Riviera Resources (RVRA) 10-Q 9 May 19 2019 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2019	Apr. 30, 2019
Document And Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
Amendment Flag	false
Trading Symbol	RVRA
Entity Registrant Name	Riviera Resources, Inc.
Entity Central Index Key	0001737204
Current Fiscal Year End	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		65,441,848
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 102,260	$ 18,529
Accounts receivable – trade, net	85,470	114,489
Derivative instruments	3,861	10,758
Restricted cash	26,721	31,248
Other current assets	19,290	26,721
Assets held for sale		38,396
Total current assets	237,602	240,141
Noncurrent assets:
Oil and natural gas properties (successful efforts method)	792,861	756,552
Less accumulated depletion and amortization	(103,955)	(93,507)
Oil and natural gas properties, successful efforts method, net	688,906	663,045
Other property and equipment	629,312	606,244
Less accumulated depreciation	(72,043)	(62,368)
Other property and equipment, net	557,269	543,876
Derivative instruments	2,024	4,603
Deferred income taxes	124,598	129,091
Other noncurrent assets	13,695	12,078
Noncurrent assets, excluding property, total	140,317	145,772
Total noncurrent assets	1,386,492	1,352,693
Total assets	1,624,094	1,592,834
Current liabilities:
Accounts payable and accrued expenses	154,162	159,228
Derivative instruments	5,579	4,719
Other accrued liabilities	18,028	34,474
Liabilities held for sale		3,725
Total current liabilities	188,427	202,146
Noncurrent liabilities:
Credit facilities	14,500	24,500
Asset retirement obligations	104,658	103,814
Other noncurrent liabilities	5,689
Total noncurrent liabilities	193,518	128,314
Commitments and contingencies (Note 10)
Equity:
Preferred Stock ($0.01 par value, 30,000,000 shares authorized; no shares issued at March 31, 2019, or December 31, 2018)		0
Common Stock ($0.01 par value, 270,000,000 shares authorized; 66,791,031 shares and 69,197,284 shares issued at March 31, 2019, and December 31, 2018, respectively)	668	692
Additional paid-in capital	1,223,803	1,256,730
Retained earnings	17,678	4,952
Total equity	1,242,149	1,262,374
Total liabilities and equity	1,624,094	$ 1,592,834
Mayzure
Current assets:
Restricted cash	1,000
Current liabilities:
Current portion of Mayzure Notes payable	10,658
Noncurrent liabilities:
Mayzure Notes payable, net	$ 68,671

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	30,000,000	30,000,000
Preferred stock, shares issued	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	270,000,000	270,000,000
Common stock, shares, issued	66,791,031	69,197,284

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Revenues and other:
Revenues	$ 149,695	$ 189,037
Losses on commodity derivatives	(13,241)	(15,030)
Total revenues	136,454	174,007
Expenses:
Lease operating expenses	24,052	47,884
Transportation expenses	19,150	19,094
Marketing expenses	53,389	41,755
General and administrative expenses	19,039	44,779
Exploration costs	1,238	1,202
Depreciation, depletion and amortization	21,772	28,465
Taxes, other than income taxes	6,300	8,452
Gains on sale of assets and other, net	(27,265)	(106,296)
Total expenses	117,675	85,335
Other income and (expenses):
Interest expense, net of amounts capitalized	(971)	(404)
Other, net	(589)	(170)
Total other income and (expenses)	(1,560)	(574)
Reorganization items, net		(1,951)
Income (loss) from continuing operations before income taxes	17,219	86,147
Income tax expense	4,493	51,539
Income from continuing operations	12,726	34,608
Income from discontinued operations, net of income taxes		36,331
Net income	$ 12,726	$ 70,939
Income per share:
Income from continuing operations per share ‒ Basic	$ 0.18	$ 0.45
Income from continuing operations per share ‒ Diluted	0.18	0.45
Income from discontinued operations per share ‒ Basic		0.48
Income from discontinued operations per share ‒ Diluted		0.48
Net income per share ‒ Basic	0.18	0.93
Net income per share ‒ Diluted	$ 0.18	$ 0.93
Weighted average shares outstanding ‒ Basic	68,817	76,191
Weighted average shares outstanding ‒ Diluted	69,000	76,191
Oil, Natural Gas and NGL Sales
Revenues and other:
Revenues	$ 76,345	$ 136,876
Marketing
Revenues and other:
Revenues	67,347	46,267
Other Revenues
Revenues and other:
Revenues	$ 6,003	$ 5,894

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited) - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid In Capital	Accumulated Deficit
Beginning of period at Dec. 31, 2017	$ 2,339,046
Net income	70,939
Net transfers to parent	(408,093)
Ending of period at Mar. 31, 2018	2,001,892
Beginning of period at Dec. 31, 2018	1,262,374	$ 692	$ 1,256,730	$ 4,952
Beginning of period , shares at Dec. 31, 2018		69,197
Net income	12,726	$ 0		12,726
Repurchases of common stock	(34,437)	$ (25)	(34,412)
Repurchases of common stock, shares		(2,488)
Issuance of common stock	1,486	$ 1	1,485
Issuance of common stock, shares		82
Ending of period at Mar. 31, 2019	$ 1,242,149	$ 668	$ 1,223,803	$ 17,678
Ending of period , shares at Mar. 31, 2019		66,791

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash flow from operating activities:
Net income	$ 12,726	$ 70,939
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		(36,331)
Depreciation, depletion and amortization	21,772	28,465
Deferred income taxes	4,493	52,025
Total losses on derivatives, net	15,421	15,030
Cash settlements on derivatives	(5,085)	(4,494)
Share-based compensation expenses	4,236	17,037
Gains on sale of assets and other, net	(28,564)	(107,223)
Other	1,583	1,421
Changes in assets and liabilities:
Decrease in accounts receivable – trade, net	26,536	5,415
Decrease in other assets	9,257	12,002
Increase (decrease) in accounts payable and accrued expenses	(15,840)	13,802
Decrease in other liabilities	(8,857)	(17,222)
Net cash provided by operating activities	37,678	50,866
Cash flow from investing activities:
Development of oil and natural gas properties	(30,512)	(26,024)
Purchases of other property and equipment	(23,183)	(46,110)
Proceeds from sale of properties and equipment and other	60,141	232,394
Net cash provided by investing activities	6,446	160,260
Cash flow from financing activities:
Net transfers to Parent		(419,556)
Repurchases of shares	(34,130)	0
Proceeds from borrowings	96,225	0
Repayments of debt	(24,300)	0
Debt issuance costs paid	(2,715)	(26)
Distributions to unitholders		(8,007)
Net cash provided by (used in) financing activities	35,080	(427,589)
Net increase (decrease) in cash, cash equivalents and restricted cash	79,204	(216,463)
Cash, cash equivalents and restricted cash:
Beginning	49,777	520,922
Ending	$ 128,981	$ 304,459

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2019
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation	Note 1 – Basis of Presentation Unless otherwise indicated or the context otherwise requires, references herein to the “Company” refer (i) prior to the Spin-off (as defined below) to Linn Energy, Inc. (the “Parent”) and its consolidated subsidiaries, and (ii) after the Spin-off, to Riviera Resources, Inc. (“Riviera”) and its consolidated subsidiaries. Unless otherwise indicated or the context otherwise requires, references herein to “LINN Energy” refer to Linn Energy, Inc. and its consolidated subsidiaries. In April 2018, the Parent announced its intention to separate Riviera from LINN Energy. To effect the separation, the Parent and certain of its then direct and indirect subsidiaries undertook an internal reorganization (including the conversion of Riviera Resources, LLC from a limited liability company to a corporation named Riviera Resources, Inc.), following which Riviera holds, directly or through its subsidiaries, substantially all of the assets of LINN Energy, other than LINN Energy’s 50% equity interest in Roan Resources LLC (“Roan”). A subsidiary of the Company held the equity interest in Roan until the Parent’s internal reorganization on July 25, 2018 (the “Reorganization Date”). Following the internal reorganization, the Parent distributed all of the outstanding shares of Riviera common stock to the Parent’s shareholders on a pro rata basis (the “Spin-off”). The Spin-off was completed on August 7, 2018. Following the Spin-off, Riviera is an independent oil and natural gas company with a strategic focus on efficiently operating its mature low-decline assets, developing its growth-oriented assets, and returning capital to shareholders. Riviera is quoted for trading on the OTCQX Market under the ticker “RVRA,” and the Parent did not retain any ownership interest in the Company. Prior to the Spin-off, the accompanying condensed consolidated financial statements were prepared on a stand-alone basis and derived from Linn Energy, Inc.’s consolidated financial statements and accounting records for the periods presented as the Company was historically managed as a subsidiary of Linn Energy, Inc. Nature of Business The Company’s upstream reporting segment properties are currently located in six operating regions in the United States (“U.S.”): the Hugoton Basin, East Texas, the Mid-Continent, Michigan/Illinois, North Louisiana and the Uinta Basin. In addition, the Company’s upstream reporting segment contributed a term overriding royalty interest in helium produced from certain oil and natural gas properties in the Hugoton Basin (the “VPP Interests”) to Mayzure, LLC (“Mayzure”), a wholly owned subsidiary of the Company. The Blue Mountain reporting segment consists of a cryogenic natural gas processing facility, a network of gathering pipelines and compressors and produced water services in the Merge/SCOOP/STACK play, each of which is owned by Blue Mountain Midstream LLC (“Blue Mountain Midstream”), a wholly owned subsidiary of the Company. During 2018, the Company divested all of its properties located in the previous Permian Basin operating region. See Note 3 for additional information. Historically, a subsidiary of the Company also owned a 50% equity interest in Roan. The Company’s equity earnings (losses), consisting of its share of Roan’s earnings or losses, are included in the condensed consolidated financial statements through the Reorganization Date. However, on the Reorganization Date, the equity interest in Roan was distributed to the Parent and is no longer affiliated with Riviera. As such, the Company has classified the investment and equity earnings (losses) in Roan as discontinued operations on its condensed consolidated financial statements. See Note 3 for additional information. 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, 2018. 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 subsidiaries. All significant intercompany transactions and balances have been eliminated. Prior to the Spin-off, the condensed consolidated financial statements were prepared on a carve-out basis and reflect significant assumptions and allocations. 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), stockholders’ equity, or cash flows. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method. 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 Standard In February 2016, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet. The Company adopted this ASU effective January 1, 2019, using the modified retrospective effective date method and applied practical expedients which, among other things, allowed the Company to carryforward its historical lease classification, for the nonrecognition of short-term leases and for the combination of lease and non-lease components, by asset class. The adoption of this ASU resulted in an increase in both assets and liabilities of approximately $1 million as of January 1, 2019, related to the Company’s leasing activities with no material impact to the statement of operations. The Company’s leases primarily include buildings, office equipment, and field equipment. The Company elected to combine lease and non-lease components for leases of office equipment and field equipment.

