ) (10.0 ) (9.4 ) (317 ) (117 ) (434 ) End of year 2,212 74.3 97.0 3,240 1,248 4,488 Proved developed reserves: Beginning of year 2,981 104.2 117.5 4,312 1,506 5,818 End of year 2,212 74.3 97.0 3,240 1,248 4,488 Proved undeveloped reserves: Beginning of year 571 43.6 28.8 1,006 480 1,486 End of year — — — — — — The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents using the ratio of one barrel to six Mcf. Reserves for the Company’s California properties and Berry are reported as discontinued operations for all periods presented. Proved reserves from continuing operations decreased by approximately 1,382 Bcfe to approximately 1,968 Bcfe for the year ended December 31, 2017 , from 3,350 Bcfe for the year ended December 31, 2016 . The year ended December 31, 2017 , includes approximately 78 Bcfe of negative revisions of previous estimates ( 264 Bcfe of negative revisions due to asset performance partially offset by 186 Bcfe of positive revisions due to higher commodity prices). During the year ended December 31, 2017 , several divestitures decreased reserves by approximately 1,213 Bcfe (see Note 4 for additional information of divestitures). In addition, extensions and discoveries, primarily from 90 productive wells drilled during the year, contributed approximately 142 Bcfe to the increase in proved reserves. Proved reserves from continuing operations increased by approximately 110 Bcfe to approximately 3,350 Bcfe for the year ended December 31, 2016 , from 3,240 Bcfe for the year ended December 31, 2015 . The year ended December 31, 2016 , includes approximately 16 Bcfe of negative revisions of previous estimates ( 97 Bcfe of negative revisions due to lower commodity prices partially offset by 81 Bcfe of positive revisions due to asset performance). In addition, extensions and discoveries, primarily from 211 productive wells drilled during the year, contributed approximately 417 Bcfe to the increase in proved reserves. Proved reserves from continuing operations decreased by approximately 2,078 Bcfe to approximately 3,240 Bcfe for the year ended December 31, 2015 , from 5,318 Bcfe for the year ended December 31, 2014. The year ended December 31, 2015 , includes approximately 1,743 Bcfe of negative revisions of previous estimates ( 1,332 Bcfe due to lower commodity prices, 197 Bcfe due to uncertainty regarding the Company’s future commitment to capital and 237 Bcfe due to the SEC five-year development limitation on PUDs, partially offset by 23 Bcfe of positive revisions due to asset performance). During the year ended December 31, 2015 , divestitures including the Howard County Assets Sale decreased proved reserves by approximately 50 Bcfe. In addition, extensions and discoveries, primarily from 388 productive wells drilled during the year, contributed approximately 32 Bcfe to the increase in proved reserves. As a result of the uncertainty regarding the Company’s future commitment to capital, the Company reclassified all of its PUDs to unproved at December 31, 2015 . Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying the year-end statutory tax rates (with consideration of any known future changes) to the pretax net cash flows, reduced by the applicable tax basis and giving effect to any tax deductions, tax credits and allowances relating to the proved oil and natural gas reserves. There are no future income tax expenses at December 31, 2016, or December 31, 2015, because the Predecessor was not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts were not material. See Note 17 for additional information about income taxes. December 31, 2017 2016 2015 (in thousands) LINN Energy: Future cash inflows $ 6,730,186 $ 9,856,698 $ 10,396,598 Future production costs (3,810,932 ) (5,755,460 ) (6,576,424 ) Future development costs (486,989 ) (917,262 ) (722,685 ) Future income tax expenses (303,803 ) — — Future net cash flows 2,128,462 3,183,976 3,097,489 10% annual discount for estimated timing of cash flows (1,083,331 ) (1,488,219 ) (1,404,304 ) Standardized measure of discounted future net cash flows – continuing operations $ 1,045,131 $ 1,695,757 $ 1,693,185 Standardized measure of discounted future net cash flows – discontinued operations $ — $ 232,941 $ 1,340,360 Representative NYMEX prices: (1) Natural gas (MMBtu) $ 2.98 $ 2.48 $ 2.59 Oil (Bbl) $ 51.34 $ 42.64 $ 50.16 (1) In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. December 31, 2017 (in thousands) Equity Method Investments: (1) Future cash inflows $ 2,635,233 Future production costs (832,362 ) Future development costs (372,884 ) Future net cash flows 1,429,987 10% annual discount for estimated timing of cash flows (832,152 ) Standardized measure of discounted future net cash flows $ 597,835 Representative NYMEX prices: (2) Natural gas (MMBtu) $ 2.98 Oil (Bbl) $ 51.34 (1) Represents the Company’s 50% equity interest in Roan. (2) In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. There are no future income tax expenses at December 31, 2017 , because Roan is not subject to federal income taxes. The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Year Ended December 31, 2017 2016 2015 (in thousands) LINN Energy: Sales and transfers of oil, natural gas and NGL produced during the period $ (438,775 ) $ (349,080 ) $ (448,963 ) Changes in estimated future development costs (5,276 ) 19,460 953,393 Net change in sales and transfer prices and production costs related to future production 400,411 (92,236 ) (5,313,449 ) Sales of minerals in place (685,050 ) — (97,785 ) Extensions, discoveries and improved recovery 187,223 221,765 46,487 Previously estimated development costs incurred during the period 9,704 — 84,329 Net change due to revisions in quantity estimates (65,935 ) 10,387 (939,030 ) Net change in income taxes (155,257 ) — — Accretion of discount 169,576 169,318 707,085 Changes in production rates and other (67,247 ) 22,958 (369,736 ) Change – continuing operations $ (650,626 ) $ 2,572 $ (5,377,669 ) Change – discontinued operations $ (232,941 ) $ (1,107,419 ) $ (4,101,077 ) Four Months Ended December 31, 2017 (in thousands) Equity Method Investments (1) Standardized measure – Beginning of period $ 304,900 Sales and transfers of oil, natural gas and NGL produced during the period (32,618 ) Changes in estimated future development costs (14,617 ) Net change in sales and transfer prices and production costs related to future production 33,912 Extensions, discoveries and improved recovery 270,737 Previously estimated development costs incurred during the period 89,457 Net change due to revisions in quantity estimates (47,222 ) Accretion of discount 10,163 Changes in production rates and other (16,877 ) Net increase 292,935 Standardized measure – End of year $ 597,835 (1) Represents the Company’s 50% equity interest in Roan. Changes in the standardized measure of discounted future net cash flows of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017 . The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

Supplemental Quarterly Data (Un

Supplemental Quarterly Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Supplemental Quarterly Data (Unaudited)	The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.” Quarterly Financial Data Predecessor Successor January 1, 2017 to February 28, 2017 March 1, 2017 to March 31, 2017 Second Quarter Third Quarter Fourth Quarter (in thousands, except per share and per unit amounts) 2017: Oil, natural gas and natural gas liquids sales $ 188,885 $ 80,325 $ 243,167 $ 206,318 $ 179,553 Gains (losses) on oil and natural gas derivatives 92,691 (11,959 ) 45,714 (14,497 ) (5,725 ) Total revenues and other 298,127 73,308 307,819 236,682 208,869 Total expenses (1) 214,327 78,349 220,548 202,143 191,491 (Gains) losses on sale of assets and other, net 829 484 (306,878 ) (26,977 ) (289,701 ) Reorganization items, net 2,331,189 (2,565 ) (3,377 ) (2,605 ) (304 ) Income (loss) from continuing operations 2,397,609 (7,324 ) 223,379 51,030 85,587 Income (loss) from discontinued operations, net of income taxes (548 ) 68 (3,322 ) 86,099 150 Net income (loss) 2,397,061 (7,256 ) 220,057 137,129 85,737 Net income attributable to noncontrolling interests — — — 66 2,741 Net income attributable to stockholders/unitholders 2,397,061 (7,256 ) 220,057 137,063 82,996 Income (loss) per share/unit – continuing operations: Basic $ 6.80 $ (0.08 ) $ 2.49 $ 0.58 $ 0.98 Diluted $ 6.80 $ (0.08 ) $ 2.47 $ 0.57 $ 0.94 Income (loss) per share/unit – discontinued operations: Basic $ (0.01 ) $ — $ (0.04 ) $ 0.98 $ — Diluted $ (0.01 ) $ — $ (0.04 ) $ 0.97 $ — Net income (loss) per share/unit: Basic $ 6.79 $ (0.08 ) $ 2.45 $ 1.56 $ 0.98 Diluted $ 6.79 $ (0.08 ) $ 2.43 $ 1.54 $ 0.94 (1) Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes. During the third quarter of 2017, the Company corrected its allocation of value between proved and unproved oil and natural gas properties initially recorded as part of fresh start accounting (see Note 3) resulting in a reclassification of approximately $459 million from proved properties to unproved properties as of February 28, 2017. As a result, during the third quarter of 2017, the Company also recorded pretax out-of-period corrections of approximately $8 million to reduce depletion expense and approximately $1 million to increase net gains on sale of assets (combined $5 million after tax), as well as approximately $8 million to increase income from discontinued operations, net of income taxes, related to errors in the first and second quarters of 2017. The Company concluded that the correction of the errors was not material to these or any previously issued financial statements. Predecessor First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per unit amounts) 2016: Oil, natural gas and natural gas liquids sales $ 184,441 $ 195,847 $ 237,986 $ 255,887 Gains (losses) on oil and natural gas derivatives 109,453 (183,794 ) 166 (90,155 ) Total revenues and other 331,261 44,245 266,975 197,163 Total expenses (1) 449,809 274,941 310,772 269,906 Losses on sale of assets and other, net 1,468 2,607 2,532 9,650 Reorganization items, net — 485,798 (28,361 ) (145,838 ) Income (loss) from continuing operations (213,868 ) 204,691 (96,301 ) (261,865 ) Income (loss) from discontinued operations, net of income taxes (1,133,878 ) 3,801 (102,064 ) (572,372 ) Net income (loss) (1,347,746 ) 208,492 (198,365 ) (834,237 ) Income (loss) per unit – continuing operations: Basic $ (0.61 ) $ 0.58 $ (0.27 ) $ (0.74 ) Diluted $ (0.61 ) $ 0.58 $ (0.27 ) $ (0.74 ) Income (loss) per unit – discontinued operations: Basic $ (3.22 ) $ 0.01 $ (0.29 ) $ (1.62 ) Diluted $ (3.22 ) $ 0.01 $ (0.29 ) $ (1.62 ) Net income (loss) per unit: Basic $ (3.83 ) $ 0.59 $ (0.56 ) $ (2.36 ) Diluted $ (3.83 ) $ 0.59 $ (0.56 ) $ (2.36 ) (1) Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.

Basis of Presentation and Sig30

Basis of Presentation and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Business	Nature of Business LINN Energy is an independent oil and natural gas company that was formed in February 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases were administered jointly under the caption In re Linn Energy, LLC, et al., Case No. 16‑60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017. The Company’s properties are currently located in six operating regions in the United States (“U.S.”): Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; TexLa, which includes properties located in east Texas and north Louisiana; Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; Mid-Continent, which includes Oklahoma properties located in the Arkoma basin and the Northwest STACK, as well as waterfloods in the Central Oklahoma Platform; Permian Basin, which includes properties located in west Texas and southeast New Mexico; and Rockies, which includes Utah properties located in Uinta Basin.
Principles of Consolidation and Reporting	Principles of Consolidation and Reporting The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Noncontrolling interests represent ownership in the net assets of the Company’s consolidated subsidiary, Linn Energy Holdco LLC (“Holdco”), not attributable to LINN Energy, and are presented as a component of equity. Changes in the Company’s ownership interests in Holdco that do not result in deconsolidation are recognized in equity. See Note 14 for additional information about noncontrolling interests. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. See Note 5 for additional information about equity method investments. The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. The Company has also classified the assets and liabilities of its California properties, as well as the results of operations and cash flows of its California properties and Berry, as discontinued operations on its consolidated financial statements. Such reclassifications have no impact on previously reported net income (loss), stockholders’/unitholders’ equity (deficit) or cash flows. See Note 4 for additional information.
Use of Estimates	Use of Estimates The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, and fair values of commodity derivatives. In addition, as part of fresh start accounting, the Company made estimates and assumptions related to its reorganization value, liabilities subject to compromise, the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting and income taxes. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Recently Issued Accounting Standards	Recently Adopted Accounting Standards In March 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The Company adopted this ASU on January 1, 2017. The adoption of this ASU had no impact on the Company’s historical financial statements or related disclosures. Upon adoption and subsequently this ASU will result in excess tax benefits, which were previously recorded in equity on the balance sheets and classified as financing activities on the statements of cash flows, being recorded in the statements of operations and classified as operating activities on the statements of cash flows. Additionally, the Company elected to begin accounting for forfeitures as they occur. New Accounting Standards Issued But Not Yet Adopted In November 2016, the FASB issued an ASU that is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures. The adoption of this ASU is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the balance sheets to cash, cash equivalents and restricted cash on the statements of cash flows. In February 2016, the FASB issued an ASU that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2018, and interim periods within those years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its financial statements and related disclosures. The Company expects the adoption of this ASU to impact its balance sheets resulting from an increase in both assets and liabilities related to the Company’s leasing activities. In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those years. The Company has completed an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. While the Company does not currently expect its net income to be materially impacted, the Company’s gross revenues and expenses are expected to be impacted based on a determination of when control of the commodity is transferred and whether it is acting as a principal or agent in certain transactions. In addition, the Company expects to recognize revenue for commodities received as noncash consideration in exchange for services provided by its midstream business and revenue and associated cost of product for the subsequent sale of those same commodities. This recognition will result in an increase to revenues and expenses with no impact on net income. The Company continues to evaluate the impact of these and other provisions of the ASU on its accounting policies, internal controls and financial statements. The Company will adopt this new standard as of January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings.
Cash Equivalents	Cash Equivalents For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows.
Accounts Receivable - Trade, Net	Accounts Receivable – Trade, Net Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $1 million and $8 million at December 31, 2017 , and December 31, 2016 , respectively.
Inventories	Inventories Materials, supplies and commodity inventories are valued at the lower of average cost and net realizable value.
Oil and Natural Gas Properties	Oil and Natural Gas Properties As a result of the application of fresh start accounting, the Company recorded its oil and natural gas properties at fair value as of the Effective Date. See Note 3 for additional information. Proved Properties The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $158,000 for the ten months ended December 31, 2017 , and approximately $257,000 and $3 million for the years ended December 31, 2016 , and December 31, 2015 , respectively. The Company did not capitalize any interest costs during the two months ended February 28, 2017. The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. 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 New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices. Based on the analysis described above, the Company recorded the following noncash impairment charges associated with proved oil and natural gas properties: Predecessor Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) Mid-Continent region $ 141,902 $ 405,370 Rockies region 23,142 1,592,256 Hugoton Basin region — 1,667,768 TexLa region — 352,422 Permian Basin region — 71,990 South Texas region — 42,433 $ 165,044 $ 4,132,239 The impairment charges in 2016 and 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. The Company recorded no impairment charges associated with proved properties during the ten months ended December 31, 2017 , or the two months ended February 28, 2017. Unproved Properties Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past. Based on the analysis described above, the Company recorded the following noncash impairment charges associated with unproved oil and natural gas properties: Predecessor Year Ended December 31, 2015 (in thousands) TexLa region $ 416,846 Permian Basin region 226,922 Rockies region 184,137 $ 827,905 The Company recorded no impairment charges associated with unproved properties for the ten months ended December 31, 2017 , the two months ended February 28, 2017, or the year ended December 31, 2016 . The impairment charges in 2015 were based primarily on no future plans to develop properties in certain operating areas as a result of declines in commodity prices. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. Exploration Costs Exploratory geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
Oil and Natural Gas Properties	Proved Properties The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $158,000 for the ten months ended December 31, 2017 , and approximately $257,000 and $3 million for the years ended December 31, 2016 , and December 31, 2015 , respectively. The Company did not capitalize any interest costs during the two months ended February 28, 2017.
Impairment of Oil and Natural Gas Properties	Based on the analysis described above, the Company recorded the following noncash impairment charges associated with proved oil and natural gas properties: Predecessor Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) Mid-Continent region $ 141,902 $ 405,370 Rockies region 23,142 1,592,256 Hugoton Basin region — 1,667,768 TexLa region — 352,422 Permian Basin region — 71,990 South Texas region — 42,433 $ 165,044 $ 4,132,239 The impairment charges in 2016 and 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations. The Company recorded no impairment charges associated with proved properties during the ten months ended December 31, 2017 , or the two months ended February 28, 2017. Unproved Properties Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past. Based on the analysis described above, the Company recorded the following noncash impairment charges associated with unproved oil and natural gas properties: Predecessor Year Ended December 31, 2015 (in thousands) TexLa region $ 416,846 Permian Basin region 226,922 Rockies region 184,137 $ 827,905 The Company recorded no impairment charges associated with unproved properties for the ten months ended December 31, 2017 , the two months ended February 28, 2017, or the year ended December 31, 2016 . The impairment charges in 2015 were based primarily on no future plans to develop properties in certain operating areas as a result of declines in commodity prices. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
Unproved Properties	Unproved Properties Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past. Based on the analysis described above, the Company recorded the following noncash impairment charges associated with unproved oil and natural gas properties: Predecessor Year Ended December 31, 2015 (in thousands) TexLa region $ 416,846 Permian Basin region 226,922 Rockies region 184,137 $ 827,905 The Company recorded no impairment charges associated with unproved properties for the ten months ended December 31, 2017 , the two months ended February 28, 2017, or the year ended December 31, 2016 . The impairment charges in 2015 were based primarily on no future plans to develop properties in certain operating areas as a result of declines in commodity prices. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
Other Property and Equipment	Other Property and Equipment Other property and equipment includes natural gas gathering systems, pipelines, furniture and office equipment, buildings, vehicles, information technology equipment, software and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from one to 39 years for the individual asset or group of assets.
Revenue Recognition	Revenue Recognition Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Upon the adoption of fresh start accounting on February 28, 2017, the Company has elected the sales method to account for natural gas production imbalances. If the Company’s sales volumes for a well exceed the Company’s proportionate share of production from the well, a liability is recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well is insufficient to satisfy this imbalance. No receivables are recorded for those wells on which the Company has taken less than its proportionate share of production. The Predecessor had applied the entitlements method to account for natural gas production imbalances in previous periods. The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses.
Equity Method Investments	Accounting for Investment in Roan Resources LLC The Company uses the equity method of accounting for its investment in Roan. The Company’s equity earnings (losses) consists of its share of Roan’s earnings or losses and the amortization of the difference between the Company’s investment in Roan and Roan’s underlying net assets attributable to certain assets. Impairment testing on the Company’s investment in Roan is performed when events or circumstances warrant such testing and considers whether there is an inability to recover the carrying value of the investment that is other than temporary. See Note 5 for additional details about the Company’s investment in Roan.
Derivative Instruments	Derivative Instruments Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials. The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date. Derivative instruments are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads are applied to the Company’s commodity derivatives. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.
Share-Based Compensation	Share-Based Compensation The Company recognizes expense for share-based compensation over the requisite service period in an amount equal to the fair value of share-based awards granted. The fair value of share-based awards, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period. The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. Beginning in 2017, the Company accounts for forfeitures as they occur. See Note 15 for additional details about the Company’s accounting for share-based compensation.
Deferred Financing Fees	Deferred Financing Fees The Company has incurred legal and bank fees related to the issuance of debt. At December 31, 2017 , net deferred financing fees of approximately $4 million are included in “other noncurrent assets” on the consolidated balance sheet. At December 31, 2016 , net deferred financing fees of approximately $17 million are included in “other current assets” and approximately $1 million are included in “current portion of long-term debt, net” on the consolidated balance sheet. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense. For the ten months ended December 31, 2017 , the two months ended February 28, 2017, and the years ended December 31, 2016 , and December 31, 2015 , amortization expense of approximately $1 million , $1 million , $10 million and $20 million , respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations. For the ten months ended December 31, 2017 , and the years ended December 31, 2016 , and December 31, 2015 , approximately $3 million , $1 million and $7 million , respectively, were written off to expense and included in “other, net” on the consolidated statements of operations related to amendments of the Company’s credit facilities. In addition, for the year ended December 31, 2016 , approximately $33 million were written off to expense and included in “reorganization items, net” on the consolidated statement of operations in connection with the filing of the Bankruptcy Petitions. No fees were written off to expense for the two months ended February 28, 2017.
Fair Value of Financial Instruments	Fair Value of Financial Instruments The carrying values of the Company’s receivables, payables an d credit facilities are estimated to be substantially the same as their fair values at December 31, 2017 , and December 31, 2016 . See Note 6 for fair value disclosures related to the Company’s other debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments.
Income Taxes	Income Taxes The Successor was formed as a C corporation. For federal and state income tax purposes (with the exception of the state of Texas), the Predecessor was a limited liability company treated as a partnership, in which income tax liabilities and/or benefits were passed through to the Predecessor’s unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Predecessor’s subsidiaries were C corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Predecessor did not directly pay federal and state income taxes and recognition was not given to federal and state income taxes for the operations of the Predecessor. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and tax carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 17 for additional details of the Company’s accounting for income taxes.

