Pressburg (ROAN) 10-Q 8 Aug 18 2018 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 31, 2018
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Amendment Flag	false
Entity Registrant Name	Linn Energy, Inc.
Entity Central Index Key	1,326,428
Current Fiscal Year End	--12-31
Entity Current Reporting Status	No
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		78,449,265
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 301,365	$ 464,508
Accounts receivable – trade, net	64,686	140,485
Derivative instruments	3,934	9,629
Restricted cash	43,387	56,445
Other current assets	46,659	79,771
Assets held for sale	22	106,963
Total current assets	460,053	857,801
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	785,815	950,083
Less accumulated depletion and amortization	(59,870)	(49,619)
Oil and natural gas properties, successful efforts method, net	725,945	900,464
Other property and equipment	566,861	480,729
Less accumulated depreciation	(44,412)	(28,658)
Other property and equipment, net	522,449	452,071
Derivative instruments	1,254	469
Deferred income taxes	169,691	198,417
Equity method investments	473,269	464,926
Other noncurrent assets	5,264	6,975
Noncurrent assets, excluding property, total	649,478	670,787
Total noncurrent assets	1,897,872	2,023,322
Total assets	2,357,925	2,881,123
Current liabilities:
Accounts payable and accrued expenses	179,887	253,975
Share-based payment liability	111,792	0
Derivative instruments	5,536	10,103
Other accrued liabilities	19,830	58,617
Liabilities held for sale	0	43,302
Total current liabilities	317,045	365,997
Derivative instruments	24	2,849
Asset retirement obligations and other noncurrent liabilities	105,531	160,720
Total noncurrent liabilities	105,555	163,569
Commitments and contingencies (Note 11)
Equity:
Preferred stock ($0.001 par value, 30,000,000 shares authorized; no shares issued at June 30, 2018, or December 31, 2017)	0	0
Class A common stock ($0.001 par value, 270,000,000 shares authorized; 78,749,510 shares and 83,582,176 shares issued at June 30, 2018, and December 31, 2017, respectively)	79	84
Additional paid-in capital	1,427,458	1,899,642
Retained earnings	507,788	432,860
Total common stockholders’ equity	1,935,325	2,332,586
Noncontrolling interests	0	18,971
Total equity	1,935,325	2,351,557
Total liabilities and equity	$ 2,357,925	$ 2,881,123

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common stock par value	$ 0.001	$ 0.001
Common stock authorized	270,000,000	270,000,000
Common stock issued	78,749,510	83,582,176
Preferred stock par value	$ 0.001	$ 0.001
Preferred stock authorized	30,000,000	30,000,000
Preferred stock issued	0	0

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Successor
Revenues and other:
Oil, natural gas and natural gas liquids sales		$ 87,004	$ 243,167	$ 323,492	$ 223,880
Gains (losses) on oil and natural gas derivatives		(7,525)	45,714	33,755	(22,555)
Marketing revenues		42,967	12,547	15,461	89,234
Other revenues		6,387	6,391	8,419	12,281
Total revenues		128,833	307,819	381,127	302,840
Expenses:
Lease operating expenses		24,088	71,057	95,687	71,972
Transportation expenses		21,213	37,388	51,111	40,307
Marketing expenses		40,327	6,976	9,515	82,082
General and administrative expenses		92,395	34,458	44,869	137,174
Exploration costs		53	811	866	1,255
Depreciation, depletion and amortization		21,980	51,987	71,901	50,445
Taxes, other than income taxes		7,297	17,871	24,948	15,749
(Gains) losses on sale of assets and other, net		(101,777)	(306,878)	(306,394)	(207,852)
Total expenses		105,576	(86,330)	(7,497)	191,132
Other income and (expenses):
Interest expense, net of amounts capitalized		(584)	(7,551)	(11,751)	(988)
Earnings (losses) from equity method investments		(9,327)	91	130	16,018
Other, net		538	(1,163)	(1,551)	369
Total other income and (expenses)		(9,373)	(8,623)	(13,172)	15,399
Reorganization items, net		(1,259)	(3,377)	(5,942)	(3,210)
Income (loss) from continuing operations before income taxes		12,625	382,149	369,510	123,897
Income tax expense (benefit)		5,722	158,770	153,455	45,896
Income (loss) from continuing operations		6,903	223,379	216,055	78,001
Income (loss) from discontinued operations, net of income taxes		0	(3,322)	(3,254)	0
Net income (loss)		6,903	220,057	212,801	78,001
Net income attributable to noncontrolling interests		1,799	0	0	3,073
Net income (loss) attributable to common stockholders/unitholders		$ 5,104	$ 220,057	$ 212,801	$ 74,928
Income (loss) from continuing operations per share/unit – Basic		$ 0.06	$ 2.49	$ 2.41	$ 0.95
Income (loss) from continuing operations per share/unit – Diluted		0.06	2.47	2.40	0.93
Income (loss) from discontinued operations per share/unit – Basic		0	(0.04)	(0.04)	0
Income (loss) from discontinued operations per share/unit – Diluted		0	(0.04)	(0.04)	0
Net income (loss) per share/unit – Basic		0.06	2.45	2.37	0.95
Net income (loss) per share/unit – Diluted		$ 0.06	$ 2.43	$ 2.36	$ 0.93
Weighted average shares/units outstanding – Basic		78,718	89,849	89,849	78,817
Weighted average shares/units outstanding – Diluted		79,277	90,484	90,065	79,764
Predecessor
Revenues and other:
Oil, natural gas and natural gas liquids sales	$ 188,885
Gains (losses) on oil and natural gas derivatives	92,691
Marketing revenues	6,636
Other revenues	9,915
Total revenues	298,127
Expenses:
Lease operating expenses	49,665
Transportation expenses	25,972
Marketing expenses	4,820
General and administrative expenses	71,745
Exploration costs	93
Depreciation, depletion and amortization	47,155
Taxes, other than income taxes	14,877
(Gains) losses on sale of assets and other, net	829
Total expenses	215,156
Other income and (expenses):
Interest expense, net of amounts capitalized	(16,725)
Earnings (losses) from equity method investments	157
Other, net	(149)
Total other income and (expenses)	(16,717)
Reorganization items, net	2,331,189
Income (loss) from continuing operations before income taxes	2,397,443
Income tax expense (benefit)	(166)
Income (loss) from continuing operations	2,397,609
Income (loss) from discontinued operations, net of income taxes	(548)
Net income (loss)	2,397,061
Net income attributable to noncontrolling interests	0
Net income (loss) attributable to common stockholders/unitholders	$ 2,397,061
Income (loss) from continuing operations per share/unit – Basic	$ 6.80
Income (loss) from continuing operations per share/unit – Diluted	6.80
Income (loss) from discontinued operations per share/unit – Basic	(0.01)
Income (loss) from discontinued operations per share/unit – Diluted	(0.01)
Net income (loss) per share/unit – Basic	6.79
Net income (loss) per share/unit – Diluted	$ 6.79
Weighted average shares/units outstanding – Basic	352,792
Weighted average shares/units outstanding – Diluted	352,792

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENT OF EQUITY (Unaudited) Statement - 6 months ended Jun. 30, 2018 - USD ($) $ in Thousands	Total	Amount	Additional Paid-in Capital	Accumulated Deficit	Total Common Stockholders’ Equity	Noncontrolling Interests
Beginning of period (in shares) (Successor) at Dec. 31, 2017	83,582,000
Beginning of period (Successor) at Dec. 31, 2017		$ 84	$ 1,899,642	$ 432,860	$ 2,332,586
Beginning of period at Dec. 31, 2017	$ 2,332,586
Beginning of period (Successor) at Dec. 31, 2017						$ 18,971
Beginning of period at Dec. 31, 2017	18,971
Beginning of period (Successor) at Dec. 31, 2017	2,351,557
Beginning of period at Dec. 31, 2017	2,351,557
Net income | Successor	74,928	0	0	74,928	74,928
Net income | Successor	3,073					3,073
Net income | Successor	$ 78,001
Issuances of successor Class A common stock | Successor	811,000
Issuances of successor Class A common stock | Successor	$ 0	0	0	0	0	0
Repurchases of successor Class A common stock | Successor	(8,429,000)
Repurchases of successor Class A common stock | Successor	$ (394,415)	(8)	(394,407)	0	(394,415)	0
Settlement of equity classified RSUs | Successor	(58,162)	0	(58,162)	0	(58,162)	0
Share-based compensation expenses | Successor	25,132	0	25,132	0	25,132	0
Equity awards modified to liabilities | Successor	(70,550)	0	(70,550)	0	(70,550)	0
Allocation of noncontrolling interest upon vesting of subsidiary units | Successor	0	0	(21,233)	0	(21,233)	21,233
Distributions to noncontrolling interests | Successor	(8,367)	0	0	0	0	(8,367)
Subsidiary equity transactions | Successor	0	0	646	0	646	(646)
Other | Successor	$ 12,129	0	12,129	0	12,129	0
Dissolution of noncontrolling interests | Successor	2,786,000
Dissolution of noncontrolling interests	2,785,681
Dissolution of noncontrolling interests | Successor		3
Dissolution of noncontrolling interests | Successor	$ 0		34,261	0	34,264	(34,264)
End of period (in shares) (Successor) at Jun. 30, 2018	78,750,000
End of period (Successor) at Jun. 30, 2018		$ 79	$ 1,427,458	$ 507,788	$ 1,935,325
End of period at Jun. 30, 2018	$ 1,935,325
End of period (Successor) at Jun. 30, 2018						$ 0
End of period at Jun. 30, 2018	0
End of period (Successor) at Jun. 30, 2018	1,935,325
End of period at Jun. 30, 2018	$ 1,935,325

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	2 Months Ended	4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2017	Jun. 30, 2018
Successor
Cash flow from operating activities:
Net income		$ 212,801	$ 78,001
Adjustments to reconcile net income to net cash provided by operating activities:
Loss from discontinued operations		3,254	0
Depreciation, depletion and amortization		71,901	50,445
Deferred income taxes		131,055	46,031
(Gains) losses on oil and natural gas derivatives		(33,755)	22,555
Cash settlements on derivatives		7,929	(25,037)
Share-based compensation expenses		19,599	66,374
Amortization and write-off of deferred financing fees		82	824
(Gains) losses on sale of assets and other, net		(293,800)	(224,091)
Reorganization items, net		0	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net		27,212	76,465
(Increase) decrease in other assets		(9,146)	35,828
Increase (decrease) in accounts payable and accrued expenses		(89,755)	(52,538)
Increase (decrease) in other liabilities		22,421	(22,955)
Net cash provided by operating activities – continuing operations		69,798	51,902
Net cash provided by operating activities – discontinued operations		13,966	0
Net cash provided by operating activities		83,764	51,902
Cash flow from investing activities:
Development of oil and natural gas properties		(61,534)	(45,938)
Purchases of other property and equipment		(27,287)	(87,377)
Proceeds from sale of properties and equipment and other		697,829	369,489
Net cash provided by (used in) investing activities – continuing operations		609,008	236,174
Net cash used in investing activities – discontinued operations		(1,645)	0
Net cash provided by (used in) investing activities		607,363	236,174
Cash flow from financing activities:
Proceeds from rights offerings, net		0	0
Repurchases of shares		0	(393,647)
Proceeds from borrowings		160,000	0
Repayments of debt		(876,570)	0
Payment to holders of claims under the Predecessor’s second lien notes		0	0
Distributions to noncontrolling interests		(2,973)	(12,174)
Cash settlements of equity classified RSUs		0	(58,162)
Other		(87)	(294)
Net cash used in financing activities – continuing operations		(719,630)	(464,277)
Net cash used in financing activities – discontinued operations		0	0
Net cash used in financing activities		(719,630)	(464,277)
Net decrease in cash, cash equivalents and restricted cash		(28,503)	(176,201)
Cash, cash equivalents and restricted cash:
Ending	$ 144,022	$ 115,519	$ 344,752
Predecessor
Cash flow from operating activities:
Net income	2,397,061
Adjustments to reconcile net income to net cash provided by operating activities:
Loss from discontinued operations	548
Depreciation, depletion and amortization	47,155
Deferred income taxes	(166)
(Gains) losses on oil and natural gas derivatives	(92,691)
Cash settlements on derivatives	(11,572)
Share-based compensation expenses	50,255
Amortization and write-off of deferred financing fees	1,338
(Gains) losses on sale of assets and other, net	1,069
Reorganization items, net	(2,359,364)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable – trade, net	(7,216)
(Increase) decrease in other assets	528
Increase (decrease) in accounts payable and accrued expenses	20,949
Increase (decrease) in other liabilities	2,801
Net cash provided by operating activities – continuing operations	50,695
Net cash provided by operating activities – discontinued operations	8,781
Net cash provided by operating activities	59,476
Cash flow from investing activities:
Development of oil and natural gas properties	(50,597)
Purchases of other property and equipment	(7,409)
Proceeds from sale of properties and equipment and other	(166)
Net cash provided by (used in) investing activities – continuing operations	(58,172)
Net cash used in investing activities – discontinued operations	(584)
Net cash provided by (used in) investing activities	(58,756)
Cash flow from financing activities:
Proceeds from rights offerings, net	514,069
Repurchases of shares	0
Proceeds from borrowings	0
Repayments of debt	(1,038,986)
Payment to holders of claims under the Predecessor’s second lien notes	(30,000)
Distributions to noncontrolling interests	0
Cash settlements of equity classified RSUs	0
Other	(6,015)
Net cash used in financing activities – continuing operations	(560,932)
Net cash used in financing activities – discontinued operations	0
Net cash used in financing activities	(560,932)
Net decrease in cash, cash equivalents and restricted cash	(560,212)
Cash, cash equivalents and restricted cash:
Ending	$ 144,022