Revenues

Revenues	3 Months Ended
	Mar. 31, 2019
Revenue From Contract With Customer [Abstract]
Revenues	Note 2 – Revenues Disaggregation of Revenue The following tables present the Company’s disaggregated revenues by source and geographic area: Three Months Ended March 31, 2019 Natural Gas Oil NGL Oil, Natural Gas and NGL Sales Marketing Revenues Other Revenues Total (in thousands) Hugoton Basin $ 22,899 $ 376 $ 9,970 $ 33,245 $ 23,692 $ 5,968 $ 62,905 East Texas 11,486 852 603 12,941 1,089 2 14,032 Mid-Continent 4,736 2,967 2,438 10,141 — 11 10,152 Michigan/Illinois 7,089 650 10 7,749 — 20 7,769 Uinta Basin 6,441 86 5 6,532 — — 6,532 North Louisiana 4,486 797 454 5,737 238 2 5,977 Blue Mountain — — — — 42,328 — 42,328 Total $ 57,137 $ 5,728 $ 13,480 $ 76,345 $ 67,347 $ 6,003 $ 149,695 Three Months Ended March 31, 2018 Natural Gas Oil NGL Oil, Natural Gas and NGL Sales Marketing Revenues Other Revenues Total (in thousands) Hugoton Basin $ 22,363 $ 2,732 $ 19,514 $ 44,609 $ 24,080 $ 5,831 $ 74,520 East Texas 14,776 1,340 1,306 17,422 36 5 17,463 Mid-Continent 7,933 11,867 3,054 22,854 — 14 22,868 Michigan/Illinois 6,472 710 11 7,193 — 29 7,222 Uinta Basin 3,380 7,370 1,358 12,108 — (2 ) 12,106 North Louisiana 6,378 1,569 (436 ) 7,511 259 1 7,771 Permian Basin 2,026 20,108 3,045 25,179 — 16 25,195 Blue Mountain — — — — 21,892 — 21,892 Total $ 63,328 $ 45,696 $ 27,852 $ 136,876 $ 46,267 $ 5,894 $ 189,037 Contract Balances Under the Company’s product sales contracts, its customers are invoiced once the Company’s performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do 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 $73 million and $107 million as of March 31, 2019, and December 31, 2018, respectively. Performance Obligations The majority of the Company’s sales are 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 that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606-10-50-14(A), which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Divestitures and Discontinued O

Divestitures and Discontinued Operations	3 Months Ended
	Mar. 31, 2019
Discontinued Operations [Abstract]
Divestitures and Discontinued Operations	Note 3 – Divestitures and Discontinued Operations Divestiture – 2019 On January 17, 2019, the Company completed the sale of its interest in properties located in the Arkoma Basin in Oklahoma (the “Arkoma Assets Sale”). Cash proceeds received from the sale of these properties were approximately $65 million (including a deposit of approximately $5 million received in 2018), and the Company recognized a net gain of approximately $28 million. The assets and liabilities associated with the Arkoma Assets Sale were classified as “held for sale” on the condensed consolidated balance sheet at December 31, 2018. 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, 2018 (in thousands) Assets: Oil and natural gas properties $ 38,083 Other property and equipment 152 Other 161 Total assets held for sale $ 38,396 Liabilities: Asset retirement obligations $ 2,700 Other 1,025 Total liabilities held for sale $ 3,725 Other assets primarily include inventories and other liabilities primarily include accounts payable. Divestitures – 2018 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 $108 million, net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $53 million. On February 28, 2018, the Company completed the sale of its Oklahoma waterflood and Texas Panhandle properties. 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 $48 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 on sale of assets and other, net” on the condensed consolidated statements of operations and were included in the upstream reporting segment. Divestiture – Subsequent Event On April 24, 2019, the Company signed a definitive agreement to sell its interest in certain non-operated properties located in the Hugoton Basin for a contract price of $31 million, subject to closing adjustments. The sale is expected to close in the second quarter of 2019. Discontinued Operations As discussed in Note 1, historically, a subsidiary of the Company owned the equity interest in Roan. However, on the Reorganization Date, the equity interest in Roan was distributed to the Parent and is no longer affiliated with Riviera. On August 31, 2017, the Parent, through certain of its then subsidiaries, completed the transaction in which the Company and Citizen Energy II, LLC (“Citizen”) each contributed certain upstream assets located in Oklahoma to a newly formed company, Roan (such contribution, the “Roan Contribution”), which was focused on the accelerated development of the Merge/SCOOP/STACK play. In exchange for their respective contributions, a subsidiary of the Company and Citizen each received a 50% equity interest in Roan. The Company used the equity method of accounting for its investment in Roan. The Company’s equity earnings (losses) consisted 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 and were classified as discontinued operations on the condensed consolidated statement of operations. The following are summarized statement of operations information for Roan. Summarized Roan Resources LLC Statement of Operations Information Three Months Ended March 31, 2018 (in thousands) Revenues and other $ 101,084 Expenses 57,909 Other income and (expenses) (1,799 ) Net income $ 41,376 For the three months ended March 31, 2018, the Company recorded equity earnings from its historical 50% interest in Roan of approximately $36 million (inclusive of an income tax benefit of approximately $11 million). The equity earnings are included in “income from discontinued operations, net of income taxes” on the condensed consolidated statement of operations.

Equity

Equity	3 Months Ended
	Mar. 31, 2019
Equity [Abstract]
Equity	Note 4 – Equity Share Repurchase Program On August 16, 2018, the Company’s Board of Directors authorized the repurchase of up to $100 million of the Company’s outstanding shares of common stock. During the three months ended March 31, 2019, the Company repurchased an aggregate of 2,495,975 shares of common stock at an average price of $13.80 per share for a total cost of approximately $34 million. In addition, in April 2019, the Company repurchased 1,351,850 shares of common stock at an average price of $14.55 for a the total cost of approximately $20 million. At April 30, 2019, approximately $28 million was available for share repurchases under the program. Any share repurchases are subject to restrictions in the Riviera Credit Facility. 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. Any future payment of cash dividends would be subject to the restrictions in the Riviera Credit Facility.

Oil and Natural Gas Properties

Oil and Natural Gas Properties	3 Months Ended
	Mar. 31, 2019
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
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: March 31, 2019 December 31, 2018 (in thousands) Proved properties $ 743,858 $ 709,053 Unproved properties 49,003 47,499 792,861 756,552 Less accumulated depletion and amortization (103,955 ) (93,507 ) $ 688,906 $ 663,045

Debt

Debt	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Debt	The following summarizes the Company’s outstanding debt: March 31, 2019 December 31, 2018 (in thousands, except percentages) Riviera Credit Facility (1) $ — $ 20,000 Blue Mountain Credit Facility (2) 14,500 4,500 Mayzure Notes (3) 81,925 — Net unamortized deferred financing fees (2,596 ) — Total debt, net 93,829 24,500 Less current portion of Mayzure Notes (10,658 ) — Total noncurrent debt, net $ 83,171 $ 24,500 (1) Variable interest rate of 5.0% at December 31, 2018. (2) Variable interest rate of 4.5% at both March 31, 2019, and December 31, 2018. (3) The Mayzure Notes are secured by Mayzure’s VPP interests, but Neither the Company, nor any of its subsidiaries other than Mayzure, have guaranteed the Mayzure Notes. Fair Value The Company’s debt is recorded at the carrying amount on the consolidated balance sheets. The carrying amounts of the credit facilities and term loans approximate fair value because the interest rates are variable and reflective of market rates. The fair value of the Company’s Mayzure Notes (as defined below) (which was estimated using a Level 2 fair value measurement) was approximately $83 million at March 31, 2019. Riviera Credit Facility Riviera’s credit agreement provides for a senior secured reserve-based revolving loan facility (the “Riviera Credit Facility”) with $385 million in borrowing commitments at March 31, 2019. In January 2019, in connection with the closing of the Arkoma Assets Sale, the maximum borrowing commitment was reduced from $425 million to $385 million. In March 2019, the Company entered into an amendment to the Riviera Credit Facility to, among other things, allow for the issuance of the Mayzure Notes (as described below). The amendment did not result in a change to the current borrowing commitment. As of March 31, 2019, there were no borrowings outstanding under the Riviera Credit Facility and there was approximately $351 million of available borrowing capacity (which includes a $34 million reduction for outstanding letters of credit). The maturity date is August 4, 2020. Redetermination of the borrowing base under the Riviera Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually, in April and October. In April 2019, the Company completed its semi-annual redetermination, and the borrowing base was reduced from $385 million to $250 million. As of April 30, 2019, there were no borrowings outstanding under the Riviera Credit Facility and there was approximately $216 million of available borrowing capacity (which includes a $34 million reduction for outstanding letters of credit. Upon closing of the sale of certain non-operated properties in the Hugoton Basin the borrowing base will be reduced to $245 million. At the Company’s election, interest on borrowings under the Riviera 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 Riviera 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 Riviera 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 excluding Mayzure and Blue Mountain Midstream, and are guaranteed by the Company and certain of its subsidiaries, subject to customary exceptions. Under the Riviera 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 Riviera Credit Facility also contains affirmative and negative covenants, including 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 Riviera 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 Riviera Credit Facility would allow the lenders, subject to customary cure rights, to require immediate payment of all amounts outstanding under the Riviera Credit Facility. Blue Mountain Credit Facility On August 10, 2018, Blue Mountain Midstream entered into a credit agreement with Royal Bank of Canada, as administrative agent, and the lenders and agents party thereto, providing for a new senior secured revolving loan facility (the “Blue Mountain Credit Facility” and together with the Riviera Credit Facility, the “Credit Facilities”), providing for an initial borrowing commitment of $200 million. Before Blue Mountain Midstream completed certain operational milestones (such completion of the operational milestones, the “Covenant Changeover Date”), a condition to any borrowing was that Blue Mountain Midstream’s consolidated total indebtedness to capitalization ratio (the “Debt/Cap Ratio”) be not greater than 0.35 to 1.00 upon giving effect to such borrowing. As such, prior to the Covenant Changeover Date, the available borrowing capacity under the Blue Mountain Credit Facility was less than the aggregate amount of the lenders’ commitments at such time. The Covenant Changeover Date occurred February 8, 2019, which increased the current borrowing availability to $200 million. Blue Mountain Midstream no longer has to comply with the Debt/Cap Ratio as a condition to drawing and may borrow up to the total amount of the lenders’ aggregate commitments. The Blue Mountain Credit Facility also provides for the ability to increase the aggregate commitments of the lenders to up to $400 million, subject to obtaining commitments for any such increase, which may result in an increase in Blue Mountain Midstream’s available borrowing capacity. As of March 31, 2019, total borrowings outstanding under the Blue Mountain Credit Facility were $14.5 million and there was approximately $174 million of available borrowing capacity (which includes a $12 million reduction for outstanding letters of credit). The Blue Mountain Credit Facility matures on August 10, 2023. At Blue Mountain Midstream’s election, interest on borrowings under the Blue Mountain Credit Facility is determined by reference to either the LIBOR plus an applicable margin ranging from 2.00% to 3.00% per annum or the ABR plus an applicable margin ranging from 1.00% to 2.00% per annum, both depending on Blue Mountain Midstream’s consolidated total leverage ratio. Interest is generally payable in arrears on the last day of March, June, September and December 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 three month intervals during such interest period. Blue Mountain Midstream is required under the Blue Mountain Credit Facility to pay a commitment fee to the lenders, which accrues at a rate per annum of 0.375% or 0.50% (depending on Blue Mountain Midstream’s consolidated total leverage ratio) on the average daily unused amount of the available revolving loan commitments of the lenders. The Blue Mountain Credit Facility is secured by a first priority lien on substantially all the assets of Blue Mountain Midstream. Under the Blue Mountain Credit Facility, Blue Mountain Midstream is required to maintain (i) for certain periods, a ratio of consolidated total debt (subject to certain carve-outs) to the sum of (a) total debt (subject to certain carve-outs) and (b) consolidated owners’ equity interest in Blue Mountain Midstream and its potential future subsidiaries of no greater than 0.35 to 1.00, and (ii) subject to satisfaction of certain conditions and for certain periods (a) a ratio of consolidated EBITDA to consolidated interest expense no less than 2.50 to 1.00, (b) a ratio of consolidated net debt to consolidated EBITDA (the “consolidated total leverage ratio”) no greater than 4.50 to 1.00 or 5.00 to 1.00, as applicable, and (c) in case certain other kinds of indebtedness are outstanding, a ratio of consolidated net debt secured by a lien on property of Blue Mountain Midstream to consolidated EBITDA no greater than 3.00 to 1.00. The Blue Mountain Credit Facility also contains affirmative and negative covenants customary for credit facilities of this nature, including compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, budgets, maintenance and operation of property, restrictions on the incurrence of liens and indebtedness, mergers, consolidations and sales of assets and transactions with affiliates. The Blue Mountain Credit Facility contains events of default and remedies customary for credit facilities of this nature. If Blue Mountain Midstream does not comply with the covenants in the Blue Mountain Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Blue Mountain Credit Facility. Mayzure Notes In March 2019, Riviera contributed the VPP Interests to Mayzure. On March 20, 2019, Mayzure issued 5.16% senior secured notes in the amount of approximately $82 million, due September 20, 2028 (the “Mayzure Notes”), which are secured by the VPP interests. Neither Riviera Resources, Inc., nor any of its subsidiaries other than Mayzure, have guaranteed the Mayzure Notes. In consideration for the distribution of the VPP Interests, Mayzure contributed the net proceeds from the issuance of the Mayzure Notes to Riviera. Financing fees and expenses of approximately $3 million incurred in connection with the Mayzure Notes will be amortized over the life of the Mayzure Notes. Such amortized expenses are recorded in “interest expense, net of amounts capitalized” on the condensed consolidated statement of operations. Principal and interest under the Mayzure Notes are payable on a monthly basis commencing April 20, 2019, as a volumetric production payment from the VPP Interests. In accordance with the terms of the Mayzure Notes, the Company made a principal repayment of approximately $1 million in April 2019.