Basis of Presentation and Sig31

Basis of Presentation and Significant Accounting Policies Tables (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Impairment of Proved Oil and Natural Gas Properties	Based on the analysis described above, the Company recorded the following noncash impairment charges associated with proved oil and natural gas properties: Predecessor Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) Mid-Continent region $ 141,902 $ 405,370 Rockies region 23,142 1,592,256 Hugoton Basin region — 1,667,768 TexLa region — 352,422 Permian Basin region — 71,990 South Texas region — 42,433 $ 165,044 $ 4,132,239
Impairment of Unproved Oil and Natural Gas Properties	Based on the analysis described above, the Company recorded the following noncash impairment charges associated with unproved oil and natural gas properties: Predecessor Year Ended December 31, 2015 (in thousands) TexLa region $ 416,846 Permian Basin region 226,922 Rockies region 184,137 $ 827,905

Emergence From Voluntary Reor32

Emergence From Voluntary Reorganization Under Chapter 11 (Tables)	12 Months Ended
	Dec. 31, 2017
Reorganizations [Abstract]
Schedule of liabilities subject to compromise [Table Text Block]	The following table summarizes the components of liabilities subject to compromise included on the consolidated balance sheet: Predecessor December 31, 2016 (in thousands) Accounts payable and accrued expenses $ 137,692 Accrued interest payable 144,184 Debt 4,023,129 Liabilities subject to compromise $ 4,305,005
Schedule of Reorganization Items [Table Text Block]	The following tables summarize the components of reorganization items included on the consolidated statements of operations: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 (in thousands) Gain on settlement of liabilities subject to compromise $ — $ 3,724,750 $ — Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement — (1,000,000 ) — Fresh start valuation adjustments — (591,525 ) — Income tax benefit related to implementation of the Plan — 264,889 — Legal and other professional advisory fees (8,902 ) (46,961 ) (56,656 ) Unamortized deferred financing fees, discounts and premiums — — (52,045 ) Gain related to interest payable on Predecessor’s Second Lien Notes — — 551,000 Terminated contracts — (6,915 ) (66,052 ) Other 51 (13,049 ) (64,648 ) Reorganization items, net $ (8,851 ) $ 2,331,189 $ 311,599

Fresh Start Accounting (Tables)

Fresh Start Accounting (Tables)	12 Months Ended
	Dec. 31, 2017
Fresh Start Accounting [Abstract]
Shareholders Equity [Table Text Block]	Adjustments to determine the equity value are presented below (in thousands): Plan confirmed enterprise value $ 2,350,000 Fair value of debt (900,000 ) Fair value of subsequently determined tax attributes 621,486 Fair value of vested Class B units (36,505 ) Value of Successor’s stockholders’ equity $ 2,034,981
Schedule of Fresh-Start Adjustments [Table Text Block]	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 February 28, 2017 Predecessor Reorganization Adjustments (1) Fresh Start Adjustments Successor (in thousands) ASSETS Current assets: Cash and cash equivalents $ 734,166 $ (679,811 ) (2) $ — $ 54,355 Accounts receivable – trade, net 212,099 — (7,808 ) (16) 204,291 Derivative instruments 15,391 — — 15,391 Restricted cash 1,602 80,164 (3) — 81,766 Other current assets 106,426 (15,983 ) (4) 1,780 (17) 92,223 Total current assets 1,069,684 (615,630 ) (6,028 ) 448,026 Noncurrent assets: Oil and natural gas properties (successful efforts method) 13,269,035 — (11,082,258 ) (18) 2,186,777 Less accumulated depletion and amortization (10,044,240 ) — 10,044,240 (18) — 3,224,795 — (1,038,018 ) 2,186,777 Other property and equipment 641,586 — (197,653 ) (19) 443,933 Less accumulated depreciation (230,952 ) — 230,952 (19) — 410,634 — 33,299 443,933 Derivative instruments 4,492 — — 4,492 Deferred income taxes — 264,889 (5) 356,597 (5) 621,486 Other noncurrent assets 15,003 151 (6) 8,139 (20) 23,293 19,495 265,040 364,736 649,271 Total noncurrent assets 3,654,924 265,040 (639,983 ) 3,279,981 Total assets $ 4,724,608 $ (350,590 ) $ (646,011 ) $ 3,728,007 LIABILITIES AND EQUITY (DEFICIT) Current liabilities: Accounts payable and accrued expenses $ 324,585 $ 41,266 (7) $ (2,351 ) (21) $ 363,500 Derivative instruments 7,361 — — 7,361 Current portion of long-term debt, net 1,937,822 (1,912,822 ) (8) — 25,000 Other accrued liabilities 41,251 (1,026 ) (9) 1,104 (22) 41,329 Total current liabilities 2,311,019 (1,872,582 ) (1,247 ) 437,190 Derivative instruments 2,116 — — 2,116 Long-term debt — 875,000 (10) — 875,000 Other noncurrent liabilities 402,776 (167 ) (11) (53,239 ) (23) 349,370 Liabilities subject to compromise 4,301,912 (4,301,912 ) (12) — — Temporary equity: Redeemable noncontrolling interests — 29,350 (13) — 29,350 As of February 28, 2017 Predecessor Reorganization Adjustments (1) Fresh Start Adjustments Successor Stockholders’/unitholders’ equity (deficit): Predecessor units issued and outstanding 5,386,812 (5,386,812 ) (14) — — Predecessor accumulated deficit (7,680,027 ) 2,884,740 (15) 4,795,287 (24) — Successor Class A common stock — 89 (14) — 89 Successor additional paid-in capital — 7,421,704 (14) (5,386,812 ) (24) 2,034,892 Successor retained earnings — — — — Total stockholders’/unitholders’ equity (deficit) (2,293,215 ) 4,919,721 (591,525 ) 2,034,981 Total liabilities and equity (deficit) $ 4,724,608 $ (350,590 ) $ (646,011 ) $ 3,728,007 Reorganization Adjustments: 1) Represent 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, repayment of certain of the Predecessor’s debt, cancellation of the Predecessor’s equity, issuances of the Successor’s Class A common stock, proceeds received from the Successor’s rights offerings and issuance of the Successor’s debt. 2) Changes in cash and cash equivalents included the following: (in thousands) Borrowings under the Successor’s revolving loan $ 600,000 Borrowings under the Successor’s term loan 300,000 Proceeds from rights offerings 530,019 Removal of restriction on cash balance 1,602 Payment to holders of claims under the Predecessor Credit Facility (1,947,357 ) Payment to holders of claims under the Second Lien Notes (30,000 ) Payment of Berry’s ad valorem taxes (23,366 ) Payment of the rights offerings backstop commitment premium (15,900 ) Payment of professional fees (13,043 ) Funding of the professional fees escrow account (41,766 ) Funding of the general unsecured claims cash distribution pool (40,000 ) Changes in cash and cash equivalents $ (679,811 ) 3) Primarily reflects the transfer to restricted cash to fund the Predecessor’s professional fees escrow account and general unsecured claims cash distribution pool. 4) Primarily reflects the write-off of the Predecessor’s deferred financing fees. 5) Reflects deferred tax assets recorded as of the Effective Date as determined in accordance with ASC 740. The deferred tax assets were primarily the result of the conversion from a limited liability company to a C corporation and differences in the accounting basis and tax basis of the Company’s oil and natural gas properties as of the Effective Date. 6) Reflects the capitalization of deferred financing fees related to the Successor’s revolving loan. 7) Net increase in accounts payable and accrued expenses reflects: (in thousands) Recognition of payables for the professional fees escrow account $ 41,766 Recognition of payables for the general unsecured claims cash distribution pool 40,000 Payment of professional fees (17,130 ) Payment of Berry’s ad valorem taxes (23,366 ) Other (4 ) Net increase in accounts payable and accrued expenses $ 41,266 8) Reflects the settlement of the Predecessor Credit Facility through repayment of approximately $1.9 billion , net of the write-off of deferred financing fees and an increase of $25 million for the current portion of the Successor’s term loan. 9) Reflects a decrease of approximately $8 million for the payment of accrued interest on the Predecessor Credit Facility partially offset by an increase of approximately $7 million related to noncash share-based compensation classified as a liability related to the incentive interest awards issued by Holdco to certain members of its management (see Note 15). 10) Reflects borrowings of $900 million under the Successor Credit Facility, which includes a $600 million revolving loan and a $300 million term loan, net of $25 million for the current portion of the Successor’s term loan. 11) Reflects a reduction in deferred tax liabilities as determined in accordance with ASC 740. 12) Settlement of liabilities subject to compromise and the resulting net gain were determined as follows: (in thousands) Accounts payable and accrued expenses $ 134,599 Accrued interest payable 144,184 Debt 4,023,129 Total liabilities subject to compromise 4,301,912 Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement 1,000,000 Funding of the general unsecured claims cash distribution pool (40,000 ) Payment to holders of claims under the Second Lien Notes (30,000 ) Issuance of Class A common stock to creditors (1,507,162 ) Gain on settlement of liabilities subject to compromise $ 3,724,750 13) Reflects redeemable noncontrolling interests classified as temporary equity related to the incentive interest awards issued by Holdco to certain members of its management. See Note 15 for additional information. 14) Net increase in capital accounts reflects: (in thousands) Issuance of Class A common stock to creditors $ 1,507,162 Issuance of Class A common stock pursuant to the rights offerings 530,019 Payment of the rights offerings backstop commitment premium (15,900 ) Payment of issuance costs (50 ) Share-based compensation expenses 13,750 Cancellation of the Predecessor’s units issued and outstanding 5,386,812 Par value of Class A common stock (89 ) Change in additional paid-in capital 7,421,704 Par value of Class A common stock 89 Predecessor’s units issued and outstanding (5,386,812 ) Net increase in capital accounts $ 2,034,981 See Note 13 for additional information on the issuances of the Successor’s equity. 15) Net decrease in accumulated deficit reflects: (in thousands) Recognition of gain on settlement of liabilities subject to compromise $ 3,724,750 Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement (1,000,000 ) Recognition of professional fees (37,680 ) Write-off of deferred financing fees (16,728 ) Recognition of deferred income taxes 264,889 Total reorganization items, net 2,935,231 Share-based compensation expenses (50,255 ) Other (236 ) Net decrease in accumulated deficit $ 2,884,740 Fresh Start Adjustments: 16) Reflects a change in accounting policy from the entitlements method to the sales method for natural gas production imbalances. 17) Reflects the recognition of intangible assets for the current portion of favorable leases, partially offset by decreases for well equipment inventory and the write-off of historical intangible assets. 18) Reflects a decrease of oil and natural gas properties, based on the methodology discussed above, and the elimination of accumulated depletion and amortization. The following table summarizes the components of oil and natural gas properties as of the Effective Date: Successor Predecessor Fair Value Historical Book Value (in thousands) Proved properties $ 1,727,834 $ 12,258,835 Unproved properties 458,943 1,010,200 2,186,777 13,269,035 Less accumulated depletion and amortization — (10,044,240 ) $ 2,186,777 $ 3,224,795 19) Reflects a decrease of other property and equipment and the elimination of accumulated depreciation. The following table summarizes the components of other property and equipment as of the Effective Date: Successor Predecessor Fair Value Historical Book Value (in thousands) Natural gas plants and pipelines $ 342,924 $ 426,914 Office equipment and furniture 39,211 106,059 Buildings and leasehold improvements 32,817 66,023 Vehicles 16,980 30,760 Land 7,747 3,727 Drilling and other equipment 4,254 8,103 443,933 641,586 Less accumulated depreciation — (230,952 ) $ 443,933 $ 410,634 In estimating the fair value of other property and equipment, the Company used a combination of cost and market approaches. A cost approach was used to value the Company’s natural gas plants and pipelines and other operating assets, 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. A market approach was used to value the Company’s vehicles and land, using recent transactions of similar assets to determine the fair value from a market participant perspective. 20) Reflects the recognition of intangible assets for the noncurrent portion of favorable leases, as well as increases in equity method investments and carbon credit allowances. Assets and liabilities for out-of-market contracts were valued based on market terms as of February 28, 2017, and will be amortized over the remaining life of the respective lease. The Company’s equity method investments were valued based on a market approach using a market EBITDA multiple. Carbon credit allowances were valued using a market approach based on trading prices for carbon credits on February 28, 2017. 21) Primarily reflects the write-off of deferred rent partially offset by an increase in carbon emissions liabilities. 22) Reflects an increase of the current portion of asset retirement obligations.

Discontinued Operations, Othe34

Discontinued Operations, Other Divestitures and Roan Contribution (Tables)	12 Months Ended
	Dec. 31, 2017
Acquisitions and divestitures [Abstract]
Discontinued operations, summarized balance sheets [Table Text Block]	The following table presents carrying amounts of the assets and liabilities of the Company’s California properties classified as discontinued operations on the consolidated balance sheet: Predecessor December 31, 2016 (in thousands) Assets: Oil and natural gas properties $ 728,190 Other property and equipment 11,402 Other 1,435 Total assets of discontinued operations $ 741,027 Liabilities: Asset retirement obligations $ 38,042 Other 1,481 Total liabilities of discontinued operations $ 39,523
Discontinued operations, summarized statements of operations [Table Text Block]	The following tables present summarized financial results of the Company’s California properties and Berry classified as discontinued operations on the consolidated statements of operations: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) Revenues and other $ 34,096 $ 14,891 $ 465,775 $ 727,211 Expenses 19,479 13,758 1,612,727 1,651,114 Other income and (expenses) (3,541 ) (1,681 ) (65,022 ) (81,756 ) Reorganization items, net — — (46,127 ) — Income (loss) from discontinued operations before income taxes 11,076 (548 ) (1,258,101 ) (1,005,659 ) Income tax expense (benefit) 4,165 — 196 (68 ) Income (loss) from discontinued operations, net of income taxes $ 6,911 $ (548 ) $ (1,258,297 ) $ (1,005,591 )
Disclosure of Long Lived Assets Held-for-sale [Table Text Block]	The following table presents carrying amounts of the assets and liabilities of the Company’s properties classified as held for sale on the consolidated balance sheet: Successor December 31, 2017 (in thousands) Assets: Oil and natural gas properties $ 92,245 Other property and equipment 12,983 Other 1,735 Total assets held for sale $ 106,963 Liabilities: Asset retirement obligations $ 42,001 Other 1,301 Total liabilities held for sale $ 43,302 Other assets primarily include inventories and other liabilities primarily include accounts payable.

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments [Table Text Block]	Following are summarized statement of operations and balance sheet information for Roan. Summarized Roan Resources LLC Statement of Operations Information Four Months Ended December 31, 2017 (in thousands) Revenues and other $ 75,461 Expenses 61,790 Other income and (expenses) (1,180 ) Net income $ 12,491 Summarized Roan Resources LLC Balance Sheet Information December 31, 2017 (in thousands) Current assets $ 27,465 Noncurrent assets 1,826,741 1,854,206 Current liabilities 149,409 Noncurrent liabilities 97,480 Members’ equity $ 1,607,317

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Summary of Outstanding Debt	The following summarizes the Company’s outstanding debt: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands, except percentages) Revolving credit facility $ — $ — Predecessor credit facility (1) — 1,654,745 Predecessor term loan (1) — 284,241 6.50% senior notes due May 2019 — 562,234 6.25% senior notes due November 2019 — 581,402 8.625% senior notes due April 2020 — 718,596 12.00% senior secured second lien notes due December 2020 — 1,000,000 7.75% senior notes due February 2021 — 779,474 6.50% senior notes due September 2021 — 381,423 Net unamortized deferred financing fees — (1,257 ) Total debt, net — 5,960,858 Less current portion, net (2) — (1,937,729 ) Less liabilities subject to compromise (3) — (4,023,129 ) Long-term debt $ — $ — (1) Variable interest rate of 5.50% at December 31, 2016 . (2) Due to covenant violations, the Predecessor’s credit facility and term loan were classified as current at December 31, 2016 . (3) The Predecessor’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016 . On the Effective Date, pursuant to the terms of the Plan, all outstanding amounts under these debt instruments were canceled.
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	Predecessor December 31, 2016 Carrying Value Fair Value (in thousands) Senior secured second lien notes $ 1,000,000 $ 863,750 Senior notes, net 3,023,129 1,179,224
Schedule of Senior Notes Exchanged	On November 20, 2015, the Company issued $1.0 billion in aggregate principal amount of 12.00% senior secured second lien notes due December 2020 (“Second Lien Notes”) in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes as follows: Par Value of Senior Notes Exchanged (in thousands) 6.50% senior notes due May 2019 $ 584,422 6.25% senior notes due November 2019 824,348 8.625% senior notes due April 2020 286,344 7.75% senior notes due February 2021 184,300 6.50% senior notes due September 2021 120,586 $ 2,000,000

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	The following table presents derivative positions for the periods indicated as of December 31, 2017 : 2018 2019 Natural gas positions: Fixed price swaps (NYMEX Henry Hub): Hedged volume (MMMBtu) 69,715 11,315 Average price ($/MMBtu) $ 3.02 $ 2.97 Oil positions: Fixed price swaps (NYMEX WTI): Hedged volume (MBbls) 548 — Average price ($/Bbl) $ 54.07 $ — Collars (NYMEX WTI): Hedged volume (MBbls) 1,825 1,825 Average floor price ($/Bbl) $ 50.00 $ 50.00 Average ceiling price ($/Bbl) $ 55.50 $ 55.50
Fair Value of Derivatives Outstanding on a Gross Basis by Location on the Balance Sheet	The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. The following table summarizes the fair value of derivatives outstanding on a gross basis: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) Assets: Commodity derivatives $ 22,589 $ 19,369 Liabilities: Commodity derivatives $ 25,443 $ 113,226

Fair Value Measurements on a 38

Fair Value Measurements on a Recurring Basis (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements on a Recurring Basis	The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis: Successor December 31, 2017 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 22,589 $ (12,491 ) $ 10,098 Liabilities: Commodity derivatives $ 25,443 $ (12,491 ) $ 12,952 Predecessor December 31, 2016 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 19,369 $ (19,369 ) $ — Liabilities: Commodity derivatives $ 113,226 $ (19,369 ) $ 93,857 (1) Represents counterparty netting under agreements governing such derivatives.