Basis of Presentation

Basis of Presentation	6 Months Ended
	Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation When referring to Linn Energy, Inc. (“Successor,” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a Delaware corporation formed in February 2017, and its then consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. During the reporting period Linn Energy, Inc. was 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. was 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 in Note 2) 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. As discussed under Holding Company Reorganization below in this Note 1, subsequent to the reporting period, on July 25, 2018, the Company completed a corporate reorganization pursuant to which LINN Energy merged with and into Linn Merger Sub #1, LLC (“Merger Sub”), a newly formed Delaware limited liability company and wholly owned subsidiary of New LINN Inc., a newly formed Delaware corporation (“New LINN”), with Merger Sub surviving such merger (the “Merger”). Immediately following the Merger, New LINN changed its name to “Linn Energy, Inc.” For purposes of Rule 15d-5 under the Exchange Act, New LINN is the successor registrant to LINN Energy. The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiary of the Predecessor through February 28, 2017. Berry was deconsolidated effective December 3, 2016. The reference to “LinnCo” herein refers to LinnCo, LLC, which was an affiliate of the Predecessor. Nature of Business LINN Energy 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. Prior to the Spin-off (as defined below), the Company’s upstream properties were located in six operating regions in the United States (“U.S.”): the Hugoton Basin, East Texas, North Louisiana, Michigan/Illinois, the Rockies and the Mid-Continent. The Company’s midstream business consisted of the Chisholm Trail gas plant system (“Chisholm Trail”) which is comprised of the newly constructed cryogenic natural gas processing facility, a refrigeration plant, and a network of gathering pipelines located in the Merge/SCOOP/STACK play. 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 2018, the Company divested all of its properties located in the previous Permian Basin operating region. During 2017, the Company divested all of its properties located in the previous California and South Texas operating regions. Holding Company Reorganization On July 25, 2018, in accordance with Section 251(g) of the Delaware General Corporation Law, LINN Energy merged with and into Merger Sub, a newly formed Delaware limited liability company and wholly owned subsidiary of New LINN, with Merger Sub surviving the Merger. The Merger was completed pursuant to the terms of an Agreement and Plan of Merger by and among LINN Energy, New LINN and Merger Sub, dated July 25, 2018 (the “Merger Agreement”). Pursuant to the Merger Agreement, at the effective time of the Merger, all outstanding shares of Class A common stock of LINN Energy were automatically converted into identical shares of Class A common stock of New LINN on a one-for-one basis, and LINN Energy’s existing stockholders became stockholders of New LINN in the same amounts and percentages as they were in LINN Energy immediately prior to the Merger. Spin-Off Transactions In April 2018, the Company announced its intention to separate its then wholly owned subsidiary, Riviera Resources, LLC (together with its corporate successor, “Riviera”) from LINN Energy. To effect the separation, Linn Energy, Inc. and certain of its direct and indirect subsidiaries undertook an internal reorganization (including the conversion of Riviera from a limited liability company to a corporation), following which Riviera Resources, Inc. holds, directly or through its subsidiaries, substantially all of the assets of LINN Energy, other than LINN Energy’s 50% equity interest in Roan. Following the internal reorganization, Linn Energy, Inc. distributed all of the outstanding shares of common stock of Riviera to LINN Energy stockholders on a pro rata basis (the “Spin-off”). Following the Spin-off, Riviera Resources, Inc. is an independent reporting company quoted for trading on the OTC Market under the ticker “RVRA.” LINN Energy did not retain any ownership interest in Riviera and will remain a reporting company quoted for trading on the OTCQB Market under the symbol “LNGG.” The Spin-off was completed on August 7, 2018. Principles of Consolidation and Reporting The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 . The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year. The condensed consolidated financial statements include the accounts of the Company and its pre-Spin-off subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Noncontrolling interests represented ownership in the net assets of the Company’s previous consolidated subsidiary, Linn Energy Holdco LLC (“Holdco”), not attributable to LINN Energy, and were presented as a component of equity. Changes in the Company’s ownership interests in Holdco that did not result in deconsolidation were recognized in equity. Effective April 10, 2018, all outstanding Class A‑2 units in Holdco (“Holdco Class A-2 units”) were converted into Class A common stock in LINN Energy in accordance with the terms of Holdco’s Limited Liability Company Operating Agreement (the “Holdco LLC Agreement”) and the noncontrolling interest was dissolved. See Note 13 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 6 for additional information about equity method investments. The condensed consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss) or stockholders equity. As a result of the adoption of ASU 2016-18 and the inclusion of restricted cash in the statements of cash flows, previously reported net cash provided by operating activities and cash provided by investing activities have been updated to conform to current presentation. See recently adopted accounting standards below for additional information. Bankruptcy Accounting 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 adoption of fresh start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statements subsequent to February 28, 2017, are not comparable to its condensed consolidated financial statements prior to February 28, 2017. References to “Successor” relate to the financial position and results of operations of the reorganized Company 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 condensed 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. See Note 2 for additional information. Use of Estimates The preparation of the accompanying condensed 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 November 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. The Company adopted this ASU on January 1, 2018, on a retrospective basis. The adoption of this ASU resulted 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 statement of cash flows (see Note 17). 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 (“ASC 606”). The Company adopted this ASU on January 1, 2018, using the modified retrospective transition method. Accordingly, the comparative information for the six months ended June 30, 2017 , has not been adjusted and continues to be reported under the previous revenue standard. The adoption of this ASU impacted the Company’s gross revenues and expenses as reported on its condensed consolidated statements of operations (see below), and resulted in increased disclosures regarding the Company’s disaggregation of revenue (see Note 3). Under ASC 606, the Company recognizes revenues based on a determination of when control of its commodities is transferred and whether it is acting as a principal or agent in certain transactions. All facts and circumstances of an arrangement are considered and judgment is often required in making this determination. For its natural gas contracts, the Company generally records its sales at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses if the processor is the customer and there is no redelivery of commodities to the Company. Conversely, the Company generally records its sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses if the processor is a service provider and there is redelivery of commodities to the Company. In addition, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities. This recognition results in an increase to revenues and expenses with no material impact on net income. The items discussed above impacted the Company’s reported “oil, natural gas and natural gas liquids sales,” “marketing revenues,” “other revenues,” “transportation expenses,” “marketing expenses” and “interest expense.” The impact of adoption on the Company’s current period results is as follows: Three Months Ended June 30, 2018 Under ASC 606 Under Prior Rule Increase/ (Decrease) (in thousands) Revenues: Natural gas sales $ 53,662 $ 53,285 $ 377 Oil sales 10,919 10,919 — NGL sales 22,423 22,280 143 Total oil, natural gas and NGL sales 87,004 86,484 520 Marketing revenues 42,967 25,406 17,561 Other revenues 6,387 6,003 384 136,358 117,893 18,465 Expenses: Transportation expenses 21,213 20,693 520 Marketing expenses 40,327 22,766 17,561 Interest expense 584 420 164 Net income $ 6,903 $ 6,683 $ 220 Six Months Ended June 30, 2018 Under ASC 606 Under Prior Rule Increase/ (Decrease) (in thousands) Revenues: Natural gas sales $ 116,990 $ 117,794 $ (804 ) Oil sales 56,615 56,615 — NGL sales 50,275 50,222 53 Total oil, natural gas and NGL sales 223,880 224,631 (751 ) Marketing revenues 89,234 53,521 35,713 Other revenues 12,281 11,676 605 325,395 289,828 35,567 Expenses: Transportation expenses 40,307 41,058 (751 ) Marketing expenses 82,082 46,369 35,713 Interest expense 988 824 164 Net income $ 78,001 $ 77,560 $ 441 New Accounting Standards Issued But Not Yet Adopted 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 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 sheet resulting from an increase in both assets and liabilities related to the Company’s leasing activities.

Emergence From Voluntary Reorga

Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting	6 Months Ended
	Jun. 30, 2018
Emergence From Voluntary Reorganization Under Chapter 11 [Abstract]
Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting	Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting 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. 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 table summarizes the components of reorganization items included on the condensed consolidated statements of operations: Successor Three Months Ended June 30, 2018 2017 (in thousands) Legal and other professional advisory fees $ (1,255 ) $ (3,446 ) Other (4 ) 69 Reorganization items, net $ (1,259 ) $ (3,377 ) Successor Predecessor Six Months Ended June 30, 2018 Four Months Ended June 30, 2017 Two Months Ended February 28, 2017 (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 fees (3,207 ) (6,016 ) (46,961 ) Terminated contracts — — (6,915 ) Other (3 ) 74 (13,049 ) Reorganization items, net $ (3,210 ) $ (5,942 ) $ 2,331,189 Fresh Start Accounting Upon the Company’s emergence from Chapter 11 bankruptcy, it adopted fresh start accounting in accordance with the provisions of Accounting Standards Codification 852 “Reorganizations” (“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.” The amount of deferred income taxes recorded was determined in accordance with ASC 740 “Income Taxes.” 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 condensed consolidated balance sheet as of February 28, 2017, and the related adjustments thereto were recorded on the condensed consolidated statement of operations for the two months ended February 28, 2017.

Revenues

Revenues	6 Months Ended
	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenues	Revenues Revenue from Contracts with Customers The Company recognized sales of oil, natural gas and NGL when it satisfied a performance obligation by transferring control of the product to a customer, in an amount that reflected the consideration to which the Company expected to be entitled in exchange for the product. Natural Gas and NGL Sales The Company’s natural gas production was primarily sold under market-sensitive contracts that were typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. For its natural gas contracts, the Company generally recorded its wet gas sales at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses, and its residual natural gas and NGL sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses. All facts and circumstances of an arrangement were considered and judgment was often required in making this determination. Oil Sales The Company’s oil production was primarily sold under market-sensitive contracts that were typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser posted prices for the producing area. For its oil contracts, the Company generally recorded its sales based on the net amount received. Production Imbalances The Company used the sales method to account for natural gas production imbalances. If the Company’s sales volumes for a well exceeded the Company’s proportionate share of production from the well, a liability was recognized to the extent that the Company’s share of estimated remaining recoverable reserves from the well was insufficient to satisfy this imbalance. No receivables were recorded for those wells on which the Company had taken less than its proportionate share of production. Marketing Revenues The Company engaged in the purchase, gathering and transportation of third-party natural gas and subsequently marketed such natural gas to independent purchasers under separate arrangements. As such, the Company separately reported third-party marketing revenues and marketing expenses. Disaggregation of Revenue The following tables present the Company’s disaggregated revenues by source and geographic area: Three Months Ended June 30, 2018 Natural Gas Oil NGL Oil, Natural Gas and NGL Sales Marketing Revenues Other Revenues Total (in thousands) Hugoton Basin $ 17,401 $ 238 $ 16,875 $ 34,514 $ 22,421 $ 6,303 $ 63,238 Mid-Continent 7,622 4,880 3,307 15,809 — 25 15,834 East Texas 12,661 1,091 1,013 14,765 467 3 15,235 Permian Basin 256 546 (488 ) 314 — 16 330 Rockies 2,146 1,885 1,201 5,232 — 1 5,233 North Louisiana 6,040 1,480 503 8,023 13 2 8,038 Michigan/Illinois 7,536 799 12 8,347 — 37 8,384 Chisholm Trail — — — — 20,066 — 20,066 Total $ 53,662 $ 10,919 $ 22,423 $ 87,004 $ 42,967 $ 6,387 $ 136,358 Six Months Ended June 30, 2018 Natural Gas Oil NGL Oil, Natural Gas and NGL Sales Marketing Revenues Other Revenues Total (in thousands) Hugoton Basin $ 39,764 $ 2,970 $ 36,389 $ 79,123 $ 46,501 $ 12,134 $ 137,758 Mid-Continent 15,555 16,747 6,361 38,663 — 39 38,702 East Texas 27,437 2,431 2,319 32,187 503 8 32,698 Permian Basin 2,282 20,654 2,557 25,493 — 32 25,525 Rockies 5,526 9,255 2,559 17,340 — (1 ) 17,339 North Louisiana 12,418 3,049 67 15,534 272 3 15,809 Michigan/Illinois 14,008 1,509 23 15,540 — 66 15,606 Chisholm Trail — — — — 41,958 — 41,958 Total $ 116,990 $ 56,615 $ 50,275 $ 223,880 $ 89,234 $ 12,281 $ 325,395 Contract Balances Under the Company’s product sales contracts, its customers were invoiced once the Company’s performance obligations had been satisfied, at which point payment was unconditional. Accordingly, the Company’s product sales contracts did not give rise to material contract assets or contract liabilities. The Company had trade accounts receivable related to revenue from contracts with customers of approximately $56 million and $117 million as of June 30, 2018 , and December 31, 2017 , respectively. Performance Obligations The majority of the Company’s sales were short-term in nature with a contract term of one year or less. For those contracts, the Company utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation was part of a contract that had an original expected duration of one year or less. For the Company’s product sales that had a contract term greater than one year, the Company utilized the practical expedient in ASC 606-10-50-14(A) which states the Company was not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration was allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represented a separate performance obligation; therefore future volumes were wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations was not required.