Derivatives

Derivatives	3 Months Ended
	Mar. 31, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
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 Company also hedges its exposure to natural gas differentials in certain operating areas. In addition, the Company hedges purchase costs and margins of its Blue Mountain Midstream business. The Company enters into commodity hedging transactions primarily in the form of fixed price swap contracts that are designed to provide a fixed price, collars, basis swaps, margin spreads 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 8 for fair value disclosures about commodity derivatives. The following table presents derivative positions for the periods indicated as of March 31, 2019: 2019 2020 Natural gas positions: Fixed price swaps (NYMEX Henry Hub): Hedged volume (MMMBtu) 42,900 10,980 Average price ($/MMBtu) $ 2.88 $ 2.82 Collars (NYMEX Henry Hub): Hedged volume (MMMBtu) 5,500 — Average floor price ($/MMBtu) $ 2.75 $ — Average ceiling price ($/MMBtu) $ 3.00 $ — Oil positions: Fixed price swaps (NYMEX WTI): Hedged volume (MBbls) 302 183 Average price ($/Bbl) $ 64.52 $ 64.63 Natural gas basis differential positions: (1) PEPL basis swaps: Hedged volume (MMMBtu) 19,250 7,320 Hedge differential $ (0.64 ) $ (0.45 ) MichCon basis swaps: Hedged volume (MMMBtu) 5,500 3,660 Hedge differential ($/MMBtu) $ (0.19 ) $ (0.19 ) NWPL basis swaps: Hedged volume (MMMBtu) 2,750 — Hedge differential ($/MMBtu) $ (0.61 ) $ — Enable basis swaps: Hedged volume (MMMBtu) 1,375 — Hedge differential ($/MMBtu) $ (0.23 ) $ — Southern Star basis swaps: Hedged volume (MMMBtu) 1,375 — Hedge differential ($/MMBtu) $ (0.57 ) $ — NGL Positions: Fixed price swap (Mont Belvieu ethane): Hedged volume (gallons in thousands) 34,650 — Average price ($/gallon) $ 0.34 $ — Fixed price swap (Mont Belvieu propane): Hedged volume (gallons in thousands) 11,550 — Average price ($/gallon) $ 0.68 $ — Margin spread (Mont Belvieu propane and Conway propane): Hedged volume (gallons in thousands) 17,325 — Average price ($/gallon) $ (0.07 ) $ — Margin spread (Mont Belvieu natural gas and Conway natural gas): Hedged volume (gallons in thousands) 17,325 — Average price ($/gallon) $ (0.09 ) $ — (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 three months ended March 31, 2019, the Company entered into commodity derivative contracts consisting of natural gas fixed price swaps and NGL fixed price swaps for 2019 and natural gas basis swaps for 2020. During the three months ended March 31, 2018, the Company entered into commodity derivative contracts consisting of natural gas basis swaps for March 2018 through December 2018 and natural gas fixed price swaps for January 2019 through December 2019. 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. The NGL derivatives are settled based on the average effective price of natural gas liquids for each day of the delivery month, published in the issue of Oil Price Information Service. Balance Sheet Presentation The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. See Note 8 for fair value disclosures about commodity derivatives. The following table summarizes the fair value of derivatives outstanding on a gross basis: March 31, 2019 December 31, 2018 (in thousands) Assets: Commodity derivatives $ 11,762 $ 21,851 Liabilities: Commodity derivatives $ 11,456 $ 11,209 By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the Credit Facilities. The Credit Facilities are secured by certain of the Company’s and its subsidiaries’ oil, natural gas and NGL reserves and personal property; therefore, the Company is not required to post any collateral. The Company does not receive collateral from its counterparties. The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $12 million at March 31, 2019. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated. Gains and Losses on Derivatives A summary of gains and losses on derivatives included on the condensed consolidated statements of operations is presented below: Three Months Ended March 31, 2019 2018 (in thousands) Losses on commodity derivatives $ (13,241 ) $ (15,030 ) Marketing expenses (2,180 ) — Losses on commodity derivatives $ (15,421 ) $ (15,030 ) The Company paid net cash settlements of approximately $5 million and $4 million for the three months March 31, 2019, and March 31, 2018, respectively.

Fair Value Measurements on a Re

Fair Value Measurements on a Recurring Basis	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements on a Recurring Basis	The Company accounts for its commodity derivatives at fair value (see Note 7 for additional information) on a recurring basis. The Company determines the fair value of its commodity derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads, are applied to the Company’s commodity derivatives. Fair Value Hierarchy In accordance with applicable accounting standards, the Company has categorized its financial instruments into a three-level fair value hierarchy based on the priority of inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis: March 31, 2019 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 11,762 $ (5,877 ) $ 5,885 Liabilities: Commodity derivatives $ 11,456 $ (5,877 ) $ 5,579 December 31, 2018 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 21,851 $ (6,490 ) $ 15,361 Liabilities: Commodity derivatives $ 11,209 $ (6,490 ) $ 4,719 (1) Represents counterparty netting under agreements governing such derivatives.

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “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 Blue Mountain Midstream’s assets. 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 Blue Mountain Midstream 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, 2018 $ 105,259 Liabilities added from drilling 130 Liabilities associated with assets divested (396 ) Current year accretion expense 1,542 Settlements (432 ) Asset retirement obligations at March 31, 2019 $ 106,103

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2019
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 10 – Commitments and Contingencies On May 11, 2016, Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo, LLC (collectively, the “LINN Debtors”) and Berry Petroleum Company, LLC (“Berry” and collectively with the LINN Debtors, the “Debtors”) filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas (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 an order approving and confirming the plan (the “Plan”) of reorganization of the Debtors (the “Confirmation Order”). Consummation of the Plan was subject to certain conditions set forth in the Plan. On February 28, 2017, all of the conditions were satisfied or waived and the Plan became effective and was implemented in accordance with its terms. On September 27, 2018, the Bankruptcy Court closed the LINN Debtors’ Chapter 11 cases, but retained jurisdiction as provided in the Confirmation Order, including to potentially reopen the Chapter 11 cases if certain matters currently on appeal in the U.S. Court of Appeals for the Fifth Circuit are overturned, including the Default Interest Appeal (as defined below). 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, which are not affected by the closure of the LINN Debtors’ Chapter 11 cases. On March 17, 2017, Wells Fargo Bank, National Association (“Wells Fargo”), the administrative agent under Linn Energy, Inc.’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 Linn Energy, Inc.’s credit facility. UMB Bank then immediately filed a notice of appeal to the U.S. 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. The U.S. Court of Appeals for the Fifth Circuit heard oral arguments on February 6, 2019. That appeal (“the Default Interest 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 three months ended March 31, 2019, or March 31, 2018. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Operating Leases

Operating Leases	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Operating Leases	Note 11 – Operating Leases Lessee The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2022. During the three months ended March 31, 2019, the Company recorded lease expenses of approximately $1.1 million. As of March 31, 2019, the right of use lease liability was approximately $2 million using a discount rate of approximately 5.0% based on the incremental borrowing rate under the Riviera Credit Facility (as defined in Note 6) and a weighted average remaining term of approximately one year. As of March 31, 2019, future minimum lease payments were as follows (in thousands): 2019 $ 3,706 2020 506 2021 45 2022 4 2023 — Thereafter — $ 4,261 Lessor The Company leases a building located in Oklahoma to Roan and to a third party under lease agreements expiring on 2020 and 2023, with the option to extend the lease. We determine if an arrangement is a lease at inception. None of our leases allow the lessee to purchase the leased asset. Lease income for the three months ended March 31, 2019, totaled approximately $320,000, not including amounts of variable lease payments that is excluded from the table below as the amounts cannot be reasonably estimated for future periods. As of March 31, 2019, future minimum lease revenues were as follows (in thousands): 2019 $ 1,501 2020 2,124 2021 2,043 2022 2,133 2023 358 Thereafter — $ 8,159