Other Property and Equipment (T

Other Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Other Property and Equipment	Other property and equipment consists of the following: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) Natural gas plant and pipeline $ 392,999 $ 421,806 Furniture and office equipment 39,551 105,353 Buildings and leasehold improvements 27,301 66,014 Vehicles 10,811 31,496 Land 6,776 3,736 Drilling and other equipment 3,291 8,082 480,729 636,487 Less accumulated depreciation (28,658 ) (224,547 ) Less other property and equipment, net – discontinued operations — (11,402 ) $ 452,071 $ 400,538

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations Reconciliation	The following table presents a reconciliation of the Company’s asset retirement obligations: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 (in thousands) Asset retirement obligations at beginning of period $ 357,397 $ 402,162 $ 523,541 Liabilities added from drilling 551 146 546 Liabilities added from acquisitions — — 1,416 Liabilities associated with assets divested (158,228 ) — — Liabilities associated with assets held for sale (42,001 ) — — Deconsolidation of Berry Petroleum Company, LLC asset retirement obligations — — (141,612 ) Current year accretion expense 14,995 4,024 30,498 Settlements (8,189 ) (618 ) (12,823 ) Revision of estimates 28 — 596 Fresh start adjustment (1) — (48,317 ) — 164,553 357,397 402,162 Less asset retirement obligations – discontinued operations — (26,978 ) (38,042 ) Asset retirement obligations at end of period $ 164,553 $ 330,419 $ 364,120 (1) As a result of the application of fresh start accounting, the Successor recorded its asset retirement obligations at fair value as of the Effective Date.

Operating Leases (Tables)

Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2016
Leases, Operating [Abstract]
Future Minimum Lease Payments	As of December 31, 2017 , future minimum lease payments were as follows (in thousands): 2018 $ 2,812 2019 2,005 2020 463 2021 12 2022 — Thereafter — $ 5,292

Share-Based Compensation and 42

Share-Based Compensation and Other Benefits (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Table Text Block]	A summary of share-based compensation expenses included on the consolidated statements of operations is presented below: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) General and administrative expenses $ 41,285 $ 50,255 $ 34,268 $ 47,312 Lease operating expenses — — 9,950 8,824 Total share-based compensation expenses $ 41,285 $ 50,255 $ 44,218 $ 56,136 Income tax benefit $ 9,861 $ 5,170 $ 16,339 $ 20,742
Schedule of Nonvested Restricted Stock Units Activity [Table Text Block]	The following summarizes the Company’s restricted stock units activity: Number of Nonvested Units Weighted Average Grant-Date Fair Value Per Unit Nonvested units at February 28, 2017 (Predecessor) — $ — Granted 2,478,606 $ 22.19 Vested (619,665 ) $ 22.19 Nonvested units at February 28, 2017 (Successor) 1,858,941 $ 22.19 Granted 1,340,350 $ 29.29 Vested (51,839 ) $ 27.86 Forfeited (187,148 ) $ 28.38 Nonvested units at December 31, 2017 (Successor) 2,960,304 $ 24.92

Earnings Per Share_Unit (Tables

Earnings Per Share/Unit (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of Earnings Per Share Reconciliation	The following tables provide a reconciliation of the numerators and denominators of the basic and diluted per share/unit computations for net income (loss): Successor Ten Months Ended December 31, 2017 Income Shares Per Share (in thousands, except per share data) Basic: Income from continuing operations $ 349,865 87,646 $ 3.99 Income from discontinued operations, net of income taxes 82,995 87,646 0.95 Net income attributable to common stockholders $ 432,860 87,646 $ 4.94 Effect of Dilutive Securities: Dilutive effect of restricted stock units $ — 1,073 Dilutive effect of unvested Class A-2 units of Holdco $ (2,180 ) — Diluted: Income from continuing operations $ 347,685 88,719 $ 3.92 Income from discontinued operations 82,995 88,719 0.93 Net income attributable to common stockholders $ 430,680 88,719 $ 4.85 Predecessor Two Months Ended February 28, 2017 Income (Loss) Units Per Unit (in thousands, except per unit data) Basic and Diluted: Income from continuing operations $ 2,397,609 352,792 $ 6.80 Loss from discontinued operations, net of income taxes (548 ) 352,792 (0.01 ) Net income attributable to common unitholders $ 2,397,061 352,792 $ 6.79 Predecessor Year Ended December 31, 2016 Loss Units Per Unit (in thousands, except per unit data) Basic and Diluted: Loss from continuing operations $ (367,343 ) 352,653 $ (1.04 ) Loss from discontinued operations, net of income taxes (1,804,513 ) 352,653 (5.12 ) Net loss attributable to common unitholders $ (2,171,856 ) 352,653 $ (6.16 ) Predecessor Year Ended December 31, 2015 Loss Units Per Unit (in thousands, except per unit data) Basic and Diluted: Loss from continuing operations $ (3,754,220 ) Allocated to participating securities (3,039 ) (3,757,259 ) 343,323 $ (10.94 ) Loss from discontinued operations, net of income taxes (1,005,591 ) 343,323 (2.93 ) Net loss attributable to common unitholders $ (4,762,850 ) 343,323 $ (13.87 )

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Components of income tax expense (benefit)	Income tax expense (benefit) consisted of the following: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) Current taxes: Federal $ 7,140 $ — $ (494 ) $ (12,021 ) State 489 — 321 1,022 Deferred taxes: Federal 366,243 — 11,582 8,237 State 15,070 (166 ) (215 ) (3,631 ) $ 388,942 $ (166 ) $ 11,194 $ (6,393 )
Effective income tax rate reconciliation	A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % 35.0 % Federal statutory rate change 14.3 — — — State, net of federal tax benefit 2.6 — 0.7 0.1 Loss excluded from nontaxable entities — (35.0 ) (24.7 ) (34.7 ) Other 0.5 — (14.1 ) (0.2 ) Effective rate 52.4 % — % (3.1 )% 0.2 %
Significant components of the deferred tax assets and liabilities	Significant components of the deferred tax assets and liabilities were as follows: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) Deferred tax assets: Net operating loss carryforwards $ 14,615 $ 1,730 Reorganization items — 14,932 Investment in Linn Energy Holdco LLC 176,662 — Valuation allowance — (19,558 ) Other 7,140 10,030 Total deferred tax assets 198,417 7,134 Deferred tax liabilities: Property and equipment principally due to differences in depreciation — (7,021 ) Other — (279 ) Total deferred tax liabilities — (7,300 ) Net deferred tax assets (liabilities) $ 198,417 $ (166 )

Supplemental Disclosures to t45

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2017
Balance Sheet and Cash Flow Supplemental Disclosures [Abstract]
Schedule of Other Current Assets [Table Text Block]	“Other current assets” reported on the consolidated balance sheets include the following: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) Prepaids $ 46,238 $ 70,116 Receivable from related party 23,163 — Inventories 7,667 15,097 Deferred financing fees — 16,809 Other 2,703 3,288 Other current assets $ 79,771 $ 105,310
Other Current Liabilities [Table Text Block]	“Other accrued liabilities” reported on the consolidated balance sheets include the following: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) Accrued compensation $ 29,089 $ 16,443 Asset retirement obligations (current portion) 3,926 9,361 Deposits 15,349 — Income taxes payable 7,496 — Other 2,757 175 Other accrued liabilities $ 58,617 $ 25,979
Supplemental Cash Flow Disclosures	Supplemental disclosures to the consolidated statements of cash flows are presented below: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) Cash payments for interest, net of amounts capitalized $ 15,165 $ 17,651 $ 143,305 $ 476,077 Cash payments for income taxes $ 275 $ — $ 4,427 $ 643 Cash payments for reorganization items, net $ 11,889 $ 21,571 $ 37,748 $ — Noncash investing activities: Accrued capital expenditures $ 31,447 $ 22,191 $ 31,128 $ 71,105

Supplemental Oil and Natural 46

Supplemental Oil and Natural Gas Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development	Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below: Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) LINN Energy: Property acquisition costs: Proved $ — $ — $ — $ — Unproved — — — — Exploration costs 103,689 15,153 40,074 19,929 Development costs 96,178 24,256 86,053 264,227 Asset retirement costs 376 312 112 3,331 Total costs incurred – continuing operations $ 200,243 $ 39,721 $ 126,239 $ 287,487 Total costs incurred – discontinued operations $ 1,313 $ 269 $ 11,453 $ 167,049 Four Months Ended December 31, 2017 (in thousands) Equity method investments (1) Property acquisition costs: Proved $ — Unproved 6,851 Exploration costs 3,626 Development costs 89,585 Total costs incurred $ 100,062 (1) Re
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities	Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below: Successor Predecessor December 31, 2017 December 31, 2016 (in thousands) LINN Energy: Proved properties $ 904,390 $ 12,234,099 Unproved properties 45,693 998,860 950,083 13,232,959 Less accumulated depletion and amortization (49,619 ) (9,999,560 ) 900,464 3,233,399 Less oil and natural gas capitalized costs, net – discontinued operations — (728,190 ) $ 900,464 $ 2,505,209 December 31, 2017 (in thousands) Equity Method Investments: (1) Proved properties $ 400,682 Unproved properties 538,703 939,385 Less accumulated depletion and amortization (28,441 ) $ 910,944 (1) Represents the Company’s 50% equity interest in Roan.
Results of Operations for Oil and Gas Producing Activities	The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs): Successor Predecessor Ten Months Ended December 31, 2017 Two Months Ended February 28, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015 (in thousands) LINN Energy: Revenues and other: Oil, natural gas and natural gas liquids sales $ 709,363 $ 188,885 $ 874,161 $ 1,065,795 Gains (losses) on oil and natural gas derivatives 13,533 92,691 (164,330 ) 1,027,014 722,896 281,576 709,831 2,092,809 Production costs: Lease operating expenses 208,446 49,665 296,891 352,077 Transportation expenses 113,128 25,972 161,574 167,023 Severance taxes, ad valorem taxes and California carbon allowances 47,411 14,851 66,616 97,732 368,985 90,488 525,081 616,832 Other costs: Exploration costs 3,137 93 4,080 9,473 Depletion and amortization 101,360 39,689 295,889 471,046 Impairment of long-lived assets — — 165,044 4,960,144 (Gains) losses on sale of assets and other, net (678,200 ) 18 417 (199,296 ) Income tax benefit (4,640 ) (166 ) (649 ) (2,721 ) (578,343 ) 39,634 464,781 5,238,646 Results of operations – continuing operations $ 932,254 $ 151,454 $ (280,031 ) $ (3,762,669 ) Results of operations – discontinued operations $ 142,175 $ 1,246 $ (1,076,407 ) $ (844,754 ) There is no federal tax provision included in the Predecessor’s results above because the Predecessor’s subsidiaries subject to federal income taxes did not own any of the Predecessor’s oil and natural gas interests. Limited liability companies are subject to Texas margin tax. See Note 17 for additional information about income taxes. Four Months Ended December 31, 2017 (in thousands) Equity Method Investments: (1) Revenues and other: Oil, natural gas and natural gas liquids sales $ 42,322 Losses on oil and natural gas derivatives (4,591 ) 37,731 Production costs: Lease operating expenses 4,102 Transportation expenses 4,576 Severance taxes and ad valorem taxes 1,026 9,704 Other costs: Exploration costs 3,626 Depletion and amortization 11,371 14,997 Results of operations $ 13,030 (1) Represents the Company’s 50% equity interest in Roan. Results of oil and natural gas producing activities of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017 . There is no tax provision included in Roan’s results above because Roan is not subject to federal income taxes.
Estimated Quantities of Oil, Natural Gas and NGL Reserves	An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below: Successor Year Ended December 31, 2017 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) LINN Energy: Proved developed and undeveloped reserves: Beginning of year 2,290 72.6 104.1 3,350 170 3,520 Revisions of previous estimates (102 ) (5.6 ) 9.7 (78 ) — (78 ) Sales of minerals in place (754 ) (37.0 ) (39.6 ) (1,213 ) (164 ) (1,377 ) Extensions and discoveries 90 3.7 4.9 142 — 142 Production (147 ) (6.6 ) (7.6 ) (233 ) (6 ) (239 ) End of year 1,377 27.1 71.5 1,968 — 1,968 Proved developed reserves: Beginning of year 2,118 66.7 94.4 3,084 170 3,254 End of year 1,323 27.0 70.5 1,908 — 1,908 Proved undeveloped reserves: Beginning of year 172 5.9 9.7 266 — 266 End of year 54 0.1 1.0 60 — 60 Four Months Ended December 31, 2017 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total (Bcfe) Equity Method Investments: (1) Proved developed and undeveloped reserves: Beginning of period 173 10.3 17.8 342 Revisions of previous estimates (14 ) (2.6 ) (1.9 ) (42 ) Extensions and discoveries 189 11.4 24.3 403 Production (5 ) (0.4 ) (0.4 ) (9 ) End of year 343 18.7 39.8 694 Proved developed reserves: Beginning of year 95 4.5 7.9 169 End of year 130 6.2 12.0 239 Proved undeveloped reserves: Beginning of year 78 5.8 9.9 173 End of year 213 12.5 27.8 455 (1) Represents the Company’s 50% equity interest in Roan. Predecessor Year Ended December 31, 2016 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) LINN Energy: Proved developed and undeveloped reserves: Beginning of year 2,212 74.3 97.0 3,240 1,248 4,488 Revisions of previous estimates — (3.8 ) 1.2 (16 ) (192 ) (208 ) Extensions and discoveries 265 10.1 15.2 417 11 428 Production (187 ) (8.0 ) (9.3 ) (291 ) (93 ) (384 ) Deconsolidation of Berry Petroleum, LLC proved reserves — — — — (804 ) (804 ) End of year 2,290 72.6 104.1 3,350 170 3,520 Proved developed reserves: Beginning of year 2,212 74.3 97.0 3,240 1,248 4,488 End of year 2,118 66.7 94.4 3,084 170 3,254 Proved undeveloped reserves: Beginning of year — — — — — — End of year 172 5.9 9.7 266 — 266 Predecessor Year Ended December 31, 2015 Natural Gas (Bcf) Oil (MMBbls) NGL (MMBbls) Total Continuing Operations (Bcfe) Total Discontinued Operations (Bcfe) Total (Bcfe) LINN Energy: Proved developed and undeveloped reserves: Beginning of year 3,552 147.8 146.3 5,318 1,986 7,304 Revisions of previous estimates (1,137 ) (62.4 ) (38.7 ) (1,743 ) (636 ) (2,379 ) Sales of minerals in place (13 ) (4.1 ) (2.0 ) (50 ) — (50 ) Extensions and discoveries 10 3.0 0.8 32 15 47 Production (200 ) (10.0 ) (9.4 ) (317 ) (117 ) (434 ) End of year 2,212 74.3 97.0 3,240 1,248 4,488 Proved developed reserves: Beginning of year 2,981 104.2 117.5 4,312 1,506 5,818 End of year 2,212 74.3 97.0 3,240 1,248 4,488 Proved undeveloped reserves: Beginning of year 571 43.6 28.8 1,006 480 1,486 End of year — — — — — — The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents using the ratio of one barrel to six Mcf. Reserves for the Company’s California properties and Berry are reported as discontinued operations for all periods presented.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves	Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying the year-end statutory tax rates (with consideration of any known future changes) to the pretax net cash flows, reduced by the applicable tax basis and giving effect to any tax deductions, tax credits and allowances relating to the proved oil and natural gas reserves. There are no future income tax expenses at December 31, 2016, or December 31, 2015, because the Predecessor was not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts were not material. See Note 17 for additional information about income taxes. December 31, 2017 2016 2015 (in thousands) LINN Energy: Future cash inflows $ 6,730,186 $ 9,856,698 $ 10,396,598 Future production costs (3,810,932 ) (5,755,460 ) (6,576,424 ) Future development costs (486,989 ) (917,262 ) (722,685 ) Future income tax expenses (303,803 ) — — Future net cash flows 2,128,462 3,183,976 3,097,489 10% annual discount for estimated timing of cash flows (1,083,331 ) (1,488,219 ) (1,404,304 ) Standardized measure of discounted future net cash flows – continuing operations $ 1,045,131 $ 1,695,757 $ 1,693,185 Standardized measure of discounted future net cash flows – discontinued operations $ — $ 232,941 $ 1,340,360 Representative NYMEX prices: (1) Natural gas (MMBtu) $ 2.98 $ 2.48 $ 2.59 Oil (Bbl) $ 51.34 $ 42.64 $ 50.16 (1) In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. December 31, 2017 (in thousands) Equity Method Investments: (1) Future cash inflows $ 2,635,233 Future production costs (832,362 ) Future development costs (372,884 ) Future net cash flows 1,429,987 10% annual discount for estimated timing of cash flows (832,152 ) Standardized measure of discounted future net cash flows $ 597,835 Representative NYMEX prices: (2) Natural gas (MMBtu) $ 2.98 Oil (Bbl) $ 51.34 (1) Represents the Company’s 50% equity interest in Roan. (2) In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow	The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Year Ended December 31, 2017 2016 2015 (in thousands) LINN Energy: Sales and transfers of oil, natural gas and NGL produced during the period $ (438,775 ) $ (349,080 ) $ (448,963 ) Changes in estimated future development costs (5,276 ) 19,460 953,393 Net change in sales and transfer prices and production costs related to future production 400,411 (92,236 ) (5,313,449 ) Sales of minerals in place (685,050 ) — (97,785 ) Extensions, discoveries and improved recovery 187,223 221,765 46,487 Previously estimated development costs incurred during the period 9,704 — 84,329 Net change due to revisions in quantity estimates (65,935 ) 10,387 (939,030 ) Net change in income taxes (155,257 ) — — Accretion of discount 169,576 169,318 707,085 Changes in production rates and other (67,247 ) 22,958 (369,736 ) Change – continuing operations $ (650,626 ) $ 2,572 $ (5,377,669 ) Change – discontinued operations $ (232,941 ) $ (1,107,419 ) $ (4,101,077 ) Four Months Ended December 31, 2017 (in thousands) Equity Method Investments (1) Standardized measure – Beginning of period $ 304,900 Sales and transfers of oil, natural gas and NGL produced during the period (32,618 ) Changes in estimated future development costs (14,617 ) Net change in sales and transfer prices and production costs related to future production 33,912 Extensions, discoveries and improved recovery 270,737 Previously estimated development costs incurred during the period 89,457 Net change due to revisions in quantity estimates (47,222 ) Accretion of discount 10,163 Changes in production rates and other (16,877 ) Net increase 292,935 Standardized measure – End of year $ 597,835 (1) Represents the Company’s 50% equity interest in Roan. Changes in the standardized measure of discounted future net cash flows of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017 .