Divestitures and Discontinued O

Divestitures and Discontinued Operations	6 Months Ended
	Jun. 30, 2018
Discontinued Operations [Abstract]
Divestitures and Discontinued Operations	Divestitures and Discontinued Operations Divestitures – 2018 On April 10, 2018, the Company completed the sale of its conventional properties located in New Mexico. Cash proceeds received from the sale of these properties were approximately $15 million and the Company recognized a net gain of approximately $11 million . On April 4, 2018, the Company completed the sale of its interest in properties located in the Altamont Bluebell Field in Utah (the “Altamont Bluebell Assets Sale”). Cash proceeds received from the sale of these properties were approximately $132 million , net of costs to sell of approximately $2 million , and the Company recognized a net gain of approximately $83 million . On March 29, 2018, the Company completed the sale of its interest in conventional properties located in west Texas. Cash proceeds received from the sale of these properties were approximately $107 million , net of costs to sell of approximately $2 million , and the Company recognized a net gain of approximately $55 million . On February 28, 2018, the Company completed the sale of its Oklahoma waterflood and Texas Panhandle properties (the “Oklahoma and Texas Assets Sale”). Cash proceeds received from the sale of these properties were approximately $112 million (including a deposit of approximately $12 million received in 2017), net of costs to sell of approximately $1 million , and the Company recognized a net gain of approximately $46 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 condensed consolidated statements of operations and were part of the upstream segment. The assets and liabilities associated with the Oklahoma and Texas Assets Sale were classified as “held for sale” on the condensed consolidated balance sheet at December 31, 2017. At December 31, 2017, the Company’s condensed 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 condensed consolidated balance sheet: 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. Divestitures – 2017 On June 30, 2017 , the Company completed the sale of its interest in properties located in the Salt Creek Field in Wyoming to Denbury Resources Inc. (the “Salt Creek Assets Sale”). Cash proceeds received from the sale of these properties were approximately $76 million and the Company recognized a net gain of approximately $22 million . On May 31, 2017, the Company completed the sale of its interest in properties located in western Wyoming to Jonah Energy LLC (the “Jonah Assets Sale”). Cash proceeds received from the sale of these properties were approximately $560 million , net of costs to sell of approximately $6 million , and the Company recognized a net gain of approximately $279 million . The gains on these divestitures are included in “(gains) losses on sale of assets and other, net” on the condensed consolidated statements of operations. Discontinued Operations During 2017, the Company completed the sale of its interest in properties located in the San Joaquin Basin and the Los Angeles Basin in California. As a result of the Company’s strategic exit from California, the Company classified the results of operations and cash flows of its California properties as discontinued operations on its condensed consolidated financial statements. The California properties were included in the upstream segment. The following tables present summarized financial results of the Company’s California properties classified as discontinued operations on the condensed consolidated statements of operations: Successor Predecessor Three Months Ended June 30, 2017 Four Months Ended June 30, 2017 Two Months Ended February 28, 2017 (in thousands) Revenues and other $ 20,511 $ 27,636 $ 14,891 Expenses 25,935 30,344 13,758 Other income and (expenses) (2,074 ) (2,791 ) (1,681 ) Loss from discontinued operations before income taxes (7,498 ) (5,499 ) (548 ) Income tax benefit (4,176 ) (2,245 ) — Loss from discontinued operations, net of income taxes $ (3,322 ) $ (3,254 ) $ (548 ) Other income and (expenses) include an allocation of interest expense for the California properties 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 .

Oil and Natural Gas Properties

Oil and Natural Gas Properties	6 Months Ended
	Jun. 30, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Natural Gas Properties	Oil and Natural Gas Properties 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: June 30, 2018 December 31, 2017 (in thousands) Proved properties $ 739,656 $ 904,390 Unproved properties 46,159 45,693 785,815 950,083 Less accumulated depletion and amortization (59,870 ) (49,619 ) $ 725,945 $ 900,464

Equity Method Investments

Equity Method Investments	6 Months Ended
	Jun. 30, 2018
Equity Method Investments [Abstract]
Equity Method Investments	Equity Method Investments 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 (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. 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 June 30, 2018 , and December 31, 2017 , the Company owned 50% of Roan’s outstanding units. At June 30, 2018 , the carrying amount of the Company’s investment in Roan of approximately $466 million was less than the Company’s ownership interest in Roan’s underlying net assets by approximately $355 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. 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 . 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 six months ended June 30, 2018 . Following is summarized statements of operations information for Roan. Summarized Roan Resources LLC Statements of Operations Information Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 (in thousands) Revenues and other $ 44,789 $ 145,873 Expenses 72,754 130,663 Other income and (expenses) (1,087 ) (2,886 ) Net income (loss) $ (29,052 ) $ 12,324

Debt

Debt	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Debt	Debt Credit Facility On August 4, 2017, the Company entered into a credit agreement with its then subsidiary, Linn Energy Holdco II LLC (“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 “Credit Facility”) with $500 million in borrowing commitments and an initial borrowing base of $500 million . On April 30, 2018, the Company entered into an amendment to the Credit Facility which, among other things, modified the borrowing base and maximum borrowing commitment amount to $425 million . As of June 30, 2018 , there were no borrowings outstanding under the Credit Facility and there was approximately $378 million of available borrowing capacity (which includes a $47 million reduction for outstanding letters of credit). The maturity date is August 4, 2020. Pursuant to the Spin-off, Holdco II became a subsidiary of Riviera and as such, Riviera and its subsidiaries have assumed all obligations under the Credit Facility. Redetermination of the borrowing base under the Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. At the Company’s election, interest on borrowings under the 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 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 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 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 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 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 Credit Facility would allow the lenders, subject to customary cure rights, to require immediate payment of all amounts outstanding under the Credit Facility.

Derivatives

Derivatives	6 Months Ended
	Jun. 30, 2018
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 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 9 for fair value disclosures about oil and natural gas commodity derivatives. The following table presents derivative positions for the periods indicated as of June 30, 2018 : July 1 – December 31, 2018 2019 Natural gas positions: Fixed price swaps (NYMEX Henry Hub): Hedged volume (MMMBtu) 35,144 22,265 Average price ($/MMBtu) $ 3.02 $ 2.89 Oil positions: Fixed price swaps (NYMEX WTI): Hedged volume (MBbls) 276 183 Average price ($/Bbl) $ 54.07 $ 64.00 Natural gas basis differential positions: (1) PEPL basis swaps: Hedged volume (MMMBtu) 7,360 14,600 Hedge differential $ (0.67 ) $ (0.67 ) NGPL TXOK basis swaps: Hedged volume (MMMBtu) 1,840 — Hedge differential $ (0.19 ) $ — (1) Settled or to be settled, as applicable, on the indicated pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price. During the six months ended June 30, 2018 , the Company entered into commodity derivative contracts consisting of natural gas basis swaps for March 2018 through December 2019, natural gas fixed price swaps for January 2019 through December 2019 and oil fixed price swaps for January 2019 through December 2019. During the four months ended June 30, 2017 , the Company entered into commodity derivative contracts consisting of oil fixed price swaps for January 2018 through December 2018 and natural gas fixed price 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 April 2018, in connection with the closing of the Altamont Bluebell Assets Sale, the Company canceled its oil collars for 2018 and 2019. The Company paid net cash settlements of approximately $20 million for the cancellations. 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 condensed consolidated balance sheets. The following table summarizes the fair value of derivatives outstanding on a gross basis: June 30, 2018 December 31, 2017 (in thousands) Assets: Commodity derivatives $ 6,825 $ 22,589 Liabilities: Commodity derivatives $ 7,197 $ 25,443 By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposed 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 Credit Facility. The Credit Facility was secured by certain of the Company’s and its then subsidiaries’ oil, natural gas and NGL reserves and personal property; therefore, the Company was not required to post any collateral. The Company did 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 $7 million at June 30, 2018 . The Company minimized 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 were subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance was somewhat mitigated. Gains and Losses on Derivatives Gains and losses on derivatives were net losses of approximately $8 million and $23 million for the three months and six months ended June 30, 2018 , respectively, and net gains of approximately $46 million and $34 million for the three months and four months ended June 30, 2017 , respectively, and approximately $93 million for the two months ended February 28, 2017. Gains and losses on derivatives are reported on the condensed consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.” The Company paid net cash settlements of approximately $21 million and $25 million for the three months and six months ended June 30, 2018 , respectively. The Company received net cash settlements of approximately $2 million and $8 million for the three months and four months ended June 30, 2017 , respectively, and paid net cash settlements of approximately $12 million for the two months ended February 28, 2017.

Fair Value Measurements on a Re

Fair Value Measurements on a Recurring Basis	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements on a Recurring Basis	Fair Value Measurements on a Recurring Basis The Company accounted for its commodity derivatives at fair value (see Note 8) on a recurring basis. The Company determined 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 included publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validated 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, were 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). The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis: June 30, 2018 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 6,825 $ (1,637 ) $ 5,188 Liabilities: Commodity derivatives $ 7,197 $ (1,637 ) $ 5,560 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 (1) Represents counterparty netting under agreements governing such derivatives.

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The Company had the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs were 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 “asset retirement obligations and other noncurrent liabilities” on the condensed consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the condensed 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. In addition, there is insufficient information to reasonably determine the timing and/or method of settlement for purposes of estimating the fair value of the asset retirement obligation of certain of the Company’s Chisholm Trail assets, which became assets of Riviera in connection with the Spin-off. In such cases, asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management’s experience, or the asset’s estimated economic life. Indeterminate asset retirement obligation costs associated with Chisholm Trail will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods. The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands): Asset retirement obligations at December 31, 2017 $ 164,553 Liabilities added from drilling 53 Liabilities associated with assets divested (62,195 ) Current year accretion expense 4,081 Settlements (1,859 ) Revisions of estimates 2,386 Asset retirement obligations at June 30, 2018 $ 107,019

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2018
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’s 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. On November 13, 2017, the Bankruptcy Court ruled that the secured lenders are not entitled to payment of post-petition default interest. That ruling was appealed by Wells Fargo and on March 29, 2018, the U.S. District Court for the Southern District of Texas affirmed the Bankruptcy Court’s ruling. On April 30, 2018, the Bankruptcy Court approved the substitution of UMB Bank, National Association (“UMB Bank”) as successor to Wells Fargo as administrative agent under the Predecessor’s credit facility. UMB Bank then immediately filed a notice of appeal to the United States Court of Appeals for the Fifth Circuit from the decision by the U.S. District Court for the Southern District of Texas, which affirmed the decision of the Bankruptcy Court. That appeal remains 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 six months ended June 30, 2018 , or June 30, 2017 . 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.

Equity

Equity	6 Months Ended
	Jun. 30, 2018
Equity [Abstract]
Equity	Equity Shares Issued and Outstanding As of June 30, 2018 , there were 78,749,510 shares of Class A common stock issued and outstanding. An additional 922,696 unvested restricted stock units were outstanding under the Company’s Omnibus Incentive Plan. Effective April 10, 2018, all outstanding Holdco Class A-2 units were converted into Class A common stock in accordance with the terms of the Holdco LLC Agreement. Pursuant to such conversion, an aggregate of 2,785,681 shares of Class A common stock were issued to the respective holders, of which 914,632 remained subject to the vesting provisions applicable to the underlying Class A-2 units as of June 30, 2018 . See Note 14 for additional information related to the restricted stock units and Holdco Class A-2 units. Share Repurchase Program The Company’s Board of Directors previously authorized the repurchase of up to $400 million of the Company’s outstanding shares of Class A common stock. The Company discontinued the share repurchase program in July 2018. During the six months ended June 30, 2018 , the Company repurchased an aggregate of 1,557,180 shares of Class A common stock at an average price of $39.13 per share for a total cost of approximately $61 million . In June 2017, the Company repurchased 7,540 shares of Class A common stock at an average price of $30.48 per share for a total cost of approximately $230,000 . In addition, in July 2018, the Company purchased 280,289 shares of Class A common stock at an average price of $40.30 for a total cost of approximately $11 million . During 2017 and 2018, the Company purchased an aggregate of 7,527,661 shares of Class A common stock at an average price of $35.94 for a total cost of approximately $271 million under the share repurchase program. Tender Offer 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 approximately $4 million related to the tender offer). Dividends The Company 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.

Noncontrolling Interests

Noncontrolling Interests	6 Months Ended
	Jun. 30, 2018
Noncontrolling Interests [Abstract]
Noncontrolling Interests	Noncontrolling Interests Noncontrolling interests represented ownership in the net assets of the Company’s then 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 14). 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 December 31, 2017 , the noncontrolling Class A-2 units represented approximately 0.88% of Holdco’s total outstanding units. Effective April 10, 2018, all outstanding Holdco Class A-2 units were converted into Class A common stock in accordance with the terms of the Holdco LLC Agreement.