Share-Based Compensation

Share-Based Compensation	3 Months Ended
	Mar. 31, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Share-Based Compensation	Note 12 – Share-Based Compensation Riviera Omnibus Incentive Plan In August 2018, the Company implemented the Riviera Resources, Inc. 2018 Omnibus Incentive Plan (the “Riviera Omnibus Incentive Plan”) pursuant to which employees, consultants and non-employee directors of the Company and its affiliates are eligible to receive stock options, restricted stock, dividend equivalents, performance awards, other stock-based awards and other cash-based awards. Pursuant to the Spin-off, on August 7, 2018, certain employees of the Company received 520,837 restricted stock units of the Company (“Riviera Legacy RSUs”). Such Riviera Legacy RSUs were originally granted as LINN RSUs pursuant to the Linn Energy, Inc. 2017 Omnibus Plan, and in connection with the Spin-off, the holders of such LINN RSUs were issued one Riviera RSU in respect of each such outstanding LINN RSU. As of March 31, 2019, 2,628,419 shares were issuable under the Riviera Omnibus Incentive Plan pursuant to outstanding Riviera RSUs, including (i) 231,364 Riviera Legacy RSUs, (ii) 497,899 restricted stock units of the Company granted to certain employees of the Company (the “Restricted Shares” and together with Riviera Legacy RSUs, the “Riviera RSUs”), (iii) 1,899,156 restricted stock units of the Company granted as performance units to certain employees of the Company (the “Riviera Performance Shares”) that, in the case of the Performance Shares, vest, if at all, based on the achievement of certain performance conditions specified in the award agreements. The Committee (as defined in the Riviera Omnibus Incentive Plan) has broad authority under the Riviera Omnibus Incentive Plan to, among other things: (i) select participants; (ii) determine the types of awards that participants receive and the number of shares that are subject to such awards; and (iii) establish the terms and conditions of awards, including the price (if any) to be paid for the shares or the award. As of March 31, 2019, up to 1,245,486 shares of common stock were available for issuance under the Riviera Omnibus Incentive Plan within the share reserve established under the Riviera Omnibus Incentive Plan, 10,160 of which the Committee has designated for issuance as Restricted Shares and 38,752 of which the Committee has designated for issuance as Performance Shares. If any stock option or other stock-based award granted under the Riviera Omnibus Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of common stock underlying any unexercised award shall again be available for the purpose of awards under the Riviera Omnibus Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of common stock awarded under the Riviera Omnibus Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the Riviera Omnibus Incentive Plan. Any award under the Riviera Omnibus Incentive Plan settled in cash shall not be counted against the maximum share limitation. As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the Riviera Omnibus Incentive Plan and any outstanding awards, as well as the exercise or purchase prices of awards, and performance targets under certain types of performance-based awards, are subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Company’s shareholders. Blue Mountain Midstream Omnibus Incentive Plan Blue Mountain Midstream is governed by its Second Amended and Restated Limited Liability Operating Agreement (as amended the “BMM LLC Agreement”), which provides for two classes of membership units: Class A Units, of which 100% are held by Linn Holdco II (a wholly owned subsidiary of Riviera) and Class B Units. Pursuant to the BMM LLC Agreement, Blue Mountain Midstream has the authority to issue an unlimited number of Class A Units and up to 58,750 Class B Units. As of March 31, 2019, Blue Mountain Midstream has issued 701,350 Class A Units and no Class B Units. In July 2018, Blue Mountain Midstream adopted the Blue Mountain Midstream LLC 2018 Omnibus Incentive Plan (the “BMM Incentive Plan”) pursuant to which employees and consultants of Blue Mountain Midstream and its affiliates are eligible to receive unit options, restricted units, dividend equivalents, performance awards, other unit-based awards and other cash-based awards. The Committee (as defined in the BMM Incentive Plan) has broad authority under the BMM Incentive Plan to, among other things: (i) select participants; (ii) determine the types of awards that participants receive and the number of units that are subject to such awards; and (iii) establish the terms and conditions of awards, including the price (if any) to be paid for the units or the award. The aggregate number of units available for issuance under the BMM Incentive Plan matches the maximum number of Class B Units issuable by Blue Mountain Midstream. As of March 31, 2019, under the BMM Incentive Plan, Blue Mountain Midstream had granted awards that could result in the issuance of 57,013 Class B Units or an equivalent value in cash, at the Board’s discretion. The issued awards include 11,399 restricted security units (“BMM RSUs”) and 22,807 performance stock units (“BMM PSUs”) (45,614 at 200% of target). The BMM RSUs can be paid, at the Board’s discretion, in cash or an equivalent number of Class B Units. Payment for the BMM PSUs only occurs upon the achievement by Blue Mountain Midstream of a certain equity value (subject to certain adjustments) specified in the award agreements. If such equity value is achieved, the recipient of the BMM PSU will receive a number of Class B Units (or an equivalent value in cash, at the Board’s discretion) equal to 50% to 200% of the target number of BMM PSUs held by such individual, as specified in the award agreements. If any unit option or other unit-based award granted under the BMM Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of units underlying any unexercised award shall again be available for the purpose of awards under the BMM Incentive Plan. If any restricted units, performance awards or other unit-based awards denominated in units awarded under the BMM Incentive Plan are forfeited for any reason, the number of forfeited units shall again be available for purposes of awards under the BMM Incentive Plan. Any award under the BMM Incentive Plan settled in cash shall not be counted against the maximum unit limitation. As is customary in incentive plans of this nature, each unit limit and the number and kind of units available under the BMM Incentive Plan and any outstanding awards, as well as the exercise or purchase prices of awards, and performance targets under certain types of performance-based awards, are subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, unit dividends or other similar events that change the number or kind of units outstanding, and extraordinary dividends or distributions of property to Blue Mountain Midstream’s unitholders. Accounting for Share-Based Compensation The condensed consolidated financial statements include 100% of the Parent’s employee-related expenses, as its personnel were employed by Riviera Operating, LLC, formerly known as Linn Operating, LLC (“Riviera Operating”), a subsidiary of the Parent that became a subsidiary of Riviera in connection with the Spin-off. Compensation cost related to the grant of share-based awards has been recorded at the subsidiary level with a corresponding credit to liability or equity, representing the Parent’s capital contribution. As a result of the Company’s history of cash settling awards, all unvested share-based compensation awards are liability classified at March 31, 2019. The Company has recognized a liability of approximately $6 million and $4 million at March 31, 2019, and December 31, 2018, respectively, related to unvested share based compensation awards included in “other accrued liabilities” and “other noncurrent liabilities” on the condensed consolidated balance sheets. All cash settlements of liability classified awards are classified as operating activities on the statement of cash flows. A summary of share-based compensation expenses included on the condensed consolidated statements of operations is presented below: Three Months Ended March 31, 2019 2018 (in thousands) Marketing expenses $ 107 $ — General and administrative expenses 6,200 17,037 Total share-based compensation expenses $ 6,307 $ 17,037 Income tax benefit $ 1,045 $ 2,417 Riviera Restricted Stock Units During the three months ended March 31, 2019, upon vesting of Riviera RSUs and at the election of participants, the Company repurchased 132,632 Riviera RSUs for a total cost of approximately $2 million. In addition, 81,923 shares of common stock were issued to participants (net of statutory tax withholdings) upon vesting of Riviera RSUs. Blue Mountain Midstream Restricted Security Units During the three months ended March 31, 2019, Blue Mountain Midstream granted 11,399 BMM RSUs with a fair value of approximately $12 million as of March 31, 2019, that vest ratably in three tranches over approximately two years with the first vesting occurring on April 2, 2019 .

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2019
Earnings Per Share [Abstract]
Earnings Per Share	Note 13 – Earnings Per Share On August 7, 2018, the Parent distributed 76,190,908 shares of Riviera common stock to LINN Energy shareholders. The Parent did not retain any ownership in Riviera. Each shareholder of the Parent received one share of Riviera common stock for each share of LINN Class A common stock held by such shareholder of the Parent at the close of business on August 7, 2018, the record date. Basic earnings per share is computed by dividing net income by the weighted average number of shares outstanding during the period. Diluted earnings per share is computed by adjusting the average number of shares outstanding for the dilutive effect, if any, of potential common shares. Basic and diluted earnings per share and the average number of shares outstanding were retrospectively restated for the number of shares of Riviera common stock outstanding immediately following the Spin-off and the same number of shares was used to calculate basic and diluted earnings per share in 2018 since there were no Riviera equity awards outstanding prior to the Spin-off. The following tables provide a reconciliation of the numerators and denominators of the basic and diluted per share computations for net income: Three Months Ended March 31, 2019 2018 (in thousands, except per share amounts) Income from continuing operations $ 12,726 $ 34,608 Income from discontinued operations, net of income taxes — 36,331 Net income $ 12,726 $ 70,939 Income per share: Income from continuing operations per share ‒ Basic $ 0.18 $ 0.45 Income from continuing operations per share ‒ Diluted $ 0.18 $ 0.45 Income from discontinued operations per share ‒ Basic $ — $ 0.48 Income from discontinued operations per share ‒ Diluted $ — $ 0.48 Net income per share ‒ Basic $ 0.18 $ 0.93 Net income per share ‒ Diluted $ 0.18 $ 0.93 Weighted average shares outstanding ‒ Basic 68,817 76,191 Dilutive effect of unit equivalents 183 — Weighted average shares outstanding ‒ Diluted 69,000 76,191 The diluted earnings per share calculation excludes the Riviera Performance Shares for the three months ended March 31, 2019, because no performance targets have been met.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Note 14 – Income Taxes For periods prior to the Spin-off, income tax expense and deferred tax balances were calculated on a separate tax return basis although Riviera’s operations have historically been included in the tax returns filed by the Parent, of which Riviera’s business was a part. Beginning August 8, 2018, as a stand-alone entity, Riviera will file tax returns on its own behalf and its deferred taxes and effective tax rate may differ from those in the historical periods. Amounts recognized as income taxes are included in “income tax expense,” as well as discontinued operations, on the condensed consolidated statements of operations. The effective income tax rates were approximately 26% and 60% for the three months March 31, 2019, and March 31, 2018, respectively. For the three months ended March 31, 2019, the Company’s federal and state statutory rate net of the federal tax benefit was approximately 24%. The increase in the effective tax rate in excess of the statutory rate in 2018 is primarily due to non-deductible executive compensation prior to the Spin-off.

Supplemental Disclosures to the

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows	3 Months Ended
	Mar. 31, 2019
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	Note 15 – 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: March 31, 2019 December 31, 2018 (in thousands) Prepaids $ 15,414 $ 13,493 Receivable from related party — 8,300 Inventories 3,863 3,720 Other 13 1,208 Other current assets $ 19,290 $ 26,721 “Other accrued liabilities” reported on the condensed consolidated balance sheets include the following: March 31, 2019 December 31, 2018 (in thousands) Accrued compensation $ 8,749 $ 16,820 Asset retirement obligations (current portion) 1,445 1,445 Deposits 4,988 10,060 Other 2,846 6,149 Other accrued liabilities $ 18,028 $ 34,474 The following table provides a reconciliation of “cash and cash equivalents” reported on the condensed consolidated balance sheets to “cash, cash equivalents and restricted cash” reported on the condensed consolidated statement of cash flows: March 31, 2019 December 31, 2018 (in thousands) Cash and cash equivalents $ 102,260 $ 18,529 Restricted cash 26,721 31,248 Cash, cash equivalents and restricted cash $ 128,981 $ 49,777 Supplemental disclosures to the condensed consolidated statements of cash flows are presented below: Three Months Ended March 31, 2019 2018 (in thousands) Cash payments for interest, net of amounts capitalized $ 219 $ — Cash payments for income taxes $ — $ — Cash payments for reorganization items, net $ — $ 1,184 Noncash investing activities: Accrued capital expenditures $ 20,120 $ 34,377 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 March 31, 2019, “restricted cash” on the condensed consolidated balance sheet consisted of approximately $21 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 $5 million related to deposits and approximately $1 million related to the Mayzure Notes. At December 31, 2018, “restricted cash” on the condensed consolidated balance sheet consisted of approximately $21 million that will be used to settle certain claims in accordance with the Plan and approximately $10 million related to deposits.

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions Disclosure	Note 16 – Related Party Transactions Roan Resources LLC On August 31, 2017, the Company completed the Roan Contribution. In exchange for their respective contributions, a subsidiary of the Company and Citizen each received a 50% equity interest in Roan. Also on such date, Roan entered into a Master Services Agreement (the “MSA”) with Riviera Operating, a subsidiary of Riviera, pursuant to which Riviera Operating provided certain operating, administrative and other services in respect of the assets contributed to Roan during a transitional period. Under the MSA, Roan reimbursed Riviera Operating for certain costs and expenses incurred by Riviera Operating in connection with providing the services, and Roan paid to Riviera Operating a service fee of $1.25 million per month, prorated for partial months. For the three months ended March 31, 2018, the Company recognized service fees of approximately $4 million, as a reduction to general and administrative expense. The MSA terminated according to its terms on April 30, 2018. On March 1, 2018, the Company commenced a lease agreement with Roan to lease office space in the Company’s building located in Oklahoma. The lease term is for five years and is recorded in “other, net” on the condensed consolidated statements of operations. In addition, the Company’s subsidiary, Blue Mountain Midstream has an agreement in place with Roan for the purchase and processing of natural gas from certain of Roan’s properties. On January 31, 2019, a subsidiary of Blue Mountain Midstream entered into an agreement to gather, treat or dispose of produced water from Roan. On April 1, 2019, Blue Mountain Midstream began providing services under the agreement. The original term of the agreement is until January 31, 2029. For the three months ended March 31, 2019, and March 31, 2018, the Company made natural gas purchases from Roan of approximately $34 million and $17 million, respectively, included in “marketing expenses” on the condensed consolidated statements of operations. At March 31, 2019, the Company had approximately $10 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, 2018, the Company had approximately $9 million due from Roan, primarily associated with amounts due to Riviera under the agreements related to the Spin-off, included in “other current assets” and approximately $14 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.

Segments

Segments	3 Months Ended
	Mar. 31, 2019
Segment Reporting [Abstract]
Segments	Note 17 – Segments At March 31, 2019, the Company had two reporting segments: Upstream and Blue Mountain. The upstream reporting segment was engaged in the exploration, development, production, and sale of oil, natural gas, and NGLs and consists of the Company’s properties in the Hugoton Basin, (including the Jayhawk natural gas processing plant, located in Kansas), East Texas, the Mid-Continent, Michigan/Illinois, North Louisiana and the Uinta Basin. The Blue Mountain reporting segment was new for the second quarter of 2018 as a result of a change in the way the chief operating decision maker (“CODM”) assesses the Company’s results of operations following the hiring of a segment manager to lead the Blue Mountain reporting segment and the commissioning of the cryogenic natural gas processing facility during the second quarter of 2018. As a result, the first quarter of 2018 segment disclosure has been recast for comparative purposes. The Blue Mountain reporting segment consists of a cryogenic natural gas processing facility, a network of gathering pipelines and compressors and produced water services in the Merge/SCOOP/STACK play. To assess the performance of the Company’s reporting 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 reporting segment is not presented because it is not reviewed by the CODM. The following tables present the Company’s financial information by reporting segment: Three Months Ended March 31, 2019 Upstream Blue Mountain Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 76,345 $ — $ — $ 76,345 Marketing revenues 25,019 42,328 — 67,347 Other revenues 6,003 — — 6,003 107,367 42,328 — 149,695 Lease operating expenses 24,052 — — 24,052 Transportation expenses 19,150 — — 19,150 Marketing expenses 19,784 31,425 2,180 53,389 Taxes other than income taxes 5,523 675 102 6,300 Total direct operating expenses 68,509 32,100 2,282 102,891 Field level cash flow $ 38,858 $ 10,228 (2,282 ) 46,804 Losses on commodity derivatives (13,241 ) (13,241 ) Other indirect income (expenses) (16,344 ) (16,344 ) Income from continuing operations before income taxes $ 17,219 Three Months Ended March 31, 2018 Upstream Blue Mountain Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 136,876 $ — $ — $ 136,876 Marketing revenues 24,375 21,892 — 46,267 Other revenues 5,894 — — 5,894 167,145 21,892 — 189,037 Lease operating expenses 47,884 — — 47,884 Transportation expenses 19,094 — — 19,094 Marketing expenses 21,136 20,619 — 41,755 Taxes other than income taxes 8,171 192 89 8,452 Total direct operating expenses 96,285 20,811 89 117,185 Field level cash flow $ 70,860 $ 1,081 (89 ) 71,852 Losses on commodity derivatives (15,030 ) (15,030 ) Other indirect income (expenses) 29,325 29,325 Income from continuing operations before income taxes $ 86,147

Basis of Presentation (Policies

Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2019
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Principles of Consolidation and Combination	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, 2018. 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 subsidiaries. All significant intercompany transactions and balances have been eliminated. Prior to the Spin-off, the condensed consolidated financial statements were prepared on a carve-out basis and reflect significant assumptions and allocations. 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), stockholders’ equity, or cash flows. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.
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 Adopted Accounting Standard	Recently Adopted Accounting Standard In February 2016, the Financial Accounting Standards Board issued an Accounting Standards Update (“ASU”) that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet. The Company adopted this ASU effective January 1, 2019, using the modified retrospective effective date method and applied practical expedients which, among other things, allowed the Company to carryforward its historical lease classification, for the nonrecognition of short-term leases and for the combination of lease and non-lease components, by asset class. The adoption of this ASU resulted in an increase in both assets and liabilities of approximately $1 million as of January 1, 2019, related to the Company’s leasing activities with no material impact to the statement of operations. The Company’s leases primarily include buildings, office equipment, and field equipment. The Company elected to combine lease and non-lease components for leases of office equipment and field equipment.

Revenues (Tables)

Revenues (Tables)	3 Months Ended
	Mar. 31, 2019
Revenue From Contract With Customer [Abstract]
Schedule of Company's Disaggregated revenues	The following tables present the Company’s disaggregated revenues by source and geographic area: Three Months Ended March 31, 2019 Natural Gas Oil NGL Oil, Natural Gas and NGL Sales Marketing Revenues Other Revenues Total (in thousands) Hugoton Basin $ 22,899 $ 376 $ 9,970 $ 33,245 $ 23,692 $ 5,968 $ 62,905 East Texas 11,486 852 603 12,941 1,089 2 14,032 Mid-Continent 4,736 2,967 2,438 10,141 — 11 10,152 Michigan/Illinois 7,089 650 10 7,749 — 20 7,769 Uinta Basin 6,441 86 5 6,532 — — 6,532 North Louisiana 4,486 797 454 5,737 238 2 5,977 Blue Mountain — — — — 42,328 — 42,328 Total $ 57,137 $ 5,728 $ 13,480 $ 76,345 $ 67,347 $ 6,003 $ 149,695 Three Months Ended March 31, 2018 Natural Gas Oil NGL Oil, Natural Gas and NGL Sales Marketing Revenues Other Revenues Total (in thousands) Hugoton Basin $ 22,363 $ 2,732 $ 19,514 $ 44,609 $ 24,080 $ 5,831 $ 74,520 East Texas 14,776 1,340 1,306 17,422 36 5 17,463 Mid-Continent 7,933 11,867 3,054 22,854 — 14 22,868 Michigan/Illinois 6,472 710 11 7,193 — 29 7,222 Uinta Basin 3,380 7,370 1,358 12,108 — (2 ) 12,106 North Louisiana 6,378 1,569 (436 ) 7,511 259 1 7,771 Permian Basin 2,026 20,108 3,045 25,179 — 16 25,195 Blue Mountain — — — — 21,892 — 21,892 Total $ 63,328 $ 45,696 $ 27,852 $ 136,876 $ 46,267 $ 5,894 $ 189,037

Divestitures and Discontinued_2

Divestitures and Discontinued Operations (Tables)	3 Months Ended
	Mar. 31, 2019
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, 2018 (in thousands) Assets: Oil and natural gas properties $ 38,083 Other property and equipment 152 Other 161 Total assets held for sale $ 38,396 Liabilities: Asset retirement obligations $ 2,700 Other 1,025 Total liabilities held for sale $ 3,725
Summarized Roan Resources LLC Statements of Operations Information	The following are summarized statement of operations information for Roan. Summarized Roan Resources LLC Statement of Operations Information Three Months Ended March 31, 2018 (in thousands) Revenues and other $ 101,084 Expenses 57,909 Other income and (expenses) (1,799 ) Net income $ 41,376

Oil and Natural Gas Properties

Oil and Natural Gas Properties (Tables)	3 Months Ended
	Mar. 31, 2019
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Schedule of 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: March 31, 2019 December 31, 2018 (in thousands) Proved properties $ 743,858 $ 709,053 Unproved properties 49,003 47,499 792,861 756,552 Less accumulated depletion and amortization (103,955 ) (93,507 ) $ 688,906 $ 663,045

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2019
Debt Disclosure [Abstract]
Summary of Outstanding Debt	The following summarizes the Company’s outstanding debt: March 31, 2019 December 31, 2018 (in thousands, except percentages) Riviera Credit Facility (1) $ — $ 20,000 Blue Mountain Credit Facility (2) 14,500 4,500 Mayzure Notes (3) 81,925 — Net unamortized deferred financing fees (2,596 ) — Total debt, net 93,829 24,500 Less current portion of Mayzure Notes (10,658 ) — Total noncurrent debt, net $ 83,171 $ 24,500 (1) Variable interest rate of 5.0% at December 31, 2018. (2) Variable interest rate of 4.5% at both March 31, 2019, and December 31, 2018. (3) The Mayzure Notes are secured by Mayzure’s VPP interests, but Neither the Company, nor any of its subsidiaries other than Mayzure, have guaranteed the Mayzure Notes.

Derivatives (Tables)

Derivatives (Tables)	3 Months Ended
	Mar. 31, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Derivative Positions	The following table presents derivative positions for the periods indicated as of March 31, 2019: 2019 2020 Natural gas positions: Fixed price swaps (NYMEX Henry Hub): Hedged volume (MMMBtu) 42,900 10,980 Average price ($/MMBtu) $ 2.88 $ 2.82 Collars (NYMEX Henry Hub): Hedged volume (MMMBtu) 5,500 — Average floor price ($/MMBtu) $ 2.75 $ — Average ceiling price ($/MMBtu) $ 3.00 $ — Oil positions: Fixed price swaps (NYMEX WTI): Hedged volume (MBbls) 302 183 Average price ($/Bbl) $ 64.52 $ 64.63 Natural gas basis differential positions: (1) PEPL basis swaps: Hedged volume (MMMBtu) 19,250 7,320 Hedge differential $ (0.64 ) $ (0.45 ) MichCon basis swaps: Hedged volume (MMMBtu) 5,500 3,660 Hedge differential ($/MMBtu) $ (0.19 ) $ (0.19 ) NWPL basis swaps: Hedged volume (MMMBtu) 2,750 — Hedge differential ($/MMBtu) $ (0.61 ) $ — Enable basis swaps: Hedged volume (MMMBtu) 1,375 — Hedge differential ($/MMBtu) $ (0.23 ) $ — Southern Star basis swaps: Hedged volume (MMMBtu) 1,375 — Hedge differential ($/MMBtu) $ (0.57 ) $ — NGL Positions: Fixed price swap (Mont Belvieu ethane): Hedged volume (gallons in thousands) 34,650 — Average price ($/gallon) $ 0.34 $ — Fixed price swap (Mont Belvieu propane): Hedged volume (gallons in thousands) 11,550 — Average price ($/gallon) $ 0.68 $ — Margin spread (Mont Belvieu propane and Conway propane): Hedged volume (gallons in thousands) 17,325 — Average price ($/gallon) $ (0.07 ) $ — Margin spread (Mont Belvieu natural gas and Conway natural gas): Hedged volume (gallons in thousands) 17,325 — Average price ($/gallon) $ (0.09 ) $ — (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.
Summary of Fair Value of Derivatives Outstanding on Gross Basis	The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. See Note 8 for fair value disclosures about commodity derivatives. The following table summarizes the fair value of derivatives outstanding on a gross basis: March 31, 2019 December 31, 2018 (in thousands) Assets: Commodity derivatives $ 11,762 $ 21,851 Liabilities: Commodity derivatives $ 11,456 $ 11,209
Summary of Gains and Losses on Derivatives	A summary of gains and losses on derivatives included on the condensed consolidated statements of operations is presented below: Three Months Ended March 31, 2019 2018 (in thousands) Losses on commodity derivatives $ (13,241 ) $ (15,030 ) Marketing expenses (2,180 ) — Losses on commodity derivatives $ (15,421 ) $ (15,030 )

Fair Value Measurements on a _2

Fair Value Measurements on a Recurring Basis (Tables)	3 Months Ended
	Mar. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of Fair Value Hierarchy for Assets and Liabilities Measured at Fair Value on Recurring Basis	The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis: March 31, 2019 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 11,762 $ (5,877 ) $ 5,885 Liabilities: Commodity derivatives $ 11,456 $ (5,877 ) $ 5,579 December 31, 2018 Level 2 Netting (1) Total (in thousands) Assets: Commodity derivatives $ 21,851 $ (6,490 ) $ 15,361 Liabilities: Commodity derivatives $ 11,209 $ (6,490 ) $ 4,719 (1) Represents counterparty netting under agreements governing such derivatives.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Reconciliation of Company's Asset Retirement Obligations	The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands): Asset retirement obligations at December 31, 2018 $ 105,259 Liabilities added from drilling 130 Liabilities associated with assets divested (396 ) Current year accretion expense 1,542 Settlements (432 ) Asset retirement obligations at March 31, 2019 $ 106,103

Operating Leases (Tables)

Operating Leases (Tables)	3 Months Ended
	Mar. 31, 2019
Leases [Abstract]
Schedule of Future Minimum Lease Payments	As of March 31, 2019, future minimum lease payments were as follows (in thousands): 2019 $ 3,706 2020 506 2021 45 2022 4 2023 — Thereafter — $ 4,261
Schedule of Future Minimum Lease Revenues	As of March 31, 2019, future minimum lease revenues were as follows (in thousands): 2019 $ 1,501 2020 2,124 2021 2,043 2022 2,133 2023 358 Thereafter — $ 8,159

Share-Based Compensation (Table

Share-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Share-Based Compensation Expenses	A summary of share-based compensation expenses included on the condensed consolidated statements of operations is presented below: Three Months Ended March 31, 2019 2018 (in thousands) Marketing expenses $ 107 $ — General and administrative expenses 6,200 17,037 Total share-based compensation expenses $ 6,307 $ 17,037 Income tax benefit $ 1,045 $ 2,417

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2019
Earnings Per Share [Abstract]
Reconciliation of Numerators and Denominators of Basic and Diluted Per Share Computations for Net Income	The following tables provide a reconciliation of the numerators and denominators of the basic and diluted per share computations for net income: Three Months Ended March 31, 2019 2018 (in thousands, except per share amounts) Income from continuing operations $ 12,726 $ 34,608 Income from discontinued operations, net of income taxes — 36,331 Net income $ 12,726 $ 70,939 Income per share: Income from continuing operations per share ‒ Basic $ 0.18 $ 0.45 Income from continuing operations per share ‒ Diluted $ 0.18 $ 0.45 Income from discontinued operations per share ‒ Basic $ — $ 0.48 Income from discontinued operations per share ‒ Diluted $ — $ 0.48 Net income per share ‒ Basic $ 0.18 $ 0.93 Net income per share ‒ Diluted $ 0.18 $ 0.93 Weighted average shares outstanding ‒ Basic 68,817 76,191 Dilutive effect of unit equivalents 183 — Weighted average shares outstanding ‒ Diluted 69,000 76,191

Supplemental Disclosures to t_2

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows (Tables)	3 Months Ended
	Mar. 31, 2019
Supplemental Disclosures To The Condensed Consolidated Statements Of Cash Flows [Abstract]
Schedule of Other Current Assets	“Other current assets” reported on the condensed consolidated balance sheets include the following: March 31, 2019 December 31, 2018 (in thousands) Prepaids $ 15,414 $ 13,493 Receivable from related party — 8,300 Inventories 3,863 3,720 Other 13 1,208 Other current assets $ 19,290 $ 26,721
Schedule of Other Accrued Liabilities	“Other accrued liabilities” reported on the condensed consolidated balance sheets include the following: March 31, 2019 December 31, 2018 (in thousands) Accrued compensation $ 8,749 $ 16,820 Asset retirement obligations (current portion) 1,445 1,445 Deposits 4,988 10,060 Other 2,846 6,149 Other accrued liabilities $ 18,028 $ 34,474
Schedule of Reconciliation of Cash, Cash Equivalents and Restricted Cash	The following table provides a reconciliation of “cash and cash equivalents” reported on the condensed consolidated balance sheets to “cash, cash equivalents and restricted cash” reported on the condensed consolidated statement of cash flows: March 31, 2019 December 31, 2018 (in thousands) Cash and cash equivalents $ 102,260 $ 18,529 Restricted cash 26,721 31,248 Cash, cash equivalents and restricted cash $ 128,981 $ 49,777
Supplemental Disclosures to the Condensed Consolidated Statements of Cash Flows	Supplemental disclosures to the condensed consolidated statements of cash flows are presented below: Three Months Ended March 31, 2019 2018 (in thousands) Cash payments for interest, net of amounts capitalized $ 219 $ — Cash payments for income taxes $ — $ — Cash payments for reorganization items, net $ — $ 1,184 Noncash investing activities: Accrued capital expenditures $ 20,120 $ 34,377

Segments (Tables)

Segments (Tables)	3 Months Ended
	Mar. 31, 2019
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	The following tables present the Company’s financial information by reporting segment: Three Months Ended March 31, 2019 Upstream Blue Mountain Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 76,345 $ — $ — $ 76,345 Marketing revenues 25,019 42,328 — 67,347 Other revenues 6,003 — — 6,003 107,367 42,328 — 149,695 Lease operating expenses 24,052 — — 24,052 Transportation expenses 19,150 — — 19,150 Marketing expenses 19,784 31,425 2,180 53,389 Taxes other than income taxes 5,523 675 102 6,300 Total direct operating expenses 68,509 32,100 2,282 102,891 Field level cash flow $ 38,858 $ 10,228 (2,282 ) 46,804 Losses on commodity derivatives (13,241 ) (13,241 ) Other indirect income (expenses) (16,344 ) (16,344 ) Income from continuing operations before income taxes $ 17,219 Three Months Ended March 31, 2018 Upstream Blue Mountain Not Allocated to Segments Consolidated (in thousands) Oil, natural gas and natural gas liquids sales $ 136,876 $ — $ — $ 136,876 Marketing revenues 24,375 21,892 — 46,267 Other revenues 5,894 — — 5,894 167,145 21,892 — 189,037 Lease operating expenses 47,884 — — 47,884 Transportation expenses 19,094 — — 19,094 Marketing expenses 21,136 20,619 — 41,755 Taxes other than income taxes 8,171 192 89 8,452 Total direct operating expenses 96,285 20,811 89 117,185 Field level cash flow $ 70,860 $ 1,081 (89 ) 71,852 Losses on commodity derivatives (15,030 ) (15,030 ) Other indirect income (expenses) 29,325 29,325 Income from continuing operations before income taxes $ 86,147

Basis of Presentation - Additio

Basis of Presentation - Additional Information (Details) - USD ($) $ in Millions	Aug. 07, 2018	Jan. 01, 2019	Mar. 31, 2018	Dec. 31, 2017	Aug. 31, 2017
Basis Of Presentation [Line Items]
Spin-off completion date	Aug. 7, 2018
ASU 2016-02
Basis Of Presentation [Line Items]
Impact on assets and liability after adoption		$ 1
Roan Resources LLC
Basis Of Presentation [Line Items]
Ownership percentage			50.00%	50.00%	50.00%

Revenues - Schedule of Company'

Revenues - Schedule of Company's Disaggregated revenues (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Disaggregation of Revenue [Line Items]
Revenues	$ 149,695	$ 189,037
Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	57,137	63,328
Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	5,728	45,696
NGL
Disaggregation of Revenue [Line Items]
Revenues	13,480	27,852
Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	76,345	136,876
Marketing
Disaggregation of Revenue [Line Items]
Revenues	67,347	46,267
Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	6,003	5,894
Hugoton Basin
Disaggregation of Revenue [Line Items]
Revenues	62,905	74,520
Hugoton Basin | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	22,899	22,363
Hugoton Basin | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	376	2,732
Hugoton Basin | NGL
Disaggregation of Revenue [Line Items]
Revenues	9,970	19,514
Hugoton Basin | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	33,245	44,609
Hugoton Basin | Marketing
Disaggregation of Revenue [Line Items]
Revenues	23,692	24,080
Hugoton Basin | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	5,968	5,831
Mid-Continent
Disaggregation of Revenue [Line Items]
Revenues	10,152	22,868
Mid-Continent | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	4,736	7,933
Mid-Continent | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	2,967	11,867
Mid-Continent | NGL
Disaggregation of Revenue [Line Items]
Revenues	2,438	3,054
Mid-Continent | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	10,141	22,854
Mid-Continent | Marketing
Disaggregation of Revenue [Line Items]
Revenues		0
Mid-Continent | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	11	14
East Texas
Disaggregation of Revenue [Line Items]
Revenues	14,032	17,463
East Texas | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	11,486	14,776
East Texas | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	852	1,340
East Texas | NGL
Disaggregation of Revenue [Line Items]
Revenues	603	1,306
East Texas | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	12,941	17,422
East Texas | Marketing
Disaggregation of Revenue [Line Items]
Revenues	1,089	36
East Texas | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	2	5
Uinta Basin
Disaggregation of Revenue [Line Items]
Revenues	6,532	12,106
Uinta Basin | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	6,441	3,380
Uinta Basin | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	86	7,370
Uinta Basin | NGL
Disaggregation of Revenue [Line Items]
Revenues	5	1,358
Uinta Basin | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	6,532	12,108
Uinta Basin | Marketing
Disaggregation of Revenue [Line Items]
Revenues		0
Uinta Basin | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues		(2)
North Louisiana
Disaggregation of Revenue [Line Items]
Revenues	5,977	7,771
North Louisiana | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	4,486	6,378
North Louisiana | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	797	1,569
North Louisiana | NGL
Disaggregation of Revenue [Line Items]
Revenues	454	(436)
North Louisiana | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	5,737	7,511
North Louisiana | Marketing
Disaggregation of Revenue [Line Items]
Revenues	238	259
North Louisiana | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	2	1
Michigan/Illinois
Disaggregation of Revenue [Line Items]
Revenues	7,769	7,222
Michigan/Illinois | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues	7,089	6,472
Michigan/Illinois | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues	650	710
Michigan/Illinois | NGL
Disaggregation of Revenue [Line Items]
Revenues	10	11
Michigan/Illinois | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	7,749	7,193
Michigan/Illinois | Marketing
Disaggregation of Revenue [Line Items]
Revenues		0
Michigan/Illinois | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues	20	29
Permian Basin
Disaggregation of Revenue [Line Items]
Revenues		25,195
Permian Basin | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues		2,026
Permian Basin | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues		20,108
Permian Basin | NGL
Disaggregation of Revenue [Line Items]
Revenues		3,045
Permian Basin | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues		25,179
Permian Basin | Marketing
Disaggregation of Revenue [Line Items]
Revenues		0
Permian Basin | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues		16
Blue Mountain
Disaggregation of Revenue [Line Items]
Revenues	42,328	21,892
Blue Mountain | Natural Gas Sales
Disaggregation of Revenue [Line Items]
Revenues		0
Blue Mountain | Oil Sales
Disaggregation of Revenue [Line Items]
Revenues		0
Blue Mountain | NGL
Disaggregation of Revenue [Line Items]
Revenues		0
Blue Mountain | Oil, Natural Gas and NGL Sales
Disaggregation of Revenue [Line Items]
Revenues	0	0
Blue Mountain | Marketing
Disaggregation of Revenue [Line Items]
Revenues	$ 42,328	21,892
Blue Mountain | Other Revenues
Disaggregation of Revenue [Line Items]
Revenues		$ 0

Revenues - Additional Informati

Revenues - Additional Information (Details) - USD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Revenue From Contract With Customer [Abstract]
Contract with Customer, Accounts Receivable	$ 73	$ 107

Divestitures and Discontinued_3

Divestitures and Discontinued Operations - Additional Information (Details) - USD ($) $ in Thousands	Jan. 17, 2019	Mar. 29, 2018	Feb. 28, 2018	Mar. 31, 2018	Apr. 24, 2019	Mar. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Aug. 31, 2017
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Deposits						$ 4,988	$ 10,060
Income from discontinued operations, net of income taxes				$ 36,331
Roan Resources LLC
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Equity method investment, ownership percentage				50.00%				50.00%	50.00%
Income from discontinued operations, net of income taxes				$ 36,000
Income tax expense of discontinued operations				$ 11,000
Hugoton Basin | Subsequent Event
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds to be received from sale of interest in non-operated properties, subject to closing adjustments					$ 31,000
Arkoma Assets Sale
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses	$ 65,000
Deposits							$ 5,000
Gain (Loss) on Disposition of Oil and Gas Property	$ 28,000
West Texas Assets Sale
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses		$ 108,000
Gain (Loss) on Disposition of Oil and Gas Property		53,000
Costs Associated With Sale of Oil and Gas Property and Equipment		$ 1,000
OK Waterfloods & TXPHS
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses			$ 112,000
Deposits								$ 12,000
Gain (Loss) on Disposition of Oil and Gas Property			48,000
Costs Associated With Sale of Oil and Gas Property and Equipment			$ 1,000

Divestitures and Discontinued_4

Divestitures and Discontinued Operations - Disclosure of Long Lived Assets Held-for-sale (Details) $ in Thousands	Dec. 31, 2018USD ($)
ASSETS
Oil and natural gas properties	$ 38,083
Other property and equipment	152
Other	161
Total assets held for sale	38,396
Liabilities:
Asset retirement obligations	2,700
Other	1,025
Total liabilities held for sale	$ 3,725

Divestitures and Discontinued_5

Divestitures and Discontinued Operations - Summarized Roan Resources LLC Statements of Operations Information (Details) - Roan Resources LLC $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
Revenues and other	$ 101,084
Expenses	57,909
Other income and (expenses)	(1,799)
Net income	$ 41,376

Equity - Additional Information

Equity - Additional Information (Details) - USD ($)	1 Months Ended	3 Months Ended
	Apr. 30, 2019	Mar. 31, 2019	Aug. 16, 2018
Class Of Stock [Line Items]
Stock repurchased during period, value		$ 34,437,000
Common Stock
Class Of Stock [Line Items]
Stock repurchased during period, shares		2,495,975
Share repurchased program average price per share		$ 13.80
Stock repurchased during period, value		$ 25,000
Stock repurchase program, available for share repurchase amount	$ 28,000,000
Common Stock | Maximum
Class Of Stock [Line Items]
Stock repurchase program, authorized amount			$ 100,000,000
Subsequent Event
Class Of Stock [Line Items]
Stock repurchased during period, value	$ 20,000,000
Subsequent Event | Common Stock
Class Of Stock [Line Items]
Stock repurchased during period, shares	1,351,850
Share repurchased program average price per share	$ 14.55

Oil and Natural Gas Propertie_2

Oil and Natural Gas Properties - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Production Activities (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Proved properties	$ 743,858	$ 709,053
Unproved properties	49,003	47,499
Oil and natural gas properties (successful efforts method)	792,861	756,552
Less accumulated depletion and amortization	(103,955)	(93,507)
Oil and natural gas properties, successful efforts method, net	$ 688,906	$ 663,045

Debt - Summary of Outstanding D

Debt - Summary of Outstanding Debt (Details) - USD ($) $ in Thousands		Apr. 30, 2019	Mar. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Net unamortized deferred financing fees			$ (2,596)
Total debt, net			93,829	$ 24,500
Total noncurrent debt, net			83,171	24,500
Mayzure
Debt Instrument [Line Items]
Mayzure Notes	[1]		81,925
Less current portion of Mayzure Notes			(10,658)
Riviera Credit Facility
Debt Instrument [Line Items]
Credit facility		$ 0	0	20,000	[2]
Blue Mountain Credit Facility
Debt Instrument [Line Items]
Credit facility	[3]		$ 14,500	$ 4,500
[1]	The Mayzure Notes are secured by Mayzure’s VPP interests, but Neither the Company, nor any of its subsidiaries other than Mayzure, have guaranteed the Mayzure Notes
[2]	Variable interest rate of 5.0% at December 31, 2018.
[3]	Variable interest rate of 4.5% at both March 31, 2019, and December 31, 2018

Debt - Summary of Outstanding_2

Debt - Summary of Outstanding Debt (Parenthetical) (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Riviera Credit Facility
Debt Instrument [Line Items]
Variable interest rate		5.00%
Blue Mountain
Debt Instrument [Line Items]
Variable interest rate	4.50%	4.50%

Debt - Additional Information (

Debt - Additional Information (Details)		Aug. 10, 2018USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)		Apr. 30, 2019USD ($)	Feb. 08, 2019USD ($)	Jan. 31, 2019USD ($)
Riviera Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity			$ 385,000,000	$ 425,000,000		$ 250,000,000		$ 385,000,000
Long-term line of credit			0	$ 20,000,000	[1]	0
Line of credit facility, remaining borrowing capacity			351,000,000			216,000,000
Letters of credit outstanding, amount			$ 34,000,000			34,000,000
Line of credit, maturity date			Aug. 4, 2020
Line of credit facility, borrowing capacity, description			Upon closing of the sale of certain non-operated properties in the Hugoton Basin the borrowing base will be reduced to $245 million.
Debt instrument, basis spread on variable rate				5.00%
Line of credit facility, unused capacity, commitment fee percentage			0.50%
Line of credit facility, interest payment term			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.
Credit facility			$ 0	$ 20,000,000	[1]	$ 0
Line of credit facility portion of properties required to maintain mortgages			85.00%
Debt to EBITDA ratio			400.00%
Current ratio			100.00%
Riviera Credit Facility | London Interbank Offered Rate (LIBOR) | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			2.50%
Riviera Credit Facility | London Interbank Offered Rate (LIBOR) | Maximum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			3.50%
Riviera Credit Facility | ABR | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			1.50%
Riviera Credit Facility | ABR | Maximum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			2.50%
Blue Mountain Credit Facility
Debt Instrument [Line Items]
Long-term line of credit	[2]		$ 14,500,000	4,500,000
Credit facility	[2]		14,500,000	$ 4,500,000
Mayzure
Debt Instrument [Line Items]
Senior secured notes			$ 82,000,000
Debt instrument, interest rate			5.16%
Debt instrument, issuance date			Mar. 31, 2019
Debt instrument, maturity date			Sep. 20, 2028
Debt Instrument, financing fees and expenses			$ 3,000,000
Debt Instrument,principal repayment			1,000,000
Blue Mountain Midstream | Blue Mountain Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 200,000,000	400,000,000
Long-term line of credit			14,500
Line of credit facility, remaining borrowing capacity			174,000
Letters of credit outstanding, amount			$ 12,000
Line of credit, maturity date		Aug. 10, 2023
Line of credit facility, interest payment term			Interest is generally payable in arrears on the last day of March, June, September and December 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 three month intervals during such interest period.
Credit facility			$ 14,500
Line of credit facility, current borrowing capacity							$ 200,000,000
Maximum ratio of consolidated owners' equity interest		35.00%
Minimum ratio of consolidated EBITDA to consolidated interest expense		250.00%
Maximum ratio of consolidated net debt secured by lien on property to consolidated EBITDA		300.00%
Blue Mountain Midstream | Blue Mountain Credit Facility | Minimum [Member]
Debt Instrument [Line Items]
Line of credit facility, unused capacity, commitment fee percentage		0.375%
Indebtedness to capitalization ratio		0.35
Maximum ratio of consolidated net debt to consolidated EBITDA		450.00%
Blue Mountain Midstream | Blue Mountain Credit Facility | Maximum
Debt Instrument [Line Items]
Line of credit facility, unused capacity, commitment fee percentage		0.50%
Maximum ratio of consolidated net debt to consolidated EBITDA		500.00%
Blue Mountain Midstream | Blue Mountain Credit Facility | London Interbank Offered Rate (LIBOR) | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		2.00%
Blue Mountain Midstream | Blue Mountain Credit Facility | London Interbank Offered Rate (LIBOR) | Maximum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		3.00%
Blue Mountain Midstream | Blue Mountain Credit Facility | ABR | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		1.00%
Blue Mountain Midstream | Blue Mountain Credit Facility | ABR | Maximum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate		2.00%
Fair Value, Inputs, Level 2 | Mayzure
Debt Instrument [Line Items]
Notes payable, fair value disclosure			$ 83,000,000
[1]	Variable interest rate of 5.0% at December 31, 2018.
[2]	Variable interest rate of 4.5% at both March 31, 2019, and December 31, 2018

Derivatives - Schedule of Deriv

Derivatives - Schedule of Derivative Positions (Details)	Mar. 31, 2019MMMBTU$ / MMBTUMBblsMgal$ / bbl$ / MMMBTU$ / gal
Year 2019 | Natural Gas Commodity Contract | Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	42,900
Average price ($/MMBtu) | $ / MMBTU	2.88
Year 2019 | Natural Gas Commodity Contract | Collars
Derivative [Line Items]
Hedged volume (MMMBtu)	5,500
Average floor price ($/MMBtu) | $ / MMBTU	2.75
Average ceiling price ($/MMBtu) | $ / MMBTU	3
Year 2019 | Oil Commodity Contract | Swap
Derivative [Line Items]
Hedged volume (MMMBtu) | MBbls	302
Average price ($/MMBtu) | $ / bbl	64.52
Year 2019 | PEPL Basis Swap | Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	19,250	[1]
Hedge differential | $ / MMMBTU	(0.64)	[1]
Year 2019 | MichCon Basis Swaps | Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	5,500	[1]
Hedge differential | $ / MMBTU	(0.19)	[1]
Year 2019 | NGPL Basis Swap | Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	1,375	[1]
Hedge differential | $ / MMBTU	(0.57)	[1]
Year 2019 | N W P L Basis Swap | Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	2,750	[1]
Hedge differential | $ / MMBTU	(0.61)	[1]
Year 2019 | Enable Basis Swap | Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	1,375	[1]
Hedge differential | $ / MMBTU	(0.23)	[1]
Year 2019 | N G L Commodity Contract | Swap
Derivative [Line Items]
Hedged volume (MMMBtu) | Mgal	34,650
Average price ($/MMBtu) | $ / gal	0.34
Year 2019 | Mont Belvieu Propane | Swap
Derivative [Line Items]
Hedged volume (MMMBtu) | Mgal	11,550
Average price ($/MMBtu) | $ / gal	0.68
Year 2019 | Mont Belvieu Propane And Conway Propane | Margin Spread
Derivative [Line Items]
Hedged volume (MMMBtu) | Mgal	17,325
Average price ($/gallon) | $ / gal	(0.07)
Year 2019 | Mont Belvieu Natural Gas And Conway Natural Gas | Margin Spread
Derivative [Line Items]
Hedged volume (MMMBtu) | Mgal	17,325
Average price ($/gallon) | $ / gal	(0.09)
Year 2020 | Natural Gas Commodity Contract | Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	10,980
Average price ($/MMBtu) | $ / MMBTU	2.82
Year 2020 | Oil Commodity Contract | Swap
Derivative [Line Items]
Hedged volume (MMMBtu) | MBbls	183
Average price ($/MMBtu) | $ / bbl	64.63
Year 2020 | PEPL Basis Swap | Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	7,320	[1]
Hedge differential | $ / MMMBTU	(0.45)	[1]
Year 2020 | MichCon Basis Swaps | Swap
Derivative [Line Items]
Hedged volume (MMMBtu)	3,660	[1]
Hedge differential | $ / MMBTU	(0.19)	[1]
[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 - Summary of Fair V

Derivatives - Summary of Fair Value of Derivatives Outstanding on Gross Basis (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Assets:
Commodity derivatives	$ 11,762	$ 21,851
Liabilities:
Commodity derivatives	$ 11,456	$ 11,209

Derivatives - Additional Inform

Derivatives - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Concentration Risk, Credit Risk, Financial Instrument, Maximum Exposure	$ 12,000
Cash settlements on derivatives	$ (5,085)	$ (4,494)

Derivatives - Summary of Gains

Derivatives - Summary of Gains and Losses on Derivatives (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments Gain Loss [Line Items]
Losses on commodity derivatives	$ (15,421)	$ (15,030)
Gains (losses) on commodity derivatives
Derivative Instruments Gain Loss [Line Items]
Losses on commodity derivatives	(13,241)	(15,030)
Marketing expenses
Derivative Instruments Gain Loss [Line Items]
Losses on commodity derivatives	$ (2,180)	$ 0

Fair Value Measurements on a _3

Fair Value Measurements on a Recurring Basis - Schedule of Fair Value Hierarchy for Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands		Mar. 31, 2019	Dec. 31, 2018
Assets:
Commodity derivatives		$ 11,762	$ 21,851
Commodity derivatives	[1]	(5,877)	(6,490)
Commodity derivatives		5,885	15,361
Liabilities:
Commodity derivatives		11,456	11,209
Commodity derivatives	[1]	(5,877)	(6,490)
Commodity derivatives		$ 5,579	$ 4,719
[1]	Represents counterparty netting under agreements governing such derivatives.

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Reconciliation of Company's Asset Retirement Obligations (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 105,259
Liabilities added from drilling	130
Liabilities associated with assets divested	(396)
Current year accretion expense	1,542
Settlements	(432)
Asset retirement obligations at end of period	$ 106,103

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details) - USD ($)	1 Months Ended	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2019	Mar. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Loss Contingency, Damages Sought, Value	$ 31,000,000
Payments for Legal Settlements		$ 0	$ 0

Operating Leases - Additional I

Operating Leases - Additional Information (Details)	3 Months Ended
	Mar. 31, 2019USD ($)
Operating Leased Assets [Line Items]
lease expenses	$ 1,100,000
Right of use lease	$ 2,000,000
Operating Lease, discount rate, percent	5.00%
Operating lease, weighted average remaining lease term	1 year
Lessor operating lease expiry date	2023
Lease income excluding variable lease payments	$ 320,000
Roan Resources LLC
Operating Leased Assets [Line Items]
Lessor operating lease expiry date	2020

Operating Leases - Future Minim

Operating Leases - Future Minimum Lease Payments (Details) $ in Thousands	Mar. 31, 2019USD ($)
Leases [Abstract]
2019	$ 3,706
2020	506
2021	45
2022	4
2023	0
Thereafter	0
Total undiscounted lease payments	$ 4,261

Operating Leases - Future Min_2

Operating Leases - Future Minimum Lease Revenues (Details) $ in Thousands	Mar. 31, 2019USD ($)
Leases [Abstract]
2019	$ 1,501
2020	2,124
2021	2,043
2022	2,133
2023	358
Thereafter	0
Total payments to be received	$ 8,159

Share-Based Compensation - Addi

Share-Based Compensation - Additional Information (Details) - USD ($)	Aug. 07, 2018	Dec. 31, 2018	Mar. 31, 2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of parent’s employee-related expenses			100.00%
Stock repurchased during period, value			$ 34,437,000
Issuance of common stock			1,486,000
Class A Units | LINN Energy
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based payment liability		$ 4,000,000	$ 6,000,000
Class A Units | Blue Mountain Midstream
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common unit, issued			701,350
Class A Units | Linn Holdco II | Blue Mountain Midstream
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common stock, ownership percentage			100.00%
Class B Common Stock | Blue Mountain Midstream
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common unit, issued			0
Maximum | Class B Common Stock | Blue Mountain Midstream
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common unit, issued			58,750
Common Stock
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock repurchased during period, Shares			2,488,000
Stock repurchased during period, value			$ 25,000
Issuance of common stock			$ 1,000
Omnibus Incentive Plan | Common Stock | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation arrangement, shares/units available for issuance			1,245,486
BMM Incentive Plan | Class B Units
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			45,614
Shares issuable under the plan			57,013
Share-based compensation arrangement by share-based payment award, description			Payment for the BMM PSUs only occurs upon the achievement by Blue Mountain of a certain equity value (subject to certain adjustments) specified in the award agreements. If such equity value is achieved, the recipient of the BMM PSU will receive a number of Class B Units (or an equivalent value in cash, at the Board’s discretion) equal to 50% to 200% of the target number of BMM PSUs held by such individual, as specified in the award agreemen
Restricted Stock Units (RSUs)
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	520,837
Restricted Stock Units (RSUs) | Liquidity program
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock repurchased during period, Shares			132,632
Stock repurchased during period, value			$ 2,000
Issuance of common stock			$ 81,923,000
Restricted Stock Units (RSUs) | Blue Mountain Midstream
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			11,399
Share-based compensation arrangement by share-based payment award, Equity instruments other than options, Vested in period, Fair value			$ 12,000,000
Vesting period			2 years
Restricted Stock Units (RSUs) | Omnibus Incentive Plan
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			497,899
Shares issuable under the plan			2,628,419
Restricted Stock Units (RSUs) | Omnibus Incentive Plan | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation arrangement, shares/units available for issuance			10,160
Restricted Stock Units (RSUs) | BMM Incentive Plan | Class B Units
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			11,399
Riviera Legacy RSUs | Omnibus Incentive Plan
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			231,364
Riviera Performance Shares
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		1,899,156	22,807
Share-based compensation arrangement by share-based payment award, Equity instruments other than options, Vested in period, Fair value		$ 3,000,000	$ 7,000,000
Riviera Performance Shares | Omnibus Incentive Plan
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			1,899,156
Riviera Performance Shares | Omnibus Incentive Plan | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based compensation arrangement, shares/units available for issuance			38,752
Riviera Performance Shares | BMM Incentive Plan | Class B Units
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			22,807

Share-Based Compensation - Summ

Share-Based Compensation - Summary of Share-Based Compensation Expenses (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Share/unit-based compensation expenses	$ 6,307	$ 17,037
Income tax benefit	1,045	2,417
Marketing expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Share/unit-based compensation expenses	107
General and Administrative Expenses
Employee Service Share-based Compensation, Allocation of Recognized Period Costs
Share/unit-based compensation expenses	$ 6,200	$ 17,037

Earnings Per Share - Additional

Earnings Per Share - Additional Information (Details) - shares	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Aug. 07, 2018
Earnings Per Share [Abstract]
Common stock, shares, issued	66,791,031	69,197,284	76,190,908
Stock split description	Each shareholder of the Parent received one share of Riviera common stock for each share of LINN Class A common stock held by such shareholder of the Parent at the close of business on August 7, 2018, the record date.

Earnings Per Share - Reconcilia

Earnings Per Share - Reconciliation of Numerators and Denominators of Basic and Diluted Per Share Computations for Net Income (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Earnings Per Share [Abstract]
Income from continuing operations	$ 12,726	$ 34,608
Income from discontinued operations, net of income taxes		36,331
Net income	$ 12,726	$ 70,939
Income per share:
Income from continuing operations per share ‒ Basic	$ 0.18	$ 0.45
Income from continuing operations per share ‒ Diluted	0.18	0.45
Income from discontinued operations per share ‒ Basic		0.48
Income from discontinued operations per share ‒ Diluted		0.48
Net income per share ‒ Basic	0.18	0.93
Net income per share ‒ Diluted	$ 0.18	$ 0.93
Weighted average shares outstanding ‒ Basic	68,817	76,191
Dilutive effect of unit equivalents	183	0
Weighted average shares outstanding ‒ Diluted	69,000	76,191

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation, Percent	26.00%	60.00%
Blended Tax Rate	24.00%

Supplemental Disclosures to t_3

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows - Schedule of Other Current Assets (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Other current assets
Prepaids	$ 15,414	$ 13,493
Receivable from related party		8,300
Inventories	3,863	3,720
Other	13	1,208
Other current assets	$ 19,290	$ 26,721

Supplemental Disclosures to t_4

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows - Schedule of Other Accrued Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Other accrued liabilities
Accrued compensation	$ 8,749	$ 16,820
Asset retirement obligations (current portion)	1,445	1,445
Deposits	4,988	10,060
Other	2,846	6,149
Other accrued liabilities	$ 18,028	$ 34,474

Supplemental Disclosures to t_5

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows - Schedule of Reconciliation of Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2017
Cash Cash Equivalents Restricted Cash And Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	$ 102,260	$ 18,529
Restricted cash	26,721	31,248
Cash, cash equivalents and restricted cash	$ 128,981	$ 49,777	$ 304,459	$ 520,922

Supplemental Disclosures to t_6

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows - Supplemental Disclosures to the Condensed Consolidated Statements of Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Supplemental Disclosures To The Condensed Consolidated Statements Of Cash Flows [Abstract]
Cash payments for interest, net of amounts capitalized	$ 219	$ 0
Cash payments for income taxes		0
Cash payments for reorganization items, net		1,184
Noncash investing activities:
Accrued capital expenditures	$ 20,120	$ 34,377

Supplemental Disclosures to t_7

Supplemental Disclosures to the Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Cash Flows - Additional Information (Details) - USD ($) $ in Thousands	2 Months Ended
	Feb. 28, 2017	Mar. 31, 2019	Dec. 31, 2018
Schedule of supplemental cash flow disclosures [Line Items]
Restricted cash		$ 26,721	$ 31,248
Mayzure
Schedule of supplemental cash flow disclosures [Line Items]
Restricted cash		1,000
Predecessor
Schedule of supplemental cash flow disclosures [Line Items]
Increase (Decrease) in Restricted Cash for Operating Activities	$ 80,000
Professional fees
Schedule of supplemental cash flow disclosures [Line Items]
Restricted cash		21,000	21,000
Deposits for divestitures
Schedule of supplemental cash flow disclosures [Line Items]
Restricted cash		$ 5,000	$ 10,000

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - Roan Resources LLC - USD ($) $ in Thousands	Aug. 31, 2017	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018	Mar. 01, 2018
Related Party Transaction [Line Items]
Equity method investment, ownership percentage	50.00%
Related party monthly fee	$ 1,250
Service fees from related party	$ 4,000
Term of lease agreement					5 years
Term of purchase agreement		Jan. 31, 2029
Related party transaction, purchases from related party		$ 34,000	$ 17,000
Due to related parties, current		$ 10,000		$ 14,000
Due from related parties, current				$ 9,000

Segments - Additional Informati

Segments - Additional Information (Details)	3 Months Ended
	Mar. 31, 2019Segment
Segment Reporting [Abstract]
Number of reportable segments	2

Segments - Schedule of Segment

Segments - Schedule of Segment Reporting Information, by Segment (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Segment Reporting Information [Line Items]
Revenues	$ 149,695	$ 189,037
Lease operating expenses	24,052	47,884
Transportation expenses	19,150	19,094
Marketing expenses	53,389	41,755
Taxes other than income taxes	6,300	8,452
Total direct operating expenses	102,891	117,185
Field level cash flow	46,804	71,852
Losses on commodity derivatives	(13,241)	(15,030)
Other indirect income (expenses)	(16,344)	29,325
Income (loss) from continuing operations before income taxes	17,219	86,147
Upstream
Segment Reporting Information [Line Items]
Revenues	107,367	167,145
Lease operating expenses	24,052	47,884
Transportation expenses	19,150	19,094
Marketing expenses	19,784	21,136
Taxes other than income taxes	5,523	8,171
Total direct operating expenses	68,509	96,285
Field level cash flow	38,858	70,860
Blue Mountain
Segment Reporting Information [Line Items]
Revenues	42,328	21,892
Marketing expenses	31,425	20,619
Taxes other than income taxes	675	192
Total direct operating expenses	32,100	20,811
Field level cash flow	10,228	1,081
Not Allocated to Segments
Segment Reporting Information [Line Items]
Marketing expenses	2,180
Taxes other than income taxes	102	89
Total direct operating expenses	2,282	89
Field level cash flow	(2,282)	(89)
Losses on commodity derivatives	(13,241)	(15,030)
Other indirect income (expenses)	(16,344)	29,325
Oil, Natural Gas and NGL Sales
Segment Reporting Information [Line Items]
Revenues	76,345	136,876
Oil, Natural Gas and NGL Sales | Upstream
Segment Reporting Information [Line Items]
Revenues	76,345	136,876
Oil, Natural Gas and NGL Sales | Blue Mountain
Segment Reporting Information [Line Items]
Revenues	0	0
Marketing
Segment Reporting Information [Line Items]
Revenues	67,347	46,267
Marketing | Upstream
Segment Reporting Information [Line Items]
Revenues	25,019	24,375
Marketing | Blue Mountain
Segment Reporting Information [Line Items]
Revenues	42,328	21,892
Other Revenues
Segment Reporting Information [Line Items]
Revenues	6,003	5,894
Other Revenues | Upstream
Segment Reporting Information [Line Items]
Revenues	$ 6,003	5,894
Other Revenues | Blue Mountain
Segment Reporting Information [Line Items]
Revenues		$ 0