Supplemental Quarterly Data (47

Supplemental Quarterly Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Quarterly Financial Data	Quarterly Financial Data Predecessor Successor January 1, 2017 to February 28, 2017 March 1, 2017 to March 31, 2017 Second Quarter Third Quarter Fourth Quarter (in thousands, except per share and per unit amounts) 2017: Oil, natural gas and natural gas liquids sales $ 188,885 $ 80,325 $ 243,167 $ 206,318 $ 179,553 Gains (losses) on oil and natural gas derivatives 92,691 (11,959 ) 45,714 (14,497 ) (5,725 ) Total revenues and other 298,127 73,308 307,819 236,682 208,869 Total expenses (1) 214,327 78,349 220,548 202,143 191,491 (Gains) losses on sale of assets and other, net 829 484 (306,878 ) (26,977 ) (289,701 ) Reorganization items, net 2,331,189 (2,565 ) (3,377 ) (2,605 ) (304 ) Income (loss) from continuing operations 2,397,609 (7,324 ) 223,379 51,030 85,587 Income (loss) from discontinued operations, net of income taxes (548 ) 68 (3,322 ) 86,099 150 Net income (loss) 2,397,061 (7,256 ) 220,057 137,129 85,737 Net income attributable to noncontrolling interests — — — 66 2,741 Net income attributable to stockholders/unitholders 2,397,061 (7,256 ) 220,057 137,063 82,996 Income (loss) per share/unit – continuing operations: Basic $ 6.80 $ (0.08 ) $ 2.49 $ 0.58 $ 0.98 Diluted $ 6.80 $ (0.08 ) $ 2.47 $ 0.57 $ 0.94 Income (loss) per share/unit – discontinued operations: Basic $ (0.01 ) $ — $ (0.04 ) $ 0.98 $ — Diluted $ (0.01 ) $ — $ (0.04 ) $ 0.97 $ — Net income (loss) per share/unit: Basic $ 6.79 $ (0.08 ) $ 2.45 $ 1.56 $ 0.98 Diluted $ 6.79 $ (0.08 ) $ 2.43 $ 1.54 $ 0.94 (1) Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes. During the third quarter of 2017, the Company corrected its allocation of value between proved and unproved oil and natural gas properties initially recorded as part of fresh start accounting (see Note 3) resulting in a reclassification of approximately $459 million from proved properties to unproved properties as of February 28, 2017. As a result, during the third quarter of 2017, the Company also recorded pretax out-of-period corrections of approximately $8 million to reduce depletion expense and approximately $1 million to increase net gains on sale of assets (combined $5 million after tax), as well as approximately $8 million to increase income from discontinued operations, net of income taxes, related to errors in the first and second quarters of 2017. The Company concluded that the correction of the errors was not material to these or any previously issued financial statements. Predecessor First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per unit amounts) 2016: Oil, natural gas and natural gas liquids sales $ 184,441 $ 195,847 $ 237,986 $ 255,887 Gains (losses) on oil and natural gas derivatives 109,453 (183,794 ) 166 (90,155 ) Total revenues and other 331,261 44,245 266,975 197,163 Total expenses (1) 449,809 274,941 310,772 269,906 Losses on sale of assets and other, net 1,468 2,607 2,532 9,650 Reorganization items, net — 485,798 (28,361 ) (145,838 ) Income (loss) from continuing operations (213,868 ) 204,691 (96,301 ) (261,865 ) Income (loss) from discontinued operations, net of income taxes (1,133,878 ) 3,801 (102,064 ) (572,372 ) Net income (loss) (1,347,746 ) 208,492 (198,365 ) (834,237 ) Income (loss) per unit – continuing operations: Basic $ (0.61 ) $ 0.58 $ (0.27 ) $ (0.74 ) Diluted $ (0.61 ) $ 0.58 $ (0.27 ) $ (0.74 ) Income (loss) per unit – discontinued operations: Basic $ (3.22 ) $ 0.01 $ (0.29 ) $ (1.62 ) Diluted $ (3.22 ) $ 0.01 $ (0.29 ) $ (1.62 ) Net income (loss) per unit: Basic $ (3.83 ) $ 0.59 $ (0.56 ) $ (2.36 ) Diluted $ (3.83 ) $ 0.59 $ (0.56 ) $ (2.36 ) (1) Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.

Basis of Presentation and Sig48

Basis of Presentation and Significant Accounting Policies (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Aug. 31, 2017
Property, Plant and Equipment [Line Items]
Allowance for doubtful accounts		$ 1,000	$ 8,000
Capitalized interest costs			257	$ 3,000
Amortization of Financing Costs	$ 1,000	1,000	$ 10,000	20,000
Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life			1 year
Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life			39 years
Successor [Member]
Property, Plant and Equipment [Line Items]
Restricted cash		56,445
Removal of restriction on cash balance		(2,151)
Deferred financing fees		$ 0
Predecessor [Member]
Property, Plant and Equipment [Line Items]
Restricted cash			$ 1,602
Removal of restriction on cash balance	80,164		0	0
Restricted cash			8,000
Deferred financing fees			16,809
Roan Resources LLC [Member] | Successor [Member]
Property, Plant and Equipment [Line Items]
Ownership percentage		50.00%			50.00%
Other [Member] | Successor [Member]
Property, Plant and Equipment [Line Items]
Restricted cash		$ 5,000
Deposits for divestitures [Member] | Successor [Member]
Property, Plant and Equipment [Line Items]
Restricted cash		15,000
Professional fees [Member] | Successor [Member]
Property, Plant and Equipment [Line Items]
Restricted cash		36,000
Other, net [Member]
Property, Plant and Equipment [Line Items]
Write off of Deferred Debt Issuance Cost	$ 0	3,000	1,000	$ 7,000
Reorganization items [Member]
Property, Plant and Equipment [Line Items]
Write off of Deferred Debt Issuance Cost			33,000
Other Current Assets [Member]
Property, Plant and Equipment [Line Items]
Deferred financing fees		$ 4,000	17,000
Current portion of long-term debt [Member]
Property, Plant and Equipment [Line Items]
Deferred financing fees			$ 1,000

Basis of Presentation and Sig49

Basis of Presentation and Significant Accounting Policies Proved Property Impairment (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties	$ 0	$ 0	$ 165,044	$ 4,132,239
Rockies region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			23,142	1,592,256
Hugoton Basin region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			0	1,667,768
TexLa region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			0	352,422
Mid-Continent region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			141,902	405,370
Permian Basin region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			0	71,990
South Texas region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of proved oil and gas properties			$ 0	$ 42,433

Basis of Presentation and Sig50

Basis of Presentation and Significant Accounting Policies Unproved Property Impairment (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment Of Unproved Oil And Gas Properties	$ 0	$ 0	$ 0	$ 827,905
TexLa region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment Of Unproved Oil And Gas Properties				416,846
Permian Basin region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment Of Unproved Oil And Gas Properties				226,922
Rockies region
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment Of Unproved Oil And Gas Properties				$ 184,137

Emergence From Voluntary Reor51

Emergence From Voluntary Reorganization Under Chapter 11 Reorganization disclosures (Details) - USD ($) $ in Thousands		1 Months Ended	2 Months Ended	3 Months Ended								10 Months Ended	12 Months Ended
		Mar. 31, 2017	Feb. 28, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016		Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Predecessor [Member]
Reorganization Items
Debtor Reorganization Items, Discharge of Claims and Liabilities			$ 3,724,750										$ 0
Debtor Reorganization Items, Provision for Expected Allowed Claims			(1,000,000)										0
Debtor Reorganization Items, Revaluation of Assets and Liabilities			(591,525)										0
Debtor Reorganization Items, Deferred Income Taxes			264,889										0
Legal and other professional advisory fees			(46,961)										(56,656)
Unamortized deferred financing fees, discounts and premiums			0										(52,045)
Gain related to interest payable on the 12.00% senior secured second lien notes due December 2020 (1)			0										551,000
Terminated contracts			(6,915)										(66,052)
Other			(13,049)										(64,648)
Reorganization items, net			2,331,189				$ (145,838)		$ (28,361)	$ 485,798	$ 0		311,599		$ 0
Liabilities Subject to Compromise
Accounts payable and accrued expenses			134,599				137,692						137,692
Accrued interest payable			144,184				144,184						144,184
Debt			4,023,129				4,023,129	[1]					4,023,129	[1]
Liabilities Subject to Compromise			$ 4,301,912				$ 4,305,005						$ 4,305,005
Successor [Member]
Reorganization Items
Debtor Reorganization Items, Discharge of Claims and Liabilities												$ 0
Debtor Reorganization Items, Provision for Expected Allowed Claims												0
Debtor Reorganization Items, Revaluation of Assets and Liabilities												0
Debtor Reorganization Items, Deferred Income Taxes												0
Legal and other professional advisory fees												(8,902)
Unamortized deferred financing fees, discounts and premiums												0
Gain related to interest payable on the 12.00% senior secured second lien notes due December 2020 (1)												0
Terminated contracts												0
Other												51
Reorganization items, net		$ (2,565)		$ (304)	$ (2,605)	$ (3,377)						(8,851)
Liabilities Subject to Compromise
Debt	[1]			0								0
Liabilities Subject to Compromise				$ 0								$ 0
[1]	The Predecessor’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016. On the Effective Date, pursuant to the terms of the Plan, all outstanding amounts under these debt instruments were canceled.

Emergence From Voluntary Reor52

Emergence From Voluntary Reorganization Under Chapter 11 Reorganization plan disclosure (Details) - USD ($)	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Percent of equity sold	49.90%
Line of Credit Facility, Maximum Borrowing Capacity		$ 500,000,000
Cash pool for unsecured claims	$ 40,000,000
bankruptcy claim amount	2,500
Successor [Member]
Debt Instrument [Line Items]
Issuances of successor Class A common stock	$ 0	0
Repayments of debt		1,090,000,000
Issuance of units (in units)	89,229,892
Rights offering [Member] | Successor [Member]
Debt Instrument [Line Items]
Issuances of successor Class A common stock	$ 530,000,000
Issuance of units (in units)	41,359,806
Line of Credit | Successor [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		500,000,000
Line of Credit Facility, Current Borrowing Capacity	$ 1,400,000,000	$ 425,000,000
Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of debt			$ 553,000,000
Revolving Line of Credit [Member] | Line of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,700,000,000
Line of Credit Facility, Current Borrowing Capacity	1,400,000,000
Term loan [Member] | Line of Credit
Debt Instrument [Line Items]
Loans Payable	300,000,000
Senior Secured Second Lien Notes Due 2020 [Member] | Senior Secured Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			12.00%
Repayments of debt	$ 30,000,000
Issuance of units (in units)	17,678,889
6.50% senior notes due May 2019 | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.50%
6.25% senior notes due November 2019 | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.25%
Issuance of units (in units)	26,724,396
Senior Notes Due April 2020 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			8.625%
Senior Notes Due February 2021 [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			7.75%
6.50% senior notes due September 2021 | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.50%
claims under $2,500 [Member]
Debt Instrument [Line Items]
Cash pool for unsecured claims	$ 2,300,000
claims over $2,500 [Member]
Debt Instrument [Line Items]
Cash pool for unsecured claims	$ 37,700,000
Commitment premium paid in cash [Member] | Successor [Member]
Debt Instrument [Line Items]
Backstop commitment premium	3.00%
Commitment premium paid in stock [Member] | Successor [Member]
Debt Instrument [Line Items]
Backstop commitment premium	1.00%

Fresh Start Accounting Fresh St

Fresh Start Accounting Fresh Start Balance Sheet (Details) - USD ($) $ in Thousands		Dec. 31, 2017		Feb. 28, 2017	Dec. 31, 2016	Dec. 31, 2015
Reorganization adjustments [Member]
Current assets:
Cash and cash equivalents				$ (679,811)
Accounts receivable – trade, net				0
Derivative instruments				0
Restricted cash				80,164
Other current assets				(15,983)
Total current assets				(615,630)
Noncurrent assets:
Oil and natural gas properties (successful efforts method)				0
Less accumulated depletion and amortization				0
Oil and Gas Property, Successful Effort Method, Net				0
Other property and equipment				0
Less accumulated depreciation				0
Property, Plant and Equipment, Other, Net				0
Derivative instruments				0
Deferred income taxes				264,889
Other noncurrent assets				151
Noncurrent assets, excluding property, total				265,040
Total noncurrent assets				265,040
Total assets				(350,590)
Current liabilities:
Accounts payable and accrued expenses				41,266
Derivative instruments				0
Current portion of long-term debt, net				(1,912,822)
Other accrued liabilities				(1,026)
Total current liabilities				(1,872,582)
Derivative instruments				0
Long-term debt				875,000
Other noncurrent liabilities				(167)
Liabilities subject to compromise				(4,301,912)
Temporary equity:
Redeemable noncontrolling interests				29,350
Stockholders’/unitholders’ equity (deficit):
Predecessor units issued and outstanding				(5,386,812)
Predecessor accumulated deficit				2,884,740
Successor Class A common stock				89
Successor additional paid-in capital				7,421,704
Successor retained earnings				0
Total stockholders’/unitholders’ equity (deficit)				4,919,721
Total liabilities and equity (deficit)				(350,590)
Fresh Start Adjustments [Member]
Current assets:
Cash and cash equivalents				0
Accounts receivable – trade, net				(7,808)
Derivative instruments				0
Restricted cash				0
Other current assets				1,780
Total current assets				(6,028)
Noncurrent assets:
Oil and natural gas properties (successful efforts method)				(11,082,258)
Less accumulated depletion and amortization				10,044,240
Oil and Gas Property, Successful Effort Method, Net				(1,038,018)
Other property and equipment				(197,653)
Less accumulated depreciation				(230,952)
Property, Plant and Equipment, Other, Net				33,299
Derivative instruments				0
Deferred income taxes				356,597
Other noncurrent assets				8,139
Noncurrent assets, excluding property, total				364,736
Total noncurrent assets				(639,983)
Total assets				(646,011)
Current liabilities:
Accounts payable and accrued expenses				(2,351)
Derivative instruments				0
Current portion of long-term debt, net				0
Other accrued liabilities				1,104
Total current liabilities				(1,247)
Derivative instruments				0
Long-term debt				0
Other noncurrent liabilities				(53,239)
Liabilities subject to compromise				0
Temporary equity:
Redeemable noncontrolling interests				0
Stockholders’/unitholders’ equity (deficit):
Predecessor units issued and outstanding				0
Predecessor accumulated deficit				4,795,287
Successor Class A common stock				0
Successor additional paid-in capital				(5,386,812)
Successor retained earnings				0
Total stockholders’/unitholders’ equity (deficit)				(591,525)
Total liabilities and equity (deficit)				(646,011)
Successor [Member]
Current assets:
Cash and cash equivalents		$ 464,508
Cash and cash equivalents				54,355
Accounts receivable – trade, net		140,485
Accounts receivable – trade, net				204,291
Derivative instruments		9,629		15,391
Restricted cash		56,445
Restricted cash				81,766
Other current assets		79,771
Other current assets				92,223
Total current assets		857,801
Total current assets				448,026
Noncurrent assets:
Oil and natural gas properties (successful efforts method)		950,083		2,186,777
Less accumulated depletion and amortization		(49,619)		0
Oil and Gas Property, Successful Effort Method, Net		900,464		2,186,777
Other property and equipment		480,729
Other property and equipment				443,933
Less accumulated depreciation		28,658
Less accumulated depreciation				0
Property, Plant and Equipment, Other, Net		452,071
Property, Plant and Equipment, Other, Net				443,933
Derivative instruments		469		4,492
Deferred income taxes		198,417
Deferred income taxes				621,486
Other noncurrent assets		6,975
Other noncurrent assets				23,293
Noncurrent assets, excluding property, total		670,787
Noncurrent assets, excluding property, total				649,271
Total noncurrent assets		2,023,322		3,279,981
Total assets		2,881,123
Total assets				3,728,007
Current liabilities:
Accounts payable and accrued expenses		253,975
Accounts payable and accrued expenses				363,500
Derivative instruments		10,103		7,361
Current portion of long-term debt, net		0	[1]	25,000
Current portion of long-term debt, net				25,000
Other accrued liabilities		58,617
Other accrued liabilities				41,329
Total current liabilities		365,997
Total current liabilities				437,190
Derivative instruments		2,849		2,116
Long-term debt		0
Long-term debt				875,000
Other noncurrent liabilities		160,720
Other noncurrent liabilities				349,370
Liabilities subject to compromise		0
Liabilities subject to compromise				0
Temporary equity:
Redeemable noncontrolling interests				29,350
Stockholders’/unitholders’ equity (deficit):
Predecessor units issued and outstanding		0		0
Predecessor accumulated deficit		0		0
Successor Class A common stock		84		89
Successor additional paid-in capital		1,899,642		2,034,892
Successor retained earnings		432,860		0
Total stockholders’/unitholders’ equity (deficit)		2,351,557		2,034,981
Total stockholders’/unitholders’ equity (deficit)				2,034,981
Total liabilities and equity (deficit)		$ 2,881,123
Total liabilities and equity (deficit)				3,728,007
Predecessor [Member]
Current assets:
Cash and cash equivalents				734,166
Cash and cash equivalents				54,355	$ 694,857	$ 1,145
Accounts receivable – trade, net				212,099
Accounts receivable – trade, net					198,064
Derivative instruments				15,391	0
Restricted cash				1,602
Restricted cash					1,602
Other current assets				106,426
Other current assets					105,310
Total current assets				1,069,684
Total current assets					1,000,534
Noncurrent assets:
Oil and natural gas properties (successful efforts method)				13,269,035	12,349,117
Less accumulated depletion and amortization				(10,044,240)	(9,843,908)
Oil and Gas Property, Successful Effort Method, Net				3,224,795	2,505,209
Other property and equipment				641,586
Other property and equipment					618,262
Less accumulated depreciation				230,952
Less accumulated depreciation					217,724
Property, Plant and Equipment, Other, Net				410,634
Property, Plant and Equipment, Other, Net					400,538
Derivative instruments				4,492	0
Deferred income taxes				0
Deferred income taxes					0
Other noncurrent assets				15,003
Other noncurrent assets					7,784
Noncurrent assets, excluding property, total				19,495
Noncurrent assets, excluding property, total					754,310
Total noncurrent assets				3,654,924	3,660,057
Total assets				4,724,608
Total assets					4,660,591
Current liabilities:
Accounts payable and accrued expenses				324,585
Accounts payable and accrued expenses					295,081
Derivative instruments				7,361	82,508
Current portion of long-term debt, net				1,937,822
Current portion of long-term debt, net	[1]				1,937,729
Other accrued liabilities				41,251
Other accrued liabilities					25,979
Total current liabilities				2,311,019
Total current liabilities					2,341,618
Derivative instruments				2,116	11,349
Long-term debt				0
Long-term debt					0
Other noncurrent liabilities				402,776
Other noncurrent liabilities					360,405
Liabilities subject to compromise				4,301,912
Liabilities subject to compromise				4,301,912	4,305,005
Temporary equity:
Redeemable noncontrolling interests				0
Stockholders’/unitholders’ equity (deficit):
Predecessor units issued and outstanding				5,386,812	5,386,885
Predecessor accumulated deficit				(7,680,027)	(7,783,873)
Successor Class A common stock				0	0
Successor additional paid-in capital				0	0
Successor retained earnings				0	0
Total stockholders’/unitholders’ equity (deficit)				(2,293,215)
Total liabilities and equity (deficit)				$ 4,724,608
Total liabilities and equity (deficit)					$ 4,660,591
[1]	Due to covenant violations, the Predecessor’s credit facility and term loan were classified as current at December 31, 2016.