Share-Based Compensation

Share-Based Compensation	6 Months Ended
	Jun. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation	Share-Based Compensation A summary of share-based compensation expenses included on the condensed consolidated statements of operations is presented below: Three Months Ended June 30, 2018 2017 (in thousands) General and administrative expenses $ 58,188 $ 15,422 Income tax benefit $ 4,315 $ 3,128 Successor Predecessor Six Months Ended June 30, 2018 Four Months Ended June 30, 2017 Two Months Ended February 28, 2017 (in thousands) General and administrative expenses $ 75,225 $ 19,599 $ 50,255 Income tax benefit $ 6,732 $ 3,555 $ 5,170 During the six months ended June 30, 2018 , the Company granted to certain employees 12,500 restricted stock units with an aggregate grant date fair value of approximately $519,000 . The restricted stock units vest over three years. As of June 30, 2018, 922,696 shares were issuable under the Omnibus Incentive Plan pursuant to outstanding restricted stock units and approximately 4.7 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. As of April 30, 2018, all current participants in the Omnibus Incentive Plan have 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 or a similar future program. The Compensation Committee has indicated that it does not intend to grant any future awards under the Omnibus Incentive Plan. 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. During May 2018, the Company began exercising its right to repurchase vesting awards under the Omnibus Incentive Plan which modified all outstanding awards to liability classification. For the six months ended June 30, 2018 , the Company has repurchased 271,314 restricted stock units for a total cost of approximately $11 million pursuant to its right to repurchase vesting awards. The Company has recognized a liability of approximately $112 million related to awards required to be liability classified, included in “share-based payment liability” on the condensed consolidated balance sheet and recorded incremental share-based compensation expense of approximately $18 million related to modifying the awards to liability classification. At June 30, 2018 , all outstanding share-based payment awards are liability classified. In April 2018, the Company entered into agreements with each of the then serving executive officers of the Company, under which the Company agreed, at the option of each officer, to repurchase certain of their vested restricted stock unit awards and outstanding Class A common stock. Pursuant to those agreements, on August 7, 2018, the Company repurchased an aggregate of 2,477,834 shares of Class A common stock for a total cost of approximately $102 million . On August 2, 2018, the Board authorized the termination of the Linn Energy, Inc. 2017 Omnibus Incentive Plan following the settlement of all outstanding RSUs and restricted common stock. In addition, all remaining unvested restricted stock units of Linn Energy, Inc. vested upon the Spin-off, which participants have the option to require the Company to settle in cash. In addition, in January 2018, the Compensation Committee approved a one-time liquidity program under which the Company agreed, at the option of the participant, 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”). For the six months ended June 30, 2018 , the Company settled 1,028,875 restricted stock units in cash and repurchased 120,829 shares of Class A common stock for a total cost of approximately $45 million pursuant to the Liquidity Program.

Earnings Per Share_Unit

Earnings Per Share/Unit	6 Months Ended
	Jun. 30, 2018
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: Successor Three Months Ended June 30, 2018 Income Shares Per Share (in thousands, except per share data) Basic: Net income attributable to common stockholders $ 5,104 78,718 $ 0.06 Effect of Dilutive Securities: Dilutive effect of restricted stock units 559 Dilutive effect of unvested Class A-2 units of Holdco $ — — Diluted: Net income attributable to common stockholders $ 5,104 79,277 $ 0.06 Successor Three Months Ended June 30, 2017 Income Shares Per Share (in thousands, except per share data) Basic: Income from continuing operations $ 223,379 89,849 $ 2.49 Loss from discontinued operations, net of income taxes (3,322 ) 89,849 (0.04 ) Net income attributable to common stockholders $ 220,057 89,849 $ 2.45 Effect of Dilutive Securities: Dilutive effect of restricted stock units $ — 635 Diluted: Income from continuing operations $ 223,379 90,484 $ 2.47 Loss from discontinued operations (3,322 ) 90,484 (0.04 ) Net income attributable to common stockholders $ 220,057 90,484 $ 2.43 Successor Six Months Ended June 30, 2018 Income Shares Per Share (in thousands, except per share data) Basic: Net income attributable to common stockholders $ 74,928 78,817 $ 0.95 Effect of Dilutive Securities: Dilutive effect of restricted stock units $ — 947 Dilutive effect of unvested Class A-2 units of Holdco $ (1,140 ) — Diluted: Net income attributable to common stockholders $ 73,788 79,764 $ 0.93 Successor Four Months Ended June 30, 2017 Income Shares Per Share (in thousands, except per share data) Basic: Income from continuing operations $ 216,055 89,849 $ 2.41 Loss from discontinued operations, net of income taxes (3,254 ) 89,849 (0.04 ) Net income attributable to common stockholders $ 212,801 89,849 $ 2.37 Effect of Dilutive Securities: Dilutive effect of restricted stock units $ — 216 Diluted: Income from continuing operations $ 216,055 90,065 $ 2.40 Loss from discontinued operations (3,254 ) 90,065 (0.04 ) Net income attributable to common stockholders $ 212,801 90,065 $ 2.36 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 The diluted earnings per share calculation excludes approximately 1,989 restricted stock units that were anti-dilutive for the six months ended June 30, 2018 . No restricted stock units were anti-dilutive for the three months ended June 30, 2018 . The diluted earnings per share calculation for the three months and four months ended June 30, 2017 , exclude approximately 3,470,051 Class B units associated with management’s profits interests awards that were not yet considered to be dilutive as the applicable hurdle rate had not been met as of June 30, 2017 . There were no potential common units outstanding during the two months ended February 28, 2017.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Amounts recognized as income taxes are included in “income tax expense (benefit),” as well as discontinued operations, on the consolidated statements of operations. The effective income tax rates were approximately 45% and 37% for the three months and six months ended June 30, 2018 , respectively, approximately 42% for both the three months and four months ended June 30, 2017 , and zero for the two months ended February 28, 2017. For the six months ended June 30, 2018 , the Company’s federal and state statutory rate net of the federal tax benefit was approximately 24% . The increase in the effective tax rate during 2018 is primarily due to non-deductible executive compensation. 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.

Supplemental Disclosures to the

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows	6 Months Ended
	Jun. 30, 2018
Supplemental Disclosures to the Condensed Consolidated Statements of Cash Flows [Abstract]
Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows	Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows “Other current assets” reported on the condensed consolidated balance sheets include the following: June 30, 2018 December 31, 2017 (in thousands) Prepaids $ 14,209 $ 46,238 Receivable from related party 25,982 23,163 Inventories 3,981 7,667 Other 2,487 2,703 Other current assets $ 46,659 $ 79,771 “Other accrued liabilities” reported on the condensed consolidated balance sheets include the following: June 30, 2018 December 31, 2017 (in thousands) Accrued compensation $ 13,533 $ 29,089 Asset retirement obligations (current portion) 1,488 3,926 Deposits 3,170 15,349 Income taxes payable 23 7,496 Other 1,616 2,757 Other accrued liabilities $ 19,830 $ 58,617 The following table provides a reconciliation of cash and cash equivalents on the condensed consolidated balance sheets to cash, cash equivalents and restricted cash on the condensed consolidated statement of cash flows: June 30, 2018 December 31, 2017 (in thousands) Cash and cash equivalents $ 301,365 $ 464,508 Restricted cash 43,387 56,445 Cash, cash equivalents and restricted cash $ 344,752 $ 520,953 Supplemental disclosures to the condensed consolidated statements of cash flows are presented below: Successor Predecessor Six Months Ended June 30, 2018 Four Months Ended June 30, 2017 Two Months Ended February 28, 2017 (in thousands) Cash payments for interest, net of amounts capitalized $ — $ 14,436 $ 17,651 Cash payments for income taxes $ 7,748 $ 215 $ — Cash payments for reorganization items, net $ 2,911 $ 6,300 $ 21,571 Noncash investing activities: Accrued capital expenditures $ 21,968 $ 34,547 $ 22,191 For purposes of the condensed 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 June 30, 2018 , “restricted cash” on the condensed consolidated balance sheet consisted of approximately $33 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 $3 million related to deposits and approximately $7 million for other items. At December 31, 2017 , “restricted cash” on the condensed consolidated balance sheet consisted of approximately $36 million that will be used to settle certain claims in accordance with the Plan, approximately $15 million related to deposits and approximately $5 million for other items.

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2018
Related Party Transactions [Abstract]
Related Party Transactions Disclosure	Related Party Transactions Roan Resources LLC On August 31, 2017, the Company completed the Roan Contribution. In exchange for their respective contributions, LINN Energy and Citizen each received a 50% equity interest in Roan. See Note 6 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 agreed to provide certain operating, administrative and other services in respect of the assets contributed to Roan during a transitional period. Under the MSA, Roan agreed to reimburse Linn Operating for certain costs and expenses incurred by Linn Operating in connection with providing the services, and to pay to Linn Operating a service fee of $1.25 million per month, prorated for partial months. The MSA terminated according to its terms on April 30, 2018. In addition, the Company’s pre-Spin-off subsidiary, Blue Mountain Midstream LLC (“Blue Mountain”), has an agreement in place with Roan for the purchase and processing of natural gas from certain of Roan’s properties. Blue Mountain became a subsidiary of Riviera on August 7, 2018 in connection with the Spin-off. For the three months and six months ended June 30, 2018 , the Company made natural gas purchases from Roan of approximately $15 million and $32 million , respectively, included in “marketing expenses” on the condensed consolidated statements of operations. In addition, for the three months and six months ended June 30, 2018 , the Company recognized service fees of approximately $1 million and $5 million , respectively, under the MSA, as a reduction to general and administrative expenses. At June 30, 2018 , the Company had approximately $26 million due from Roan, primarily associated with capital spending, included in “other current assets” and approximately $11 million due to Roan, associated with natural gas purchases, included in “accounts payable and accrued expenses” on the condensed consolidated balance sheet. At December 31, 2017 , 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 condensed consolidated balance sheet. Berry Petroleum Company, LLC Berry, a former subsidiary of the Predecessor, was deconsolidated effective December 31, 2016 . 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, Berry incurred management fees of approximately $6 million for services provided by LOI. LinnCo, LLC LinnCo, which was an affiliate of the Predecessor, was formed on April 30, 2012. 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.

Segments

Segments	6 Months Ended
	Jun. 30, 2018
Segment Reporting [Abstract]
Segments	Segments During the second quarter of 2018, the Company had two reporting segments: Upstream and Chisholm Trail. The Upstream reporting segment was engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs. The Chisholm Trail reporting segment is new for the second quarter of 2018 as a result of a change in the way our chief operating decision maker (“CODM”) assesses the Company’s results of operations following the hiring of a segment manager to lead the Chisholm Trail reporting segment and the commissioning of the cryogenic natural gas processing facility during the second quarter of 2018. The Chisholm Trail reporting segment consisted of the Chisholm Trail gas plant system, which is comprised of the newly constructed cryogenic natural gas processing facility, a refrigeration plant, and a network of gathering pipelines located in the Merge/SCOOP/STACK play. To assess the performance of the Company’s operating segments, the CODM analyzes field level cash flow. The Company defines field level cash flow as revenues less direct operating expenses. Other indirect income (expenses) include “general and administrative expenses,” “exploration costs,” “depreciation, depletion and amortization,” “gains on sale of assets and other, net,” “other income and (expenses)” and “reorganization items, net.” Prior period amounts are presented on a comparable basis. In addition, information regarding total assets by segment is not presented because it is not reviewed by the CODM. The following tables present the Company’s financial information by reportable segment: Successor Three Months Ended June 30, 2018 Upstream Chisholm Trail Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 87,004 $ — $ — $ 87,004 Marketing revenues 22,901 20,066 — 42,967 Other revenues 6,387 — — 6,387 116,292 20,066 — 136,358 Lease operating expenses 24,088 — — 24,088 Transportation expenses 21,213 — — 21,213 Marketing expenses 20,244 20,083 — 40,327 Taxes other than income taxes 6,737 285 275 7,297 Total direct operating expenses 72,282 20,368 275 92,925 Field level cash flow $ 44,010 $ (302 ) (275 ) 43,433 Losses on oil and natural gas derivatives (7,525 ) (7,525 ) Other indirect income (expenses) (23,283 ) (23,283 ) Income from continuing operations before income taxes $ 12,625 Successor Three Months Ended June 30, 2017 Upstream Chisholm Trail Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 243,167 $ — $ — $ 243,167 Marketing revenues 10,793 1,754 — 12,547 Other revenues 6,391 — — 6,391 260,351 1,754 — 262,105 Lease operating expenses 71,057 — — 71,057 Transportation expenses 37,388 — — 37,388 Marketing expenses 6,156 820 — 6,976 Taxes other than income taxes 17,486 116 269 17,871 Total direct operating expenses 132,087 936 269 133,292 Field level cash flow $ 128,264 $ 818 (269 ) 128,813 Gains on oil and natural gas derivatives 45,714 45,714 Other indirect income (expenses) 207,622 207,622 Income from continuing operations before income taxes $ 382,149 Successor Six Months Ended June 30, 2018 Upstream Chisholm Trail Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 223,880 $ — $ — $ 223,880 Marketing revenues 47,276 41,958 — 89,234 Other revenues 12,281 — — 12,281 283,437 41,958 — 325,395 Lease operating expenses 71,972 — — 71,972 Transportation expenses 40,307 — — 40,307 Marketing expenses 41,380 40,702 — 82,082 Taxes other than income taxes 14,908 477 364 15,749 Total direct operating expenses 168,567 41,179 364 210,110 Field level cash flow $ 114,870 $ 779 (364 ) 115,285 Losses on oil and natural gas derivatives (22,555 ) (22,555 ) Other indirect income (expenses) 31,167 31,167 Income from continuing operations before income taxes $ 123,897 Successor Four Months Ended June 30, 2017 Upstream Chisholm Trail Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 323,492 $ — $ — $ 323,492 Marketing revenues 13,273 2,188 — 15,461 Other revenues 8,419 — — 8,419 345,184 2,188 — 347,372 Lease operating expenses 95,687 — — 95,687 Transportation expenses 51,111 — — 51,111 Marketing expenses 8,513 1,002 — 9,515 Taxes other than income taxes 24,478 155 315 24,948 Total direct operating expenses 179,789 1,157 315 181,261 Field level cash flow $ 165,395 $ 1,031 (315 ) 166,111 Gains on oil and natural gas derivatives 33,755 33,755 Other indirect income (expenses) 169,644 169,644 Income from continuing operations before income taxes $ 369,510 Predecessor Two Months Ended February 28, 2017 Upstream Chisholm Trail Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 188,885 $ — $ — $ 188,885 Marketing revenues 5,999 637 — 6,636 Other revenues 9,915 — — 9,915 204,799 637 — 205,436 Lease operating expenses 49,665 — — 49,665 Transportation expenses 25,972 — — 25,972 Marketing expenses 4,602 218 — 4,820 Taxes other than income taxes 14,773 78 26 14,877 Total direct operating expenses 95,012 296 26 95,334 Field level cash flow $ 109,787 $ 341 (26 ) 110,102 Gains on oil and natural gas derivatives 92,691 92,691 Other indirect income (expenses) 2,194,650 2,194,650 Income from continuing operations before income taxes $ 2,397,443