Fresh Start Accounting (Details

Fresh Start Accounting (Details) - USD ($) $ in Thousands	Feb. 28, 2017	Dec. 31, 2017	[1]
Plan confirmed enterprise value	$ 2,350,000
Fresh start adjustment, increase (decrease) in asset retirement obligations noncurrent	(49,000)
Fresh start adjustment, write off of deferred rent	5,000
Fresh start adjustments, write off of carbon emissions liabilities	1,000
Successor [Member]
Plan confirmed enterprise value	2,350,000
Total stockholders’/unitholders’ equity (deficit)	2,034,981
Fair Value of Class B Units	36,505
Current portion of long-term debt, net	25,000	$ 0
Reorganization adjustments [Member]
Payment to holders of claims under the Predecessor Credit Facility	1,947,357
Current portion of long-term debt, net	(1,912,822)
Increase (decrease) in Accrued Interest Payable	(8,000)
Increase (decrease) in liability for share based compensation	7,000
Proceeds from Lines of Credit	900,000
Borrowings under the Successor’s revolving loan	600,000
Borrowings under the Successor’s term loan	300,000
Other Current Liabilities [Member] | Successor [Member]
Fair Value of Class B Units	7,000
Temporary equity [Member] | Successor [Member]
Fair Value of Class B Units	$ 29,000
[1]	Due to covenant violations, the Predecessor’s credit facility and term loan were classified as current at December 31, 2016.

Fresh Start Accounting Fresh 55

Fresh Start Accounting Fresh Start Adjustment Schedules (Details) - USD ($) $ in Thousands		Feb. 28, 2017	Mar. 31, 2017	Feb. 28, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016		Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Postconfirmation, Stockholders' Equity [Abstract]
Plan confirmed enterprise value		$ 2,350,000		$ 2,350,000
Predecessor [Member]
Cash and Cash Equivalents, Period Increase (Decrease) [Abstract]
Proceeds from rights offerings				0										$ 0		$ 224,665
Removal of restriction on cash balance				80,164										0		0
Increase (Decrease) in Accounts Payable and Accrued Liabilities [Abstract]
Increase (decrease) in accounts payable and accrued expenses				20,949										38,468		(98,223)
Liabilities Subject to Compromise
Accounts payable and accrued expenses		134,599		134,599				$ 137,692						137,692
Accrued interest payable		144,184		144,184				144,184						144,184
Liabilities Subject to Compromise, Debt and Accrued Interest		4,023,129		4,023,129				4,023,129	[1]					4,023,129	[1]
Liabilities subject to compromise		4,301,912		4,301,912				4,305,005						4,305,005
Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement				1,000,000										0
Gain on settlement of liabilities subject to compromise				(3,724,750)										0
Capital [Abstract]
Proceeds from sale of units				0										0		224,665
Unit-based compensation expenses														44,218		56,136
Cancellation of the Predecessor’s units issued and outstanding				0
Issuances of successor Class A common stock																224,665
Sale of units, net of offering costs of $8,762																224,665
Predecessor’s units issued and outstanding				0
Retained Earnings (Accumulated Deficit) [Abstract]
Recognition of gain on settlement of liabilities subject to compromise				(3,724,750)										0
Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement				1,000,000										0
Recognition of professional fees				46,961										56,656
Write-off of deferred financing fees				0										52,045
Total reorganization items, net				(2,331,189)				145,838		$ 28,361	$ (485,798)	$ 0		(311,599)		0
Share-based compensation expenses														44,218		56,136
Oil and Gas Property [Abstract]
Proved properties		12,258,835		12,258,835
Unproved properties		1,010,200		1,010,200
Oil and natural gas properties (successful efforts method)		13,269,035		13,269,035				12,349,117						12,349,117
Less accumulated depletion and amortization		10,044,240		10,044,240				9,843,908						9,843,908
Oil and Gas Property, Successful Effort Method, Net		3,224,795		3,224,795				$ 2,505,209						2,505,209
Postconfirmation, Property and Equipment, Net [Abstract]
Natural gas plants and pipelines		426,914		426,914
Office equipment and furniture		106,059		106,059
Buildings and leasehold improvements		66,023		66,023
Vehicles		30,760		30,760
Land		3,727		3,727
Drilling and other equipment		8,103		8,103
Other property and equipment		641,586		641,586
Less accumulated depreciation		230,952		230,952
Property, Plant and Equipment, Other, Net		410,634		410,634
Reorganization adjustments [Member]
Cash and Cash Equivalents, Period Increase (Decrease) [Abstract]
Borrowings under the Successor’s revolving loan		600,000
Borrowings under the Successor’s term loan		300,000
Proceeds from rights offerings		530,019
Removal of restriction on cash balance		(1,602)
Payment to holders of claims under the Predecessor Credit Facility		1,947,357
Payment to holders of claims under the Second Lien Notes		30,000
Payment of Berry’s ad valorem taxes		23,366
Payment of the rights offerings backstop commitment premium		15,900
Payment of professional fees		13,043
Funding of the professional fees escrow account		41,766
Funding of the general unsecured claims cash distribution pool		40,000
Changes in cash and cash equivalents		679,811
Increase (Decrease) in Accounts Payable and Accrued Liabilities [Abstract]
Recognition of payables for the professional fees escrow account		(41,766)
Recognition of payables for the general unsecured claims cash distribution pool		(40,000)
Payment of professional fees		(17,130)
Payment of Berry’s ad valorem taxes		23,366
Other		(4)
Increase (decrease) in accounts payable and accrued expenses		41,266
Liabilities Subject to Compromise
Liabilities subject to compromise		(4,301,912)		(4,301,912)
Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement		1,000,000
Funding of the general unsecured claims cash distribution pool		40,000
Payment to holders of claims under the Second Lien Notes		30,000
Issuance of Class A common stock to creditors		1,507,162
Gain on settlement of liabilities subject to compromise		(3,724,750)
Capital [Abstract]
Issuance of Class A common stock to creditors		1,507,162
Proceeds from sale of units		530,019
Payment of the rights offerings backstop commitment premium		15,900
Payment of issuance costs		(50)
Unit-based compensation expenses		(50,255)
Issuances of successor Class A common stock		89
Change in additional paid-in capital		7,421,704		7,421,704
Sale of units, net of offering costs of $8,762		89
Net increase in capital accounts		(2,034,981)
Retained Earnings (Accumulated Deficit) [Abstract]
Recognition of gain on settlement of liabilities subject to compromise		(3,724,750)
Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement		1,000,000
Recognition of professional fees		37,680
Write-off of deferred financing fees		16,728
Recognition of deferred income taxes		264,889
Total reorganization items, net		(2,935,231)
Share-based compensation expenses		(50,255)
Other		236
Net decrease in accumulated deficit		2,884,740
Oil and Gas Property [Abstract]
Oil and natural gas properties (successful efforts method)		0		0
Less accumulated depletion and amortization		0		0
Oil and Gas Property, Successful Effort Method, Net		0		0
Successor [Member]
Postconfirmation, Stockholders' Equity [Abstract]
Plan confirmed enterprise value		2,350,000		2,350,000
Fair value of debt		(900,000)		(900,000)
Fair value of subsequently determined tax attributes		(621,486)		(621,486)
Fair value of vested Class B units		(36,505)		(36,505)
Value of Successor’s stockholders’ equity		2,034,981		2,034,981
Cash and Cash Equivalents, Period Increase (Decrease) [Abstract]
Proceeds from rights offerings													$ 0
Removal of restriction on cash balance													(2,151)
Increase (Decrease) in Accounts Payable and Accrued Liabilities [Abstract]
Increase (decrease) in accounts payable and accrued expenses													(48,963)
Liabilities Subject to Compromise
Liabilities Subject to Compromise, Debt and Accrued Interest	[1]				$ 0								0
Liabilities subject to compromise					0								0
Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement													0
Gain on settlement of liabilities subject to compromise													0
Capital [Abstract]
Proceeds from sale of units													0
Unit-based compensation expenses													77,790
Issuances of successor Class A common stock		0											0
Sale of units, net of offering costs of $8,762		0											0
Retained Earnings (Accumulated Deficit) [Abstract]
Recognition of gain on settlement of liabilities subject to compromise													0
Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement													0
Recognition of professional fees													8,902
Write-off of deferred financing fees													0
Total reorganization items, net			$ 2,565		304	$ 2,605	$ 3,377						8,851
Share-based compensation expenses													77,790
Oil and Gas Property [Abstract]
Proved properties		1,727,834		1,727,834
Unproved properties		458,943		458,943
Oil and natural gas properties (successful efforts method)		2,186,777		2,186,777	950,083								950,083
Less accumulated depletion and amortization		0		0	49,619								49,619
Oil and Gas Property, Successful Effort Method, Net		2,186,777		2,186,777	$ 900,464								900,464
Postconfirmation, Property and Equipment, Net [Abstract]
Natural gas plants and pipelines		342,924		342,924
Office equipment and furniture		39,211		39,211
Buildings and leasehold improvements		32,817		32,817
Vehicles		16,980		16,980
Land		7,747		7,747
Drilling and other equipment		4,254		4,254
Other property and equipment		443,933		443,933
Less accumulated depreciation		0		0
Property, Plant and Equipment, Other, Net		443,933		443,933
Unitholders’ Capital
Capital [Abstract]
Unit-based compensation expenses		13,750
Retained Earnings (Accumulated Deficit) [Abstract]
Share-based compensation expenses		13,750
Unitholders’ Capital | Predecessor [Member]
Capital [Abstract]
Unit-based compensation expenses														44,218		56,136
Cancellation of the Predecessor’s units issued and outstanding				(5,386,812)
Issuances of successor Class A common stock																224,665
Sale of units, net of offering costs of $8,762																224,665
Predecessor’s units issued and outstanding				$ (5,386,812)
Retained Earnings (Accumulated Deficit) [Abstract]
Share-based compensation expenses														$ 44,218		$ 56,136
Retained Earnings | Reorganization adjustments [Member]
Capital [Abstract]
Cancellation of the Predecessor’s units issued and outstanding		5,386,812
Predecessor’s units issued and outstanding		$ 5,386,812
Retained Earnings | Successor [Member]
Capital [Abstract]
Unit-based compensation expenses													0
Issuances of successor Class A common stock													0
Sale of units, net of offering costs of $8,762													0
Retained Earnings (Accumulated Deficit) [Abstract]
Share-based compensation expenses													$ 0
[1]	The Predecessor’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016. On the Effective Date, pursuant to the terms of the Plan, all outstanding amounts under these debt instruments were canceled.

Discontinued Operations, Othe56

Discontinued Operations, Other Divestitures and Roan Contribution Discontinued Operations (Details) - USD ($) $ in Thousands	Jul. 31, 2017	Jul. 21, 2017	Feb. 28, 2017	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Predecessor [Member]
ASSETS
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment, Noncurrent						$ 728,190
Other property and equipment						11,402
Other						1,435
Total assets of discontinued operations						741,027
LIABILITIES
Asset retirement obligations			$ 26,978			38,042
Other						1,481
Total liabilities of discontinued operations						39,523
Discontinued Operations, Statements of Operations
Revenues and other			14,891			465,775	$ 727,211
Expenses			13,758			1,612,727	1,651,114
Other income and (expenses)			(1,681)			(65,022)	(81,756)
Reorganization items, net			0			(46,127)	0
Income (loss) from discontinued operations before income taxes			(548)			(1,258,101)	(1,005,659)
Income tax expense (benefit)			0			196	(68)
Income (loss) from discontinued operations, net of income taxes			(548)			(1,258,297)	(1,005,591)
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax						546,000
Successor [Member]
ASSETS
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment, Noncurrent					$ 0
LIABILITIES
Asset retirement obligations					0
Discontinued Operations, Statements of Operations
Revenues and other					34,096
Expenses					19,479
Other income and (expenses)					(3,541)
Reorganization items, net					0
Income (loss) from discontinued operations before income taxes					11,076
Income tax expense (benefit)					4,165
Income (loss) from discontinued operations, net of income taxes					6,911
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax					76,000
Discontinued Operation, Tax Effect of Gain (Loss) from Disposal of Discontinued Operation					46,000
San Joaquin Basin Sale [Member]
Discontinued Operations, Statements of Operations
Proceeds from sale of oil and natural gas property	$ 253,000
Costs Associated With Sale of Oil and Gas Property and Equipment	4,000
Gain (Loss) on Disposition of Oil and Gas Property	120,000
Los Angeles Basin Sale [Member]
Discontinued Operations, Statements of Operations
Proceeds from sale of oil and natural gas property		$ 93,000
Costs Associated With Sale of Oil and Gas Property and Equipment				$ 2,000
Gain (Loss) on Disposition of Oil and Gas Property	$ (2,000)
Contingent receivable		$ 7,000
California operating region [Member] | Predecessor [Member]
Discontinued Operations, Statements of Operations
Disposal Group, Including Discontinued Operation, Interest Expense			$ 2,000			$ 8,000	$ 4,000
California operating region [Member] | Successor [Member]
Discontinued Operations, Statements of Operations
Disposal Group, Including Discontinued Operation, Interest Expense					$ 4,000
May-June 2017 [Member]
Discontinued Operations, Statements of Operations
Contractual management fee				6,000
March-April 2017 [Member]
Discontinued Operations, Statements of Operations
Contractual management fee				$ 2,700

Discontinued Operations, Othe57

Discontinued Operations, Other Divestitures and Roan Contribution (Divestiture) (Details) - USD ($) $ in Thousands	Aug. 31, 2017	Jul. 31, 2017	Jul. 28, 2017	Jun. 30, 2017	May 31, 2017	Aug. 31, 2015	Dec. 31, 2017	Dec. 18, 2017	Dec. 31, 2016
Successor [Member]
ASSETS
Total assets held for sale							$ 106,963
Liabilities:
Total liabilities held for sale				$ 43,000			43,302
Equity method investments							$ 464,926
Predecessor [Member]
ASSETS
Total assets held for sale									$ 0
Liabilities:
Total liabilities held for sale									0
Equity method investments									$ 6,200
Howard County [Member]
Liabilities:
Costs Associated With Sale of Oil and Gas Property and Equipment						$ 1,000
Gain (Loss) on Disposition of Oil and Gas Property						177,000
Proceeds from sale of oil and natural gas property						$ 276,000
OK Waterfloods & TXPHS [Member] | Successor [Member]
ASSETS
Oil and natural gas properties				92,245
Other property and equipment				12,983
Other				1,735
Total assets held for sale				106,963
Liabilities:
Asset retirement obligations				42,001
Other				1,301
Total liabilities held for sale				43,302
Divestiture Contract Price								$ 122,000
Williston [Member] | Successor [Member]
Liabilities:
Costs Associated With Sale of Oil and Gas Property and Equipment		$ 3,000
Gain (Loss) on Disposition of Oil and Gas Property		116,000
Proceeds from sale of oil and natural gas property		255,000
Washakie [Member] | Successor [Member]
Liabilities:
Costs Associated With Sale of Oil and Gas Property and Equipment		2,000
Gain (Loss) on Disposition of Oil and Gas Property		175,000
Proceeds from sale of oil and natural gas property		193,000
South Texas region | Successor [Member]
Liabilities:
Costs Associated With Sale of Oil and Gas Property and Equipment		1,000
Gain (Loss) on Disposition of Oil and Gas Property		14,000
Proceeds from sale of oil and natural gas property		$ 48,000
Permian Basin region | Successor [Member]
Liabilities:
Gain (Loss) on Disposition of Oil and Gas Property			$ 29,000
Proceeds from sale of oil and natural gas property			$ 31,000
Salt Creek [Member] | Successor [Member]
Liabilities:
Costs Associated With Sale of Oil and Gas Property and Equipment					$ 1,000
Gain (Loss) on Disposition of Oil and Gas Property				30,000
Proceeds from sale of oil and natural gas property				$ 73,000
Jonah [Member] | Successor [Member]
Liabilities:
Costs Associated With Sale of Oil and Gas Property and Equipment					6,000
Gain (Loss) on Disposition of Oil and Gas Property					277,000
Proceeds from sale of oil and natural gas property					$ 559,000
Roan Resources LLC [Member] | Successor [Member]
Liabilities:
Costs Associated With Sale of Oil and Gas Property and Equipment	$ 17,000
Roan Resources LLC [Member] | Successor [Member]
Liabilities:
Ownership percentage	50.00%						50.00%
Equity method investments	$ 452,000						$ 458,000