Basis of Presentation (Policies

Basis of Presentation (Policies)	6 Months Ended
	Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Business	Nature of Business LINN Energy 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. Prior to the Spin-off (as defined below), the Company’s upstream properties were located in six operating regions in the United States (“U.S.”): the Hugoton Basin, East Texas, North Louisiana, Michigan/Illinois, the Rockies and the Mid-Continent
Principles of Consolidation and Reporting	Principles of Consolidation and Reporting The information reported herein reflects all normal recurring adjustments that are, in the opinion of management, necessary for the fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) have been condensed or omitted under Securities and Exchange Commission rules and regulations; as such, this report should be read in conjunction with the financial statements and notes in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017 . The results reported in these unaudited condensed consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year. The condensed consolidated financial statements include the accounts of the Company and its pre-Spin-off subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Noncontrolling interests represented ownership in the net assets of the Company’s previous consolidated subsidiary, Linn Energy Holdco LLC (“Holdco”), not attributable to LINN Energy, and were presented as a component of equity. Changes in the Company’s ownership interests in Holdco that did not result in deconsolidation were recognized in equity. Effective April 10, 2018, all outstanding Class A‑2 units in Holdco (“Holdco Class A-2 units”) were converted into Class A common stock in LINN Energy in accordance with the terms of Holdco’s Limited Liability Company Operating Agreement (the “Holdco LLC Agreement”) and the noncontrolling interest was dissolved. See Note 13 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 6 for additional information about equity method investments. The condensed consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss) or stockholders equity. As a result of the adoption of ASU 2016-18 and the inclusion of restricted cash in the statements of cash flows, previously reported net cash provided by operating activities and cash provided by investing activities have been updated to conform to current presentation. See recently adopted accounting standards below for additional information.
Use of Estimates	Use of Estimates The preparation of the accompanying condensed 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 November 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. The Company adopted this ASU on January 1, 2018, on a retrospective basis. The adoption of this ASU resulted 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 statement of cash flows (see Note 17). 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 (“ASC 606”). The Company adopted this ASU on January 1, 2018, using the modified retrospective transition method. Accordingly, the comparative information for the six months ended June 30, 2017 , has not been adjusted and continues to be reported under the previous revenue standard. The adoption of this ASU impacted the Company’s gross revenues and expenses as reported on its condensed consolidated statements of operations (see below), and resulted in increased disclosures regarding the Company’s disaggregation of revenue (see Note 3). Under ASC 606, the Company recognizes revenues based on a determination of when control of its commodities is transferred and whether it is acting as a principal or agent in certain transactions. All facts and circumstances of an arrangement are considered and judgment is often required in making this determination. For its natural gas contracts, the Company generally records its sales at the wellhead or inlet of the plant as revenues net of transportation, gathering and processing expenses if the processor is the customer and there is no redelivery of commodities to the Company. Conversely, the Company generally records its sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses if the processor is a service provider and there is redelivery of commodities to the Company. In addition, the Company recognizes revenues for commodities received as noncash consideration in exchange for services provided by its midstream operations and revenues and associated cost of product for the subsequent sale of those same commodities. This recognition results in an increase to revenues and expenses with no material impact on net income. The items discussed above impacted the Company’s reported “oil, natural gas and natural gas liquids sales,” “marketing revenues,” “other revenues,” “transportation expenses,” “marketing expenses” and “interest expense.” The impact of adoption on the Company’s current period results is as follows: Three Months Ended June 30, 2018 Under ASC 606 Under Prior Rule Increase/ (Decrease) (in thousands) Revenues: Natural gas sales $ 53,662 $ 53,285 $ 377 Oil sales 10,919 10,919 — NGL sales 22,423 22,280 143 Total oil, natural gas and NGL sales 87,004 86,484 520 Marketing revenues 42,967 25,406 17,561 Other revenues 6,387 6,003 384 136,358 117,893 18,465 Expenses: Transportation expenses 21,213 20,693 520 Marketing expenses 40,327 22,766 17,561 Interest expense 584 420 164 Net income $ 6,903 $ 6,683 $ 220 Six Months Ended June 30, 2018 Under ASC 606 Under Prior Rule Increase/ (Decrease) (in thousands) Revenues: Natural gas sales $ 116,990 $ 117,794 $ (804 ) Oil sales 56,615 56,615 — NGL sales 50,275 50,222 53 Total oil, natural gas and NGL sales 223,880 224,631 (751 ) Marketing revenues 89,234 53,521 35,713 Other revenues 12,281 11,676 605 325,395 289,828 35,567 Expenses: Transportation expenses 40,307 41,058 (751 ) Marketing expenses 82,082 46,369 35,713 Interest expense 988 824 164 Net income $ 78,001 $ 77,560 $ 441 New Accounting Standards Issued But Not Yet Adopted 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 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 sheet resulting from an increase in both assets and liabilities related to the Company’s leasing activities.

Basis of Presentation (Tables)

Basis of Presentation (Tables)	6 Months Ended
	Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	The impact of adoption on the Company’s current period results is as follows: Three Months Ended June 30, 2018 Under ASC 606 Under Prior Rule Increase/ (Decrease) (in thousands) Revenues: Natural gas sales $ 53,662 $ 53,285 $ 377 Oil sales 10,919 10,919 — NGL sales 22,423 22,280 143 Total oil, natural gas and NGL sales 87,004 86,484 520 Marketing revenues 42,967 25,406 17,561 Other revenues 6,387 6,003 384 136,358 117,893 18,465 Expenses: Transportation expenses 21,213 20,693 520 Marketing expenses 40,327 22,766 17,561 Interest expense 584 420 164 Net income $ 6,903 $ 6,683 $ 220 Six Months Ended June 30, 2018 Under ASC 606 Under Prior Rule Increase/ (Decrease) (in thousands) Revenues: Natural gas sales $ 116,990 $ 117,794 $ (804 ) Oil sales 56,615 56,615 — NGL sales 50,275 50,222 53 Total oil, natural gas and NGL sales 223,880 224,631 (751 ) Marketing revenues 89,234 53,521 35,713 Other revenues 12,281 11,676 605 325,395 289,828 35,567 Expenses: Transportation expenses 40,307 41,058 (751 ) Marketing expenses 82,082 46,369 35,713 Interest expense 988 824 164 Net income $ 78,001 $ 77,560 $ 441

Emergence From Voluntary Reor28

Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting (Tables)	6 Months Ended
	Jun. 30, 2018
Emergence From Voluntary Reorganization Under Chapter 11 [Abstract]
Schedule of Reorganization Items	The following table summarizes the components of reorganization items included on the condensed consolidated statements of operations: Successor Three Months Ended June 30, 2018 2017 (in thousands) Legal and other professional advisory fees $ (1,255 ) $ (3,446 ) Other (4 ) 69 Reorganization items, net $ (1,259 ) $ (3,377 ) Successor Predecessor Six Months Ended June 30, 2018 Four Months Ended June 30, 2017 Two Months Ended February 28, 2017 (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 fees (3,207 ) (6,016 ) (46,961 ) Terminated contracts — — (6,915 ) Other (3 ) 74 (13,049 ) Reorganization items, net $ (3,210 ) $ (5,942 ) $ 2,331,189

Revenues (Tables)

Revenues (Tables)	6 Months Ended
	Jun. 30, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	The following tables present the Company’s disaggregated revenues by source and geographic area: Three Months Ended June 30, 2018 Natural Gas Oil NGL Oil, Natural Gas and NGL Sales Marketing Revenues Other Revenues Total (in thousands) Hugoton Basin $ 17,401 $ 238 $ 16,875 $ 34,514 $ 22,421 $ 6,303 $ 63,238 Mid-Continent 7,622 4,880 3,307 15,809 — 25 15,834 East Texas 12,661 1,091 1,013 14,765 467 3 15,235 Permian Basin 256 546 (488 ) 314 — 16 330 Rockies 2,146 1,885 1,201 5,232 — 1 5,233 North Louisiana 6,040 1,480 503 8,023 13 2 8,038 Michigan/Illinois 7,536 799 12 8,347 — 37 8,384 Chisholm Trail — — — — 20,066 — 20,066 Total $ 53,662 $ 10,919 $ 22,423 $ 87,004 $ 42,967 $ 6,387 $ 136,358 Six Months Ended June 30, 2018 Natural Gas Oil NGL Oil, Natural Gas and NGL Sales Marketing Revenues Other Revenues Total (in thousands) Hugoton Basin $ 39,764 $ 2,970 $ 36,389 $ 79,123 $ 46,501 $ 12,134 $ 137,758 Mid-Continent 15,555 16,747 6,361 38,663 — 39 38,702 East Texas 27,437 2,431 2,319 32,187 503 8 32,698 Permian Basin 2,282 20,654 2,557 25,493 — 32 25,525 Rockies 5,526 9,255 2,559 17,340 — (1 ) 17,339 North Louisiana 12,418 3,049 67 15,534 272 3 15,809 Michigan/Illinois 14,008 1,509 23 15,540 — 66 15,606 Chisholm Trail — — — — 41,958 — 41,958 Total $ 116,990 $ 56,615 $ 50,275 $ 223,880 $ 89,234 $ 12,281 $ 325,395

Divestitures and Discontinued30

Divestitures and Discontinued Operations (Tables)	6 Months Ended
	Jun. 30, 2018
Discontinued Operations [Abstract]
Disclosure of Long Lived Assets Held-for-sale	The following table presents carrying amounts of the assets and liabilities of the Company’s properties classified as held for sale on the condensed consolidated balance sheet: 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.
Summarized statements of operations	The following tables present summarized financial results of the Company’s California properties classified as discontinued operations on the condensed consolidated statements of operations: Successor Predecessor Three Months Ended June 30, 2017 Four Months Ended June 30, 2017 Two Months Ended February 28, 2017 (in thousands) Revenues and other $ 20,511 $ 27,636 $ 14,891 Expenses 25,935 30,344 13,758 Other income and (expenses) (2,074 ) (2,791 ) (1,681 ) Loss from discontinued operations before income taxes (7,498 ) (5,499 ) (548 ) Income tax benefit (4,176 ) (2,245 ) — Loss from discontinued operations, net of income taxes $ (3,322 ) $ (3,254 ) $ (548 ) Other income and (expenses) include an allocation of interest expense for the California properties 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 .