Equity Method Investments (Deta

Equity Method Investments (Details) - USD ($) $ in Thousands	4 Months Ended
	Dec. 31, 2017	Aug. 31, 2017
Summarized Roan Resources LLC Statement of Operations Information
Revenues and other	$ 75,461
Expenses	61,790
Other income and (expenses)	(1,180)
Net income	12,491
Summarized Roan Resources LLC Balance Sheet Information
Current assets	27,465
Noncurrent assets	1,826,741
Total assets	1,854,206
Current liabilities	149,409
Noncurrent liabilities	97,480
Members’ equity	1,607,317
Successor [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 464,926
Successor [Member] | Roan Resources LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%	50.00%
Equity method investments	$ 458,000	$ 452,000
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 346,000

Debt (Details)

Debt (Details) $ in Thousands	Feb. 28, 2017USD ($)	Feb. 28, 2017USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2017USD ($)
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 500,000	$ 500,000
Gain (Losses) on Extinguishment of Debt excluding TDR						$ 356,000
Extinguishment of Debt, Amount						$ 927,000
Contractual Interest Expense on Prepetition Liabilities Not Recognized in Statement of Operations		$ 57,000
Loans Payable
Debt Instrument [Line Items]
Loans Payable	$ 300,000	300,000
Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line Of Credit Facility Portion Of Properties Required To Maintain Mortgages				85.00%	85.00%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage					0.50%
Debt to EBITDAX Ratio				4	4
Current Ratio				1	1
Senior Secured Notes [Member] | Senior Secured Second Lien Notes Due 2020 [Member]
Debt Instrument [Line Items]
Repayments of debt	30,000
Debt Instrument, Interest Rate, Stated Percentage						12.00%
Senior Notes [Member]
Debt Instrument [Line Items]
Repayments of debt						$ 553,000
Senior Notes [Member] | 6.50% senior notes due May 2019
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						6.50%
Extinguishment of Debt, Amount						$ 53,000
Senior Notes [Member] | 6.25% senior notes due November 2019
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						6.25%
Extinguishment of Debt, Amount						$ 395,000
Senior Notes [Member] | Senior Notes Due April 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						8.625%
Extinguishment of Debt, Amount						$ 295,000
Senior Notes [Member] | Senior Notes Due February 2021 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						7.75%
Extinguishment of Debt, Amount						$ 36,000
Senior Notes [Member] | 6.50% senior notes due September 2021
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						6.50%
Extinguishment of Debt, Amount						$ 148,000
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate					1.50%
Minimum [Member] | ABR [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate					2.50%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate					2.50%
Maximum [Member] | ABR [Member] | Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate					3.50%
Successor [Member]
Debt Instrument [Line Items]
Credit facilities				$ 0	$ 0
Repayments of debt				1,090,000
Line of credit facility, reduction in borrowing base			$ 1,000,000
Successor [Member] | Line of Credit
Debt Instrument [Line Items]
Maximum letter of credit			$ 25,000				$ 50,000
Line of Credit Facility, Maximum Borrowing Capacity				500,000	500,000
Line of Credit Facility, Current Borrowing Capacity	$ 1,400,000	$ 1,400,000		425,000	425,000
Credit facilities				0	0
Line of Credit Facility, Current Borrowing Capacity				381,000	381,000
Letters of Credit Outstanding, Amount				$ 44,000	$ 44,000

Debt Schedule of Long-Term Debt

Debt Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands		Dec. 31, 2017		Feb. 28, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Senior notes, net					$ 3,023,129
Senior secured second lien notes					$ 1,000,000
Line of Credit | Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End					5.50%
Successor [Member]
Debt Instrument [Line Items]
Credit facilities		$ 0
Total debt, net		0
Less current portion		0	[1]	$ (25,000)
Liabilities Subject to Compromise, Debt and Accrued Interest	[2]	0
Total long-term debt, net		0
Successor [Member] | Line of Credit
Debt Instrument [Line Items]
Credit facilities		$ 0
Predecessor [Member]
Debt Instrument [Line Items]
Total debt, net					$ 5,960,858
Less current portion	[1]				(1,937,729)
Liabilities Subject to Compromise, Debt and Accrued Interest				$ 4,023,129	4,023,129	[2]
Total long-term debt, net					0
Predecessor [Member] | Line of Credit
Debt Instrument [Line Items]
Credit facilities	[3]				1,654,745
Predecessor [Member] | Loans Payable
Debt Instrument [Line Items]
Term loan	[3]				284,241
Predecessor [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Net unamortized deferred financing fees					(1,257)
Predecessor [Member] | Senior Notes [Member] | 6.50% senior notes due May 2019
Debt Instrument [Line Items]
Senior notes, net					562,234
Predecessor [Member] | Senior Notes [Member] | 6.25% senior notes due November 2019
Debt Instrument [Line Items]
Senior notes, net					581,402
Predecessor [Member] | Senior Notes [Member] | 8.625% senior notes due April 2020
Debt Instrument [Line Items]
Senior notes, net					718,596
Predecessor [Member] | Senior Notes [Member] | 7.75% senior notes due February 2021
Debt Instrument [Line Items]
Senior notes, net					779,474
Predecessor [Member] | Senior Notes [Member] | 6.50% senior notes due September 2021
Debt Instrument [Line Items]
Senior notes, net					381,423
Predecessor [Member] | Senior Secured Notes [Member] | Senior Secured Second Lien Notes Due 2020 [Member]
Debt Instrument [Line Items]
Senior secured second lien notes					$ 1,000,000
[1]	Due to covenant violations, the Predecessor’s credit facility and term loan were classified as current at December 31, 2016.
[2]	The Predecessor’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016. On the Effective Date, pursuant to the terms of the Plan, all outstanding amounts under these debt instruments were canceled.
[3]	Variable interest rate of 5.50% at December 31, 2016.

Debt Debt Fair Value Disclosure

Debt Debt Fair Value Disclosure (Details) $ in Thousands	Dec. 31, 2016USD ($)
Carrying Value
Senior secured second lien notes	$ 1,000,000
Senior notes, net	3,023,129
Fair Value
Senior secured second lien notes	863,750
Senior notes, net	$ 1,179,224

Debt Debt Exchange (Details)

Debt Debt Exchange (Details) - USD ($)	1 Months Ended	12 Months Ended
	Nov. 30, 2015	Dec. 31, 2016
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	$ 2,000,000,000
Gains (Losses) on Restructuring of Debt		$ 352,000,000
Troubled Debt Restructuring, Debtor, Current Period, Gain (Loss) on Restructuring, Per Share, Net		$ 1.03
Senior Secured Notes [Member] | Senior Secured Second Lien Notes Due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 1,000,000,000
Senior Notes [Member] | 6.50% senior notes due May 2019
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	584,422,000
Senior Notes [Member] | 6.25% senior notes due November 2019
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	824,348,000
Senior Notes [Member] | 8.625% senior notes due April 2020
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	286,344,000
Senior Notes [Member] | 7.75% senior notes due February 2021
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	184,300,000
Senior Notes [Member] | 6.50% senior notes due September 2021
Debt Instrument [Line Items]
Par Value of Senior Notes Exchanged	$ 120,586,000

Derivatives (Commodity Derivati

Derivatives (Commodity Derivatives) (Details)	Sep. 30, 2017MMMBTUMBbls$ / bbl$ / MMBTU
2018 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	69,715
Average Fixed Price (in usd per energy unit) | $ / MMBTU	3.02
2018 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	548
Average Fixed Price (in usd per energy unit)	54.07
2018 | Oil Derivative Instruments | Curde Oil Sales - Collars [Member]
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	1,825
Derivative, Floor Price	50
Derivative, Cap Price	55.50
2019 | Natural Gas Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MMMBTU	11,315
Average Fixed Price (in usd per energy unit) | $ / MMBTU	2.97
2019 | Oil Derivative Instruments | Fixed price swaps
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	0
Average Fixed Price (in usd per energy unit)	0
2019 | Oil Derivative Instruments | Curde Oil Sales - Collars [Member]
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls	1,825
Derivative, Floor Price	50
Derivative, Cap Price	55.50

Derivatives (Balance Sheet Pres

Derivatives (Balance Sheet Presentation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Assets:
Commodity derivatives	$ 22,589	$ 19,369
Liabilities:
Commodity derivatives	25,443	$ 113,226
Maximum Loss Upon All Counterparties Failing To Perform	$ 23,000

Derivatives Gains (Losses) on D

Derivatives Gains (Losses) on Derivatives (Details) - USD ($) $ in Thousands

1 Months Ended

2 Months Ended

3 Months Ended

10 Months Ended

12 Months Ended

Mar. 31, 2017

Feb. 28, 2017

May 31, 2016

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Successor [Member]

Derivative [Line Items]

Derivative, Cash Received on Hedge

$ (26,793)

Gains (losses) on oil and natural gas derivatives

$ (11,959)

$ (5,725)

$ (14,497)

$ 45,714

$ 13,533

Predecessor [Member]

Derivative [Line Items]

Derivative, Cash Received on Hedge

$ 11,572

$ (860,778)

$ (1,135,319)

Cash Settlements On Derivatives including canceled derivatives

(861,000)

Settlements on Canceled Derivatives

$ 1,200,000

Gains (losses) on oil and natural gas derivatives

$ 92,691

$ (90,155)

$ 166

$ (183,794)

$ 109,453

(164,330)

$ 1,027,014

Noncash Settlements on Derivatives

$ 841,000

Fair Value Measurements on a 66

Fair Value Measurements on a Recurring Basis (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Assets:
Commodity derivatives		$ 22,589	$ 19,369
Commodity derivatives	[1]	(12,491)	(19,369)
Commodity derivatives		10,098	0
Liabilities:
Commodity derivatives		25,443	113,226
Commodity derivatives	[1]	(12,491)	(19,369)
Commodity derivatives		$ 12,952	$ 93,857
[1]	Represents counterparty netting under agreements governing such derivatives.

Other Property and Equipment (D

Other Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Successor [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 480,729
Property, Plant and Equipment, Other, Gross, inclusive of discontinued operations	480,729
Less accumulated depreciation	(28,658)
Less other property and equipment, net – discontinued operations	0
Other property and equipment, net	452,071
Successor [Member] | Natural gas plant and pipeline
Property, Plant and Equipment [Line Items]
Other property and equipment	392,999
Successor [Member] | Furniture and office equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	39,551
Successor [Member] | Buildings and leasehold improvements
Property, Plant and Equipment [Line Items]
Other property and equipment	27,301
Successor [Member] | Vehicles
Property, Plant and Equipment [Line Items]
Other property and equipment	10,811
Successor [Member] | Land
Property, Plant and Equipment [Line Items]
Other property and equipment	6,776
Successor [Member] | Drilling and other equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 3,291
Predecessor [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment		$ 618,262
Property, Plant and Equipment, Other, Gross, inclusive of discontinued operations		636,487
Less accumulated depreciation		(224,547)
Less other property and equipment, net – discontinued operations		(11,402)
Other property and equipment, net		400,538
Predecessor [Member] | Natural gas plant and pipeline
Property, Plant and Equipment [Line Items]
Other property and equipment		421,806
Predecessor [Member] | Furniture and office equipment
Property, Plant and Equipment [Line Items]
Other property and equipment		105,353
Predecessor [Member] | Buildings and leasehold improvements
Property, Plant and Equipment [Line Items]
Other property and equipment		66,014
Predecessor [Member] | Vehicles
Property, Plant and Equipment [Line Items]
Other property and equipment		31,496
Predecessor [Member] | Land
Property, Plant and Equipment [Line Items]
Other property and equipment		3,736
Predecessor [Member] | Drilling and other equipment
Property, Plant and Equipment [Line Items]
Other property and equipment		$ 8,082

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands		2 Months Ended	10 Months Ended	12 Months Ended
		Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016
Predecessor [Member]
Asset retirement obligations rollforward
Asset retirement obligations at beginning of period		$ 402,162	$ 357,397	$ 523,541
Liabilities added from drilling		146		546
Liabilities added from acquisitions		0		1,416
Liabilities associated with assets divested		0		0
Liabilities associated with assets held for sale		0		0
Deconsolidation of Berry Petroleum Company, LLC asset retirement obligations		0		141,612
Current year accretion expense		4,024		30,498
Settlements		(618)		(12,823)
Revision of estimates		0		596
Fresh start adjustment	[1]	(48,317)		0
Asset retirement obligations at end of year		357,397		402,162
Less asset retirement obligations – discontinued operations		(26,978)		(38,042)
Asset retirement obligations at beginning of period		330,419		$ 364,120
Successor [Member]
Asset retirement obligations rollforward
Asset retirement obligations at beginning of period			357,397
Liabilities added from drilling			551
Liabilities added from acquisitions			0
Liabilities associated with assets divested			(158,228)
Liabilities associated with assets held for sale			(42,001)
Deconsolidation of Berry Petroleum Company, LLC asset retirement obligations			0
Current year accretion expense			14,995
Settlements			(8,189)
Revision of estimates			28
Fresh start adjustment	[1]		0
Asset retirement obligations at end of year		$ 357,397	164,553
Less asset retirement obligations – discontinued operations			0
Asset retirement obligations at beginning of period			$ 164,553
[1]	As a result of the application of fresh start accounting, the Successor recorded its asset retirement obligations at fair value as of the Effective Date.

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 31
Loss Contingency, Estimate [Abstract]
Payments for Legal Settlements	$ 0	$ 0	$ 0

Operating Leases (Details)

Operating Leases (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Leases, Operating [Abstract]
Operating lease expense	$ 1,000	$ 6,000	$ 9,000	$ 15,000
Future Minimum Lease Payments [Abstract]
2,018		2,812
2,019		2,005
2,020		463
2,021		12
2,022		0
Thereafter		0
Operating Leases, Future Minimum Payments Due, Total		$ 5,292

Equity (Deficit) (Details)

Equity (Deficit) (Details) - USD ($)	Feb. 28, 2017	Jan. 31, 2018	Aug. 31, 2015	May 31, 2015	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 14, 2017	Oct. 04, 2017	Jun. 28, 2017	Jun. 01, 2017
Schedule of Equity Offerings [Line Items]
Common Stock, Par or Stated Value Per Share						$ 0.001	$ 0.001
Successor [Member]
Schedule of Equity Offerings [Line Items]
Shares, Outstanding						83,582,176	83,582,176
Issuance of units (in units)	89,229,892
Sale of units (in units)							42,000
Issuances of successor Class A common stock	$ 0						$ 0
Stock Repurchased and Retired During Period, Shares							5,690,000
Common Stock, Shares, Outstanding	89,229,892				89,229,892	83,582,000	83,582,000
Common Stock, Par or Stated Value Per Share	$ 0.001				$ 0.001	$ 0.001	$ 0.001
Stock Repurchased During Period, Shares						5,690,192
Accelerated Share Repurchases, Final Price Paid Per Share						$ 34.85
Accelerated Share Repurchases, Settlement (Payment) or Receipt						$ 198,000,000	$ 198,000,000
Stock Repurchase Program, Authorized Amount											$ 400,000,000	$ 200,000,000	$ 75,000,000
Payments for Repurchase of Common Stock							$ 198,288,000
Successor [Member] | Senior Secured Second Lien Notes Due 2020 [Member]
Schedule of Equity Offerings [Line Items]
Issuance of units (in units)	17,678,889
Successor [Member] | Unsecured claims [Member]
Schedule of Equity Offerings [Line Items]
Issuance of units (in units)	26,724,396
Successor [Member] | Backstop Commitment Premium [Member]
Schedule of Equity Offerings [Line Items]
Issuance of units (in units)	471,110
Successor [Member] | Backstop Commitment Agreement [Member]
Schedule of Equity Offerings [Line Items]
Issuance of units (in units)	2,995,691
Successor [Member] | Rights offering [Member]
Schedule of Equity Offerings [Line Items]
Issuance of units (in units)	41,359,806
Issuances of successor Class A common stock	$ 530,000,000
Predecessor [Member]
Schedule of Equity Offerings [Line Items]
Canceled (in units)								2,230,182
Issuances of successor Class A common stock									$ 224,665,000
Stock Repurchased and Retired During Period, Shares			191,446
Payments for Repurchase of Common Stock			$ 672,000		$ 0			$ 0	$ 0
Predecessor [Member] | At-the-Market Offering Program [Member]
Schedule of Equity Offerings [Line Items]
Equity Offering Program Maximum Value								$ 500,000,000
Sale of units (in units)								0	3,621,983
Stock issued during period, sales price per unit									$ 12.37
Issuances of successor Class A common stock									$ 44,000,000
Payment of the rights offerings backstop commitment premium									448,000
Professional Fees									$ 459,000
Predecessor [Member] | Public Offering of Units [Member]
Schedule of Equity Offerings [Line Items]
Sale of units (in units)				16,000,000
Stock issued during period, sales price per unit				$ 11.79
Public Offering Price Per Unit Net				$ 11.32
Issuances of successor Class A common stock				$ 181,000,000
Payment of the rights offerings backstop commitment premium				$ 8,000,000
Restricted Stock Units (RSUs) [Member] | Successor [Member]
Schedule of Equity Offerings [Line Items]
Vested equity awards outstanding						609,905	609,905
Unvested equity awards						2,960,304	2,960,304
Class A-2 Unit [Member] | Successor [Member]
Schedule of Equity Offerings [Line Items]
Vested equity awards outstanding						768,787	768,787
Unvested equity awards						2,306,361	2,306,361
Subsequent Event [Member] | Successor [Member]
Schedule of Equity Offerings [Line Items]
Stock Repurchased During Period, Shares		77,229,257
Subsequent Event [Member] | Restricted Stock Units (RSUs) [Member] | Successor [Member]
Schedule of Equity Offerings [Line Items]
Unvested equity awards		2,953,294
Equity awards scheduled to vest		1,165,134
Subsequent Event [Member] | Class A-2 Unit [Member] | Successor [Member]
Schedule of Equity Offerings [Line Items]
Unvested equity awards		2,820,804
Equity awards scheduled to vest		1,410,402
Tender offer [Member] | Successor [Member]
Schedule of Equity Offerings [Line Items]
Stock Repurchase Program, Authorized Amount										$ 250,000,000
Tender offer [Member] | Subsequent Event [Member] | Successor [Member]
Schedule of Equity Offerings [Line Items]
Stock Repurchased During Period, Shares		6,770,833
Accelerated Share Repurchases, Final Price Paid Per Share		$ 48
Accelerated Share Repurchases, Settlement (Payment) or Receipt		$ 325,000,000

Noncontrolling Interests (Detai

Noncontrolling Interests (Details)	Dec. 31, 2017
Noncontrolling Interest [Abstract]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	0.88%