Oil and Natural Gas Properties

Oil and Natural Gas Properties (Tables)	6 Months Ended
	Jun. 30, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized Costs Related to Oil, Natural Gas and NGL Production Activities	Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below: June 30, 2018 December 31, 2017 (in thousands) Proved properties $ 739,656 $ 904,390 Unproved properties 46,159 45,693 785,815 950,083 Less accumulated depletion and amortization (59,870 ) (49,619 ) $ 725,945 $ 900,464

Equity Method Investments (Tabl

Equity Method Investments (Tables)	6 Months Ended
	Jun. 30, 2018
Equity Method Investments [Abstract]
Summarized Roan Resources LLC statement of operations information	Following is summarized statements of operations information for Roan. Summarized Roan Resources LLC Statements of Operations Information Three Months Ended June 30, 2018 Six Months Ended June 30, 2018 (in thousands) Revenues and other $ 44,789 $ 145,873 Expenses 72,754 130,663 Other income and (expenses) (1,087 ) (2,886 ) Net income (loss) $ (29,052 ) $ 12,324

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments	The following table presents derivative positions for the periods indicated as of June 30, 2018 : July 1 – December 31, 2018 2019 Natural gas positions: Fixed price swaps (NYMEX Henry Hub): Hedged volume (MMMBtu) 35,144 22,265 Average price ($/MMBtu) $ 3.02 $ 2.89 Oil positions: Fixed price swaps (NYMEX WTI): Hedged volume (MBbls) 276 183 Average price ($/Bbl) $ 54.07 $ 64.00 Natural gas basis differential positions: (1) PEPL basis swaps: Hedged volume (MMMBtu) 7,360 14,600 Hedge differential $ (0.67 ) $ (0.67 ) NGPL TXOK basis swaps: Hedged volume (MMMBtu) 1,840 — Hedge differential $ (0.19 ) $ — (1) Settled or to be settled, as applicable, on the indicated pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.
Fair Value of Derivatives Outstanding on a Gross Basis by Location on the Balance Sheets	The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the condensed consolidated balance sheets. The following table summarizes the fair value of derivatives outstanding on a gross basis: June 30, 2018 December 31, 2017 (in thousands) Assets: Commodity derivatives $ 6,825 $ 22,589 Liabilities: Commodity derivatives $ 7,197 $ 25,443

Fair Value Measurements on a 34

Fair Value Measurements on a Recurring Basis (Tables)	6 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements, Recurring Basis	The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis: June 30, 2018 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 6,825 $ (1,637 ) $ 5,188 Liabilities: Commodity derivatives $ 7,197 $ (1,637 ) $ 5,560 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 (1) Represents counterparty netting under agreements governing such derivatives.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations Reconciliation	The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands): Asset retirement obligations at December 31, 2017 $ 164,553 Liabilities added from drilling 53 Liabilities associated with assets divested (62,195 ) Current year accretion expense 4,081 Settlements (1,859 ) Revisions of estimates 2,386 Asset retirement obligations at June 30, 2018 $ 107,019

Share-Based Compensation (Table

Share-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share/Unit-Based Compensation	A summary of share-based compensation expenses included on the condensed consolidated statements of operations is presented below: Three Months Ended June 30, 2018 2017 (in thousands) General and administrative expenses $ 58,188 $ 15,422 Income tax benefit $ 4,315 $ 3,128 Successor Predecessor Six Months Ended June 30, 2018 Four Months Ended June 30, 2017 Two Months Ended February 28, 2017 (in thousands) General and administrative expenses $ 75,225 $ 19,599 $ 50,255 Income tax benefit $ 6,732 $ 3,555 $ 5,170

Earnings Per Share_Unit (Tables

Earnings Per Share/Unit (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The following tables provide a reconciliation of the numerators and denominators of the basic and diluted per share/unit computations for net income: Successor Three Months Ended June 30, 2018 Income Shares Per Share (in thousands, except per share data) Basic: Net income attributable to common stockholders $ 5,104 78,718 $ 0.06 Effect of Dilutive Securities: Dilutive effect of restricted stock units 559 Dilutive effect of unvested Class A-2 units of Holdco $ — — Diluted: Net income attributable to common stockholders $ 5,104 79,277 $ 0.06 Successor Three Months Ended June 30, 2017 Income Shares Per Share (in thousands, except per share data) Basic: Income from continuing operations $ 223,379 89,849 $ 2.49 Loss from discontinued operations, net of income taxes (3,322 ) 89,849 (0.04 ) Net income attributable to common stockholders $ 220,057 89,849 $ 2.45 Effect of Dilutive Securities: Dilutive effect of restricted stock units $ — 635 Diluted: Income from continuing operations $ 223,379 90,484 $ 2.47 Loss from discontinued operations (3,322 ) 90,484 (0.04 ) Net income attributable to common stockholders $ 220,057 90,484 $ 2.43 Successor Six Months Ended June 30, 2018 Income Shares Per Share (in thousands, except per share data) Basic: Net income attributable to common stockholders $ 74,928 78,817 $ 0.95 Effect of Dilutive Securities: Dilutive effect of restricted stock units $ — 947 Dilutive effect of unvested Class A-2 units of Holdco $ (1,140 ) — Diluted: Net income attributable to common stockholders $ 73,788 79,764 $ 0.93 Successor Four Months Ended June 30, 2017 Income Shares Per Share (in thousands, except per share data) Basic: Income from continuing operations $ 216,055 89,849 $ 2.41 Loss from discontinued operations, net of income taxes (3,254 ) 89,849 (0.04 ) Net income attributable to common stockholders $ 212,801 89,849 $ 2.37 Effect of Dilutive Securities: Dilutive effect of restricted stock units $ — 216 Diluted: Income from continuing operations $ 216,055 90,065 $ 2.40 Loss from discontinued operations (3,254 ) 90,065 (0.04 ) Net income attributable to common stockholders $ 212,801 90,065 $ 2.36 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

Supplemental Disclosures to t38

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Tables)	6 Months Ended
	Jun. 30, 2018
Supplemental Disclosures to the Condensed Consolidated Statements of Cash Flows [Abstract]
Other Current Assets	“Other current assets” reported on the condensed consolidated balance sheets include the following: June 30, 2018 December 31, 2017 (in thousands) Prepaids $ 14,209 $ 46,238 Receivable from related party 25,982 23,163 Inventories 3,981 7,667 Other 2,487 2,703 Other current assets $ 46,659 $ 79,771
Other Current Liabilities	“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following: June 30, 2018 December 31, 2017 (in thousands) Accrued compensation $ 13,533 $ 29,089 Asset retirement obligations (current portion) 1,488 3,926 Deposits 3,170 15,349 Income taxes payable 23 7,496 Other 1,616 2,757 Other accrued liabilities $ 19,830 $ 58,617
Reconciliation of cash, cash equivalents and restricted cash	The following table provides a reconciliation of cash and cash equivalents on the condensed consolidated balance sheets to cash, cash equivalents and restricted cash on the condensed consolidated statement of cash flows: June 30, 2018 December 31, 2017 (in thousands) Cash and cash equivalents $ 301,365 $ 464,508 Restricted cash 43,387 56,445 Cash, cash equivalents and restricted cash $ 344,752 $ 520,953
Supplemental Disclosures to the Condensed Consolidated Statements of Cash Flows	Supplemental disclosures to the condensed consolidated statements of cash flows are presented below: Successor Predecessor Six Months Ended June 30, 2018 Four Months Ended June 30, 2017 Two Months Ended February 28, 2017 (in thousands) Cash payments for interest, net of amounts capitalized $ — $ 14,436 $ 17,651 Cash payments for income taxes $ 7,748 $ 215 $ — Cash payments for reorganization items, net $ 2,911 $ 6,300 $ 21,571 Noncash investing activities: Accrued capital expenditures $ 21,968 $ 34,547 $ 22,191

Segments (Tables)

Segments (Tables)	6 Months Ended
	Jun. 30, 2018
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	The following tables present the Company’s financial information by reportable segment: Successor Three Months Ended June 30, 2018 Upstream Chisholm Trail Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 87,004 $ — $ — $ 87,004 Marketing revenues 22,901 20,066 — 42,967 Other revenues 6,387 — — 6,387 116,292 20,066 — 136,358 Lease operating expenses 24,088 — — 24,088 Transportation expenses 21,213 — — 21,213 Marketing expenses 20,244 20,083 — 40,327 Taxes other than income taxes 6,737 285 275 7,297 Total direct operating expenses 72,282 20,368 275 92,925 Field level cash flow $ 44,010 $ (302 ) (275 ) 43,433 Losses on oil and natural gas derivatives (7,525 ) (7,525 ) Other indirect income (expenses) (23,283 ) (23,283 ) Income from continuing operations before income taxes $ 12,625 Successor Three Months Ended June 30, 2017 Upstream Chisholm Trail Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 243,167 $ — $ — $ 243,167 Marketing revenues 10,793 1,754 — 12,547 Other revenues 6,391 — — 6,391 260,351 1,754 — 262,105 Lease operating expenses 71,057 — — 71,057 Transportation expenses 37,388 — — 37,388 Marketing expenses 6,156 820 — 6,976 Taxes other than income taxes 17,486 116 269 17,871 Total direct operating expenses 132,087 936 269 133,292 Field level cash flow $ 128,264 $ 818 (269 ) 128,813 Gains on oil and natural gas derivatives 45,714 45,714 Other indirect income (expenses) 207,622 207,622 Income from continuing operations before income taxes $ 382,149 Successor Six Months Ended June 30, 2018 Upstream Chisholm Trail Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 223,880 $ — $ — $ 223,880 Marketing revenues 47,276 41,958 — 89,234 Other revenues 12,281 — — 12,281 283,437 41,958 — 325,395 Lease operating expenses 71,972 — — 71,972 Transportation expenses 40,307 — — 40,307 Marketing expenses 41,380 40,702 — 82,082 Taxes other than income taxes 14,908 477 364 15,749 Total direct operating expenses 168,567 41,179 364 210,110 Field level cash flow $ 114,870 $ 779 (364 ) 115,285 Losses on oil and natural gas derivatives (22,555 ) (22,555 ) Other indirect income (expenses) 31,167 31,167 Income from continuing operations before income taxes $ 123,897 Successor Four Months Ended June 30, 2017 Upstream Chisholm Trail Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 323,492 $ — $ — $ 323,492 Marketing revenues 13,273 2,188 — 15,461 Other revenues 8,419 — — 8,419 345,184 2,188 — 347,372 Lease operating expenses 95,687 — — 95,687 Transportation expenses 51,111 — — 51,111 Marketing expenses 8,513 1,002 — 9,515 Taxes other than income taxes 24,478 155 315 24,948 Total direct operating expenses 179,789 1,157 315 181,261 Field level cash flow $ 165,395 $ 1,031 (315 ) 166,111 Gains on oil and natural gas derivatives 33,755 33,755 Other indirect income (expenses) 169,644 169,644 Income from continuing operations before income taxes $ 369,510 Predecessor Two Months Ended February 28, 2017 Upstream Chisholm Trail Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 188,885 $ — $ — $ 188,885 Marketing revenues 5,999 637 — 6,636 Other revenues 9,915 — — 9,915 204,799 637 — 205,436 Lease operating expenses 49,665 — — 49,665 Transportation expenses 25,972 — — 25,972 Marketing expenses 4,602 218 — 4,820 Taxes other than income taxes 14,773 78 26 14,877 Total direct operating expenses 95,012 296 26 95,334 Field level cash flow $ 109,787 $ 341 (26 ) 110,102 Gains on oil and natural gas derivatives 92,691 92,691 Other indirect income (expenses) 2,194,650 2,194,650 Income from continuing operations before income taxes $ 2,397,443

Basis of Presentation Details (

Basis of Presentation Details (Details) - Successor - USD ($) $ in Thousands	3 Months Ended		4 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Item Effected [Line Items]
Natural Gas	$ 53,662			$ 116,990
Oil	10,919			56,615
NGL	22,423			50,275
Oil, natural gas and natural gas liquids sales	87,004	$ 243,167	$ 323,492	223,880
Marketing revenues	42,967	12,547	15,461	89,234
Other revenues	6,387	6,391	8,419	12,281
Revenues	136,358	262,105	347,372	325,395
Transportation expenses	21,213	37,388	51,111	40,307
Marketing expenses	40,327	6,976	9,515	82,082
Interest expense	584	7,551	11,751	988
Net income	6,903	$ 220,057	$ 212,801	78,001
Accounting Standards Update 2014-09 [Member]
Item Effected [Line Items]
Natural Gas	377			(804)
Oil	0			0
NGL	143			53
Oil, natural gas and natural gas liquids sales	520			(751)
Marketing revenues	17,561			35,713
Other revenues	384			605
Revenues	18,465			35,567
Transportation expenses	520			(751)
Marketing expenses	17,561			35,713
Interest expense	164			164
Net income	220			441
ASC 606 [Member]
Item Effected [Line Items]
Natural Gas	53,662			116,990
Oil	10,919			56,615
NGL	22,423			50,275
Oil, natural gas and natural gas liquids sales	87,004			223,880
Marketing revenues	42,967			89,234
Other revenues	6,387			12,281
Revenues	136,358			325,395
Transportation expenses	21,213			40,307
Marketing expenses	40,327			82,082
Interest expense	584			988
Net income	6,903			78,001
ASC 605 [Member]
Item Effected [Line Items]
Natural Gas	53,285			117,794
Oil	10,919			56,615
NGL	22,280			50,222
Oil, natural gas and natural gas liquids sales	86,484			224,631
Marketing revenues	25,406			53,521
Other revenues	6,003			11,676
Revenues	117,893			289,828
Transportation expenses	20,693			41,058
Marketing expenses	22,766			46,369
Interest expense	420			824
Net income	$ 6,683			$ 77,560

Emergence From Voluntary Reor41

Emergence From Voluntary Reorganization Under Chapter 11 and Fresh Start Accounting Reorganization (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Predecessor
Reorganization Items
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	(46,961)
Terminated contracts	(6,915)
Other	(13,049)
Total reorganization items, net	$ 2,331,189
Successor
Reorganization Items
Gain on settlement of liabilities subject to compromise				$ 0	$ 0
Recognition of an additional claim for the Predecessor’s Second Lien Notes settlement				0	0
Fresh start valuation adjustments				0	0
Income tax benefit related to implementation of the Plan				0	0
Legal and other professional advisory fees		$ (1,255)	$ (3,446)	(6,016)	(3,207)
Terminated contracts				0	0
Other		(4)	69	74	(3)
Total reorganization items, net		$ (1,259)	$ (3,377)	$ (5,942)	$ (3,210)

Revenues (Details)

Revenues (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Contract with Customer, Accounts Receivable	$ 56	$ 117

Revenues Disaggregated revenues

Revenues Disaggregated revenues (Details) - Successor - USD ($) $ in Thousands	3 Months Ended		4 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Natural Gas	$ 53,662			$ 116,990
Oil	10,919			56,615
NGL	22,423			50,275
Oil, natural gas and natural gas liquids sales	87,004	$ 243,167	$ 323,492	223,880
Marketing revenues	42,967	12,547	15,461	89,234
Other revenues	6,387	6,391	8,419	12,281
Total	136,358	$ 262,105	$ 347,372	325,395
East Texas
Disaggregation of Revenue [Line Items]
Natural Gas	12,661			27,437
Oil	1,091			2,431
NGL	1,013			2,319
Oil, natural gas and natural gas liquids sales	14,765			32,187
Marketing revenues	467			503
Other revenues	3			8
Total	15,235			32,698
Hugoton Basin
Disaggregation of Revenue [Line Items]
Natural Gas	17,401			39,764
Oil	238			2,970
NGL	16,875			36,389
Oil, natural gas and natural gas liquids sales	34,514			79,123
Marketing revenues	22,421			46,501
Other revenues	6,303			12,134
Total	63,238			137,758
Mid-Continent
Disaggregation of Revenue [Line Items]
Natural Gas	7,622			15,555
Oil	4,880			16,747
NGL	3,307			6,361
Oil, natural gas and natural gas liquids sales	15,809			38,663
Marketing revenues	0			0
Other revenues	25			39
Total	15,834			38,702
Permian Basin
Disaggregation of Revenue [Line Items]
Natural Gas	256			2,282
Oil	546			20,654
NGL	(488)			2,557
Oil, natural gas and natural gas liquids sales	314			25,493
Marketing revenues	0			0
Other revenues	16			32
Total	330			25,525
Rockies
Disaggregation of Revenue [Line Items]
Natural Gas	2,146			5,526
Oil	1,885			9,255
NGL	1,201			2,559
Oil, natural gas and natural gas liquids sales	5,232			17,340
Marketing revenues	0			0
Other revenues	1			(1)
Total	5,233			17,339
North Louisiana
Disaggregation of Revenue [Line Items]
Natural Gas	6,040			12,418
Oil	1,480			3,049
NGL	503			67
Oil, natural gas and natural gas liquids sales	8,023			15,534
Marketing revenues	13			272
Other revenues	2			3
Total	8,038			15,809
Michigan/Illinois
Disaggregation of Revenue [Line Items]
Natural Gas	7,536			14,008
Oil	799			1,509
NGL	12			23
Oil, natural gas and natural gas liquids sales	8,347			15,540
Marketing revenues	0			0
Other revenues	37			66
Total	8,384			15,606
ChisholmTrail [Domain]
Disaggregation of Revenue [Line Items]
Natural Gas	0			0
Oil	0			0
NGL	0			0
Oil, natural gas and natural gas liquids sales	0			0
Marketing revenues	20,066			41,958
Other revenues	0			0
Total	$ 20,066			$ 41,958

Divestitures and Discontinued44

Divestitures and Discontinued Operations (Details) - USD ($) $ in Thousands	Jul. 31, 2017	Jun. 30, 2017	Apr. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017
ASSETS
Assets held for sale, oil and natural gas properties						$ 92,245
Assets held for sale, property and other equipment						12,983
Assets held for sale, other assets						1,735
Assets held for sale				$ 22		106,963
Liabilities [Abstract]
Liabilities held for sale, asset retirement obligations						42,001
Liabilities held for sale, other liabilities						1,301
Liabilities held for sale				0		43,302
Deposits				3,170		15,349
Successor
Liabilities [Abstract]
Liabilities held for sale		$ 43,000
West Texas Assets Sale [Member]
Liabilities [Abstract]
Proceeds from Divestiture of Businesses					$ 107,000
Costs Associated With Sale of Oil and Gas Property and Equipment	$ 2,000
Gain (Loss) on Disposition of Oil and Gas Property					55,000
OK Waterfloods & TXPHS [Member]
Liabilities [Abstract]
Proceeds from Divestiture of Businesses					112,000
Deposits						$ 12,000
Costs Associated With Sale of Oil and Gas Property and Equipment					1,000
Gain (Loss) on Disposition of Oil and Gas Property					$ 46,000
OK Waterfloods & TXPHS [Member] | Successor
ASSETS
Assets held for sale		107,000
New Mexico Assets Sale [Member]
Liabilities [Abstract]
Proceeds from Divestiture of Businesses			$ 15,000
Gain (Loss) on Disposition of Oil and Gas Property				11,000
Altamont Bluebell Assets Sale [Member]
Liabilities [Abstract]
Proceeds from Divestiture of Businesses			132,000
Costs Associated With Sale of Oil and Gas Property and Equipment			$ 2,000
Gain (Loss) on Disposition of Oil and Gas Property				$ 83,000
Salt Creek [Member] | Successor
Liabilities [Abstract]
Proceeds from Divestiture of Businesses		76,000
Gain (Loss) on Disposition of Oil and Gas Property		22,000
May-June 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual management fee		6,000
March-April 2017 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contractual management fee		$ 2,700

Divestitures and Discontinued45

Divestitures and Discontinued Operations Discontinued summary financial information (Details) - USD ($) $ in Thousands	May 31, 2017	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Successor
Discontinued operations - Income statement disclosures
Revenues and other				$ 20,511	$ 27,636
Expenses				25,935	30,344
Other income and (expenses)				(2,074)	(2,791)
Income (loss) from discontinued operations before income taxes				(7,498)	(5,499)
Income tax expense				(4,176)	(2,245)
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest			$ 0	$ (3,322)	$ (3,254)	$ 0
Predecessor
Discontinued operations - Income statement disclosures
Revenues and other		$ 14,891
Expenses		13,758
Other income and (expenses)		(1,681)
Income (loss) from discontinued operations before income taxes		(548)
Income tax expense		0
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest		$ (548)
Jonah [Member] | Successor
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 560,000
Discontinued operations - Income statement disclosures
Costs Associated With Sale of Oil and Gas Property and Equipment	6,000
Gain (Loss) on Disposition of Oil and Gas Property	$ 279,000

Oil and Natural Gas Propertie46

Oil and Natural Gas Properties (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved properties	$ 739,656	$ 904,390
Unproved properties	46,159	45,693
Oil and natural gas properties (successful efforts method)	785,815	950,083
Less accumulated depletion and amortization	(59,870)	(49,619)
Oil and natural gas properties, successful efforts method, net	$ 725,945	$ 900,464

Equity Method Investments (Deta

Equity Method Investments (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 473,269	$ 464,926
Roan Resources LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%	50.00%
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 355,000
Successor | Roan Resources LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Equity method investments	$ 466,000	$ 458,000
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity		$ 346,000

Equity Method Investments Summa

Equity Method Investments Summarized Roan Resources LLC Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018
Equity Method Investments [Abstract]
Revenues and other	$ 44,789	$ 145,873
Expenses	72,754	130,663
Other income and (expenses)	(1,087)	(2,886)
Net income (loss)	$ (29,052)	$ 12,324

Debt (Details)

Debt (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018USD ($)	Apr. 30, 2018USD ($)
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		$ 425
Line of Credit Facility, Maximum Borrowing Capacity	$ 500
Long-term Line of Credit	0
Line of Credit Facility, Remaining Borrowing Capacity	378
Letters of Credit Outstanding, Amount	$ 47
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
Line Of Credit Facility Portion Of Properties Required To Maintain Mortgages	85.00%
Debt to EBITDAX Ratio	4
Current Ratio	1
London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
ABR [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
ABR [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.50%

Derivatives (Commodity Derivati

Derivatives (Commodity Derivatives) (Details)		1 Months Ended
		Apr. 30, 2018USD ($)	Jun. 30, 2018USD ($)MMMBTUMBbls$ / bbl$ / MMBTU
Derivative [Line Items]
Settlements on Canceled Derivatives | $		$ 20,000,000
Year 2018 [Member] | Natural Gas Commodity Contract [Member] | Swap [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)			35,144
Average price (in usd per energy unit) | $ / MMBTU			3.02
Year 2018 [Member] | Oil Commodity Contract [Member] | Swap [Member]
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls			276
Average price (in usd per energy unit) | $ / bbl			54.07
Year 2018 [Member] | Swap [Member] | Swap [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	[1]		7,360
Hedged Differential | $	[1]		$ (0.67)
Year 2018 [Member] | Basis Swap [Member] | Swap [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	[1]		1,840
Hedged Differential | $	[1]		$ (0.19)
Year 2019 [Member] | Natural Gas Commodity Contract [Member] | Swap [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)			22,265
Average price (in usd per energy unit) | $ / MMBTU			2.89
Year 2019 [Member] | Oil Commodity Contract [Member] | Swap [Member]
Derivative [Line Items]
Hedged Volume (in energy unit) | MBbls			183
Average price (in usd per energy unit) | $ / bbl			64
Year 2019 [Member] | Swap [Member] | Swap [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	[1]		14,600
Hedged Differential | $	[1]		$ (0.67)
Year 2019 [Member] | Basis Swap [Member] | Swap [Member]
Derivative [Line Items]
Hedged Volume (in energy unit)	[1]		0
Hedged Differential | $	[1]		$ 0
[1]	Settled or to be settled, as applicable, on the indicated pricing index to hedge basis differential to the NYMEX Henry Hub natural gas price.

Derivatives (Balance Sheet Pres

Derivatives (Balance Sheet Presentation) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Assets:
Commodity derivatives	$ 6,825	$ 22,589
Liabilities:
Commodity derivatives	7,197	$ 25,443
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 7,000

Derivatives (Gains (Losses) On

Derivatives (Gains (Losses) On Derivatives) (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure					$ 7,000
Successor
Derivative Instruments, Gain (Loss) [Line Items]
Gains (losses) on oil and natural gas derivatives		$ (7,525)	$ 45,714	$ 33,755	(22,555)
Cash settlements on derivatives		$ (21,000)	$ 2,000	$ 7,929	$ (25,037)
Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Gains (losses) on oil and natural gas derivatives	$ 92,691
Cash settlements on derivatives	$ (11,572)

Fair Value Measurements on a 53

Fair Value Measurements on a Recurring Basis (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
Assets:
Commodity derivatives		$ 6,825	$ 22,589
Commodity derivatives	[1]	(1,637)	(12,491)
Commodity derivatives		5,188	10,098
Liabilities:
Commodity derivatives		7,197	25,443
Commodity derivatives	[1]	(1,637)	(12,491)
Commodity derivatives		$ 5,560	$ 12,952
[1]	Represents counterparty netting under agreements governing such derivatives.

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2018USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at December 31, 2017	$ 164,553
Liabilities added from drilling	53
Liabilities associated with assets divested	62,195
Current year accretion expense	4,081
Settlements	(1,859)
Asset retirement obligations at June 30, 2018	107,019
Asset Retirement Obligation, Revision of Estimate	$ (2,386)

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Loss Contingency, Damages Sought, Value	$ 31,000
Payments for Legal Settlements	$ 0	$ 0

Equity Equity Offering (Details

Equity Equity Offering (Details) - USD ($) $ / shares in Units, $ in Thousands	Aug. 07, 2018	Jul. 31, 2018	Jan. 31, 2018	Jun. 30, 2017	Jun. 30, 2018	Jul. 31, 2018	Dec. 31, 2017	Dec. 14, 2017	Oct. 04, 2017
Schedule of Equity Offerings [Line Items]
Common stock issued					78,749,510		83,582,176
Issuances of successor Class A common stock					2,785,681
Stock Repurchase Program, Authorized Amount									$ 400,000
Stock Repurchased During Period, Shares					1,557,180
Accelerated Share Repurchases, Final Price Paid Per Share					$ 39.13
Accelerated Share Repurchases, Settlement (Payment) or Receipt					$ 61,000
Subsequent Event [Member]
Schedule of Equity Offerings [Line Items]
Stock Repurchased During Period, Shares	2,477,834	280,289				7,527,661
Accelerated Share Repurchases, Final Price Paid Per Share		$ 40.30				$ 35.94
Accelerated Share Repurchases, Settlement (Payment) or Receipt	$ 271,000	$ 11,000				$ 11,000
Restricted Stock Units (RSUs) [Member]
Schedule of Equity Offerings [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number					922,696
Tender offer [Member]
Schedule of Equity Offerings [Line Items]
Stock Repurchase Program, Authorized Amount								$ 250,000
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
Share tender, fees			$ 4,000
Successor
Schedule of Equity Offerings [Line Items]
Issuances of successor Class A common stock					2,786,000
Stock Repurchased During Period, Shares				7,540
Accelerated Share Repurchases, Final Price Paid Per Share				$ 30.48
Accelerated Share Repurchases, Settlement (Payment) or Receipt				$ 230

Noncontrolling Interests (Detai

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

Share-Based Compensation (Detai

Share-Based Compensation (Details) - USD ($) $ in Thousands	Aug. 07, 2018	Jul. 31, 2018	Jun. 30, 2018	Jun. 30, 2018	Jul. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Plan Modification, Incremental Compensation Cost				$ 18,000
Stock Repurchased During the Period, Restricted Stock Units			271,314
Stock Repurchased During Period, Shares				1,557,180
Cash settlements of equity classified RSUs			$ 11,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant			4,700,000	4,700,000
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, Equity Instruments Other than Options, Grants in Period				12,500
Stock Issued During Period, Value, Restricted Stock Award, Gross				$ 519
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number			922,696	922,696
Liquidity program [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Repurchased During the Period, Restricted Stock Units				1,028,875
Employee Service Share-based Compensation, Cash Flow Effect, Cash Used to Settle Awards				$ 45,000
Stock Repurchased During Period, Shares				120,829
Subsequent Event [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Repurchased During Period, Shares	2,477,834	280,289			7,527,661
Cash settlements of equity classified RSUs	$ 102,000

Share-Based Compensation (Compe

Share-Based Compensation (Compensation Expenses) (Details) - USD ($) $ / shares in Units, $ in Thousands	2 Months Ended		3 Months Ended		4 Months Ended	6 Months Ended
	Jun. 30, 2018	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018	Dec. 31, 2017
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	4,700,000		4,700,000			4,700,000
Stock Repurchased During the Period, Restricted Stock Units	271,314
Cash settlements of equity classified RSUs	$ 11,000
Share-based payment liability	111,792		$ 111,792			$ 111,792	$ 0
Successor
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Cash settlements of equity classified RSUs					$ 0	58,162
Share/unit-based compensation expenses					19,599	75,225
Income tax benefit					$ 3,555	6,732
Predecessor
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Earnings Per Share, Basic and Diluted		$ 6.79
Cash settlements of equity classified RSUs		$ 0
Share/unit-based compensation expenses		50,255	58,188	$ 15,422
Income tax benefit		$ 5,170	4,315	$ 3,128
Common Class A [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Share-based payment liability	$ 112,000		$ 112,000			$ 112,000

Earnings Per Share_Unit (Detail

Earnings Per Share/Unit (Details) - shares	2 Months Ended	3 Months Ended	4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018
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)				1,989
Earnings Per Share, Potentially Dilutive Securities	0
Class B Units [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)		3,470,051	3,470,051

Earnings Per Share_Unit EPS Cal

Earnings Per Share/Unit EPS Calculation (Details) - USD ($) $ / shares in Units, shares in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Effect of Dilutive Securities:
Dilutive effect of restricted stock units		559			947
Basic and Diluted:
Dilutive Securities, Effect on Basic Earnings Per Share, Options and Restrictive Stock Units		$ 0	$ 0	$ 0	$ 0
Predecessor
Basic:
Weighted average shares outstanding - basic	352,792
Net income attributable to common stockholders	$ 6.79
Diluted:
Weighted average shares outstanding - diluted	(352,792)
Net income attributable to common stockholders	$ 6.79
Basic and Diluted:
Loss from continuing operations	$ 2,397,609,000
Weighted Average Number of Shares Outstanding, Basic and Diluted	352,792
Income (Loss) from Continuing Operations, Per Basic and Diluted Share	$ 6.80
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic and Diluted Share	(0.01)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	(0.01)
Income (Loss) from Continuing Operations, Per Basic Share	$ 6.80
Loss from discontinued operations, net of income taxes	$ (548,000)
Net income	$ 2,397,061,000
Loss from continuing operations	$ 6.80
Loss from discontinued operations, net of income taxes	(0.01)
Earnings Per Share, Basic and Diluted	$ 6.79
Successor
Basic:
Net income attributable to common stockholders		$ 5,104,000			$ 74,928,000
Weighted average shares outstanding - basic		78,718	89,849	89,849	78,817
Net income attributable to common stockholders		$ 0.06	$ 2.45	$ 2.37	$ 0.95
Effect of Dilutive Securities:
Dilutive effect of unvested Class A-2 units of Holdco		$ 0			$ (1,140,000)
Dilutive effect of restricted stock units		0	635	216	0
Diluted:
Net income attributable to common stockholders		$ 5,104,000			$ 73,788,000
Weighted average shares outstanding - diluted		(79,277)	(90,484)	(90,065)	(79,764)
Net income attributable to common stockholders		$ 0.06	$ 2.43	$ 2.36	$ 0.93
Basic and Diluted:
Loss from continuing operations			$ 223,379,000	$ 216,055,000
Weighted Average Number of Shares Outstanding, Basic and Diluted			89,849	89,849
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share		0	$ (0.04)	$ (0.04)	0
Income (Loss) from Continuing Operations, Per Basic Share		$ 0.06	$ 2.49	$ 2.41	$ 0.95
Loss from discontinued operations, net of income taxes			$ (3,322,000)	$ (3,254,000)	$ 0
Net income		$ 5,104,000	$ 220,057,000	$ 212,801,000	$ 74,928,000
Loss from continuing operations		$ 0.06	$ 2.47	$ 2.40	$ 0.93
Loss from discontinued operations, net of income taxes		$ 0	$ (0.04)	$ (0.04)	$ 0

Income Taxes Details (Details)

Income Taxes Details (Details)	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation, Percent	0.00%	45.00%	42.00%	42.00%
Blended Tax Rate					24.00%

Supplemental Disclosures to t63

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Cash Flows) (Details) - USD ($) $ in Thousands	2 Months Ended	4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2017	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Schedule of supplemental cash flow disclosures [Line Items]
Cash and cash equivalents			$ 301,365	$ 464,508
Restricted cash			43,387	56,445
Cash payments for interest, net of amounts capitalized	$ 17,651	$ 14,436	0
Cash payments for income taxes	0	215	7,748
Cash payments for reorganization items, net	21,571	6,300	2,911
Noncash investing activities:
Accrued capital expenditures	22,191	34,547	21,968
Successor
Schedule of supplemental cash flow disclosures [Line Items]
Cash, cash equivalents and restricted cash	144,022	$ 115,519	344,752	520,953
Predecessor
Schedule of supplemental cash flow disclosures [Line Items]
Increase (Decrease) in Restricted Cash for Operating Activities	80,000
Cash, cash equivalents and restricted cash	$ 144,022				$ 704,234
Professional fees [Member] | Successor
Schedule of supplemental cash flow disclosures [Line Items]
Restricted cash			33,000	36,000
Deposits for divestitures [Member] | Successor
Schedule of supplemental cash flow disclosures [Line Items]
Restricted cash			3,000	15,000
Other [Member] | Successor
Schedule of supplemental cash flow disclosures [Line Items]
Restricted cash			$ 7,000	$ 5,000

Supplemental Disclosures to t64

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows Balance Sheet (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Other current assets
Prepaids	$ 14,209	$ 46,238
Receivable from related party	25,982	23,163
Inventories	3,981	7,667
Other	2,487	2,703
Other current assets	46,659	79,771
Other accrued liabilities
Accrued compensation	13,533	29,089
Asset retirement obligations (current portion)	1,488	3,926
Deposits	3,170	15,349
Income taxes payable	23	7,496
Other	1,616	2,757
Other accrued liabilities	$ 19,830	$ 58,617

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Jun. 30, 2018	Aug. 31, 2017
Roan Resources LLC [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage						50.00%
Related party monthly fee		$ 1,000	$ 1,250		$ 5,000
Related Party Transaction, Purchases from Related Party		15,000			32,000
Revenue from Related Parties				$ 23,000	26,000
Due to Related Parties, Current		$ 11,000		$ 18,000	$ 11,000
Berry [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Other Revenues from Transactions with Related Party	$ 6,000
LinnCo [Member]
Related Party Transaction [Line Items]
General and administrative expenses	287
Related Party Transaction, Amounts of Transaction	$ 240

Segments Segments (Details)

Segments Segments (Details) - USD ($) $ in Thousands	2 Months Ended	3 Months Ended		4 Months Ended	6 Months Ended
	Feb. 28, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2017	Jun. 30, 2018
Predecessor
Segment Reporting Information [Line Items]
Oil, natural gas and natural gas liquids sales	$ 188,885
Marketing revenues	6,636
Other revenues	9,915
Total	205,436
Lease operating expenses	49,665
Transportation expenses	25,972
Marketing expenses	4,820
Taxes other than income taxes	14,877
Total direct operating expenses	95,334
Field level cash flow	110,102
Gains on oil and natural gas derivatives	92,691
Other indirect income (expenses)	2,194,650
Income from continuing operations before income taxes	2,397,443
Predecessor | Upstream
Segment Reporting Information [Line Items]
Oil, natural gas and natural gas liquids sales	188,885
Marketing revenues	5,999
Other revenues	9,915
Total	204,799
Lease operating expenses	49,665
Transportation expenses	25,972
Marketing expenses	4,602
Taxes other than income taxes	14,773
Total direct operating expenses	95,012
Field level cash flow	109,787
Predecessor | Chisholm Trail
Segment Reporting Information [Line Items]
Oil, natural gas and natural gas liquids sales	0
Marketing revenues	637
Other revenues	0
Total	637
Lease operating expenses	0
Transportation expenses	0
Marketing expenses	218
Taxes other than income taxes	78
Total direct operating expenses	296
Field level cash flow	341
Predecessor | Not Allocated to Segments
Segment Reporting Information [Line Items]
Oil, natural gas and natural gas liquids sales	0
Marketing revenues	0
Other revenues	0
Total	0
Lease operating expenses	0
Transportation expenses	0
Marketing expenses	0
Taxes other than income taxes	26
Total direct operating expenses	26
Field level cash flow	(26)
Gains on oil and natural gas derivatives	92,691
Other indirect income (expenses)	$ 2,194,650
Successor
Segment Reporting Information [Line Items]
Oil, natural gas and natural gas liquids sales		$ 87,004	$ 243,167	$ 323,492	$ 223,880
Marketing revenues		42,967	12,547	15,461	89,234
Other revenues		6,387	6,391	8,419	12,281
Total		136,358	262,105	347,372	325,395
Lease operating expenses		24,088	71,057	95,687	71,972
Transportation expenses		21,213	37,388	51,111	40,307
Marketing expenses		40,327	6,976	9,515	82,082
Taxes other than income taxes		7,297	17,871	24,948	15,749
Total direct operating expenses		92,925	133,292	181,261	210,110
Field level cash flow		43,433	128,813	166,111	115,285
Gains on oil and natural gas derivatives		(7,525)	45,714	33,755	(22,555)
Other indirect income (expenses)		(23,283)	207,622	169,644	31,167
Income from continuing operations before income taxes		12,625	382,149	369,510	123,897
Successor | Upstream
Segment Reporting Information [Line Items]
Oil, natural gas and natural gas liquids sales		87,004	243,167	323,492	223,880
Marketing revenues		22,901	10,793	13,273	47,276
Other revenues		6,387	6,391	8,419	12,281
Total		116,292	260,351	345,184	283,437
Lease operating expenses		24,088	71,057	95,687	71,972
Transportation expenses		21,213	37,388	51,111	40,307
Marketing expenses		20,244	6,156	8,513	41,380
Taxes other than income taxes		6,737	17,486	24,478	14,908
Total direct operating expenses		72,282	132,087	179,789	168,567
Field level cash flow		44,010	128,264	165,395	114,870
Successor | Chisholm Trail
Segment Reporting Information [Line Items]
Oil, natural gas and natural gas liquids sales		0	0	0	0
Marketing revenues		20,066	1,754	2,188	41,958
Other revenues		0	0	0	0
Total		20,066	1,754	2,188	41,958
Lease operating expenses		0	0	0	0
Transportation expenses		0	0	0	0
Marketing expenses		20,083	820	1,002	40,702
Taxes other than income taxes		285	116	155	477
Total direct operating expenses		20,368	936	1,157	41,179
Field level cash flow		(302)	818	1,031	779
Successor | Not Allocated to Segments
Segment Reporting Information [Line Items]
Oil, natural gas and natural gas liquids sales		0	0	0	0
Marketing revenues		0	0	0	0
Other revenues		0	0	0	0
Total		0	0	0	0
Lease operating expenses		0	0	0	0
Transportation expenses		0	0	0	0
Marketing expenses		0	0	0	0
Taxes other than income taxes		275	269	315	364
Total direct operating expenses		275	269	315	364
Field level cash flow		(275)	(269)	(315)	(364)
Gains on oil and natural gas derivatives		(7,525)	45,714	33,755	(22,555)
Other indirect income (expenses)		$ (23,283)	$ 207,622	$ 169,644	$ 31,167