Share-Based Compensation and 73

Share-Based Compensation and Other Benefits (Details) - USD ($) $ in Thousands	Feb. 28, 2017	Dec. 31, 2016	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Number Of Shares Issuable		0		6,600,000	6,600,000	0
Share-based Compensation Arrangement, Shares Reserved for Issuance	6,444,381		6,444,381
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant				2,800,000	2,800,000
Defined Contribution Plan, Employer Matching Contribution, Percent of Match					100.00%	100.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay					4.00%	6.00%
Defined Contribution Plan, Cost			$ 812	$ 3,000		$ 9,000	$ 11,000
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Number Of Shares Issuable				3,500,000	3,500,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 14,000			$ 2,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized				$ 49,000	$ 49,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition					2 years 1 month 29 days
Class B Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Number Of Shares Issuable				3,100,000	3,100,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 28,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized				$ 61,000	$ 61,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition					2 years 1 month 29 days
Granted (in units)	3,470,051
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	25.00%
Predecessor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense		$ 14,000	$ 50,255			$ 44,218	$ 56,136
Successor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense				$ 41,285
Successor [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in units)	2,478,606			1,340,350

Share-Based Compensation and 74

Share-Based Compensation and Other Benefits Unvested RSU rollforward (Details) - Restricted Stock Units (RSUs) [Member] - $ / shares	Feb. 28, 2017	Dec. 31, 2017
Predecessor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested units (in units)	0
Nonvested units (in dollars)	$ 0
Successor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested units (in units)	1,858,941	2,960,304
Granted (in units)	2,478,606	1,340,350
Vested (in units)	(619,665)	(51,839)
Forfeited (in units)		(187,148)
Nonvested units (in dollars)	$ 22.19	$ 24.92
Granted (in dollars)	22.19	29.29
Vested (in dollars)	$ 22.19	27.86
Forfeited (in dollars)		$ 28.38

Share-Based Compensation and 75

Share-Based Compensation and Other Benefits Share based Compensation Expense (Details) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	10 Months Ended	12 Months Ended
	Dec. 31, 2016	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Successor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense			$ 41,285
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense			9,861
Successor [Member] | General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense			41,285
Successor [Member] | Operating Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense			$ 0
Predecessor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 14,000	$ 50,255		$ 44,218	$ 56,136
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense		5,170		16,339	20,742
Predecessor [Member] | General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense		50,255		34,268	47,312
Predecessor [Member] | Operating Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense		$ 0		$ 9,950	$ 8,824

Earnings Per Share_Unit (Detail

Earnings Per Share/Unit (Details) - shares shares in Millions	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock Units (RSUs) [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average anti-dilutive unit equivalents excluded from computation of earnings per unit (in units)		0
Unit Options And Warrants [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average anti-dilutive unit equivalents excluded from computation of earnings per unit (in units)	0		1	4

Earnings Per Share_Unit EPS (De

Earnings Per Share/Unit EPS (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended							10 Months Ended	12 Months Ended
	Mar. 31, 2017	Feb. 28, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Predecessor [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income attributable to common stockholders												$ (4,762,850)
Basic weighted average units outstanding		352,792									352,653	343,323
Basic loss per unit – continuing operations		$ 6.80				$ (0.74)	$ (0.27)	$ 0.58	$ (0.61)		$ (1.04)	$ (10.94)
Basic income (loss) per unit – discontinued operations		(0.01)				(1.62)	(0.29)	0.01	(3.22)
Basic net loss per unit		$ 6.79				(2.36)	(0.56)	0.59	(3.83)		$ (6.16)	$ (13.87)
Weighted average shares/units outstanding – Diluted		352,792									352,653	343,323
Diluted loss per unit – continuing operations		$ 6.80				(0.74)	(0.27)	0.58	(0.61)		$ (1.04)	$ (10.94)
Diluted income (loss) per unit – discontinued operations		(0.01)				(1.62)	(0.29)	0.01	(3.22)
Diluted net loss per unit		$ 6.79				$ (2.36)	$ (0.56)	$ 0.59	$ (3.83)		$ (6.16)	$ (13.87)
Income (loss) from continuing operations		$ 2,397,609				$ (261,865)	$ (96,301)	$ 204,691	$ (213,868)		$ (367,343)	$ (3,754,220)
Allocated to participating securities												(3,039)
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent												(3,757,259)
Income (loss) from discontinued operations, net of income taxes		(548)				$ (572,372)	$ (102,064)	$ 3,801	$ (1,133,878)		(1,804,513)	(1,005,591)
Net loss		$ 2,397,061									$ (2,171,856)	$ (4,759,811)
Weighted Average Number of Shares Outstanding, Basic and Diluted		352,792									352,653	343,323
Income (Loss) from Continuing Operations, Per Basic and Diluted Share		$ 6.80									$ (1.04)	$ (10.94)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share		(0.01)									(5.12)	(2.93)
Earnings Per Share, Basic and Diluted		$ 6.79									$ (6.16)	$ (13.87)
Successor [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Income from continuing operations										$ 349,865
Income from discontinued operations, net of income taxes										82,995
Net income attributable to common stockholders										$ 432,860
Basic weighted average units outstanding										87,646
Basic loss per unit – continuing operations	$ (0.08)		$ 0.98	$ 0.58	$ 2.49					$ 3.99
Basic income (loss) per unit – discontinued operations	0		0	0.98	(0.04)					0.95
Basic net loss per unit	(0.08)		0.98	1.56	2.45					$ 4.94
Dilutive effect of restricted stock units										1,073
Dilutive effect of unvested Class A-2 units of Holdco										$ (2,180)
Income from continuing operations										347,685
Income from discontinued operations										82,995
Net income attributable to common stockholders										$ 430,680
Weighted average shares/units outstanding – Diluted										88,719
Diluted loss per unit – continuing operations	(0.08)		0.94	0.57	2.47					$ 3.92
Diluted income (loss) per unit – discontinued operations	0		0	0.97	(0.04)					0.93
Diluted net loss per unit	$ (0.08)		$ 0.94	$ 1.54	$ 2.43					$ 4.85
Income (loss) from continuing operations	$ (7,324)		$ 85,587	$ 51,030	$ 223,379					$ 352,672
Income (loss) from discontinued operations, net of income taxes	68		150	86,099	(3,322)					82,995
Net loss	$ (7,256)		$ 82,996	$ 137,063	$ 220,057					$ 432,860

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effective income tax rate reconciliation [Abstract]
Federal statutory rate	35.00%	35.00%		35.00%	35.00%
Federal statutory rate change	0.00%	14.30%		0.00%	0.00%
State, net of federal tax benefit	0.00%	2.60%		0.70%	0.10%
Loss excluded from nontaxable entities	(35.00%)	(0.00%)		(24.70%)	(34.70%)
Other	0.00%	0.50%		(14.10%)	(0.20%)
Effective rate	0.00%	52.40%		(3.10%)	0.20%
Deferred tax assets:
Net operating loss carryforwards		$ 14,615	$ 14,615	$ 1,730
Reorganization items		0	0	14,932
Investment in Linn Energy Holdco LLC		176,662	176,662	0
Valuation allowance		0	0	(19,558)
Other		7,140	7,140	10,030
Total deferred tax assets		198,417	198,417	7,134
Deferred tax liabilities:
Property and equipment principally due to differences in depreciation		0	0	(7,021)
Other		0	0	(279)
Total deferred tax liabilities		0	0	(7,300)
Net deferred tax assets (liabilities)		198,417	198,417
Deferred Tax Liabilities, Net				166
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount			106,000
Material Uncertain Tax Position		0	0	0
Federal [Member]
Deferred tax liabilities:
Net operating loss carryforwards		$ 60,000	$ 60,000
Net operating loss carryforwards, expiration dates			Jan. 1, 2038
Subsequent to 2017 [Member]
Effective income tax rate reconciliation [Abstract]
Federal statutory rate		21.00%
Successor [Member]
Current taxes:
Federal		$ 7,140
State		489
Deferred taxes:
Federal		366,243
State		15,070
Income tax expense (benefit)		$ 388,942
Predecessor [Member]
Current taxes:
Federal	$ 0			(494)	$ (12,021)
State	0			321	1,022
Deferred taxes:
Federal	0			11,582	8,237
State	(166)			(215)	(3,631)
Income tax expense (benefit)	$ (166)			$ 11,194	$ (6,393)

Supplemental Disclosures to t79

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Balance Sheets) (Details) - USD ($)	1 Months Ended	2 Months Ended	10 Months Ended	12 Months Ended
	Nov. 30, 2015	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other current assets
Par Value of Senior Notes Exchanged	$ 2,000,000,000
Senior Secured Second Lien Notes Due 2020 [Member] | Senior Secured Notes [Member]
Other current assets
Debt Instrument, Face Amount				$ 1,000,000,000
Predecessor [Member]
Other current assets
Prepaids				70,116,000
Accounts Receivable, Related Parties, Current				0
Inventories				15,097,000
Deferred financing fees				16,809,000
Other				3,288,000
Other current assets				105,310,000
Accrued Salaries				16,443,000
Restricted cash				1,602,000
Removal of restriction on cash balance		$ 80,164,000		0	$ 0
Par Value of Senior Notes Exchanged	$ 2,000,000,000
Noncash Settlements on Derivatives				841,000,000
Restricted cash				8,000,000
Net Outstanding Checks				6,000,000
Asset Retirement Obligation, Current				9,361,000
Deposits				0
Taxes Payable, Current				0
Other current liabilities				175,000
Other accrued liabilities				$ 25,979,000
Predecessor [Member] | Linn Energy, LLC | Senior Secured Second Lien Notes Due 2020 [Member] | Senior Secured Notes [Member]
Other current assets
Debt Instrument, Face Amount					$ 1,000,000,000
Successor [Member]
Other current assets
Prepaids			$ 46,238,000
Accounts Receivable, Related Parties, Current			23,163,000
Inventories			7,667,000
Deferred financing fees			0
Other			2,703,000
Other current assets			79,771,000
Accrued Salaries			29,089,000
Restricted cash			56,445,000
Removal of restriction on cash balance			(2,151,000)
Asset Retirement Obligation, Current			3,926,000
Deposits			15,349,000
Taxes Payable, Current			7,496,000
Other current liabilities			2,757,000
Other accrued liabilities			58,617,000
Successor [Member] | Professional fees [Member]
Other current assets
Restricted cash			36,000,000
Successor [Member] | Deposits for divestitures [Member]
Other current assets
Restricted cash			15,000,000
Successor [Member] | Other [Member]
Other current assets
Restricted cash			$ 5,000,000

Supplemental Disclosures to t80

Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows (Cash Flows) (Details) - USD ($)	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Cash payments for interest, net of amounts capitalized	$ 17,651,000	$ 15,165,000	$ 143,305,000	$ 476,077,000
Cash payments for income taxes	0	275,000	4,427,000	643,000
Cash payments for reorganization items, net	21,571,000	11,889,000	37,748,000	0
Noncash investing activities:
Accrued capital expenditures	$ 22,191,000	$ 31,447,000	31,128,000	$ 71,105,000
Senior Secured Notes [Member] | Senior Secured Second Lien Notes Due 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 1,000,000,000

Significant Customers (Details)

Significant Customers (Details) - Credit Risk [Member]	Dec. 31, 2017
Trade Accounts Receivable [Member]
Concentration Risk [Line Items]
Total Number Of Largest Customers Represented In Sales	0
Sales [Member]
Concentration Risk [Line Items]
Total Number Of Largest Customers Represented In Sales	0

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended		12 Months Ended
	Sep. 30, 2017	Feb. 28, 2017	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Sep. 30, 2014
Related Party Transaction [Line Items]
Notes Payable, Related Parties								$ 352,000
Payments for Advance to Affiliate			$ 129,000	$ 58,000			$ 223,000
Proceeds from Contributions from Affiliates					$ 0	$ 89,000
Roan Resources LLC [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Other Revenues from Transactions with Related Party	$ 23,000
Ownership percentage					50.00%
Related party monthly fee	$ 1,250
Due to Related Parties, Current					$ 18,000
LinnCo
Related Party Transaction [Line Items]
Ownership percentage					71.00%
General and administrative expenses		$ 287			$ 6,100	3,400
General and administrative expenses paid on behalf of related party					5,900
Distributions to unitholders						121,000
Related party transaction, amounts of transaction		240			2,400	2,000
Berry
Related Party Transaction [Line Items]
Related Party Transaction, Other Revenues from Transactions with Related Party		$ 6,000			69,000	78,000
Investment in discontinued operations					0	471,000
Noncash investment in affiliate						250,000
Director
Related Party Transaction [Line Items]
Related party transaction, amounts of transaction					5,000	$ 8,000
Accounts Payable [Member] | Berry
Related Party Transaction [Line Items]
Due to Related Parties, Current					3,000
Liabilities subject to compromise [Member] | Berry
Related Party Transaction [Line Items]
Due to Related Parties, Current					$ 25,000

Supplemental Oil and Natural 83

Supplemental Oil and Natural Gas Data (Unaudited) (Details) Mcfe in Millions, Mcf in Millions, MMBbls in Millions		1 Months Ended	2 Months Ended	3 Months Ended								4 Months Ended		10 Months Ended		12 Months Ended
		Mar. 31, 2017USD ($)	Feb. 28, 2017USD ($)McfeMMBblsMcf	Dec. 31, 2017USD ($)McfeMMBblsMcf		Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2016USD ($)McfeMMBblsMcf	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)McfeMMBblsMcf	Dec. 31, 2017USD ($)McfeMMBblsMcf		Dec. 31, 2017USD ($)McfeMMBblsMcf		Dec. 31, 2017USD ($)Mcfe$ / bbl$ / MMBTUMMBblsMcf		Dec. 31, 2016USD ($)Mcfe$ / bbl$ / MMBTUMMBblsMcf	Dec. 31, 2015USD ($)Mcfe$ / bbl$ / MMBTUMMBblsMcf	Dec. 31, 2014McfeMMBblsMcf	Aug. 31, 2017USD ($)
Property acquisition costs:
Proved			$ 0											$ 0				$ 0	$ 0
Unproved			0											0				0	0
Exploration costs			15,153,000											103,689,000				40,074,000	19,929,000
Development costs			24,256,000											96,178,000				86,053,000	264,227,000
Asset retirement costs			312,000											376,000				112,000	3,331,000
Total costs incurred – continuing operations			39,721,000											200,243,000				126,239,000	287,487,000
Total costs incurred – discontinued operations			$ 269											$ 1,313				$ 11,453	$ 167,049
Proved developed and undeveloped reserves:
Beginning of year | Mcfe			3,350								3,240					3,350		3,240	5,318
Beginning of year | Mcfe			170								1,248					170		1,248	1,986
Beginning of year | Mcfe			3,520								4,488					3,520		4,488	7,304
Revisions of previous estimates | Mcfe																(78)		(16)	(1,743)
Revisions of previous estimates | Mcfe																0		(192)	(636)
Revisions of previous estimates | Mcfe																(78)		(208)	(2,379)
Sales of minerals in place | Mcfe																(1,213)			(50)
Sales of minerals in place | Mcfe																(164)			0
Sales of minerals in place | Mcfe																1,377			50
Extensions and discoveries | Mcfe																142		417	32
Extensions and discoveries | Mcfe																0		11	15
Extensions and discoveries | Mcfe																(142)		(428)	(47)
Production | Mcfe																(233)		(291)	(317)
Production | Mcfe																(6)		(93)	(117)
Production | Mcfe																(239)		(384)	(434)
Deconsolidation of Berry Petroleum, LLC proved reserves | Mcfe																		0
Deconsolidation of Berry Petroleum, LLC proved reserves | Mcfe																		804
Deconsolidation of Berry Petroleum, LLC proved reserves | Mcfe																		804
End of year | Mcfe				1,968				3,350				1,968		1,968		1,968		3,350	3,240	5,318
End of year | Mcfe				0				170				0		0		0		170	1,248	1,986
End of year | Mcfe				1,968				3,520				1,968		1,968		1,968		3,520	4,488	7,304
Proved developed reserves:
Beginning of year | Mcfe			3,084								3,240					3,084		3,240	4,312
Beginning of year | Mcfe			170								1,248					170		1,248	1,506
Beginning of year | Mcfe			3,254								4,488					3,254		4,488	5,818
End of year | Mcfe				1,908				3,084				1,908		1,908		1,908		3,084	3,240	4,312
End of year | Mcfe				0				170				0		0		0		170	1,248	1,506
End of year | Mcfe				1,908				3,254				1,908		1,908		1,908		3,254	4,488	5,818
Proved undeveloped reserves:
Beginning of year | Mcfe			266								0					266		0	1,006
Beginning of year | Mcfe			0								0					0		0	480
Beginning of year | Mcfe			266								0					266		0	1,486
End of year | Mcfe				60				266				60		60		60		266	0	1,006
End of year | Mcfe				0				0				0		0		0		0	0	480
End of year | Mcfe				60				266				60		60		60		266	0	1,486
Conversion rate between oil and NGL volumes to natural gas																		6
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | Mcfe																(1,382)		(110)	0
Change in proved reserves due to change in commodity prices (in Mcfe) | Mcfe																		186	97	(23)
Change in proved reserves due to the SEC five-year development limitation on PUDs | Mcfe																			237	1,332
Change in proved reserves due to the uncertainty of future capital commitments | Mcfe																			(197)
Change in proved reserves due to asset performance (in Mcfe) | Mcfe																		(264)	81
Productive wells drilled																90		211	0
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows				$ 6,730,186,000				$ 9,856,698,000				$ 6,730,186,000		$ 6,730,186,000		$ 6,730,186,000		$ 9,856,698,000	$ 10,396,598,000
Future production costs				(3,810,932,000)				(5,755,460,000)				(3,810,932,000)		(3,810,932,000)		(3,810,932,000)		(5,755,460,000)	(6,576,424,000)
Future development costs				(486,989,000)				(917,262,000)				(486,989,000)		(486,989,000)		(486,989,000)		(917,262,000)	(722,685,000)
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Income Tax Expense				(303,803,000)				0				(303,803,000)		(303,803,000)		(303,803,000)		0	0
Future net cash flows				2,128,462,000				3,183,976,000				2,128,462,000		2,128,462,000		2,128,462,000		3,183,976,000	3,097,489,000
10% annual discount for estimated timing of cash flows				(1,083,331,000)				(1,488,219,000)				(1,083,331,000)		(1,083,331,000)		(1,083,331,000)		(1,488,219,000)	(1,404,304,000)
Standardized measure of discounted future net cash flows – continuing operations				1,045,131,000				1,695,757,000				1,045,131,000		1,045,131,000		1,045,131,000		1,695,757,000	1,693,185,000
Standardized measure of discounted future net cash flows – discontinued operations				$ 0				$ 232,941,000				$ 0		$ 0		$ 0		$ 232,941,000	$ 1,340,360,000
Representative NYMEX prices: (1)
Natural gas (MMBtu) | $ / MMBTU	[1]															2.98	[2]	2.48	2.59
Oil (Bbl) | $ / bbl	[1]															51.34	[2]	42.64	50.16
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Sales and transfers of oil, natural gas and NGL produced during the period																$ (438,775,000)		$ (349,080,000)	$ (448,963,000)
Changes in estimated future development costs																(5,276,000)		19,460,000	953,393,000
Net change in sales and transfer prices and production costs related to future production																400,411,000		(92,236,000)	(5,313,449,000)
Sales of minerals in place																685,050,000		0	97,785,000
Extensions, discoveries and improved recovery																187,223,000		221,765,000	46,487,000
Previously estimated development costs incurred during the period																9,704,000		0	84,329,000
Net change due to revisions in quantity estimates																65,935,000		(10,387,000)	939,030,000
Net change in income taxes																(155,257,000)		0	0
Accretion of discount																169,576,000		169,318,000	707,085,000
Changes in production rates and other																(67,247,000)		22,958,000	(369,736,000)
Change – continuing operations																(650,626,000)		2,572,000	(5,377,669,000)
Change – discontinued operations																$ (232,941,000)		$ (1,107,419,000)	$ (4,101,077,000)
Natural Gas (Bcf)
Proved developed and undeveloped reserves:
Beginning of year | Mcf			2,290								2,212					2,290		2,212	3,552
Revisions of previous estimates | Mcf																(102)		0	(1,137)
Sales of minerals in place | Mcf																(754)			(13)
Extensions and discoveries | Mcf																90		265	10
Production | Mcf																(147)		(187)	(200)
Deconsolidation of Berry Petroleum, LLC proved reserves | Mcf																			0
End of year | Mcf				1,377				2,290				1,377		1,377		1,377		2,290	2,212	3,552
Proved developed reserves:
Beginning of year | Mcf			2,118								2,212					2,118		2,212	2,981
End of year | Mcf				1,323				2,118				1,323		1,323		1,323		2,118	2,212	2,981
Proved undeveloped reserves:
Beginning of year | Mcf			172								0					172		0	571
End of year | Mcf				54				172				54		54		54		172	0	571
Oil (MMBbls)
Proved developed and undeveloped reserves:
Beginning of year | MMBbls			72.6								74.3					72.6		74.3	147.8
Revisions of previous estimates | MMBbls																(5.6)		(3.8)	(62.4)
Sales of minerals in place | MMBbls																(37)			(4.1)
Extensions and discoveries | MMBbls																3.7		10.1	3
Production | MMBbls																(6.6)		(8)	(10)
Deconsolidation of Berry Petroleum, LLC proved reserves | Mcf																			0
End of year | MMBbls				27.1				72.6				27.1		27.1		27.1		72.6	74.3	147.8
Proved developed reserves:
Beginning of year | MMBbls			66.7								74.3					66.7		74.3	104.2
End of year | MMBbls				27				66.7				27		27		27		66.7	74.3	104.2
Proved undeveloped reserves:
Beginning of year | MMBbls			5.9								0					5.9		0	43.6
End of year | MMBbls				0.1				5.9				0.1		0.1		0.1		5.9	0	43.6
NGL (MMBbls)
Proved developed and undeveloped reserves:
Beginning of year | MMBbls			104.1								97					104.1		97	146.3
Revisions of previous estimates | MMBbls																9.7		1.2	(38.7)
Sales of minerals in place | MMBbls																(39.6)			(2)
Extensions and discoveries | MMBbls																4.9		15.2	0.8
Production | MMBbls																(7.6)		(9.3)	(9.4)
Deconsolidation of Berry Petroleum, LLC proved reserves | Mcf																			0
End of year | MMBbls				71.5				104.1				71.5		71.5		71.5		104.1	97	146.3
Proved developed reserves:
Beginning of year | MMBbls			94.4								97					94.4		97	117.5
End of year | MMBbls				70.5				94.4				70.5		70.5		70.5		94.4	97	117.5
Proved undeveloped reserves:
Beginning of year | MMBbls			9.7								0					9.7		0	28.8
End of year | MMBbls				1				9.7				1		1		1		9.7	0	28.8
Equity Method Investee [Member]
Property acquisition costs:
Proved												$ 0
Unproved												6,851,000
Exploration costs												3,626,000
Development costs												89,585,000
Total costs incurred – continuing operations												100,062,000
Oil and Natural Gas Capitalized Costs
Proved properties	[3]			$ 400,682,000								400,682,000		$ 400,682,000		$ 400,682,000
Unproved properties	[3]			538,703,000								538,703,000		538,703,000		538,703,000
Capitalized cost, oil and gas producing activities	[3]			939,385,000								939,385,000		939,385,000		939,385,000
Less accumulated depletion and amortization	[3]			(28,441,000)								(28,441,000)		(28,441,000)		(28,441,000)
Capitalized costs, oil and gas producing activities, net	[3]			$ 910,944,000								$ 910,944,000		$ 910,944,000		$ 910,944,000
Proved developed and undeveloped reserves:
Beginning of year | Mcfe			342													342
Revisions of previous estimates | Mcfe																(42)
Sales of minerals in place | Mcfe																403
Extensions and discoveries | Mcfe																(9)
End of year | Mcfe				694				342				694		694		694		342
Proved developed reserves:
Beginning of year | Mcfe			169													169
End of year | Mcfe				239				169				239		239		239		169
Proved undeveloped reserves:
Beginning of year | Mcfe			173													173
End of year | Mcfe				455				173				455		455		455		173
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows	[4]			$ 2,635,233,000								$ 2,635,233,000		$ 2,635,233,000		$ 2,635,233,000
Future production costs	[4]			(832,362,000)								(832,362,000)		(832,362,000)		(832,362,000)
Future development costs	[4]			(372,884,000)								(372,884,000)		(372,884,000)		(372,884,000)
Future net cash flows	[4]			1,429,987,000								1,429,987,000		1,429,987,000		1,429,987,000
10% annual discount for estimated timing of cash flows	[4]			(832,152,000)								(832,152,000)		(832,152,000)		(832,152,000)
Standardized measure of discounted future net cash flows – continuing operations	[5]			$ 597,835,000	[4]							597,835,000	[4]	$ 597,835,000	[4]	$ 597,835,000	[4]				$ 304,900,000
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Sales and transfers of oil, natural gas and NGL produced during the period	[5]											(32,618,000)
Changes in estimated future development costs	[5]											(14,617,000)
Net change in sales and transfer prices and production costs related to future production	[5]											33,912,000
Extensions, discoveries and improved recovery	[5]											270,737,000
Previously estimated development costs incurred during the period	[5]											89,457,000
Net change due to revisions in quantity estimates	[5]											47,222,000
Accretion of discount	[5]											10,163,000
Changes in production rates and other	[5]											(16,877,000)
Change – continuing operations	[5]											$ 292,935,000
Equity Method Investee [Member] | Natural Gas (Bcf)
Proved developed and undeveloped reserves:
Beginning of year | Mcf			173													173
Revisions of previous estimates | Mcf																(14)
Extensions and discoveries | Mcf																189
Production | Mcf																(5)
End of year | Mcf				343				173				343		343		343		173
Proved developed reserves:
Beginning of year | Mcf			95													95
End of year | Mcf				130				95				130		130		130		95
Proved undeveloped reserves:
Beginning of year | Mcf			78													78
End of year | Mcf				213				78				213		213		213		78
Equity Method Investee [Member] | Oil (MMBbls)
Proved developed and undeveloped reserves:
Beginning of year | MMBbls			10.3													10.3
Revisions of previous estimates | MMBbls																(2.6)
Extensions and discoveries | MMBbls																11.4
Production | MMBbls																(0.4)
End of year | MMBbls				18.7				10.3				18.7		18.7		18.7		10.3
Proved developed reserves:
Beginning of year | MMBbls			4.5													4.5
End of year | MMBbls				6.2				4.5				6.2		6.2		6.2		4.5
Proved undeveloped reserves:
Beginning of year | MMBbls			5.8													5.8
End of year | MMBbls				12.5				5.8				12.5		12.5		12.5		5.8
Equity Method Investee [Member] | NGL (MMBbls)
Proved developed and undeveloped reserves:
Beginning of year | MMBbls			17.8													17.8
Revisions of previous estimates | MMBbls																(1.9)
Extensions and discoveries | MMBbls																24.3
Production | MMBbls																(0.4)
End of year | MMBbls				39.8				17.8				39.8		39.8		39.8		17.8
Proved developed reserves:
Beginning of year | MMBbls			7.9													7.9
End of year | MMBbls				12				7.9				12		12		12		7.9
Proved undeveloped reserves:
Beginning of year | MMBbls			9.9													9.9
End of year | MMBbls				27.8				9.9				27.8		27.8		27.8		9.9
Successor [Member]
Oil and Natural Gas Capitalized Costs
Proved properties				$ 904,390,000								$ 904,390,000		$ 904,390,000		$ 904,390,000
Unproved properties				45,693,000								45,693,000		45,693,000		45,693,000
Capitalized cost, oil and gas producing activities				950,083,000								950,083,000		950,083,000		950,083,000
Less accumulated depletion and amortization				(49,619,000)								(49,619,000)		(49,619,000)		(49,619,000)
Proved oil and gas properties, inclusive of discontinued operations				900,464,000								900,464,000		900,464,000		900,464,000
Less oil and natural gas capitalized costs, net – discontinued operations				0								0		0		0
Capitalized costs, oil and gas producing activities, net				900,464,000								$ 900,464,000		900,464,000		$ 900,464,000
Revenues and other:
Oil, natural gas and natural gas liquids sales														709,363,000
Gains (losses) on oil and natural gas derivatives		$ (11,959,000)		$ (5,725,000)		$ (14,497,000)	$ 45,714,000							13,533,000
Results of Operations, Revenue from Oil and Gas Producing Activities														722,896,000
Production costs:
Lease operating expenses														208,446,000
Transportation expenses														113,128,000
Severance taxes, ad valorem taxes and California carbon allowances														47,411,000
Results of Operations, Expense from Oil and Gas Producing Activities														368,985,000
Other costs:
Exploration costs														3,137,000
Depletion and amortization														101,360,000
Impairment of long-lived assets														0
(Gains) losses on sale of assets and other, net														(678,200,000)
Income tax benefit														(4,640,000)
Total other costs														(578,343,000)
Results of operations – continuing operations														932,254,000
Results of operations – discontinued operations														142,175,000
Successor [Member] | Equity Method Investee [Member]
Revenues and other:
Oil, natural gas and natural gas liquids sales	[6]													42,322,000
Gains (losses) on oil and natural gas derivatives	[6]													(4,591,000)
Results of Operations, Revenue from Oil and Gas Producing Activities	[6]													37,731,000
Production costs:
Lease operating expenses	[6]													4,102,000
Transportation expenses	[6]													4,576,000
Severance taxes, ad valorem taxes and California carbon allowances	[6]													1,026,000
Results of Operations, Expense from Oil and Gas Producing Activities	[6]													9,704,000
Other costs:
Exploration costs	[6]													3,626,000
Depletion and amortization	[6]													11,371,000
Total other costs	[6]													14,997,000
Results of operations – continuing operations	[6]													$ 13,030,000
Predecessor [Member]
Oil and Natural Gas Capitalized Costs
Proved properties								$ 12,234,099,000										$ 12,234,099,000
Unproved properties								998,860,000										998,860,000
Capitalized cost, oil and gas producing activities								13,232,959,000										13,232,959,000
Less accumulated depletion and amortization								(9,999,560,000)										(9,999,560,000)
Proved oil and gas properties, inclusive of discontinued operations								3,233,399,000										3,233,399,000
Less oil and natural gas capitalized costs, net – discontinued operations								(728,190,000)										(728,190,000)
Capitalized costs, oil and gas producing activities, net								2,505,209,000										2,505,209,000
Revenues and other:
Oil, natural gas and natural gas liquids sales			$ 188,885,000															874,161,000	$ 1,065,795,000
Gains (losses) on oil and natural gas derivatives			92,691,000					$ (90,155,000)	$ 166,000	$ (183,794,000)	$ 109,453,000							(164,330,000)	1,027,014,000
Results of Operations, Revenue from Oil and Gas Producing Activities			281,576,000															709,831,000	2,092,809,000
Production costs:
Lease operating expenses			49,665,000															296,891,000	352,077,000
Transportation expenses			25,972,000															161,574,000	167,023,000
Severance taxes, ad valorem taxes and California carbon allowances			14,851,000															66,616,000	97,732,000
Results of Operations, Expense from Oil and Gas Producing Activities			90,488,000															525,081,000	616,832,000
Other costs:
Exploration costs			93,000															4,080,000	9,473,000
Depletion and amortization			39,689,000															295,889,000	471,046,000
Impairment of long-lived assets			0															165,044,000	4,960,144,000
(Gains) losses on sale of assets and other, net			18,000															417,000	(199,296,000)
Income tax benefit			(166,000)															(649,000)	(2,721,000)
Total other costs			39,634,000															464,781,000	5,238,646,000
Results of operations – continuing operations			151,454,000															(280,031,000)	(3,762,669,000)
Results of operations – discontinued operations			$ 1,246,000															$ (1,076,407,000)	$ (844,754,000)
[1]	In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.
[2]	In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves.
[3]	Represents the Company’s 50% equity interest in Roan.
[4]	Represents the Company’s 50% equity interest in Roan.
[5]	Represents the Company’s 50% equity interest in Roan. Changes in the standardized measure of discounted future net cash flows of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017.
[6]	Represents the Company’s 50% equity interest in Roan. Results of oil and natural gas producing activities of Roan for 2017 is for the period from September 1, 2017 through December 31, 2017.

Supplemental Quarterly Data (84

Supplemental Quarterly Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands		Feb. 28, 2017	Mar. 31, 2017	Feb. 28, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Predecessor [Member]
Oil, natural gas and natural gas liquids sales				$ 188,885				$ 255,887	$ 237,986	$ 195,847	$ 184,441		$ 874,161	$ 1,065,795
Gains (losses) on oil and natural gas derivatives				92,691				(90,155)	166	(183,794)	109,453		(164,330)	1,027,014
Total revenues and other				298,127				197,163	266,975	44,245	331,261		839,644	2,234,456
Total expenses	[1]			214,327				269,906	310,772	274,941	449,809
(Gains) losses on sale of assets and other, net				829				9,650	2,532	2,607	1,468		16,257	(194,805)
Reorganization items, net				2,331,189				(145,838)	(28,361)	485,798	0		311,599	0
Income (loss) from continuing operations				2,397,609				(261,865)	(96,301)	204,691	(213,868)		(367,343)	(3,754,220)
Income (loss) from discontinued operations, net of income taxes				(548)				(572,372)	(102,064)	3,801	(1,133,878)		(1,804,513)	(1,005,591)
Net income (loss)				2,397,061				$ (834,237)	$ (198,365)	$ 208,492	$ (1,347,746)		(2,171,856)	(4,759,811)
Net loss				2,397,061									(2,171,856)	(4,759,811)
Net income attributable to noncontrolling interests				$ 0									$ 0	$ 0
Income (loss) per share/unit – continuing operations:
Basic loss per unit – continuing operations				$ 6.80				$ (0.74)	$ (0.27)	$ 0.58	$ (0.61)		$ (1.04)	$ (10.94)
Diluted loss per unit – continuing operations				6.80				(0.74)	(0.27)	0.58	(0.61)		(1.04)	(10.94)
Income (loss) per unit – discontinued operations:
Basic income (loss) per unit – discontinued operations				(0.01)				(1.62)	(0.29)	0.01	(3.22)
Diluted income (loss) per unit – discontinued operations				(0.01)				(1.62)	(0.29)	0.01	(3.22)
Net income (loss) per share/unit:
Basic net loss per unit				6.79				(2.36)	(0.56)	0.59	(3.83)		(6.16)	(13.87)
Diluted net loss per unit				$ 6.79				$ (2.36)	$ (0.56)	$ 0.59	$ (3.83)		$ (6.16)	$ (13.87)
Successor [Member]
Oil, natural gas and natural gas liquids sales			$ 80,325		$ 179,553	$ 206,318	$ 243,167					$ 709,363
Gains (losses) on oil and natural gas derivatives			(11,959)		(5,725)	(14,497)	45,714					13,533
Total revenues and other			73,308		208,869	236,682	307,819					826,678
Total expenses	[1]		78,349		191,491	202,143	220,548
(Gains) losses on sale of assets and other, net			484		(289,701)	(26,977)	(306,878)					(623,072)
Reorganization items, net			(2,565)		(304)	(2,605)	(3,377)					(8,851)
Income (loss) from continuing operations			(7,324)		85,587	51,030	223,379					352,672
Income (loss) from discontinued operations, net of income taxes			68		150	86,099	(3,322)					82,995
Net income (loss)			(7,256)		85,737	137,129	220,057					435,667
Net loss			(7,256)		82,996	137,063	220,057					432,860
Net income attributable to noncontrolling interests			$ 0		$ 2,741	$ 66	$ 0					$ 2,807
Income (loss) per share/unit – continuing operations:
Basic loss per unit – continuing operations			$ (0.08)		$ 0.98	$ 0.58	$ 2.49					$ 3.99
Diluted loss per unit – continuing operations			(0.08)		0.94	0.57	2.47					3.92
Income (loss) per unit – discontinued operations:
Basic income (loss) per unit – discontinued operations			0		0	0.98	(0.04)					0.95
Diluted income (loss) per unit – discontinued operations			0		0	0.97	(0.04)					0.93
Net income (loss) per share/unit:
Basic net loss per unit			(0.08)		0.98	1.56	2.45					4.94
Diluted net loss per unit			$ (0.08)		$ 0.94	$ 1.54	$ 2.43					$ 4.85
Successor [Member] | Unproved Property [Member]
Net income (loss) per share/unit:
Quantifying Misstatement in Current Year Financial Statements, Amount		$ 459,000
Successor [Member] | Depletion Expense [Member]
Net income (loss) per share/unit:
Quantifying Misstatement in Current Year Financial Statements, Amount						$ 8,000
Successor [Member] | Gain on sale of assets [Member]
Net income (loss) per share/unit:
Quantifying Misstatement in Current Year Financial Statements, Amount						1,000
Successor [Member] | Income from continuing operations, net of income taxes [Member]
Net income (loss) per share/unit:
Quantifying Misstatement in Current Year Financial Statements, Amount						5,000
Successor [Member] | Income from discontinued operations, net of income taxes [Member]
Net income (loss) per share/unit:
Quantifying Misstatement in Current Year Financial Statements, Amount						$ 8,000
[1]	Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes.