Pressburg (ROAN) 10-K 1 Apr 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Mar. 27, 2019	Jun. 30, 2018
Document And Entity Information [Abstract]
Entity Registrant Name	ROAN RESOURCES, INC.
Entity Central Index Key	0001326428
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		152,539,532
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 6,883	$ 1,471
Accounts receivable
Oil, natural gas and natural gas liquid sales	55,564	74,527
Affiliates	9,669	4,695
Joint interest owners and other, net	133,387	320
Prepaid drilling advances	28,977	0
Derivative contracts	82,180	152
Prepaid expenses	2,644	651
Other current assets	4,011	279
Total current assets	323,315	82,095
Noncurrent assets
Oil and natural gas properties, successful efforts method	2,628,333	1,876,951
Accumulated depreciation, depletion, amortization and impairment	(230,836)	(78,307)
Oil and natural gas properties, net	2,397,497	1,798,644
Derivative contracts	20,638	996
Other	7,659	3,857
Total assets	2,749,109	1,885,592
Current liabilities
Accounts payable	49,746	0
Accrued liabilities	176,494	10,245
Accounts payable and accrued liabilities – Affiliates	8,577	183,820
Revenue payable	97,963	0
Drilling advances	31,058	0
Derivative contracts	845	9,279
Asset retirement obligations	790	0
Total current liabilities	365,473	203,344
Noncurrent liabilities
Long-term debt	514,639	85,339
Deferred tax liabilities, net	356,862	0
Asset retirement obligations	16,058	10,769
Derivative contracts	141	1,371
Other	902	0
Total liabilities	1,254,075	300,823
Commitments and contingencies (Note 14)
Equity
Common stock, $0.001 par value; 800,000,000 shares authorized; 152,539,532 shares issued and outstanding at December 31, 2018	153	0
Preferred stock, $0.001 par value; 50,000,000 shares authorized; no shares issued and outstanding at December 31, 2018	0	0
Additional paid-in capital	1,646,401	0
Accumulated deficit	(151,520)	0
Members’ equity	0	1,584,769
Total equity	1,495,034	1,584,769
Total liabilities and equity	$ 2,749,109	$ 1,885,592

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical)	Dec. 31, 2018$ / sharesshares
Statement of Financial Position [Abstract]
Common stock, par value (usd per share) | $ / shares	$ 0.001
Common shares authorized (shares)	800,000,000
Common shares issued (shares)	152,539,532
Common shares outstanding (shares)	152,539,532
Preferred stock, par value (usd per share) | $ / shares	$ 0.001
Preferred shares authorized (shares)	50,000,000
Preferred shares issued (shares)	0
Preferred shares outstanding (shares)	0

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Revenues
Gain (loss) on derivative contracts	$ 78,054,000		$ (6,797,000)	$ 0
Total revenues	517,821,000		159,588,000	54,965,000
Operating Expenses
Production expenses	47,600,000		16,872,000	5,090,000
Gathering, transportation and processing	0		18,602,000	5,920,000
Production taxes	17,579,000		3,685,000	1,087,000
Exploration expenses	43,303,000		32,629,000	5,258,000
Depreciation, depletion, amortization and accretion	123,922,000		37,376,000	24,996,000
General and administrative	60,874,000		31,357,000	5,581,000
Gain on sale of oil and natural gas properties	0		(838,000)	0
Total operating expenses	293,278,000		139,683,000	47,932,000
Total operating income	224,543,000		19,905,000	7,033,000
Other income (expense)
Interest expense, net	(8,352,000)		(1,461,000)	(86,000)
Other income	0		13,000	0
Net income before income taxes	216,191,000		18,457,000	6,947,000
Income tax expense	356,862,000		0	0
Net (loss) income	$ (140,671,000)	[1]	$ 18,457,000	$ 6,947,000
Earnings (loss) per share
Basic (usd per share)	$ (0.92)		$ 0.18	$ 0.11
Diluted (usd per share)	$ (0.92)		$ 0.18	$ 0.11
Weighted average number of shares outstanding
Basic (shares)	152,232		100,473	62,394
Diluted (shares)	152,232		100,473	62,394
Oil sales
Revenues
Revenues	$ 275,239,000		$ 76,876,000	$ 30,565,000
Natural gas sales
Revenues
Revenues	46,966,000		46,303,000	16,093,000
Natural gas sales | Affiliates
Revenues
Revenues	29,090,000		2,908,000	0
Natural gas liquid sales
Revenues
Revenues	51,467,000		35,217,000	8,307,000
Natural gas liquid sales | Affiliates
Revenues
Revenues	$ 37,005,000		$ 5,081,000	$ 0
[1]	Amounts are allocated to stockholders’ equity and members’ equity to reflect the Reorganization. See Note 10 – Equity for discussion of the Reorganization.

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) shares in Thousands, $ in Thousands		Total	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Members’ Equity
Beginning balance (shares) at Dec. 31, 2015			0
Beginning balance at Dec. 31, 2015		$ 98,292	$ 0	$ 0	$ 0	$ 98,292
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Contributions from Citizen Members		169,008				169,008
Acquisition of oil and natural gas properties for equity		0
Net (loss) income		6,947				6,947
Ending balance (shares) at Dec. 31, 2016			0
Ending balance at Dec. 31, 2016		274,247	$ 0	0	0	274,247
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Contributions from Citizen Members		95,557				95,557
Distributions to Citizen Members		(85,614)				(85,614)
Acquisition of oil and natural gas properties for equity		1,281,743				1,281,743
Equity-based compensation		379				379
Net (loss) income		18,457				18,457
Ending balance (shares) at Dec. 31, 2017			0
Ending balance at Dec. 31, 2017		1,584,769	$ 0	0	0	1,584,769
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Acquisition of oil and natural gas properties for equity		39,906				39,906
Equity-based compensation	[1]	11,030		3,162		7,868
Net (loss) income	[1]	(140,671)			(151,520)	10,849
Issuance of common stock upon Reorganization (shares)			152,540
Issuance of common stock upon Reorganization		0	$ 153	1,643,239		(1,643,392)
Ending balance (shares) at Dec. 31, 2018			152,540
Ending balance at Dec. 31, 2018		$ 1,495,034	$ 153	$ 1,646,401	$ (151,520)	$ 0
[1]	Amounts are allocated to stockholders’ equity and members’ equity to reflect the Reorganization. See Note 10 – Equity for discussion of the Reorganization.

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities
Net (loss) income	$ (140,671)	$ 18,457	$ 6,947
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	123,922	37,376	24,996
Unproved leasehold amortization and impairment	36,046	25,377	5,258
Gain on sale of oil and natural gas properties	0	(838)	0
Amortization of deferred financing costs	853	175	0
Amortization of deferred rent	902	0	0
(Gain) loss on derivative contracts	(78,054)	6,797	0
Net cash (paid) received upon settlement of derivative contracts	(33,279)	2,705	0
Equity-based compensation	11,030	379	0
Deferred income taxes	356,862	0	0
Other	2,971	(11)	(41)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable – Oil, natural gas and natural gas liquid sales	18,963	(62,170)	(12,473)
Accounts receivable – Affiliates	(4,974)	(4,695)	0
Accounts receivable – Joint interest owners and other	(136,367)	(8,729)	(35,398)
Prepaid drilling advances	(28,977)	0	0
Prepaid expenses	(1,992)	(2,312)	(1,221)
Other current assets	(2,584)	(2)	3
Accounts payable	16,733	0	6,006
Accrued liabilities	21,536	47,801	8,403
Accounts payable and accrued liabilities – Affiliates	(23,645)	31,121	0
Drilling advances	31,058	(25,363)	22,760
Revenue payable	97,963	(5,793)	10,900
Net cash provided by operating activities	268,296	60,275	36,140
Cash flows from investing activities
Acquisition of oil and natural gas properties	(22,935)	(42,701)	(144,774)
Capital expenditures for oil and natural gas properties	(673,465)	(167,122)	(96,335)
Acquisition of other property and equipment	(3,237)	(1,332)	0
Proceeds from sale of oil and natural gas properties	10,545	1,435	0
Other	0	(2,801)	0
Net cash used in investing activities	(689,092)	(212,521)	(241,109)
Cash flows from financing activities
Proceeds from borrowings	429,300	105,339	20,000
Repayment of borrowings	0	(40,000)	0
Deferred financing costs	(2,279)	(2,885)	0
Deferred offering costs	(813)	0	0
Contributions from Citizen members	0	95,557	169,008
Distributions to Citizen members	0	(11,147)	0
Net cash provided by financing activities	426,208	146,864	189,008
Net increase (decrease) in cash and cash equivalents	5,412	(5,382)	(15,961)
Cash and cash equivalents, beginning of year	1,471	6,853	22,814
Cash and cash equivalents, end of year	6,883	1,471	6,853
Supplemental disclosure of cash flow information
Cash paid for interest, net of capitalized interest	7,029	1,036	86
Supplemental disclosure of non-cash investing and financing activities
Change in accrued capital expenditures	65,699	147,142	4,922
Acquisition of oil and natural gas properties for equity	39,906	1,281,743	0
Distribution to Citizen Members of assets and liabilities	$ 0	$ (74,467)	$ 0

Business and Organization

Business and Organization	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Business and Organization	Note 1 – Business and Organization Roan Resources, Inc. (“Roan Inc.”) was formed in September 2018 to facilitate a reorganization and to become the holding company for Roan Resources LLC (“Roan LLC”). In September 2018, a series of transactions were executed with Roan LLC’s members which resulted in Roan LLC becoming a wholly- owned subsidiary of Roan Inc. These transactions are hereafter referred to as the “Reorganization” and Roan Inc. with its subsidiaries are collectively referred to as the “Company.” See Note 10 – Equity for further discussion of the Reorganization transaction. The accompanying historical financial statements through the date of Reorganization are the financial statements of Roan LLC, our accounting predecessor. Following the Reorganization, the historical financial statements are the results of Roan Inc. Roan LLC was initially formed by Citizen Energy II, LLC (“Citizen”) in May 2017. On August 31, 2017, the Company executed a contribution agreement (the “Contribution Agreement”) by and among Roan LLC, Citizen, Linn Energy Holdings, LLC (“LEH”) and Linn Operating, LLC (“LOI”, and together with LEH, “Linn”) pursuant to which, among other things, Citizen and Linn agreed to contribute oil and natural gas properties within an area-of-mutual-interest to the Company (collectively the “Contribution”). In exchange for their contributions, Citizen and Linn each received a 50% equity interest in Roan LLC. The contributions of oil and natural gas properties to Roan LLC by Citizen and Linn were determined to meet the definition of a business. However, as Roan LLC had no assets or operations prior to the Contribution, it was determined that Citizen was the acquirer for accounting purposes in accordance with ASC Topic 805, Business Combinations . As a result, the information in the accompanying financial statements and footnotes for the period prior to the Contribution reflects the historical results of Citizen. Citizen was formed in July 2014 to engage in the acquisition, exploration, development, production, and sale of oil and natural gas reserves in Central Oklahoma. Subsequent to the Contribution, the information in the accompanying financial statements and footnotes reflects the results of Roan LLC and after the Reorganization, the results of Roan Inc. See Note 4 – Acquisitions for additional discussion of the business combination of the oil and natural gas properties contributed by Linn. In conjunction with the Contribution Agreement, the Company entered into management services agreements with both Citizen and Linn (“MSAs”) through April 2018. See Note 12 –Transactions with Affiliates for additional discussion of the MSAs and transactions with Citizen and Linn. The Company was formed to engage in the acquisition, exploration, development, production, and sale of oil and natural gas reserves. The Company’s oil and natural gas properties are located in Central Oklahoma. The Company’s corporate headquarters is located in Oklahoma City, Oklahoma.

Basis of Presentation and Signi

Basis of Presentation and Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation and Significant Accounting Policies	Note 2 – Basis of Presentation and Significant Accounting Policies Basis of Presentation The accompanying consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements of the Company include the accounts of Roan Inc. and its wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated. Certain amounts in the prior period financial statements have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on net income (loss), total stockholders’ equity or total cash flows. Use of Estimates The preparation of financial statements and related footnotes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management’s estimates and assumptions is the estimate of proved oil, natural gas and NGL reserves which are used in the calculation of depletion of the Company’s oil and natural gas properties and impairment, if any, of proved oil and natural gas properties. Changes in estimated quantities of its reserves could impact the Company’s reported financial results as well as disclosures regarding the quantities and value of proved oil and natural gas reserves. Although management believes these estimates are reasonable, actual results could differ from these estimates. Revenue Recognition Revenues from the sale of oil, natural gas and NGLs are recognized when control of the product has been transferred to the customer, all performance obligations have been satisfied and collectability is reasonably assured. We recognize revenues from the sale of oil, natural gas and NGLs based on our share of volumes sold. See Note 3 – Revenue from Contracts with Customers for additional discussion. Fair Value Measurements The Company follows a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1— Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2— Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date. Level 3— Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during 2018 or 2017 . Business Combinations The Company accounts for all business combinations using the acquisition method, which involves the use of significant judgment. In a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill. The Company estimates the fair values of assets acquired and liabilities assumed in a business combination using various assumptions (all of which are Level 3 inputs within the fair value hierarchy). The most significant assumptions typically relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of the proved and unproved oil and natural gas properties, the Company develops estimates of oil, natural gas and NGL reserves. Estimates of reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Additionally, a risk factor is applied to reserves by reserve type based on industry standards. The Company estimates future prices to apply to the estimated net quantities of reserves based on the applicable ownership percentage acquired and estimates future operating and development costs to arrive at estimates of future net cash flows. The future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. Oil and Natural Gas Properties The Company follows the successful efforts method to account for its exploration and production activities. Under this method, costs incurred to purchase, lease, or otherwise acquire a property, whether unproved or proved, are capitalized when incurred. The Company initially capitalizes exploratory well costs pending a determination whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed as incurred. Additionally, costs to operate and maintain wells and field equipment are expensed as incurred. Depletion is computed using the units-of-production method on a field level basis over the remaining estimated life of proved reserves. The Company determined its oil and natural gas properties are comprised of one single field. Capitalized drilling and development costs of producing oil and natural gas properties are amortized based on the total estimated proved developed reserves. Proved leasehold costs associated with proved reserves are depleted based on total proved reserves, which includes proved undeveloped reserves. Under the unit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. The Company recorded depletion expense on capitalized oil and natural gas properties of $122.2 million , $37.0 million , and $24.9 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property. The net carrying values of retired, sold or abandoned proved properties that constitute less than a complete unit of depletable property are charged, net of proceeds, to accumulate depreciation, depletion and amortization unless doing so significantly affect the unit-of-production amortization rate, in which case a gain or loss is recognized to earnings. Gains or losses from the disposal of complete units of depletable property are recognized in earnings. Proceeds from sales of all or a partial interest in individual unproved properties assessed for impairment on a group basis are accounted for as a recovery of costs. No gain or loss is recognized unless the sales proceeds exceed the original cost of the entire interest in the property, in which a gain will be recognized for the excess. The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. The Company capitalized interest of $8.3 million for the year ended December 31, 2018 . No interest was capitalized in the years ended December 31, 2017 or 2016. Impairment of Oil and Natural Gas Properties Proved oil and natural gas properties are evaluated for impairment when facts or circumstances indicate that the carrying value of those assets may not be recoverable, such as when there are declines in oil and natural gas prices or well performance. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. An impairment loss is indicated if the sum of the estimated undiscounted future cash flows related to an asset group is less than the carrying value of that asset group. If an impairment loss has been incurred, the loss recognized is the excess of the carrying amount over the estimated fair value. The Company calculates the estimated fair value using a discounted future cash flow model. Management’s assumptions associated with the calculation of future cash flows include oil and natural gas prices based on NYMEX futures price strips, as well as other assumptions, including (i) pricing adjustments for differentials, (ii) production costs, (iii) capital expenditures, (iv) production volumes, (v) timing of development, and (vi) estimated reserves. A discount rate, consistent with that used by market participants, is applied to the estimated future cash flows in order to estimate fair value. Cash flow estimates for impairment testing exclude the effects of derivative instruments. It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) oil and natural gas futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, and (iv) results of future drilling activities. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2018 , 2017 , and 2016 . The Company’s unproved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictated that the carrying value of those assets may not be recoverable. For the years ended December 31, 2017 and 2016 , the Company recorded abandonment and impairment expense on its unproved oil and natural gas properties of $4.5 million and $5.3 million , respectively, for leases which have expired, or are expected to expire. Impairment expense on unproved oil and natural gas properties is included in exploration expense in the accompanying consolidated statements of operations. No impairment of unproved oil and natural gas properties was recorded for the year ended December 31, 2018 . Unproved leasehold costs are amortized on a group basis if individually insignificant, and a valuation allowance is established with a monthly amortization charge to exploration expense for the portion of the properties’ total cost that management estimates may never be transferred to proved properties during the terms of the respective leases. The impairment amortization rate considers the Company’s current drilling plans, the remaining terms of the respective leases and the results of exploratory drilling activity, and can be affected by economic factors including oil and natural gas price outlooks, projected capital costs, and available liquidity. For the years ended December 31, 2018 and 2017 , the Company recorded amortization expense on its unproved oil and natural gas properties of $36.0 million and $19.6 million , respectively, which is reflected in exploration expense on the accompanying consolidated statements of operations. There was no such expense recorded for the year ended December 31, 2016 . Costs of expired or relinquished leases are charged against the valuation allowance. Derivative Instruments The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value and are included in the balance sheet as derivative assets and derivative liabilities, on a net basis by counterparty. The Company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s commodity derivative instruments are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The Company has not designated any of the derivative contracts as fair value or cash flow hedges for accounting purposes for any of the periods presented. Accordingly, net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments and are included in gain (loss) on derivative contracts in the consolidated statements of operations. The Company’s cash flow is impacted when the settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty and are reflected as operating activities in the Company’s consolidated statements of cash flows. The Company’s firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment. Accrued Liabilities The components of accrued liabilities are presented below: December 31, 2018 2017 (in thousands) Accrued capital expenditures $ 151,965 $ 7,252 Accrued production expenses 10,879 — Accrued general and administrative expenses 7,450 2,696 Other 6,200 297 Total accrued liabilities $ 176,494 $ 10,245 Drilling Advances The Company’s drilling advances consist of cash provided to the Company from its joint interest partners for planned drilling activities. Advances are applied against the joint interest partner’s share of expenses incurred. As noted above, the Company entered into MSAs with Citizen and Linn to perform services, including operating the contributed assets. At December 31, 2017 and through the termination of the MSAs, Citizen and Linn maintained any drilling advances from joint interest partners. See Note 12 –Transactions with Affiliates for discussion of the MSAs with Citizen and Linn. Asset Retirement Obligation The Company is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company’s asset retirement obligations (“ARO”) relate to the plugging of wells and the related abandonment of oil and natural gas properties. AROs are recognized as liabilities with an increase to the carrying amounts of the related assets when the obligation is incurred. The cost of the asset, including ARO, is depreciated over the useful life of the asset. Fair value of ARO is measured using the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value and the liability is settled or the well is sold, at which time the liability is removed. Accretion expense is included in accretion expense in the consolidated statements of operations. Cash and Cash Equivalents The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains its cash balances at credit-worthy financial institutions that are insured by the Federal Deposit Insurance Corporation (“FDIC”). At times, cash balances may be in excess of FDIC limits. The Company has not incurred any losses related to the amounts in excess of FDIC limits. Accounts Receivable Accounts receivable consists mainly of receivables from oil, natural gas and NGL purchasers and joint interest owners on properties the Company operates. Accounts receivable from the sale of oil, natural gas and NGLs are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. The Company routinely reviews outstanding balances, assesses the financial strength of its purchasers and joint interest owners and records a reserve for amounts not expected to be fully recovered. The need for an allowance is determined based upon reviews of individual accounts, existing economic conditions and other pertinent factors. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. At December 31, 2018 , the Company recorded an allowance for doubtful accounts of $3.3 million related to receivables from joint interest owners. The Company had no reserve for bad debts at December 31, 2017 . Deferred Financing Costs Costs incurred in connection with the Company’s debt are capitalized and amortized as interest expense over the scheduled maturity period. Unamortized costs are associated with the Company’s revolving credit facility and are reflected as a component of long-term assets in the consolidated balance sheets. Equity-Based Compensation Equity-based compensation is measured based on the grant date fair value of the award and recognized over the requisite service period. For employees directly involved in exploration and development activities, equity compensation is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses or production expense in the consolidated statements of operations. The Company accounts for forfeitures of stock compensation as they occur. As of December 31, 2018 , no forfeitures have occurred. Earnings (Loss) per Share The Company uses the treasury stock method to determine the potential dilutive effect of outstanding performance share units and restricted stock units. Refer to Note 11 – Equity Compensation for details on the Company’s performance share units and restricted stock units. Income Taxes The Company is a corporation and therefore a taxable entity. Our predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for income tax purposes, flowed through to its members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of its members. As a result of the Reorganization, the Company recorded a deferred tax liability based on the change in its tax status. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. See Note 13 – Income Taxes for further information on the Company’s taxes. The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not, based on technical merits, that the tax position will be sustained upon examination. Any interest or penalties would be recognized as a component of income tax expense. Defined Contribution Plan In 2018, the Company adopted a 401(k) retirement plan and health and welfare benefit plans in which our employees are eligible to participate. Under the 401(k) retirement plan, the Company provides for an employer match of employee contributions of up to 6% of eligible compensation and a profit-sharing contribution of up to 8% of eligible compensation. For the year ended December 31, 2018 , the Company paid $1.2 million in contributions to the plan. Comprehensive Income The Company has no elements of comprehensive income other than net income. Concentrations of Credit Risk The Company sells oil, natural gas and NGLs to various types of customers. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. Additionally, limitations on capacity at processing plants could also impact the Company’s ability to sell its oil, natural gas and NGLs. The Company is subject to credit risk resulting from the concentration of its oil, natural gas and NGL receivables with its significant purchasers. The Company does not believe the loss of any single purchaser would materially impact its results of operations because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers. For the years ended December 31, 2018 , 2017 , and 2016 , the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues: Years Ended December 31, 2018 2017 2016 Coffeyville Resources Refining & Marketing LLC 31 % * * Sunoco Inc. 18 % 40 % 55 % Blue Mountain Midstream LLC 15 % * * EnLink Oklahoma Gas Processing, LP 13 % 39 % 31 % * Revenue from customer was less than 10% in this period. Blue Mountain Midstream LLC (“Blue Mountain”) is deemed a related party as it is a wholly-owned subsidiary of Riviera Resources, Inc. (“Riviera”). See Note 12 –Transactions with Affiliates . The Company’s derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties, which are financial institutions, may be unable to meet the financial terms of the transactions. The Company monitors on an ongoing basis the credit ratings of its derivative counterparties and considers its counterparties’ credit default risk ratings in determining the fair value of its derivative contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. The counterparties to the Company’s derivative contracts at December 31, 2018 are also lenders under its revolving credit facility. As a result, the Company does not require collateral or other security from counterparties nor is the Company required to post collateral to support derivative instruments. The Company has master netting agreements with all of its derivative counterparties, which allow the Company to net its derivative assets and liabilities with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts. Commitments and Contingencies The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. The amount of ultimate loss may differ from these estimates. Except for environmental contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Risks and Uncertainties Historically, the markets for oil, natural gas, and NGLs have experienced significant price fluctuations. Price fluctuations can result from variations in weather, regional levels of production, availability of transportation capacity, and various other factors. Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities. A portion of the Company’s oil and natural gas production may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions, the unavailability of gathering, processing, compression, transportation or refining facilities or equipment or field labor issues, or intentionally as a result of market conditions such as oil or natural gas prices that the Company deems uneconomic. If a substantial amount of the Company’s production is interrupted or shut in, the Company’s cash flows and, in turn, it’s financial condition and results of operations could be materially and adversely affected. Recently Issued Accounting Standards In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”). This guidance supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (“ASU 2016-08”), pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity records revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Applying the guidance in ASU 2016-08 requires significant judgment in determining the point in time when control of products transfers to customers. Effective January 1, 2018, the Company adopted ASC 606 using the modified retrospective method of transition under which the standard is applied only to the most current period presented. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard. See Note 3 – Revenue from Contracts with Customers for discussion of the impact upon adoption and the additional disclosures. Recently Issued Accounting Standards Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”). This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for fiscal years beginning after December 15, 2018, including interim reporting periods within those fiscal years, with early application permitted. The Company enters into lease agreements to support its operations, such as office space, drilling rigs and field equipment. ASU 2016-02 will not impact the accounting or financial presentation of the Company’s mineral leases. The Company plans to adopt the new standard using the simplified transition method described in ASU 2018-11 Leases (Topic 842): Targeted Improvements , and therefore will apply the new standard as of January 1, 2019. Accordingly, comparative information will not be adjusted and will continue to be reported under the previous lease standard. The Company plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases, but does not plan to elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. The Company also plans to elect the practical expedient under ASU 2018-01 Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 that allows it to not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The Company is working to complete its evaluation of the impact of ASU 2016-02 on its financial statements, accounting policies, and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures. At this time, the impact upon adoption of ASU 2016-02 and other related ASUs is expected to result in recognition of additional operating liabilities ranging from $7 million to $12 million , with corresponding right-of-use assets of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company currently plans to elect the short-term lease recognition exemption for all leases that qualify and the practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contracts with Customers	Note 3 – Revenue from Contracts with Customers The Company adopted ASC 606 on January 1, 2018 using a modified retrospective approach, which only applies to contracts that were not completed as of the date of initial application. The adoption did not require an adjustment to opening retained earnings for the cumulative effect adjustment. The adoption does not have a material impact on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but does impact the Company’s presentation of revenues and expenses under the gross-versus-net presentation guidance in ASU 2016-08. The following table shows the impact of the adoption of ASC 606 on the Company’s current period results as compared to the previous revenue recognition standard, ASC Topic 605, Revenue Recognition (“ASC 605”): Year Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase/ (decrease) (in thousands) Revenues Oil sales $ 275,239 $ 275,399 $ (160 ) Natural gas sales $ 76,056 $ 96,086 $ (20,030 ) Natural gas liquid sales $ 88,472 $ 114,021 $ (25,549 ) Operating expenses Gathering, transportation and processing $ — $ 45,739 $ (45,739 ) Net loss $ (140,671 ) $ (140,671 ) $ — Oil Sales Most of the Company’s oil contracts transfer physical custody and title at or near the wellhead, which is commonly when control of the oil has been transferred to the purchaser. The Company’s oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price. Any differentials incurred after the transfer of control of the oil are net against oil sales as they represent part of the transaction price of the contract. For its oil contracts, the Company generally records its sales based on the net amount received. Natural Gas and NGL Sales Most of the Company’s natural gas is sold at the wellhead or inlet to the processor’s facility, which is commonly when control of the natural gas has been transferred to the purchaser. The natural gas is sold under percentage of proceeds processing contracts. Under these contracts, the purchaser gathers the natural gas where it is produced and transports it via pipeline to natural gas processing plants where NGL products are extracted. The NGL products and remaining residue gas are then sold by the purchaser. Under the natural gas percentage of proceeds contracts, the Company receives a percentage of the value for the extracted NGLs and the residue gas. For its natural gas processing contracts, the Company generally records its natural gas and NGL sales net of gathering, processing and transportation expenses based on a principal versus agent assessment for individual contracts. Performance Obligations The Company satisfies the performance obligations under its oil and natural gas sales contracts through delivery of its production and transfer of control to a customer. Upon delivery of production, the Company has the right to receive consideration from its customers in amounts that correspond with the value of the production transferred. The Company typically receives payment for oil, natural gas and NGL sales within 30 days of the month of delivery for operated properties and within 90 days of the month of delivery for non-operated properties. The Company’s oil sales contracts 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, which provides an exemption 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 natural gas and NGL sales contracts that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606 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. Contract Balances The Company recognizes sales of oil, natural gas, and NGLs at a point in time when it satisfies a performance obligation and at that point the Company has an unconditional right to receive payment. Accordingly, these contracts do not give rise to contract assets or contract liabilities under ASC 606. The Company had accounts receivable related to revenue from contracts with customers of approximately $65.2 million as of December 31, 2018 , which represent this unconditional right to receive payment. Prior Period Performance Obligations To record revenues for oil, natural gas and NGLs, the Company estimates the amount of production delivered at the end of each month and the prices expected to be received for those sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer. For the year ended December 31, 2018 , revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Acquisitions	Note 4 – Acquisitions Linn Acquisition As noted in Note 1 – Business and Organization , in connection with the Contribution, Roan LLC acquired from Linn certain oil and natural gas properties located in Central Oklahoma (the “Linn Acquisition”). In exchange for the contributed oil and natural gas properties, Linn received a 50% equity interest in Roan LLC valued at approximately $1.3 billion based on the value of the business. Accordingly, the fair value of the Company was primarily comprised of the fair value of these contributed oil and natural gas properties. See Note 10 – Equity for further discussion of the equity issued to Linn. Because the Linn Acquisition was determined to be a business combination as the acquired oil and natural gas properties met the definition of a business, the acquired assets and liabilities were recorded at fair value as of August 31, 2017, the acquisition date. The following assumptions were used to determine the fair value of the oil and natural gas properties: Discount rate 9.50 % Reserve risk factor (1) 35%-100% Oil price three years NYMEX WTI forward curve Natural gas price three years NYMEX Henry Hub forward curve NGL price 39% of oil price Price escalation (2) 2.00 % (1) Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%. (2) Prices were escalated at the end of the forward curve The following table summarizes the purchase price and allocation of the fair values of assets acquired and liabilities assumed (in thousands): Consideration given Equity units $ 1,281,743 Allocation of purchase price Inventory $ 205 Proved oil and natural gas properties 214,647 Unproved oil and natural gas properties 1,086,600 Total assets acquired 1,301,452 Asset retirement obligations (7,547 ) Revenue suspense (12,162 ) Total fair value of net assets acquired $ 1,281,743 The following unaudited pro forma combined results of operations is provided for the years ended December 31, 2017 and 2016 as though the Linn Acquisition had been completed as of the earliest period presented at the time of the acquisition. The pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of the assets acquired in the Linn Acquisition. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Linn Acquisition or any estimated costs incurred to integrate the Linn Acquisition. (Unaudited) Years Ended December 31, 2017 2016 (in thousands) Revenue $ 215,161 $ 90,238 Net income $ 44,873 $ 26,378 Acquisitions of Unproved Properties During the year ended December 31, 2017, the Company acquired, from unrelated third parties, interests in approximately 23,400 net acres of leasehold in separately negotiated transactions for aggregate cash consideration of $49.7 million , all of which were accounted for as asset acquisitions and recorded as additions to unproved oil and natural gas properties. As discussed in Note 12 –Transactions with Affiliates , Citizen and Linn acquired acreage during 2017 on behalf of Roan LLC for $63.0 million , which was included in accounts payable and accrued liabilities – affiliates at December 31, 2017. In March 2018, Roan LLC paid Linn $22.9 million in cash and issued equity units to both Citizen and Linn to settle the amount due.

Oil and Natural Gas Properties

Oil and Natural Gas Properties	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Oil and Natural Gas Properties	Note 5 – Oil and Natural Gas Properties The Company’s oil and natural gas properties are in the continental United States. The oil and natural gas properties include the following: December 31, 2018 2017 (in thousands) Oil and natural gas properties Proved $ 1,538,379 $ 750,492 Unproved 1,089,954 1,126,459 Less: accumulated depreciation, depletion, amortization and impairment (230,836 ) (78,307 ) Oil and natural gas properties, net $ 2,397,497 $ 1,798,644 There were no exploratory well costs pending determination of proved reserves at December 31, 2018 or 2017 no r any unsuccessful exploratory dry hole costs during the years ended December 31, 2018 and 2016 . During the year ended December 31, 2017 , there was $1.3 million of pre-drilling costs associated with an exploratory dry hole that is included in exploration costs in the accompanying consolidated statements of operations.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6 – Asset Retirement Obligations The following is a reconciliation of the changes in the Company’s ARO for the years ended December 31, 2018 and 2017 : Years Ended December 31, 2018 2017 (in thousands) Asset retirement obligation, beginning balance $ 10,769 $ 2,245 Liabilities incurred or acquired (1) 3,347 8,118 Revisions in estimated cash flows (2) 2,018 42 Liabilities settled (139 ) — Accretion expense 853 364 Asset retirement obligation, ending balance 16,848 10,769 Less: current portion of obligations 790 — Asset retirement obligation - long term $ 16,058 $ 10,769 (1) For the year ended December 31, 2017, liabilities incurred or acquired included $7.5 million assumed as part of the Linn Acquisition. (2) For the year ended December 31, 2018 , revisions primarily represent changes in the economic lives of producing properties and the Company’s share of estimated costs.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long-Term Debt	Note 7 – Long-Term Debt In September 2017, the Company entered into a $750.0 million credit agreement with an initial borrowing base of $200.0 million and maturity on September 5, 2022 (as amended, the “2017 Credit Facility”). In September 2018, the redetermination resulted in an increase to the borrowing base to $675.0 million . Redetermination of the borrowing base of the 2017 Credit Facility occurs semiannually on or about October 1 and April 1. As of December 31, 2018 , the Company had $ 514.6 million of outstanding borrowings and no letters of credit outstanding under the 2017 Credit Facility. At December 31, 2018 , the weighted average interest rate on borrowings under our 2017 Credit Facility was 5.21% . The 2017 Credit Facility is secured by substantially all of the assets of the Company. The Company amended the 2017 Credit Facility in September 2018 to increase the borrowing base as noted above as well as to allow for permitted additional debt of up to $500 million before any reduction in the borrowing base would occur, to reduce the applicable margin for both London Interbank Offered Rate (“LIBOR”) and alternate base rate (“ABR”) loans by 0.25% for each utilization level, and to reduce the commitment fee rate for the two lowest utilization levels to 0.375% . Principal maturities of the Company’s borrowings at December 31, 2018 , consisting of amounts outstanding under the 2017 Credit Facility, are as follows (in thousands): 2019 $ — 2020 — 2021 — 2022 514,639 $ 514,639 Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the ABR at the Company’s election. The rate used for ABR loans is based on the higher of the prime rate, the federal funds effective rate plus 0.50% or the one-month LIBOR rate plus 1% . Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the 2017 Credit Facility. Additionally, the 2017 Credit Facility provides for a commitment fee, which is payable at the end of each calendar quarter. The pricing grid below shows the applicable margin for LIBOR rate or ABR loans as well as the commitment fee depending on the Utilization Level (as defined in the credit agreement): Utilization Level Utilization LIBOR Margin ABR Margin Commitment Fee Level I <25% 2.00% 1.00% 0.375% Level II >25% but <50% 2.25% 1.25% 0.375% Level III >50% but <75% 2.50% 1.50% 0.500% Level IV >75% but <90% 2.75% 1.75% 0.500% Level V >90% 3.00% 2.00% 0.500% The 2017 Credit Facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on the sale of property, mergers, consolidations and other similar transactions covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on dividends, distributions, redemptions and restricted payments covenants. Additionally, the Company is prohibited from hedging in excess of (a) 80% of reasonably anticipated projected production for the first thirty (30) month rolling period (based upon the Company’s internal projections) and (b) 80% of reasonably anticipated projected production from proved reserves for the second thirty (30) month rolling period of such sixty (60) month period (based on the most recently delivered reserve report). If the amount of borrowings outstanding exceed 50% of the borrowing base, the Company is required to hedge a minimum of 50% of the future production expected to be derived from proved developed reserves for the next eight quarters per its most recent reserve report. The 2017 Credit Facility also contains financial covenants requiring the Company to comply with a leverage ratio of the Company’s consolidated debt to consolidated EBITDAX (as defined in the credit agreement) for the period of four fiscal quarters then ended of not more than 4.00 to 1.00 and a current ratio of the Company’s consolidated current assets to consolidated current liabilities (as defined in the credit agreement to exclude non-cash assets and liabilities under ASC Topic 815 Derivatives and Hedging and ASC Topic 410 Asset Retirement and Environmental Obligations ) as of the fiscal quarter ended of not less than 1.00 to 1.00 . As of December 31, 2018 , the Company was in compliance with the covenants under the 2017 Credit Facility. Prior to the 2017 Credit Facility, Citizen had a two -year, $500.0 million credit facility (“Citizen 2017 Credit Facility”) with an initial borrowing base of $82.5 million . In August 2017, the Citizen 2017 Credit Facility was terminated and the outstanding balance of $20.3 million was repaid.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Note 8 – Derivative Instruments The Company utilizes fixed price swaps and basis swaps to manage the price risk associated with the sale of its oil, natural gas and NGL production. Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract and the referenced settlement price. Basis swaps are settled monthly based on differences between a fixed price differential and the applicable market price differential, the Panhandle Eastern Pipeline or Natural Gas Pipeline Company of America Mid-Continent. When the referenced settlement price is less than the price specified in the contract, the Company receives an amount from the counterparty based on the price difference multiplied by the volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company pays the counterparty an amount based on the price difference multiplied by the volume. The following table reflects the Company’s open commodity contracts at December 31, 2018 : 2019 2020 Total Oil fixed price swaps Volume (Bbl) 5,405,670 1,599,500 7,005,170 Weighted-average price $ 60.05 $ 63.14 $ 60.76 Natural gas fixed price swaps Volume (MMBtu) 43,800,000 12,325,000 56,125,000 Weighted-average price $ 2.90 $ 2.63 $ 2.84 Natural gas basis swaps Volume (MMBtu) 29,200,000 3,640,000 32,840,000 Weighted-average price $ 0.60 $ 0.62 $ 0.60 Natural gas liquids fixed price swaps Volume (Bbl) 1,095,000 — 1,095,000 Weighted-average price $ 32.25 $ — $ 32.25 The Company nets the fair value of derivative instruments by counterparty in the accompanying consolidated balance sheets where the right to offset exists. See Note 9 – Fair Value Measurements for further information regarding the fair value measurement of the Company’s derivatives. As the Company has elected to not account for commodity derivative instruments as hedging instruments, gains or losses resulting from the change in fair value along with the gains or losses resulting in settlement of derivative contracts are reflected in gain (loss) on derivative contracts included in the consolidated statement of operations. The following table presents the Company’s gain (loss) on derivative contracts and net cash (paid) received upon settlement of its derivative contracts for the years ended December 31, 2018 and 2017 : Years Ended December 31, 2018 2017 (in thousands) Gain (loss) on derivative contracts $ 78,054 $ (6,797 ) Net cash (paid) received upon settlement of derivative contracts (1) $ (33,279 ) $ 2,705 (1) Includes $1.3 million of cash received upon settlement of derivative contracts prior to their contractual maturity for the year ended December 31, 2017 . There were no gains or losses on derivative contracts in the year ended December 31, 2016 and no derivative contracts outstanding as of December 31, 2016 .

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 9 – Fair Value Measurements Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Company’s recurring fair value measurements are performed for its commodity derivatives. Commodity Derivative Instruments Commodity derivative contracts are stated at fair value in the accompanying consolidated balance sheets. The Company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s commodity derivative instruments are classified as Level 2 measurements as they are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of December 31, 2018 and 2017 , as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands): December 31, 2018 Level 1 Level 2 Level 3 Gross Fair Value Netting Carrying Value Assets Current commodity derivatives $ — $ 85,728 $ — $ 85,728 $ (3,548 ) $ 82,180 Noncurrent commodity derivatives — 21,565 — 21,565 (927 ) 20,638 Total assets $ — $ 107,293 $ — $ 107,293 $ (4,475 ) $ 102,818 Liabilities Current commodity derivatives $ — $ (4,393 ) $ — $ (4,393 ) $ 3,548 $ (845 ) Noncurrent commodity derivatives — (1,068 ) — (1,068 ) 927 (141 ) Total liabilities $ — $ (5,461 ) $ — $ (5,461 ) $ 4,475 $ (986 ) December 31, 2017 Level 1 Level 2 Level 3 Gross Fair Value Netting Carrying Value Assets Current commodity derivatives $ — $ 2,856 $ — $ 2,856 $ (2,704 ) $ 152 Noncurrent commodity derivatives — 2,182 — 2,182 (1,186 ) 996 Total assets $ — $ 5,038 $ — $ 5,038 $ (3,890 ) $ 1,148 Liabilities Current commodity derivatives $ — $ (11,983 ) $ — $ (11,983 ) $ 2,704 $ (9,279 ) Noncurrent commodity derivatives — (2,557 ) — (2,557 ) 1,186 (1,371 ) Total liabilities $ — $ (14,540 ) $ — $ (14,540 ) $ 3,890 $ (10,650 ) Non-Recurring Fair Value Measurements The Company utilizes fair value on a non‑recurring basis to review its proved oil and natural gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. The Company uses an income approach analysis based on management’s estimated net discounted future cash‑flows of proved property. Unobservable inputs included estimates of oil and natural gas production, as the case may be, from the Company’s reserve reports, commodity prices based on the sales contract terms or forward price curves, operating and development costs, and a discount rate based on a market-based weighted average cost of capital (all of which are Level 3 inputs within the fair value hierarchy). The Company’s non‑recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations and the determination of the grant date fair value of the Company’s performance share units. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted‑cash flow approach using level 3 inputs. The fair value of assets or liabilities associated with purchase price allocations is on a non‑recurring basis and is not measured in periods after initial recognition. The grant date fair value of the Company’s performance share units is determined using a Monte Carlo simulation model and is classified as a Level 3 measurement. Please refer to Note 4 – Acquisitions and Note 11 – Equity Compensation for additional discussion. Other Financial Instruments The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables, and long-term debt. The carrying values of cash and cash equivalents, accounts payable, revenue payable, and accounts receivable approximate fair values due to the short-term maturities of these instruments and the carrying value of long-term debt approximates fair value as the applicable interest rates are variable and reflective of market rates.

Equity

Equity	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Equity	Note 10 – Equity In September 2018 and in conjunction with the Reorganization, the Company issued 152.5 million shares of its Class A common stock to the members of Roan LLC in exchange for their equity interest in Roan LLC. The Reorganization was accounted for as a reverse recapitalization with Roan Inc. as the accounting acquirer and therefore did not result in any change in the accounting basis for the underlying assets. Net income before taxes and equity-based compensation were allocated ratably to the members of Roan LLC and the stockholders of Roan Inc. for the period before and after the Reorganization, respectively. For comparative purposes, the issuance of the shares to the members of Roan LLC at the time of the Reorganization was reflected on a retroactive basis with the units outstanding during each period presented. For the period of September 1, 2017 through the date of the Reorganization, Roan LLC was governed by the Amended and Restated Limited Liability Company Agreement of Roan Resources LLC. In connection with the Contribution in August 2017, Roan LLC issued 1.5 billion membership units representing capital interests in Roan LLC (the “LLC Units”) for a 50% equity interest in Roan LLC, to Linn in exchange for the contribution of oil and natural gas properties. See Note 4 – Acquisitions for additional discussion of the Linn Acquisition. Additionally, Roan LLC issued 1.5 billion LLC Units, which represented a 50% equity interest in Roan LLC, to Citizen in exchange for the contribution of oil and natural gas properties. The fair value of the LLC Units issued to Citizen was the same as that of the LLC Units issued to Linn. As discussed in Note 4 – Acquisitions , Citizen and Linn acquired acreage during 2017 on Roan LLC’s behalf. In March 2018, Roan LLC issued 19.2 million LLC Units to each Citizen and Linn for the additional leasehold acreage. For the period January 1, 2017 through August 31, 2017, Citizen’s operations were governed by the provisions of the Citizen Amended and Restated Operating Agreement (the “Citizen Operating Agreement”), effective February 29, 2016, and Citizen had two classes of membership interests outstanding, Class A and Class B interests. Class A interests represented capital interests in Citizen and Class B interests represented interests in profits, losses and distributions. Distributions were made to the Class A interests and Class B interests members pro rata in accordance with their membership interests; however, once the Class A interests members received an internal rate of return threshold of 9% prior to distributions to any other class of interest, the Class B interests members received a percentage of distributions in excess of their membership interests based on the terms of the Citizen Operating Agreement.

Equity Compensation

Equity Compensation	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity Compensation	Note 11 – Equity Compensation The Company has adopted the Roan Resources, Inc. Amended and Restated Management Incentive Plan (the “Plan”), which provides for grants of options, stock appreciation rights, restricted stock unit, stock awards, dividend equivalents, other stock-based awards, cash awards and substitute awards. Performance Share Units Prior to the Reorganization, Roan LLC granted performance share units to certain of its employees under the Roan LLC Management Incentive Plan. The performance share units were converted into awards of performance share units under the Plan, hereafter referred to as the “PSUs,” and are subject to the terms of the Plan and individual award agreements. The amount of PSUs that can be earned range from 0% to 200% based on the Company’s market value on December 31, 2020 (“Performance Period End Date”). The Company’s market value on the Performance Period End Date will be determined by reference to the volume-weighted average price of the Company’s Class A common stock for the 30 consecutive trading days immediately preceding the Performance Period End Date. Each earned PSU will be settled through the issuance of one share of the Company’s Class A common stock. Other than the security in which the PSUs are settled, no terms of the PSUs were modified in connection with the conversion of the PSUs. The following table presents activity for the Company’s PSUs during the years ended December 31, 2018 and 2017. Number of Weighted Total Fair Outstanding at December 31, 2016 — $ — $ — Granted 16,350,000 1.41 23,054 Vested — — — Outstanding at December 31, 2017 16,350,000 $ 1.41 $ 23,054 Granted 6,825,000 1.88 12,810 Vested — — — Conversion (1) (22,016,250 ) — — Outstanding at December 31, 2018 1,158,750 $ 30.95 $ 35,864 (1) PSUs were converted on a basis of 0.05 to 1.0. There was no change to the deemed fair value of the awards based on assessment of modification. Compensation expense associated with the PSUs for the years ended December 31, 2018 and 2017 was $11.0 million and $0.4 million , respectively, and is included in general and administrative expenses on the accompanying consolidated statements of operations. There was no such expense during the year ended December 31, 2016. Unrecognized expense as of December 31, 2018 for all outstanding PSU awards was $24.4 million , which will be recognized over a weighted-average remaining period of 2.0 years. Under the treasury stock method, the PSUs are antidilutive for the weighted average share calculation and therefore are excluded from dilutive weighted average shares in the accompanying consolidated statements of operations. The grant date fair value of the PSUs was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned and estimated Company value on the Performance Period End Date. The grant date fair value of the PSUs is expensed on a straight-line basis from the grant date to the Performance Period End Date. The following table shows the range of assumptions that were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSUs granted during the year ended December 31, 2018 : Company enterprise value (in billions) $4.19 - $4.56 Equity volatility 34.0% - 36.0% Weighted average risk-free interest rate 1.96% - 2.54% Restricted Stock Units Under the Plan, the Company is authorized to issue restricted stock and restricted stock units to eligible employees. The Company estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents activity for the Company’s restricted stock units during the year ended December 31, 2018 : Number of Weighted Total Fair Value ($ in thousands) Outstanding at December 31, 2017 — $ — $ — Granted 11,800 16.95 200 Vested — — — Forfeited — — — Outstanding at December 31, 2018 11,800 $ 16.95 $ 200 Compensation expense associated with the restricted stock units for the year ended December 31, 2018 was $0.03 million and is included in general and administrative expenses on the accompanying consolidated statements of operations. There were no restricted stock units issued prior to 2018. As of December 31, 2018 , the Company’s unrecognized compensation cost related to unvested restricted stock units was $0.2 million , which will be recognized over a weighted-average remaining period of 0.9 year. Under the treasury stock method, the restricted stock units are antidilutive for the weighted average share calculation and therefore are excluded from dilutive weighted average shares in the accompanying consolidated statements of operations.

Transactions with Affiliates

Transactions with Affiliates	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Transactions with Affiliates	Note 12 –Transactions with Affiliates Management Service Agreements Under the MSAs, Citizen and Linn provided certain services in respect to the oil and natural gas properties they contributed to the Company. Such services included serving as operator of the oil and natural gas properties contributed, land administration, marketing, information technology and accounting services. As a result of Citizen and Linn continuing to serve as operator of the contributed assets and contracting directly with vendors for goods and services for operations, Citizen and Linn collected amounts due from joint interest owners for their share of costs and billed the Company for its share of costs. The services provided under the MSAs ended in April 2018 when the Company took over as operator for the oil and natural gas properties contributed by Citizen and Linn. In conjunction with the conclusion of the MSAs in April 2018, the Company assumed certain working capital accounts associated with the properties contributed from Citizen and Linn. For each of the years ended December 31, 2018 and 2017 , the Company incurred approximately $ 10.0 million for charges related to the services provided under the MSAs, which are recorded in general and administrative expenses in the accompanying consolidated statements of operations. Through April 2018, Citizen and Linn billed the Company for its share of operating costs in accordance with the MSAs. At December 31, 2017, the Company had $55.5 million and $46.5 million due to Linn and Citizen, respectively, included in accounts payable and accrued liabilities – affiliates in the accompanying consolidated balance sheets. At December 31, 2017, the Company had $19.0 million due to Linn and Citizen for revenue suspense associated with the oil and natural gas properties contributed to the Company included in accounts payable and accrued liabilities – affiliates in the accompanying consolidated balance sheets. Acquisition of Acreage As provided for in the Contribution Agreement, Citizen and Linn acquired additional acreage within an area of mutual interest on behalf of the Company. As of December 31, 2017, the additional acreage acquired totaled $63.0 million and the Company reflected the amount due to Citizen and Linn in accounts payable and accrued liabilities – affiliates. See Note 4 – Acquisitions and Note 10 – Equity for further discussion of the settlement of the payable due to Citizen and Linn related to the additional acquired acreage. Natural Gas Dedication Agreement The Company has a gas dedication agreement with Blue Mountain, a subsidiary of Riviera, which has directors and shareholders in common with the Company. Amounts due from Blue Mountain at December 31, 2018 and 2017 are reflected as accounts receivable – affiliates in the accompanying consolidated balance sheets and represent accrued revenue for the Company’s portion of the production sold to Blue Mountain. Sales to Blue Mountain are reflected as natural gas sales – affiliates and NGL sales – affiliates in the accompanying consolidated statements of operations. See further discussion of this gas dedication agreement in Note 14 – Commitments and Contingencies . Corporate Office Lease During 2018, the Company entered into a lease for office space in Oklahoma City, Oklahoma that is owned by a subsidiary of Riviera under a lease with an initial term of 5 years with an option to extend the lease for an additional 5 years at the end of the initial term. The Company paid $0.5 million during the year ended December 31, 2018 under this lease. Total remaining payments under the lease are $8.1 million . Reorganization Transactions In conjunction with the Reorganization, the Company entered into a tax matters agreement (“TMA”) with Riviera. See Note 13 – Income Taxes for further discussion of the TMA and the related payable to Riviera. Also in conjunction with the Reorganization, the Company paid certain legal costs incurred by Riviera on the Company’s behalf. These costs totaled $1.8 million and were included in general and administrative expenses in the accompanying consolidated statement of operations for the year ended December 31, 2018 . Consulting Services Atlas, LLC (“Atlas”) provided the Company supervisory services throughout drilling and completion operations. Atlas is wholly owned jointly by a director and an employee of Citizen. For the year ended December 31, 2017, the Company incurred $2.3 million in charges related to services provided which are recorded within oil and natural gas properties, successful efforts on the accompanying consolidated balance sheet. As of December 31, 2017, the Company had no amounts payable to Atlas. There were no such services provided by Atlas to the Company during the year ended December 31, 2018 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Note 13 – Income Taxes As discussed in Note 1 – Business and Organization , the Company was formed in September 2018 in connection with the Reorganization. The Company’s accounting predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for income tax purposes, flowed through to its members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of its members. A deferred tax liability was recorded as a result of the Reorganization based on the Company becoming a corporation that is a taxable entity under the Internal Revenue Code of 1986, as amended (the “Code”). The initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization was reflected in income tax expense based on the deferred tax liability resulting from the change in tax status. Due to the nontaxable nature of the Reorganization, there were no adjustments to the tax basis or other tax attributes in the measurement of the deferred taxes except to the extent any gain was recognized by the other parties to the Reorganization. The Company’s effective combined U.S. federal and state income tax rate for the year ended December 31, 2018 excluding discrete items was 24.3% . During the year ended December 31, 2018 , the Company recognized income tax expense of $356.9 million , including $304.5 million related to the initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization. In conjunction with the Reorganization, the Company entered into the TMA with Riviera. The TMA, in part, provides for the indemnification of the Company and the entitlement of Riviera to refunds related to certain taxes of Linn Energy, Inc. prior to the spinoff of assets from Linn Energy, Inc. to Riviera. As a result of the TMA and an estimated overpayment of federal taxes by Linn Energy, Inc. received by the Company, the Company recorded a payable of $7.6 million to Riviera at December 31, 2018 . The payable is included in accounts payable and accrued liabilities - affiliates in the accompanying consolidated balance sheets. At December 31, 2018 , the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax year for 2018 remains subject to examination by the major tax jurisdictions. The components of the Company’s provision for income taxes for the year ended December 31, 2018 are as follows (in thousands): Current income tax expense Federal $ — State — — Deferred income tax expense Federal 277,794 State 79,068 356,862 Provision for income taxes $ 356,862 The Company’s deferred tax assets and liabilities as of December 31, 2018 include the following (in thousands): Deferred income tax assets Net operating losses $ 42,013 Other 4,409 46,422 Deferred income tax liabilities Oil and natural gas properties (377,362 ) Derivative contracts (25,922 ) (403,284 ) Deferred tax liabilities, net $ (356,862 ) The following is a reconciliation, stated as a percentage of pretax income, of the United States statutory federal income tax rate to the Company’s effective tax rate for the year ended December 31, 2018: Amount Percent (in thousands) Income (loss) at U.S. federal statutory rate $ 45,400 21.0 % Net effect of state income taxes 9,173 4.2 % Change in tax status 304,455 140.8 % Other (2,166 ) (1.0 )% Income tax provision / Effective rate $ 356,862 165.0 % As of December 31, 2018 , the Company has federal and Oklahoma net operating loss carryforwards for both jurisdictions of $165.0 million , which do not expire.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 14 – Commitments and Contingencies Commitments The following table presents the future minimum payments under noncancelable operating leases and other commitments as of December 31, 2018 (in thousands): 2019 2020 2021 2022 2023 Thereafter Total Office building leases $ 1,692 $ 2,047 $ 2,136 $ 2,229 $ 456 $ 171 $ 8,731 Pipe and equipment purchase commitments (1) 1,455 — — — — — 1,455 Drilling rig commitments (2) 15,352 — — — — — 15,352 Total $ 18,499 $ 2,047 $ 2,136 $ 2,229 $ 456 $ 171 $ 25,538 (1) Reflects commitments to purchase specified amounts of pipe and equipment. (2) Reflects future minimum drilling fees including early termination fees as specified by the contract. Office building leases The Company leases its corporate office space in Oklahoma City, Oklahoma from a subsidiary of Riviera. This lease began in 2018 and expires in 2023. The Company leases additional office space from unrelated third parties for its field locations in Oklahoma. Rent expense with respect to these lease commitments was approximately $1.4 million for the year ended December 31, 2018. Drilling Contracts As of December 31, 2018 , the Company had entered into drilling rig contracts with various third parties in the ordinary course of business to ensure rig availability to complete the Company’s drilling projects. These commitments are not recorded in the accompanying consolidated balance sheets. Purchase Commitments As of December 31, 2018 , the Company had entered into pipeline and equipment purchase commitments with various third parties in the ordinary course of business to purchase specified amounts of pipe and equipment. These commitments are not recorded in the accompanying consolidated balance sheets. Litigation In the ordinary course of business, the Company may at times be subject to claims and legal actions. Management believes it is remote that the impact of such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. At December 31, 2018 and 2017 , the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability. Natural Gas Dedication Agreements The Company has dedicated its natural gas production from the oil and natural gas properties contributed by Citizen under an agreement with a third party. Under this dedication agreement, the Company is required to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement. For the oil and natural gas properties contributed by Linn, the Company assumed Linn’s dedication agreement with Blue Mountain. The agreement with Blue Mountain requires the Company to deliver its natural gas production from the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement. Volume Commitment Under an agreement with a third party, the Company has a requirement to deliver a minimum volume of natural gas from a specified area, as defined in the agreement. In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees on any undelivered volumes as of November 2021. If the Company is unable to deliver any natural gas volumes subsequent to December 31, 2018 through November 2021, it will owe deficiency fees of $8.1 million at the end of the commitment period.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Note 15 – Subsequent Events In January 2019, the Company entered into a water management services agreement with Blue Mountain. Under this agreement, Blue Mountain will provide water management services including pipeline gathering, disposal, treatment and redelivery of recycled water. The agreement provides for an acreage dedication for water management services through January 2029. In March 2019, the Company amended its 2017 Credit Facility to, among other things, increase its borrowing base to $750 million . Subsequent to December 31, 2018 , the Company entered into fixed price swaps of 40,000 MMBtu per day of natural gas production at a weighted average price of $2.68 for the period of October 2020 through December 2020 and for 2,000 Bbls per day of oil production at a weighted average price of $57.80 for the period of January 2020 through December 2020.

Supplemental Information on Oil

Supplemental Information on Oil and Natural Gas Operations (Unaudited) (Unaudited)	12 Months Ended
	Dec. 31, 2018
Extractive Industries [Abstract]
Supplemental Information on Oil and Natural Gas Operations (Unaudited)	Note 16. Supplemental Information on Oil and Natural Gas Operations (Unaudited) The following disclosures provide supplemental unaudited information regarding the Company’s oil, natural gas and NGL activities, which were entirely within the United States. Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: December 31, 2018 2017 (in thousands) Oil and natural gas properties Proved properties $ 1,538,379 $ 750,492 Unproved properties 1,089,954 1,126,459 Total oil and natural gas properties 2,628,333 1,876,951 Accumulated depreciation, depletion, amortization and impairment (230,836 ) (78,307 ) Oil and natural gas properties, net $ 2,397,497 $ 1,798,644 Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities are summarized as follows: December 31, 2018 2017 2016 (in thousands) Acquisition costs of properties Proved properties $ 5,655 $ 214,647 $ 1,079 Unproved properties 42,738 1,018,978 93,705 Development costs 719,198 390,991 152,284 Exploratory (1) 7,257 8,538 — Total costs incurred $ 774,848 $ 1,633,154 $ 247,068 (1) Includes seismic costs. Results of Operations for Oil, Natural Gas and NGL Producing Activities The following table sets forth the Company’s results of operations for oil, natural gas and NGL producing activities for the years ended December 31, 2018 , 2017 and 2016: Years Ended December 31, 2018 2017 2016 (in thousands) Oil, natural gas and NGL sales $ 439,767 $ 166,385 $ 54,965 Production expenses 47,600 16,872 5,090 Production taxes 17,579 3,685 1,087 Exploration expenses 43,303 28,154 — Gathering, transportation and processing (1) — 18,602 5,920 Depreciation, depletion, amortization, and accretion 123,062 37,376 24,996 Impairment — 4,475 5,258 Income tax expense (2) 13,103 — — Results of operations $ 195,120 $ 57,221 $ 12,614 (1) Gathering, transportation and processing for the year ended December 31, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard. (2) Income tax expense is calculated using results from the period after the Reorganization when the Company became a taxable entity and the Company’s effective tax rate of 24.3% . Oil, Natural Gas and NGL Reserves Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first day of the month prices. Proved reserves are estimated volumes of oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating quantities of proved reserves, and projecting future production rates and timing of future development costs. The following table sets forth proved reserves during the periods indicated: Oil (MBbls) Natural Gas (MMcf) NGLs (MBbls) Total (MBoe) Proved reserves at December 31, 2015 387 8,517 678 2,484 Purchases of reserves 22 333 33 111 Extensions and discoveries 2,632 33,218 2,956 11,124 Revisions of previous estimates 598 4,145 398 1,687 Production (740 ) (6,382 ) (546 ) (2,350 ) Proved reserves at December 31, 2016 2,900 39,831 3,519 13,057 Purchases of reserves 9,843 163,638 16,870 53,986 Extensions and discoveries 30,554 486,510 61,599 173,238 Revisions of previous estimates (3,583 ) 20,844 (260 ) (369 ) Production (2,294 ) (24,953 ) (2,150 ) (8,603 ) Proved reserves at December 31, 2017 37,420 685,869 79,578 231,309 Purchases of reserves — — — — Extensions and discoveries 34,714 451,750 48,791 158,797 Revisions of previous estimates (12,087 ) (184,547 ) (25,365 ) (68,209 ) Production (4,364 ) (41,890 ) (4,592 ) (15,938 ) Proved reserves at December 31, 2018 55,683 911,182 98,412 305,959 At December 31, 2018 , the Company had approximately 305,959 MBoe of proved reserves. During 2018, the Company drilled 214 gross wells. This continued development of the Company’s acreage and the drilling activity of other operators in the area with consideration of the Company’s development plan resulted in extensions and discoveries of 158,797 MBoe. Revisions of previous estimates for the year ended December 31, 2018 reflect downward revisions of 33,342 MBoe associated with production performance and downward revisions of 36,038 MBoe that resulted from reworking of the Company’s development plan, primarily driven by changes in wellbore lateral length and well density. The Company’s current development plan reflects allocation of capital with a focus on efficiencies, recoveries and rates of return. The impact of pricing on revisions of previous estimates was minimal. At December 31, 2017, the Company had approximately 231,309 MBoe of proved reserves. During 2017, the Company acquired unproved leasehold acreage and drilled 93 gross wells. The Company’s drilling activity and the drilling activity of other operators in the area resulted in extensions and discoveries of 173,238 MBoe. Purchase of reserves of 53,986 MBoe reflects the reserves acquired in the Linn Acquisition. Revisions of previous estimates reflects upward revisions associated with increases in pricing of 3,277 MBoe, offset by downward revisions associated with performance of 3,646 MBoe. The purchase of reserves and extensions and discoveries were the primary drivers in the increase in reserves from December 31, 2016 to December 31, 2017. At December 31, 2016, the Company had approximately 13,057 MBoe of proved reserves. During 2016, Citizen acquired approximately 62,500 net acres of unproved leasehold. Citizen’s drilling of 55 gross wells and the drilling activity of other operators in the area resulted in extensions and discoveries of 11,124 MBoe. Additionally, the Company had additions to reserves during 2016 of 111 MBoe from purchase of reserves and 1,687 MBoe as a result of revisions of previous estimates due to well performance. Extensions and discoveries were the primary driver in the increase in proved reserves from December 31, 2015 to December 31, 2016. The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped (“PUD”) oil, natural gas and NGL reserves of the Company as of December 31, 2018 , 2017, and 2016: December 31, 2018 2017 2016 Proved Developed Reserves Oil (MBbls) 18,652 12,352 2,900 Natural gas (MMcf) 369,677 259,193 39,831 NGL (MBbls) 39,927 24,034 3,519 Total (MBoe) 120,192 79,585 13,057 Proved Undeveloped Reserves Oil (MBbls) 37,031 25,068 — Natural gas (MMcf) 541,505 426,676 — NGL (MBbls) 58,485 55,544 — Total (MBoe) 185,767 151,724 — Total Proved Reserves Oil (MBbls) 55,683 37,420 2,900 Natural gas (MMcf) 911,182 685,869 39,831 NGL (MBbls) 98,412 79,578 3,519 Total (MBoe) 305,959 231,309 13,057 In accordance with SEC regulations, the Company uses the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period. The oil and natural gas prices used in computing the Company’s reserves as of December 31, 2018 , 2017, and 2016 were $65.66 , $51.34 , and $42.64 per barrel of oil, respectively, $3.16 , $2.98 , and $2.48 per MMBtu of natural gas, respectively. The NGL prices used in computing the Company’s reserves as of December 31, 2018 , 2017, and 2016 were $20.35 , $19.00 , and $15.26 per barrel, respectively. Approximately 93% of our proved reserve estimates as of December 31, 2018 were prepared by DeGolyer and MacNaughton, our independent reserve engineers. Our personnel prepared reserve estimates with respect to the remaining approximate 7% of our proved reserves as of December 31, 2018. All estimates of proved reserves are determined according to the rules prescribed by the SEC in existence at the time estimates were made. These rules require that the standard of “reasonable certainty” be applied to proved reserve estimates, which is defined as having a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as more technical and economic data becomes available, a positive or upward revision or no revision is much more likely than a negative or downward revision. Estimates are subject to revision based upon a number of factors, including many factors beyond the Company’s control such as reservoir performance, prices, economic conditions, and government restrictions. In addition, results of drilling, testing, and production subsequent to the date of an estimate may justify revision of that estimate. Reserve estimates are often different from the quantities of oil, natural gas, and NGLs that are ultimately recovered. Estimating quantities of proved oil, natural gas and NGL reserves is a complex process that involves significant interpretations and assumptions and cannot be measured in an exact manner. It requires interpretations and judgment of available technical data, including the evaluation of available geological, geophysical and engineering data. The accuracy of any reserve estimate is highly dependent on the quality of available data, the accuracy of the assumptions on which they are based upon, economic factors, such as oil, natural gas and NGL prices, production costs, severance and excise taxes, capital expenditures, workover and remedial costs, and the assumed effects of governmental regulation. In addition, due to the lack of substantial, if any, production data, there are greater uncertainties in estimating PUD reserves, proved developed non-producing reserves and proved developed reserves that are early in their production life. As a result, the Company’s reserve estimates are inherently imprecise. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based. In general, the volume of production from oil and natural gas properties the Company owns declines as reserves are depleted. Except to the extent the Company conducts successful exploration and development activities or acquires additional properties containing proved reserves, or both, the Company’s proved reserves will decline as reserves are produced. Standardized Measure of Discounted Future Net Cash Flows The following summary sets forth the Company’s standardized measure of discounted future net cash flows relating from its proved oil, natural gas and NGL reserves. December 31, 2018 2017 2016 (in thousands) Future cash inflows $ 7,325,386 $ 5,270,465 $ 271,428 Future production costs (1,773,779 ) (1,664,724 ) (102,817 ) Future development costs (1,294,565 ) (745,769 ) — Future income tax expense (1) (797,247 ) — — Future net cash flows 3,459,795 2,859,972 168,611 Discount to present value at 10% annual rate (1,760,094 ) (1,664,303 ) (50,339 ) Standardized measure of discounted future net cash flows $ 1,699,701 $ 1,195,669 $ 118,272 (1) Roan Inc. is a corporation, and as a result, is subject to U.S. federal, state and local income taxes. Our accounting predecessor, Roan LLC, passed through its taxable income to its owners for income tax purposes and thus was not subject to U.S. federal or state income taxes. Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows: Years Ended December 31, 2018 2017 2016 (in thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 1,195,669 $ 118,272 $ 18,910 Sales of oil and natural gas, net of production costs (374,588 ) (124,526 ) (42,868 ) Acquisition of reserves — 279,026 462 Extensions and discoveries, net of future development costs 1,126,713 877,846 104,581 Previously estimated development costs incurred during the period 124,822 148,505 — Net changes in prices and production costs 172,928 36,233 18,256 Changes in estimated future development costs (13,160 ) (17,970 ) — Revisions of previous quantity estimates (281,054 ) (5,676 ) 15,573 Accretion of discount 119,567 11,827 1,891 Net change in income taxes (1) (391,808 ) — — Net changes in timing of production and other 20,612 (127,868 ) 1,467 Standardized measure of discounted future net cash flows at the end of the period $ 1,699,701 $ 1,195,669 $ 118,272 (1) Roan Inc. is a corporation, and as a result, is subject to U.S. federal, state and local income taxes. Our accounting predecessor, Roan LLC, passed through its taxable income to its owners for income tax purposes and thus was not subject to U.S. federal or state income taxes.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Note 17. Quarterly Financial Data (Unaudited) The Company’s unaudited quarterly financial data for 2018 and 2017 is summarized below. 2018 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts) Total revenues $ 91,356 $ 35,965 $ 83,448 $ 307,052 Income (loss) from operations $ 36,880 $ (21,670 ) $ 514 $ 208,819 Net income (loss) $ 35,081 $ (22,757 ) $ (301,240 ) $ 148,245 Earnings (loss) per share Basic $ 0.23 $ (0.15 ) $ (1.97 ) $ 0.97 Diluted $ 0.23 $ (0.15 ) $ (1.97 ) $ 0.97 Weighted average number of shares outstanding (1) 151,294 152,540 152,540 152,540 (1) For first and second quarter of 2018, amounts reflect the weighted average number of shares of common stock outstanding based on retrospectively reflecting the impacting of the Reorganization. Total revenues for the 2018 quarters reflect the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. The Company elected the modified retrospective method of transition. Accordingly, comparative information from the year ended December 31, 2017 has not been adjusted and continues to be reported under the previous revenue standard. Net loss for the third quarter of 2018 includes the recognition of $299.7 million of income tax expense primarily representing the initial recording of the deferred tax liability recognized by the Company as a result of the Reorganization (see Note 13 – Income Taxes ). 2017 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts) Total revenues $ 30,979 $ 30,290 $ 39,751 $ 58,568 Income (loss) from operations $ 16,437 $ 1,867 $ 10,974 $ (9,373 ) Net income (loss) $ 16,310 $ 1,817 $ 10,710 $ (10,380 ) Earnings (loss) per share Basic $ 0.22 $ 0.02 $ 0.11 $ (0.07 ) Diluted $ 0.22 $ 0.02 $ 0.11 $ (0.07 ) Weighted average number of shares outstanding (1) 75,303 75,303 99,859 150,607 (1) For 2017, amounts reflect the weighted average number of shares of common stock outstanding based on retrospectively reflecting the impacting of the Reorganization. Income (loss) from operations and net income (loss) for the 2017 quarters includes bonuses paid by Citizen of approximately $9.0 million in the second quarter, impairment of unproved properties of $4.2 million in the third quarter and amortization of unproved leasehold properties of $19.6 million in the fourth quarter. Additionally, the Linn Acquisition was completed in August 2017 and the results of the properties acquired are included in the third and fourth quarters of 2017.

Basis of Presentation and Sig_2

Basis of Presentation and Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation	The accompanying consolidated financial statements were prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements of the Company include the accounts of Roan Inc. and its wholly-owned subsidiaries. All intercompany balances and transactions have been eliminated.
Reclassifications	Certain amounts in the prior period financial statements have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on net income (loss), total stockholders’ equity or total cash flows.
Use of Estimates	The preparation of financial statements and related footnotes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management’s estimates and assumptions is the estimate of proved oil, natural gas and NGL reserves which are used in the calculation of depletion of the Company’s oil and natural gas properties and impairment, if any, of proved oil and natural gas properties. Changes in estimated quantities of its reserves could impact the Company’s reported financial results as well as disclosures regarding the quantities and value of proved oil and natural gas reserves. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Revenue Recognition	Revenues from the sale of oil, natural gas and NGLs are recognized when control of the product has been transferred to the customer, all performance obligations have been satisfied and collectability is reasonably assured. We recognize revenues from the sale of oil, natural gas and NGLs based on our share of volumes sold. See Note 3 – Revenue from Contracts with Customers for additional discussion. Oil Sales Most of the Company’s oil contracts transfer physical custody and title at or near the wellhead, which is commonly when control of the oil has been transferred to the purchaser. The Company’s oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the NYMEX price. Any differentials incurred after the transfer of control of the oil are net against oil sales as they represent part of the transaction price of the contract. For its oil contracts, the Company generally records its sales based on the net amount received. Natural Gas and NGL Sales Most of the Company’s natural gas is sold at the wellhead or inlet to the processor’s facility, which is commonly when control of the natural gas has been transferred to the purchaser. The natural gas is sold under percentage of proceeds processing contracts. Under these contracts, the purchaser gathers the natural gas where it is produced and transports it via pipeline to natural gas processing plants where NGL products are extracted. The NGL products and remaining residue gas are then sold by the purchaser. Under the natural gas percentage of proceeds contracts, the Company receives a percentage of the value for the extracted NGLs and the residue gas. For its natural gas processing contracts, the Company generally records its natural gas and NGL sales net of gathering, processing and transportation expenses based on a principal versus agent assessment for individual contracts. Performance Obligations The Company satisfies the performance obligations under its oil and natural gas sales contracts through delivery of its production and transfer of control to a customer. Upon delivery of production, the Company has the right to receive consideration from its customers in amounts that correspond with the value of the production transferred. The Company typically receives payment for oil, natural gas and NGL sales within 30 days of the month of delivery for operated properties and within 90 days of the month of delivery for non-operated properties. The Company’s oil sales contracts 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, which provides an exemption 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 natural gas and NGL sales contracts that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606 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. Contract Balances The Company recognizes sales of oil, natural gas, and NGLs at a point in time when it satisfies a performance obligation and at that point the Company has an unconditional right to receive payment. Accordingly, these contracts do not give rise to contract assets or contract liabilities under ASC 606. The Company had accounts receivable related to revenue from contracts with customers of approximately $65.2 million as of December 31, 2018 , which represent this unconditional right to receive payment. Prior Period Performance Obligations To record revenues for oil, natural gas and NGLs, the Company estimates the amount of production delivered at the end of each month and the prices expected to be received for those sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer. For the year ended December 31, 2018 , revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
Fair Value Measurements	The Company follows a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: Level 1— Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2— Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date. Level 3— Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during 2018 or 2017 . Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Business Combinations	The Company accounts for all business combinations using the acquisition method, which involves the use of significant judgment. In a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill. The Company estimates the fair values of assets acquired and liabilities assumed in a business combination using various assumptions (all of which are Level 3 inputs within the fair value hierarchy). The most significant assumptions typically relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of the proved and unproved oil and natural gas properties, the Company develops estimates of oil, natural gas and NGL reserves. Estimates of reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Additionally, a risk factor is applied to reserves by reserve type based on industry standards. The Company estimates future prices to apply to the estimated net quantities of reserves based on the applicable ownership percentage acquired and estimates future operating and development costs to arrive at estimates of future net cash flows. The future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition.
Oil and Natural Gas Properties	The Company follows the successful efforts method to account for its exploration and production activities. Under this method, costs incurred to purchase, lease, or otherwise acquire a property, whether unproved or proved, are capitalized when incurred. The Company initially capitalizes exploratory well costs pending a determination whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed as incurred. Additionally, costs to operate and maintain wells and field equipment are expensed as incurred. Depletion is computed using the units-of-production method on a field level basis over the remaining estimated life of proved reserves. The Company determined its oil and natural gas properties are comprised of one single field. Capitalized drilling and development costs of producing oil and natural gas properties are amortized based on the total estimated proved developed reserves. Proved leasehold costs associated with proved reserves are depleted based on total proved reserves, which includes proved undeveloped reserves. Under the unit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. The Company recorded depletion expense on capitalized oil and natural gas properties of $122.2 million , $37.0 million , and $24.9 million for the years ended December 31, 2018 , 2017 , and 2016 , respectively. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property. The net carrying values of retired, sold or abandoned proved properties that constitute less than a complete unit of depletable property are charged, net of proceeds, to accumulate depreciation, depletion and amortization unless doing so significantly affect the unit-of-production amortization rate, in which case a gain or loss is recognized to earnings. Gains or losses from the disposal of complete units of depletable property are recognized in earnings. Proceeds from sales of all or a partial interest in individual unproved properties assessed for impairment on a group basis are accounted for as a recovery of costs. No gain or loss is recognized unless the sales proceeds exceed the original cost of the entire interest in the property, in which a gain will be recognized for the excess. The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. The Company capitalized interest of $8.3 million for the year ended December 31, 2018 . No interest was capitalized in the years ended December 31, 2017 or 2016. Impairment of Oil and Natural Gas Properties Proved oil and natural gas properties are evaluated for impairment when facts or circumstances indicate that the carrying value of those assets may not be recoverable, such as when there are declines in oil and natural gas prices or well performance. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. An impairment loss is indicated if the sum of the estimated undiscounted future cash flows related to an asset group is less than the carrying value of that asset group. If an impairment loss has been incurred, the loss recognized is the excess of the carrying amount over the estimated fair value. The Company calculates the estimated fair value using a discounted future cash flow model. Management’s assumptions associated with the calculation of future cash flows include oil and natural gas prices based on NYMEX futures price strips, as well as other assumptions, including (i) pricing adjustments for differentials, (ii) production costs, (iii) capital expenditures, (iv) production volumes, (v) timing of development, and (vi) estimated reserves. A discount rate, consistent with that used by market participants, is applied to the estimated future cash flows in order to estimate fair value. Cash flow estimates for impairment testing exclude the effects of derivative instruments. It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair carrying values. The primary factors that may affect estimates of future cash flows are (i) oil and natural gas futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, and (iv) results of future drilling activities. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2018 , 2017 , and 2016 . The Company’s unproved properties are assessed for impairment annually, or more frequently if events or changes in circumstances dictated that the carrying value of those assets may not be recoverable. For the years ended December 31, 2017 and 2016 , the Company recorded abandonment and impairment expense on its unproved oil and natural gas properties of $4.5 million and $5.3 million , respectively, for leases which have expired, or are expected to expire. Impairment expense on unproved oil and natural gas properties is included in exploration expense in the accompanying consolidated statements of operations. No impairment of unproved oil and natural gas properties was recorded for the year ended December 31, 2018 . Unproved leasehold costs are amortized on a group basis if individually insignificant, and a valuation allowance is established with a monthly amortization charge to exploration expense for the portion of the properties’ total cost that management estimates may never be transferred to proved properties during the terms of the respective leases. The impairment amortization rate considers the Company’s current drilling plans, the remaining terms of the respective leases and the results of exploratory drilling activity, and can be affected by economic factors including oil and natural gas price outlooks, projected capital costs, and available liquidity. For the years ended December 31, 2018 and 2017 , the Company recorded amortization expense on its unproved oil and natural gas properties of $36.0 million and $19.6 million , respectively, which is reflected in exploration expense on the accompanying consolidated statements of operations. There was no such expense recorded for the year ended December 31, 2016 . Costs of expired or relinquished leases are charged against the valuation allowance.
Derivative Instruments	The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value and are included in the balance sheet as derivative assets and derivative liabilities, on a net basis by counterparty. The Company adjusts the valuations from the valuation model for nonperformance risk and for counterparty risk. The fair values of the Company’s commodity derivative instruments are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The Company has not designated any of the derivative contracts as fair value or cash flow hedges for accounting purposes for any of the periods presented. Accordingly, net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments and are included in gain (loss) on derivative contracts in the consolidated statements of operations. The Company’s cash flow is impacted when the settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty and are reflected as operating activities in the Company’s consolidated statements of cash flows. The Company’s firm sales contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment.
Drilling Advances	The Company’s drilling advances consist of cash provided to the Company from its joint interest partners for planned drilling activities. Advances are applied against the joint interest partner’s share of expenses incurred
Asset Retirement Obligation	The Company is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company’s asset retirement obligations (“ARO”) relate to the plugging of wells and the related abandonment of oil and natural gas properties. AROs are recognized as liabilities with an increase to the carrying amounts of the related assets when the obligation is incurred. The cost of the asset, including ARO, is depreciated over the useful life of the asset. Fair value of ARO is measured using the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value and the liability is settled or the well is sold, at which time the liability is removed. Accretion expense is included in accretion expense in the consolidated statements of operations.
Cash and Cash Equivalents	The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains its cash balances at credit-worthy financial institutions that are insured by the Federal Deposit Insurance Corporation (“FDIC”). At times, cash balances may be in excess of FDIC limits. The Company has not incurred any losses related to the amounts in excess of FDIC limits.
Accounts Receivable	Accounts receivable consists mainly of receivables from oil, natural gas and NGL purchasers and joint interest owners on properties the Company operates. Accounts receivable from the sale of oil, natural gas and NGLs are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. The Company routinely reviews outstanding balances, assesses the financial strength of its purchasers and joint interest owners and records a reserve for amounts not expected to be fully recovered. The need for an allowance is determined based upon reviews of individual accounts, existing economic conditions and other pertinent factors. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts.
Deferred Financing Costs	Costs incurred in connection with the Company’s debt are capitalized and amortized as interest expense over the scheduled maturity period. Unamortized costs are associated with the Company’s revolving credit facility and are reflected as a component of long-term assets in the consolidated balance sheets.
Equity-Based Compensation	Equity-based compensation is measured based on the grant date fair value of the award and recognized over the requisite service period. For employees directly involved in exploration and development activities, equity compensation is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses or production expense in the consolidated statements of operations. The Company accounts for forfeitures of stock compensation as they occur.
Earnings (Loss) per Share	The Company uses the treasury stock method to determine the potential dilutive effect of outstanding performance share units and restricted stock units.
Income Taxes	The Company is a corporation and therefore a taxable entity. Our predecessor, Roan LLC, was treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of Roan LLC and any related tax credits, for income tax purposes, flowed through to its members. Accordingly, no tax provision was made in the historical financial statements of Roan LLC since the income tax was an obligation of its members. As a result of the Reorganization, the Company recorded a deferred tax liability based on the change in its tax status. The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. See Note 13 – Income Taxes for further information on the Company’s taxes. The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not, based on technical merits, that the tax position will be sustained upon examination. Any interest or penalties would be recognized as a component of income tax expense.
Defined Contribution Plan	In 2018, the Company adopted a 401(k) retirement plan and health and welfare benefit plans in which our employees are eligible to participate. Under the 401(k) retirement plan, the Company provides for an employer match of employee contributions of up to 6% of eligible compensation and a profit-sharing contribution of up to 8% of eligible compensation.
Concentrations of Credit Risk	The Company sells oil, natural gas and NGLs to various types of customers. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. Additionally, limitations on capacity at processing plants could also impact the Company’s ability to sell its oil, natural gas and NGLs. The Company is subject to credit risk resulting from the concentration of its oil, natural gas and NGL receivables with its significant purchasers. The Company does not believe the loss of any single purchaser would materially impact its results of operations because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers. For the years ended December 31, 2018 , 2017 , and 2016 , the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues: Years Ended December 31, 2018 2017 2016 Coffeyville Resources Refining & Marketing LLC 31 % * * Sunoco Inc. 18 % 40 % 55 % Blue Mountain Midstream LLC 15 % * * EnLink Oklahoma Gas Processing, LP 13 % 39 % 31 % * Revenue from customer was less than 10% in this period. Blue Mountain Midstream LLC (“Blue Mountain”) is deemed a related party as it is a wholly-owned subsidiary of Riviera Resources, Inc. (“Riviera”). See Note 12 –Transactions with Affiliates . The Company’s derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties, which are financial institutions, may be unable to meet the financial terms of the transactions. The Company monitors on an ongoing basis the credit ratings of its derivative counterparties and considers its counterparties’ credit default risk ratings in determining the fair value of its derivative contracts. The Company’s derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. The counterparties to the Company’s derivative contracts at December 31, 2018 are also lenders under its revolving credit facility. As a result, the Company does not require collateral or other security from counterparties nor is the Company required to post collateral to support derivative instruments. The Company has master netting agreements with all of its derivative counterparties, which allow the Company to net its derivative assets and liabilities with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts.
Commitments and Contingencies	The Company is subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. An accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. The amount of ultimate loss may differ from these estimates. Except for environmental contingencies acquired in a business combination, which are recorded at fair value, the Company accrues losses associated with environmental obligations when such losses are probable and can be reasonably estimated.
Recently Issued Accounting Standards	In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”). This guidance supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) (“ASU 2016-08”), pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity records revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Applying the guidance in ASU 2016-08 requires significant judgment in determining the point in time when control of products transfers to customers. Effective January 1, 2018, the Company adopted ASC 606 using the modified retrospective method of transition under which the standard is applied only to the most current period presented. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard. See Note 3 – Revenue from Contracts with Customers for discussion of the impact upon adoption and the additional disclosures. Recently Issued Accounting Standards Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”). This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for fiscal years beginning after December 15, 2018, including interim reporting periods within those fiscal years, with early application permitted. The Company enters into lease agreements to support its operations, such as office space, drilling rigs and field equipment. ASU 2016-02 will not impact the accounting or financial presentation of the Company’s mineral leases. The Company plans to adopt the new standard using the simplified transition method described in ASU 2018-11 Leases (Topic 842): Targeted Improvements , and therefore will apply the new standard as of January 1, 2019. Accordingly, comparative information will not be adjusted and will continue to be reported under the previous lease standard. The Company plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases, but does not plan to elect the practical expedient of hindsight when determining the lease term of existing contracts at the effective date. The Company also plans to elect the practical expedient under ASU 2018-01 Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 that allows it to not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The Company is working to complete its evaluation of the impact of ASU 2016-02 on its financial statements, accounting policies, and internal controls, including implementation of systems and processes to capture, classify and account for leases within the scope of the new guidance and to provide the related disclosures. At this time, the impact upon adoption of ASU 2016-02 and other related ASUs is expected to result in recognition of additional operating liabilities ranging from $7 million to $12 million , with corresponding right-of-use assets of the same amount based on the present value of the remaining minimum rental payments under current leasing standards for existing operating leases. The new standard also provides practical expedients for an entity’s ongoing accounting. The Company currently plans to elect the short-term lease recognition exemption for all leases that qualify and the practical expedient to not separate lease and non-lease components for the majority of classes of underlying assets.

Basis of Presentation and Sig_3

Basis of Presentation and Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Schedule of Accrued Liabilities	The components of accrued liabilities are presented below: December 31, 2018 2017 (in thousands) Accrued capital expenditures $ 151,965 $ 7,252 Accrued production expenses 10,879 — Accrued general and administrative expenses 7,450 2,696 Other 6,200 297 Total accrued liabilities $ 176,494 $ 10,245
Schedules of Major Customers	For the years ended December 31, 2018 , 2017 , and 2016 , the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues: Years Ended December 31, 2018 2017 2016 Coffeyville Resources Refining & Marketing LLC 31 % * * Sunoco Inc. 18 % 40 % 55 % Blue Mountain Midstream LLC 15 % * * EnLink Oklahoma Gas Processing, LP 13 % 39 % 31 % * Revenue from customer was less than 10% in this period.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	The following table shows the impact of the adoption of ASC 606 on the Company’s current period results as compared to the previous revenue recognition standard, ASC Topic 605, Revenue Recognition (“ASC 605”): Year Ended December 31, 2018 Under ASC 606 Under ASC 605 Increase/ (decrease) (in thousands) Revenues Oil sales $ 275,239 $ 275,399 $ (160 ) Natural gas sales $ 76,056 $ 96,086 $ (20,030 ) Natural gas liquid sales $ 88,472 $ 114,021 $ (25,549 ) Operating expenses Gathering, transportation and processing $ — $ 45,739 $ (45,739 ) Net loss $ (140,671 ) $ (140,671 ) $ —

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
Schedule of Assumptions to Determine Fair value of the Oil and Natural Gas	The following assumptions were used to determine the fair value of the oil and natural gas properties: Discount rate 9.50 % Reserve risk factor (1) 35%-100% Oil price three years NYMEX WTI forward curve Natural gas price three years NYMEX Henry Hub forward curve NGL price 39% of oil price Price escalation (2) 2.00 % (1) Possible reserves had a reserve risk factor of 35%, probable reserves had a reserve risk factor of 75%, and proved undeveloped reserves had a reserve risk factor of 90%. (2) Prices were escalated at the end of the forward curve
Summary of Purchase Price and Allocation of Fair value of Assets Acquired And Liabilities Assumed	The following table summarizes the purchase price and allocation of the fair values of assets acquired and liabilities assumed (in thousands): Consideration given Equity units $ 1,281,743 Allocation of purchase price Inventory $ 205 Proved oil and natural gas properties 214,647 Unproved oil and natural gas properties 1,086,600 Total assets acquired 1,301,452 Asset retirement obligations (7,547 ) Revenue suspense (12,162 ) Total fair value of net assets acquired $ 1,281,743
Schedule of Supplemental Pro Forma Results of Operations	The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Linn Acquisition or any estimated costs incurred to integrate the Linn Acquisition. (Unaudited) Years Ended December 31, 2017 2016 (in thousands) Revenue $ 215,161 $ 90,238 Net income $ 44,873 $ 26,378

Oil and Natural Gas Properties

Oil and Natural Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities	The oil and natural gas properties include the following: December 31, 2018 2017 (in thousands) Oil and natural gas properties Proved $ 1,538,379 $ 750,492 Unproved 1,089,954 1,126,459 Less: accumulated depreciation, depletion, amortization and impairment (230,836 ) (78,307 ) Oil and natural gas properties, net $ 2,397,497 $ 1,798,644 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: December 31, 2018 2017 (in thousands) Oil and natural gas properties Proved properties $ 1,538,379 $ 750,492 Unproved properties 1,089,954 1,126,459 Total oil and natural gas properties 2,628,333 1,876,951 Accumulated depreciation, depletion, amortization and impairment (230,836 ) (78,307 ) Oil and natural gas properties, net $ 2,397,497 $ 1,798,644

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Reconciliation of Asset Retirement Obligations	The following is a reconciliation of the changes in the Company’s ARO for the years ended December 31, 2018 and 2017 : Years Ended December 31, 2018 2017 (in thousands) Asset retirement obligation, beginning balance $ 10,769 $ 2,245 Liabilities incurred or acquired (1) 3,347 8,118 Revisions in estimated cash flows (2) 2,018 42 Liabilities settled (139 ) — Accretion expense 853 364 Asset retirement obligation, ending balance 16,848 10,769 Less: current portion of obligations 790 — Asset retirement obligation - long term $ 16,058 $ 10,769 (1) For the year ended December 31, 2017, liabilities incurred or acquired included $7.5 million assumed as part of the Linn Acquisition. (2) For the year ended December 31, 2018 , revisions primarily represent changes in the economic lives of producing properties and the Company’s share of estimated costs.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule of Principal Maturities of Borrowings	Principal maturities of the Company’s borrowings at December 31, 2018 , consisting of amounts outstanding under the 2017 Credit Facility, are as follows (in thousands): 2019 $ — 2020 — 2021 — 2022 514,639 $ 514,639
Schedule of Applicable Margin for LIBOR Rate Loans Depending on the Utilization Level	The pricing grid below shows the applicable margin for LIBOR rate or ABR loans as well as the commitment fee depending on the Utilization Level (as defined in the credit agreement): Utilization Level Utilization LIBOR Margin ABR Margin Commitment Fee Level I <25% 2.00% 1.00% 0.375% Level II >25% but <50% 2.25% 1.25% 0.375% Level III >50% but <75% 2.50% 1.50% 0.500% Level IV >75% but <90% 2.75% 1.75% 0.500% Level V >90% 3.00% 2.00% 0.500%

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Company's Open Commodity Contracts	The following table reflects the Company’s open commodity contracts at December 31, 2018 : 2019 2020 Total Oil fixed price swaps Volume (Bbl) 5,405,670 1,599,500 7,005,170 Weighted-average price $ 60.05 $ 63.14 $ 60.76 Natural gas fixed price swaps Volume (MMBtu) 43,800,000 12,325,000 56,125,000 Weighted-average price $ 2.90 $ 2.63 $ 2.84 Natural gas basis swaps Volume (MMBtu) 29,200,000 3,640,000 32,840,000 Weighted-average price $ 0.60 $ 0.62 $ 0.60 Natural gas liquids fixed price swaps Volume (Bbl) 1,095,000 — 1,095,000 Weighted-average price $ 32.25 $ — $ 32.25
Schedule of Net Gains and Loss on Derivative Contracts	The following table presents the Company’s gain (loss) on derivative contracts and net cash (paid) received upon settlement of its derivative contracts for the years ended December 31, 2018 and 2017 : Years Ended December 31, 2018 2017 (in thousands) Gain (loss) on derivative contracts $ 78,054 $ (6,797 ) Net cash (paid) received upon settlement of derivative contracts (1) $ (33,279 ) $ 2,705 (1) Includes $1.3 million of cash received upon settlement of derivative contracts prior to their contractual maturity for the year ended December 31, 2017 .

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Summary of Classifications of the Company's Derivative Assets and Liabilities	The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of December 31, 2018 and 2017 , as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands): December 31, 2018 Level 1 Level 2 Level 3 Gross Fair Value Netting Carrying Value Assets Current commodity derivatives $ — $ 85,728 $ — $ 85,728 $ (3,548 ) $ 82,180 Noncurrent commodity derivatives — 21,565 — 21,565 (927 ) 20,638 Total assets $ — $ 107,293 $ — $ 107,293 $ (4,475 ) $ 102,818 Liabilities Current commodity derivatives $ — $ (4,393 ) $ — $ (4,393 ) $ 3,548 $ (845 ) Noncurrent commodity derivatives — (1,068 ) — (1,068 ) 927 (141 ) Total liabilities $ — $ (5,461 ) $ — $ (5,461 ) $ 4,475 $ (986 ) December 31, 2017 Level 1 Level 2 Level 3 Gross Fair Value Netting Carrying Value Assets Current commodity derivatives $ — $ 2,856 $ — $ 2,856 $ (2,704 ) $ 152 Noncurrent commodity derivatives — 2,182 — 2,182 (1,186 ) 996 Total assets $ — $ 5,038 $ — $ 5,038 $ (3,890 ) $ 1,148 Liabilities Current commodity derivatives $ — $ (11,983 ) $ — $ (11,983 ) $ 2,704 $ (9,279 ) Noncurrent commodity derivatives — (2,557 ) — (2,557 ) 1,186 (1,371 ) Total liabilities $ — $ (14,540 ) $ — $ (14,540 ) $ 3,890 $ (10,650 )

Equity Compensation (Tables)

Equity Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Activity	The following table presents activity for the Company’s restricted stock units during the year ended December 31, 2018 : Number of Weighted Total Fair Value ($ in thousands) Outstanding at December 31, 2017 — $ — $ — Granted 11,800 16.95 200 Vested — — — Forfeited — — — Outstanding at December 31, 2018 11,800 $ 16.95 $ 200 The following table presents activity for the Company’s PSUs during the years ended December 31, 2018 and 2017. Number of Weighted Total Fair Outstanding at December 31, 2016 — $ — $ — Granted 16,350,000 1.41 23,054 Vested — — — Outstanding at December 31, 2017 16,350,000 $ 1.41 $ 23,054 Granted 6,825,000 1.88 12,810 Vested — — — Conversion (1) (22,016,250 ) — — Outstanding at December 31, 2018 1,158,750 $ 30.95 $ 35,864 (1) PSUs were converted on a basis of 0.05 to 1.0. There was no change to the deemed fair value of the awards based on assessment of modification.
Schedule of Fair Value Assumptions Used	The following table shows the range of assumptions that were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSUs granted during the year ended December 31, 2018 : Company enterprise value (in billions) $4.19 - $4.56 Equity volatility 34.0% - 36.0% Weighted average risk-free interest rate 1.96% - 2.54%

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	The components of the Company’s provision for income taxes for the year ended December 31, 2018 are as follows (in thousands): Current income tax expense Federal $ — State — — Deferred income tax expense Federal 277,794 State 79,068 356,862 Provision for income taxes $ 356,862
Schedule of Deferred Tax Liabilities	The Company’s deferred tax assets and liabilities as of December 31, 2018 include the following (in thousands): Deferred income tax assets Net operating losses $ 42,013 Other 4,409 46,422 Deferred income tax liabilities Oil and natural gas properties (377,362 ) Derivative contracts (25,922 ) (403,284 ) Deferred tax liabilities, net $ (356,862 )
Schedule of Effective Income Tax Rate Reconciliation	The following is a reconciliation, stated as a percentage of pretax income, of the United States statutory federal income tax rate to the Company’s effective tax rate for the year ended December 31, 2018: Amount Percent (in thousands) Income (loss) at U.S. federal statutory rate $ 45,400 21.0 % Net effect of state income taxes 9,173 4.2 % Change in tax status 304,455 140.8 % Other (2,166 ) (1.0 )% Income tax provision / Effective rate $ 356,862 165.0 %

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Payments	The following table presents the future minimum payments under noncancelable operating leases and other commitments as of December 31, 2018 (in thousands): 2019 2020 2021 2022 2023 Thereafter Total Office building leases $ 1,692 $ 2,047 $ 2,136 $ 2,229 $ 456 $ 171 $ 8,731 Pipe and equipment purchase commitments (1) 1,455 — — — — — 1,455 Drilling rig commitments (2) 15,352 — — — — — 15,352 Total $ 18,499 $ 2,047 $ 2,136 $ 2,229 $ 456 $ 171 $ 25,538 (1) Reflects commitments to purchase specified amounts of pipe and equipment. (2) Reflects future minimum drilling fees including early termination fees as specified by the contract.

Supplemental Information on O_2

Supplemental Information on Oil and Natural Gas Operations (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Extractive Industries [Abstract]
Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities	The oil and natural gas properties include the following: December 31, 2018 2017 (in thousands) Oil and natural gas properties Proved $ 1,538,379 $ 750,492 Unproved 1,089,954 1,126,459 Less: accumulated depreciation, depletion, amortization and impairment (230,836 ) (78,307 ) Oil and natural gas properties, net $ 2,397,497 $ 1,798,644 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: December 31, 2018 2017 (in thousands) Oil and natural gas properties Proved properties $ 1,538,379 $ 750,492 Unproved properties 1,089,954 1,126,459 Total oil and natural gas properties 2,628,333 1,876,951 Accumulated depreciation, depletion, amortization and impairment (230,836 ) (78,307 ) Oil and natural gas properties, net $ 2,397,497 $ 1,798,644
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities	Costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities are summarized as follows: December 31, 2018 2017 2016 (in thousands) Acquisition costs of properties Proved properties $ 5,655 $ 214,647 $ 1,079 Unproved properties 42,738 1,018,978 93,705 Development costs 719,198 390,991 152,284 Exploratory (1) 7,257 8,538 — Total costs incurred $ 774,848 $ 1,633,154 $ 247,068
Results of Operations for Oil and Gas Producing Activities	The following table sets forth the Company’s results of operations for oil, natural gas and NGL producing activities for the years ended December 31, 2018 , 2017 and 2016: Years Ended December 31, 2018 2017 2016 (in thousands) Oil, natural gas and NGL sales $ 439,767 $ 166,385 $ 54,965 Production expenses 47,600 16,872 5,090 Production taxes 17,579 3,685 1,087 Exploration expenses 43,303 28,154 — Gathering, transportation and processing (1) — 18,602 5,920 Depreciation, depletion, amortization, and accretion 123,062 37,376 24,996 Impairment — 4,475 5,258 Income tax expense (2) 13,103 — — Results of operations $ 195,120 $ 57,221 $ 12,614 (1) Gathering, transportation and processing for the year ended December 31, 2018 reflects the adoption of ASC 606 on January 1, 2018. The adoption of ASC 606 requires certain costs that were previously recorded as gathering, processing and transportation expenses to be accounted for as a deduction from revenue. We elected the modified retrospective method of transition. Accordingly, comparative information has not been adjusted and continues to be reported under the previous revenue standard. (2) Income tax expense is calculated using results from the period after the Reorganization when the Company became a taxable entity and the Company’s effective tax rate of 24.3% .
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	The following table sets forth proved reserves during the periods indicated: Oil (MBbls) Natural Gas (MMcf) NGLs (MBbls) Total (MBoe) Proved reserves at December 31, 2015 387 8,517 678 2,484 Purchases of reserves 22 333 33 111 Extensions and discoveries 2,632 33,218 2,956 11,124 Revisions of previous estimates 598 4,145 398 1,687 Production (740 ) (6,382 ) (546 ) (2,350 ) Proved reserves at December 31, 2016 2,900 39,831 3,519 13,057 Purchases of reserves 9,843 163,638 16,870 53,986 Extensions and discoveries 30,554 486,510 61,599 173,238 Revisions of previous estimates (3,583 ) 20,844 (260 ) (369 ) Production (2,294 ) (24,953 ) (2,150 ) (8,603 ) Proved reserves at December 31, 2017 37,420 685,869 79,578 231,309 Purchases of reserves — — — — Extensions and discoveries 34,714 451,750 48,791 158,797 Revisions of previous estimates (12,087 ) (184,547 ) (25,365 ) (68,209 ) Production (4,364 ) (41,890 ) (4,592 ) (15,938 ) Proved reserves at December 31, 2018 55,683 911,182 98,412 305,959 The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped (“PUD”) oil, natural gas and NGL reserves of the Company as of December 31, 2018 , 2017, and 2016: December 31, 2018 2017 2016 Proved Developed Reserves Oil (MBbls) 18,652 12,352 2,900 Natural gas (MMcf) 369,677 259,193 39,831 NGL (MBbls) 39,927 24,034 3,519 Total (MBoe) 120,192 79,585 13,057 Proved Undeveloped Reserves Oil (MBbls) 37,031 25,068 — Natural gas (MMcf) 541,505 426,676 — NGL (MBbls) 58,485 55,544 — Total (MBoe) 185,767 151,724 — Total Proved Reserves Oil (MBbls) 55,683 37,420 2,900 Natural gas (MMcf) 911,182 685,869 39,831 NGL (MBbls) 98,412 79,578 3,519 Total (MBoe) 305,959 231,309 13,057
Summary of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves	The following summary sets forth the Company’s standardized measure of discounted future net cash flows relating from its proved oil, natural gas and NGL reserves. December 31, 2018 2017 2016 (in thousands) Future cash inflows $ 7,325,386 $ 5,270,465 $ 271,428 Future production costs (1,773,779 ) (1,664,724 ) (102,817 ) Future development costs (1,294,565 ) (745,769 ) — Future income tax expense (1) (797,247 ) — — Future net cash flows 3,459,795 2,859,972 168,611 Discount to present value at 10% annual rate (1,760,094 ) (1,664,303 ) (50,339 ) Standardized measure of discounted future net cash flows $ 1,699,701 $ 1,195,669 $ 118,272 (1) Roan Inc. is a corporation, and as a result, is subject to U.S. federal, state and local income taxes. Our accounting predecessor, Roan LLC, passed through its taxable income to its owners for income tax purposes and thus was not subject to U.S. federal or state income taxes.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows	Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows: Years Ended December 31, 2018 2017 2016 (in thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 1,195,669 $ 118,272 $ 18,910 Sales of oil and natural gas, net of production costs (374,588 ) (124,526 ) (42,868 ) Acquisition of reserves — 279,026 462 Extensions and discoveries, net of future development costs 1,126,713 877,846 104,581 Previously estimated development costs incurred during the period 124,822 148,505 — Net changes in prices and production costs 172,928 36,233 18,256 Changes in estimated future development costs (13,160 ) (17,970 ) — Revisions of previous quantity estimates (281,054 ) (5,676 ) 15,573 Accretion of discount 119,567 11,827 1,891 Net change in income taxes (1) (391,808 ) — — Net changes in timing of production and other 20,612 (127,868 ) 1,467 Standardized measure of discounted future net cash flows at the end of the period $ 1,699,701 $ 1,195,669 $ 118,272 (1) Roan Inc. is a corporation, and as a result, is subject to U.S. federal, state and local income taxes. Our accounting predecessor, Roan LLC, passed through its taxable income to its owners for income tax purposes and thus was not subject to U.S. federal or state income taxes.

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data	The Company’s unaudited quarterly financial data for 2018 and 2017 is summarized below. 2018 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts) Total revenues $ 91,356 $ 35,965 $ 83,448 $ 307,052 Income (loss) from operations $ 36,880 $ (21,670 ) $ 514 $ 208,819 Net income (loss) $ 35,081 $ (22,757 ) $ (301,240 ) $ 148,245 Earnings (loss) per share Basic $ 0.23 $ (0.15 ) $ (1.97 ) $ 0.97 Diluted $ 0.23 $ (0.15 ) $ (1.97 ) $ 0.97 Weighted average number of shares outstanding (1) 151,294 152,540 152,540 152,540 (1) For first and second quarter of 2018, amounts reflect the weighted average number of shares of common stock outstanding based on retrospectively reflecting the impacting of the Reorganization. 2017 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts) Total revenues $ 30,979 $ 30,290 $ 39,751 $ 58,568 Income (loss) from operations $ 16,437 $ 1,867 $ 10,974 $ (9,373 ) Net income (loss) $ 16,310 $ 1,817 $ 10,710 $ (10,380 ) Earnings (loss) per share Basic $ 0.22 $ 0.02 $ 0.11 $ (0.07 ) Diluted $ 0.22 $ 0.02 $ 0.11 $ (0.07 ) Weighted average number of shares outstanding (1) 75,303 75,303 99,859 150,607 (1) For 2017, amounts reflect the weighted average number of shares of common stock outstanding based on retrospectively reflecting the impacting of the Reorganization.

Business and Organization - Add

Business and Organization - Additional information (Details)	Aug. 31, 2017
Citizen
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%
Linn
Schedule of Equity Method Investments [Line Items]
Ownership percentage	50.00%

Basis of Presentation and Sig_4

Basis of Presentation and Significant Accounting Policies - Additional Information (Details) - USD ($)	3 Months Ended		12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2019
Accounting Policies [Abstract]
Depletion expense on capitalized oil and natural gas properties			$ 122,200,000	$ 37,000,000	$ 24,900,000
Capitalized interest			8,300,000	0	0
Property, Plant and Equipment [Line Items]
Abandonment and impairment expense		$ 4,200,000	0	4,500,000	5,300,000
Amortization expense on oil and gas properties	$ 19,600,000		36,000,000	19,600,000	0
Bad debts expense				0	0
Reserve for bad debts	$ 0		3,300,000	0
Contribution to the plan			$ 1,200,000
401(k)
Property, Plant and Equipment [Line Items]
Employer match contribution percent			6.00%
Profit-sharing
Property, Plant and Equipment [Line Items]
Employer match contribution percent			8.00%
Proved oil and natural gas properties
Property, Plant and Equipment [Line Items]
Impaired expense			$ 0	$ 0	$ 0
Subsequent event | ASU 2016-02 | Forecast | Minimum
Property, Plant and Equipment [Line Items]
Operating liabilities						$ 7,000,000
Right-of-use asset						7,000,000
Subsequent event | ASU 2016-02 | Forecast | Maximum
Property, Plant and Equipment [Line Items]
Operating liabilities						12,000,000
Right-of-use asset						$ 12,000,000

Basis of Presentation and Sig_5

Basis of Presentation and Significant Accounting Policies - Schedule of Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Accrued capital expenditures	$ 151,965	$ 7,252
Accrued production expenses	10,879	0
Accrued general and administrative expenses	7,450	2,696
Other	6,200	297
Total accrued liabilities	$ 176,494	$ 10,245

Basis of Presentation and Sig_6

Basis of Presentation and Significant Accounting Policies - Schedules of Major Customers (Details) - Total oil, natural gas and NGL revenues - Customer	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Coffeyville Resources Refining & Marketing LLC
Concentration Risk [Line Items]
Concentration percentage	31.00%
Sunoco Inc.
Concentration Risk [Line Items]
Concentration percentage	18.00%	40.00%	55.00%
Blue Mountain Midstream LLC
Concentration Risk [Line Items]
Concentration percentage	15.00%
EnLink Oklahoma Gas Processing, LP
Concentration Risk [Line Items]
Concentration percentage	13.00%	39.00%	31.00%

Revenue from Contracts with C_3

Revenue from Contracts with Customers - Summary of New Accounting Pronouncements and Changes in Accounting Principles (Details) - USD ($) $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Operating expenses

Gathering, transportation and processing

$ 0

$ 18,602

$ 5,920

Net loss

$ 148,245

$ (301,240)

$ (22,757)

$ 35,081

$ (10,380)

$ 10,710

$ 1,817

$ 16,310

(140,671)

[1]

18,457

6,947

Under ASC 605

Operating expenses

Gathering, transportation and processing

45,739

Net loss

(140,671)

Oil sales

Revenues

Revenues

275,239

$ 76,876

$ 30,565

Oil sales | Under ASC 605

Revenues

Revenues

275,399

Natural gas sales

Revenues

Revenues

76,056

Natural gas sales | Under ASC 605

Revenues

Revenues

96,086

Natural gas liquid sales

Revenues

Revenues

88,472

Natural gas liquid sales | Under ASC 605

Revenues

Revenues

114,021

Accounting Standards Update 2014-09 | Increase/ (decrease)

Operating expenses

Gathering, transportation and processing

(45,739)

Net loss

0

Accounting Standards Update 2014-09 | Oil sales | Increase/ (decrease)

Revenues

Revenues

(160)

Accounting Standards Update 2014-09 | Natural gas sales | Increase/ (decrease)

Revenues

Revenues

(20,030)

Accounting Standards Update 2014-09 | Natural gas liquid sales | Increase/ (decrease)

Revenues

Revenues

$ (25,549)

[1]

Amounts are allocated to stockholders’ equity and members’ equity to reflect the Reorganization. See Note 10 – Equity for discussion of the Reorganization.

Revenue from Contracts with C_4

Revenue from Contracts with Customers - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Revenue from Contract with Customer [Abstract]
Timing of performance obligation	The Company typically receives payment for oil, natural gas and NGL sales within 30 days of the month of delivery for operated properties and within 90 days of the month of delivery for non-operated properties.
Contract with customer accounts receivable	$ 65.2

Acquisitions - Additional Infor

Acquisitions - Additional Information (Details) $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)a	Aug. 31, 2017
Business Acquisition [Line Items]
Area acquired in leasehold property | a			23,400
Cash consideration for interest acquired in leasehold property			$ 49.7
Accounts payable and accrued liabilities
Business Acquisition [Line Items]
Costs incurred for acquisition of acreage			$ 63
Linn
Business Acquisition [Line Items]
Ownership percentage		50.00%
Equity units issued in acquisition		$ 1,300
Roan LLC | Linn
Business Acquisition [Line Items]
Ownership percentage				50.00%
Cash consideration for interest acquired in leasehold property	$ 22.9

Acquisitions - Schedule of Assu

Acquisitions - Schedule of Assumptions to Determine Fair value of the Oil and Natural Gas (Details)	Aug. 31, 2017
Reserve risk factor | Minimum
Business Acquisition [Line Items]
Acquisition, measurement input	0.35
Reserve risk factor | Maximum
Business Acquisition [Line Items]
Acquisition, measurement input	1
Possible reserves | Reserve risk factor
Business Acquisition [Line Items]
Acquisition, measurement input	0.35
Probable reserve | Reserve risk factor
Business Acquisition [Line Items]
Acquisition, measurement input	0.75
Proved undeveloped reserves | Reserve risk factor
Business Acquisition [Line Items]
Acquisition, measurement input	0.90
Linn Acquisition | Discount rate
Business Acquisition [Line Items]
Acquisition, measurement input	0.0950
Linn Acquisition | Price escalation
Business Acquisition [Line Items]
Acquisition, measurement input	0.0200
Linn Acquisition | Oil price | Oil price
Business Acquisition [Line Items]
Acquisition, measurement input description	three years NYMEX WTI forward curve
Linn Acquisition | Natural gas price
Business Acquisition [Line Items]
Acquisition, measurement input description	three years NYMEX Henry Hub forward curve
Linn Acquisition | NGL price
Business Acquisition [Line Items]
Acquisition, measurement input description	39% of oil price
Linn Acquisition | NGL price | Oil price
Business Acquisition [Line Items]
Acquisition, measurement input	0.39

Acquisitions - Summary of Purch

Acquisitions - Summary of Purchase Price and Allocation of Fair value of Assets Acquired And Liabilities Assumed (Details) - Linn Acquisition $ in Thousands	1 Months Ended
	Aug. 31, 2017USD ($)
Consideration given
Equity units	$ 1,281,743
Allocation of purchase price
Inventory	205
Total assets acquired	1,301,452
Asset retirement obligations	(7,547)
Revenue suspense	(12,162)
Total fair value of net assets acquired	1,281,743
Proved oil and natural gas properties
Allocation of purchase price
Properties	214,647
Unproved oil and natural gas properties
Allocation of purchase price
Properties	$ 1,086,600

Acquisitions - Schedule of Supp

Acquisitions - Schedule of Supplemental Proforma Results of Operations (Details) - Linn Acquisition - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition, Pro Forma Information [Line Items]
Revenue	$ 215,161	$ 90,238
Net income	$ 44,873	$ 26,378

Oil and Natural Gas Propertie_2

Oil and Natural Gas Properties - Schedule of Oil and Natural Gas Properties (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Property [Abstract]
Proved	$ 1,538,379	$ 750,492
Unproved	1,089,954	1,126,459
Less: accumulated depreciation, depletion, amortization and impairment	(230,836)	(78,307)
Oil and natural gas properties, net	$ 2,397,497	$ 1,798,644

Oil and Natural Gas Propertie_3

Oil and Natural Gas Properties - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Exploratory well costs	$ 0	$ 0
Pre-drilling costs from exploratory dry hole	$ 0	$ 1,300,000	$ 0

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Reconciliation of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation, beginning balance	$ 10,769	$ 2,245
Liabilities incurred or acquired	3,347	8,118
Revisions in estimated cash flows	2,018	42
Liabilities settled	(139)	0
Accretion expense	853	364
Asset retirement obligation, ending balance	16,848	10,769
Less: current portion of obligations	790	0
Asset retirement obligation – long term	$ 16,058	10,769
Linn Acquisition
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities incurred or acquired		$ 7,500

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail)	Jul. 31, 2017USD ($)	Sep. 30, 2018USD ($)	Aug. 31, 2017USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2017USD ($)
2017 Credit Facility
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity					$ 750,000,000
Line of credit facility, current borrowing capacity		$ 675,000,000			$ 200,000,000
Line of credit facility, outstanding borrowings				$ 514,600,000
Weighted average interest rate on borrowings				5.21%
Percentage of projected production hedged, first rolling 30 months				80.00%
Percentage of projected production hedged, second rolling 30 months				80.00%
Borrowings outstanding threshold percentage				50.00%
Minimum future production hedge percentage				50.00%
Debt to EBITDAX Ratio				4
Current assets to current liabilities				1
2017 Credit Facility | Level I
Line of Credit Facility [Line Items]
Commitment Fee				0.375%
2017 Credit Facility | Level II
Line of Credit Facility [Line Items]
Commitment Fee				0.375%
2017 Credit Facility | LIBOR Margin | Level I
Line of Credit Facility [Line Items]
Variable rate				2.00%
2017 Credit Facility | LIBOR Margin | Level II
Line of Credit Facility [Line Items]
Variable rate				2.25%
2017 Credit Facility | ABR
Line of Credit Facility [Line Items]
Reduction of applicable margin rate				0.25%
2017 Credit Facility | ABR | Level I
Line of Credit Facility [Line Items]
Variable rate				1.00%
2017 Credit Facility | ABR | Level II
Line of Credit Facility [Line Items]
Variable rate				1.25%
2017 Credit Facility | Letter of credit
Line of Credit Facility [Line Items]
Line of credit facility, outstanding borrowings				$ 0
Amended 2017 Credit Facility
Line of Credit Facility [Line Items]
Increase in borrowing base		$ 500,000,000
Amended 2017 Credit Facility | Level I
Line of Credit Facility [Line Items]
Commitment Fee		0.375%
Amended 2017 Credit Facility | LIBOR Margin
Line of Credit Facility [Line Items]
Reduction of applicable margin rate		0.25%
Variable rate		1.00%
Amended 2017 Credit Facility | Federal funds effective rate
Line of Credit Facility [Line Items]
Variable rate		0.50%
Citizen 2017 Credit Facility
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000
Line of credit facility, current borrowing capacity	$ 82,500,000
Line of credit facility, expiration period	2 years
Outstanding borrowing, amount repaid			$ 20,300,000

Long-Term Debt - Schedule of Pr

Long-Term Debt - Schedule of Principal Maturities of Borrowings (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Long-term debt	$ 514,639	$ 85,339
Amended 2017 Credit Facility
Line of Credit Facility [Line Items]
2019	0
2020	0
2021	0
2022	514,639
Long-term debt	$ 514,639

Long-Term Debt - Schedule of Ap

Long-Term Debt - Schedule of Applicable Margin for LIBOR Rate Loans Depending on the Utilization Level (Details) - 2017 Credit Facility	12 Months Ended
	Dec. 31, 2018
Level I
Line of Credit Facility [Line Items]
Commitment Fee	0.375%
Level II
Line of Credit Facility [Line Items]
Commitment Fee	0.375%
Level III
Line of Credit Facility [Line Items]
Commitment Fee	0.50%
Level IV
Line of Credit Facility [Line Items]
Commitment Fee	0.50%
Level V
Line of Credit Facility [Line Items]
Commitment Fee	0.50%
LIBOR Margin | Level I
Line of Credit Facility [Line Items]
Margin percentage	2.00%
LIBOR Margin | Level II
Line of Credit Facility [Line Items]
Margin percentage	2.25%
LIBOR Margin | Level III
Line of Credit Facility [Line Items]
Margin percentage	2.50%
LIBOR Margin | Level IV
Line of Credit Facility [Line Items]
Margin percentage	2.75%
LIBOR Margin | Level V
Line of Credit Facility [Line Items]
Margin percentage	3.00%
ABR Margin | Level I
Line of Credit Facility [Line Items]
Margin percentage	1.00%
ABR Margin | Level II
Line of Credit Facility [Line Items]
Margin percentage	1.25%
ABR Margin | Level III
Line of Credit Facility [Line Items]
Margin percentage	1.50%
ABR Margin | Level IV
Line of Credit Facility [Line Items]
Margin percentage	1.75%
ABR Margin | Level V
Line of Credit Facility [Line Items]
Margin percentage	2.00%

Derivative Instrument - Schedul

Derivative Instrument - Schedule of Company's Open Commodity Contracts (Details) MMBTU in Thousands	12 Months Ended
	Dec. 31, 2018MMBTU$ / BTU$ / bblbbl
Fixed price swaps | Oil fixed price swaps
Derivative Instruments [Line Items]
Volume (Bbl) | bbl	7,005,170
Weighted average price (usd per bbl) | $ / bbl	60.76
Fixed price swaps | Oil fixed price swaps | 2019
Derivative Instruments [Line Items]
Volume (Bbl) | bbl	5,405,670
Weighted average price (usd per bbl) | $ / bbl	60.05
Fixed price swaps | Oil fixed price swaps | 2020
Derivative Instruments [Line Items]
Volume (Bbl) | bbl	1,599,500
Weighted average price (usd per bbl) | $ / bbl	63.14
Fixed price swaps | Natural gas fixed price swaps
Derivative Instruments [Line Items]
Volume (MMBtu) | MMBTU	56,125
Weighted average price (usd per bbl) | $ / BTU	2.84
Fixed price swaps | Natural gas fixed price swaps | 2019
Derivative Instruments [Line Items]
Volume (MMBtu) | MMBTU	43,800
Weighted average price (usd per bbl) | $ / BTU	2.90
Fixed price swaps | Natural gas fixed price swaps | 2020
Derivative Instruments [Line Items]
Volume (MMBtu) | MMBTU	12,325
Weighted average price (usd per bbl) | $ / BTU	2.63
Fixed price swaps | Natural gas liquids fixed price swaps
Derivative Instruments [Line Items]
Volume (Bbl) | bbl	1,095,000
Weighted average price (usd per bbl) | $ / bbl	32.25
Fixed price swaps | Natural gas liquids fixed price swaps | 2019
Derivative Instruments [Line Items]
Volume (Bbl) | bbl	1,095,000
Weighted average price (usd per bbl) | $ / bbl	32.25
Fixed price swaps | Natural gas liquids fixed price swaps | 2020
Derivative Instruments [Line Items]
Volume (Bbl) | bbl	0
Weighted average price (usd per bbl) | $ / bbl	0
Basis swaps | Natural gas basis swaps
Derivative Instruments [Line Items]
Volume (MMBtu) | MMBTU	32,840
Weighted average price (usd per bbl) | $ / BTU	0.60
Basis swaps | Natural gas basis swaps | 2019
Derivative Instruments [Line Items]
Volume (MMBtu) | MMBTU	29,200
Weighted average price (usd per bbl) | $ / BTU	0.60
Basis swaps | Natural gas basis swaps | 2020
Derivative Instruments [Line Items]
Volume (MMBtu) | MMBTU	3,640
Weighted average price (usd per bbl) | $ / BTU	0.62

Derivative Instruments - Schedu

Derivative Instruments - Schedule of Net Gains and Loss on Derivative Contracts (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gain (loss) on derivative contracts	$ 78,054,000	$ (6,797,000)	$ 0
Net cash (paid) received upon settlement of derivative contracts	$ (33,279,000)	2,705,000	$ 0
Net cash (paid) received upon settlement of derivative contracts prior to contractual maturity		$ 1,300,000

Fair Value Measurements - Summa

Fair Value Measurements - Summary of Classifications of the Company's Derivative Assets and Liabilities (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 107,293	$ 5,038
Netting	(4,475)	(3,890)
Total assets, Carrying Value	102,818	1,148
Derivative Liabilities	(5,461)	(14,540)
Netting	4,475	3,890
Total liabilities, Carrying Value	(986)	(10,650)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Derivative Liabilities	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	107,293	5,038
Derivative Liabilities	(5,461)	(14,540)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Derivative Liabilities	0	0
Current commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	85,728	2,856
Netting	(3,548)	(2,704)
Total assets, Carrying Value	82,180	152
Derivative Liabilities	(4,393)	(11,983)
Netting	3,548	2,704
Total liabilities, Carrying Value	(845)	(9,279)
Current commodity derivatives | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Derivative Liabilities	0	0
Current commodity derivatives | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	85,728	2,856
Derivative Liabilities	(4,393)	(11,983)
Current commodity derivatives | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Derivative Liabilities	0	0
Noncurrent commodity derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	21,565	2,182
Netting	(927)	(1,186)
Total assets, Carrying Value	20,638	996
Derivative Liabilities	(1,068)	(2,557)
Netting	927	1,186
Total liabilities, Carrying Value	(141)	(1,371)
Noncurrent commodity derivatives | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Derivative Liabilities	0	0
Noncurrent commodity derivatives | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	21,565	2,182
Derivative Liabilities	(1,068)	(2,557)
Noncurrent commodity derivatives | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0	0
Derivative Liabilities	$ 0	$ 0

Equity - Additional Information

Equity - Additional Information (Details)	1 Months Ended		3 Months Ended
	Mar. 31, 2018shares	Aug. 31, 2017classshares	Dec. 31, 2017	Dec. 31, 2018shares	Sep. 30, 2018shares
Capital Unit [Line Items]
Common shares issued (shares)				152,539,532
Number of membership interests outstanding | class		2
Class A Unit
Capital Unit [Line Items]
Internal rate of return threshold of prior to distributions			9.00%
Members of Roan LLC | Class A common stock
Capital Unit [Line Items]
Common shares issued (shares)					152,500,000
Linn Energy Holdings | Roan LLC
Capital Unit [Line Items]
Ownership percentage		50.00%
Linn Energy Holdings | Roan LLC | Membership units
Capital Unit [Line Items]
Units issued (shares)	19,200,000	1,500,000,000
Citizen | Roan LLC
Capital Unit [Line Items]
Ownership percentage		50.00%
Citizen | Roan LLC | Membership units
Capital Unit [Line Items]
Units issued (shares)	19,200,000	1,500,000,000

Equity Compensation - Additiona

Equity Compensation - Additional Information (Details) - USD ($)	Dec. 31, 2020	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
PSU
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense		$ 11,000,000	$ 400,000	$ 0
Unrecognized expense		$ 24,400,000
Weighted average remaining period		2 years 4 days
PSU | Forecast
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Consecutive trading days	30 days
PSU | Forecast | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awarded PSUs recipient vesting	0.00%
PSU | Forecast | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awarded PSUs recipient vesting	200.00%
RSU
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense		$ 30,000
Unrecognized expense		$ 200,000
Weighted average remaining period		11 months

Equity Compensation - Summary o

Equity Compensation - Summary of Activity (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)$ / sharesshares	Dec. 31, 2017USD ($)$ / sharesshares	Dec. 31, 2016USD ($)
PSU
Number of PSUs
Beginning balance (shares) | shares	16,350,000	0
Units granted (shares) | shares	6,825,000	16,350,000
Units vested (shares) | shares	0	0
Conversion (shares) | shares	(22,016,250)
Ending balance (shares) | shares	1,158,750	16,350,000
Weighted Average Fair Value
Beginning balance (usd per share) | $ / shares	$ 1.41	$ 0
Units granted (usd per share) | $ / shares	1.88	1.41
Units vested (usd per share) | $ / shares	0	0
Conversion (usd per share) | $ / shares	0
Ending balance (usd per share) | $ / shares	$ 30.95	$ 1.41
Total Fair Value ($ in thousands)
Units outstanding | $	$ 35,864	$ 23,054	$ 0
Granted | $	12,810	23,054
Vested | $	0	$ 0
Conversion | $	$ 0
Conversion ratio	0.05
RSU
Number of PSUs
Beginning balance (shares) | shares	0
Units granted (shares) | shares	11,800
Units vested (shares) | shares	0
Forfeited (shares) | shares	0
Ending balance (shares) | shares	11,800	0
Weighted Average Fair Value
Beginning balance (usd per share) | $ / shares	$ 0
Units granted (usd per share) | $ / shares	16.95
Units vested (usd per share) | $ / shares	0
Forfeited (usd per share) | $ / shares	0
Ending balance (usd per share) | $ / shares	$ 16.95	$ 0
Total Fair Value ($ in thousands)
Units outstanding | $	$ 200	$ 0
Granted | $	200
Vested | $	0
Forfeited | $	$ 0

Equity Compensation - Schedule

Equity Compensation - Schedule of Fair Value Assumptions Used (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity volatility, minimum	34.00%
Equity volatility, maximum	36.00%
Weighted average risk-free interest rate, minimum	1.96%
Weighted average risk-free interest rate, maximum	2.54%
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Company enterprise value (in billions)	$ 4,190
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Company enterprise value (in billions)	$ 4,560

Transactions with Affiliates -

Transactions with Affiliates - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Accounts payable and accrued liabilities – Affiliates	$ 8,577	$ 183,820
Total commitment, remaining term	8,731
Oil and natural gas properties, successful efforts method	2,628,333	1,876,951
Linn Energy Holdings and Citizen Energy LLC
Related Party Transaction [Line Items]
Accounts payable and accrued liabilities – Affiliates		63,000
MSAs
Related Party Transaction [Line Items]
Charges related to services	$ 10,000	10,000
MSAs | Linn
Related Party Transaction [Line Items]
Accounts payable and accrued liabilities – Affiliates		55,500
MSAs | Citizen
Related Party Transaction [Line Items]
Accounts payable and accrued liabilities – Affiliates		46,500
MSAs | Linn Energy Holdings and Citizen Energy LLC
Related Party Transaction [Line Items]
Accounts payable and accrued liabilities – Affiliates		19,000
Corporate office lease | Blue Mountain | Affiliates
Related Party Transaction [Line Items]
Initial term	5 years
Renewal term	5 years
Lease expense	$ 500
Total commitment, remaining term	8,100
Costs incurred on the Company's behalf | Riviera | Affiliates
Related Party Transaction [Line Items]
Reorganization costs	$ 1,800
Supervisory services | Atlas LLC
Related Party Transaction [Line Items]
Oil and natural gas properties, successful efforts method		$ 2,300

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Effective combined U.S. federal and state income tax rate		24.30%
Income tax expense	$ 299,700	$ 356,862	$ 0	$ 0
Deferred tax liabilities related to reorganization		304,500
Related Party Transaction [Line Items]
Accounts payable and accrued liabilities – Affiliates		8,577	$ 183,820
Net operating loss carryforwards		165,000
Riviera | TMA
Related Party Transaction [Line Items]
Accounts payable and accrued liabilities – Affiliates		$ 7,600

Income Taxes - Schedule of Prov

Income Taxes - Schedule of Provision for Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current income tax expense
Federal		$ 0
State		0
Total		0
Deferred income tax expense
Federal		277,794
State		79,068
Total		356,862
Provision for income taxes	$ 299,700	$ 356,862	$ 0	$ 0

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Liabilities (Details) $ in Thousands	Dec. 31, 2018USD ($)
Deferred income tax assets
Net operating losses	$ 42,013
Other	4,409
Deferred income tax assets	46,422
Deferred income tax liabilities
Oil and natural gas properties	(377,362)
Derivative contracts	(25,922)
Deferred tax liabilities	(403,284)
Deferred tax liabilities, net	$ (356,862)

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Amount
Income (loss) at U.S. federal statutory rate		$ 45,400
Net effect of state income taxes		9,173
Change in tax status		304,455
Other		(2,166)
Provision for income taxes	$ 299,700	$ 356,862	$ 0	$ 0
Percent
Income (loss) at U.S. federal statutory rate		21.00%
Net effect of state income taxes		4.20%
Change in tax status		140.80%
Other		(1.00%)
Income tax provision / Effective rate		165.00%

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Future Minimum Payments (Details) $ in Thousands	Dec. 31, 2018USD ($)
Office building leases
2019	$ 1,692
2020	2,047
2021	2,136
2022	2,229
2023	456
Thereafter	171
Total	8,731
Pipe and equipment purchase commitments
2019	1,455
2020	0
2021	0
2022	0
2023	0
Thereafter	0
Total	1,455
Drilling rig commitments
2019	15,352
2020	0
2021	0
2022	0
2023	0
Thereafter	0
Total	15,352
Total
2019	18,499
2020	2,047
2021	2,136
2022	2,229
2023	456
Thereafter	171
Total	$ 25,538

Commitments and Contingencies_2

Commitments and Contingencies - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Commitments and Contingencies Disclosure [Abstract]
Lease expense	$ 1.4
Deficiency fees	$ 8.1

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) MMBTU in Thousands	3 Months Ended	12 Months Ended
	Apr. 01, 2019MMBTU$ / BTU$ / bblbbl	Dec. 31, 2018MMBTU$ / BTU$ / bblbbl	Mar. 27, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)
Fixed price swaps | Natural gas fixed price swaps
Subsequent Event [Line Items]
Volume (MMBtu) | MMBTU		56,125
Weighted average price (usd per bbl) | $ / BTU		2.84
Fixed price swaps | Oil fixed price swaps
Subsequent Event [Line Items]
Weighted average price (usd per bbl) | $ / bbl		60.76
Volume | bbl		7,005,170
2017 Credit Facility
Subsequent Event [Line Items]
Line of credit facility, current borrowing capacity | $				$ 675,000,000	$ 200,000,000
Subsequent event | Fixed price swaps | Natural gas fixed price swaps
Subsequent Event [Line Items]
Volume (MMBtu) | MMBTU	40
Weighted average price (usd per bbl) | $ / BTU	2.68
Subsequent event | Fixed price swaps | Oil fixed price swaps
Subsequent Event [Line Items]
Weighted average price (usd per bbl) | $ / bbl	57.80
Volume | bbl	2,000
Subsequent event | 2017 Credit Facility
Subsequent Event [Line Items]
Line of credit facility, current borrowing capacity | $			$ 750,000,000

Supplemental Information on O_3

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Oil and natural gas properties
Proved properties	$ 1,538,379	$ 750,492
Unproved properties	1,089,954	1,126,459
Total oil and natural gas properties	2,628,333	1,876,951
Accumulated depreciation, depletion, amortization and impairment	(230,836)	(78,307)
Oil and natural gas properties, net	$ 2,397,497	$ 1,798,644

Supplemental Information on O_4

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Acquisition costs of properties:
Proved properties	$ 5,655	$ 214,647	$ 1,079
Unproved properties	42,738	1,018,978	93,705
Development costs	719,198	390,991	152,284
Exploratory	7,257	8,538	0
Costs incurred	$ 774,848	$ 1,633,154	$ 247,068

Supplemental Information on O_5

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Results of Operations for Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Extractive Industries [Abstract]
Oil, natural gas and NGL sales	$ 439,767	$ 166,385	$ 54,965
Production expenses	47,600	16,872	5,090
Production taxes	17,579	3,685	1,087
Exploration expenses	43,303	28,154	0
Gathering, transportation and processing	0	18,602	5,920
Depreciation, depletion, amortization and accretion	123,062	37,376	24,996
Impairment	0	4,475	5,258
Income tax expense	13,103	0	0
Results of operations	$ 195,120	$ 57,221	$ 12,614
Effective combined U.S. federal and state income tax rate	24.30%

Supplemental Information on O_6

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2018MBoeMBblsMMcf	Dec. 31, 2017MBoeMBblsMMcf	Dec. 31, 2016MBoeMBblsMMcf
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Balance, beginning | MBoe	231,309	13,057	2,484
Purchase of reserves | MBoe	0	53,986	111
Extensions and discoveries | MBoe	158,797	173,238	11,124
Revisions of previous estimates | MBoe	(68,209)	(369)	1,687
Production | MBoe	(15,938)	(8,603)	(2,350)
Balance, ending | MBoe	305,959	231,309	13,057
Oil (mbbl)
Proved Developed and Undeveloped Reserves [Roll Forward]
Balance, beginning	37,420	2,900	387
Purchase of reserves	0	9,843	22
Extensions and discoveries	34,714	30,554	2,632
Revisions of previous estimates	(12,087)	(3,583)	598
Production	(4,364)	(2,294)	(740)
Balance, ending	55,683	37,420	2,900
Natural Gas (mmcf)
Proved Developed and Undeveloped Reserves [Roll Forward]
Balance, beginning | MMcf	685,869	39,831	8,517
Purchase of reserves | MMcf	0	163,638	333
Extensions and discoveries | MMcf	451,750	486,510	33,218
Revisions of previous estimates | MMcf	(184,547)	20,844	4,145
Production | MMcf	(41,890)	(24,953)	(6,382)
Balance, ending | MMcf	911,182	685,869	39,831
NGLs (mbbl)
Proved Developed and Undeveloped Reserves [Roll Forward]
Balance, beginning	79,578	3,519	678
Purchase of reserves	0	16,870	33
Extensions and discoveries	48,791	61,599	2,956
Revisions of previous estimates	(25,365)	(260)	398
Production	(4,592)	(2,150)	(546)
Balance, ending	98,412	79,578	3,519

Supplemental Information on O_7

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Additional Information (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2018MBoewell$ / bbl$ / MMBTU	Dec. 31, 2017MBoewell$ / bbl$ / MMBTU	Dec. 31, 2016aMBoewell$ / bbl$ / MMBTU	Dec. 31, 2015MBoe
Reserve Quantities [Line Items]
Total proved reserves	305,959	231,309	13,057	2,484
Number of wells | well	214	93	55
Extensions and discoveries	158,797	173,238	11,124
Revisions of previous estimates	(68,209)	(369)	1,687
Purchase of reserves	0	53,986	111
Unproved leasehold acquired, net | a			62,500
Proved reserve estimates prepared by independent reserve engineers	93.00%
Proved reserve estimate prepared by personnel	7.00%
Production performance
Reserve Quantities [Line Items]
Revisions of previous estimates	(33,342)	(3,646)
Development plan
Reserve Quantities [Line Items]
Revisions of previous estimates	(36,038)
Revision of previous estimate
Reserve Quantities [Line Items]
Revisions of previous estimates		3,277
Oil (mbbl)
Reserve Quantities [Line Items]
Prices used in computing the Company's reserves | $ / bbl	65.66	51.34	42.64
Natural Gas (mmcf)
Reserve Quantities [Line Items]
Prices used in computing the Company's reserves | $ / MMBTU	3.16	2.98	2.48
NGLs (mbbl)
Reserve Quantities [Line Items]
Prices used in computing the Company's reserves | $ / bbl	20.35	19	15.26

Supplemental Information on O_8

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Schedule of Estimated Quantities of Proved Developed and Proved Undeveloped ("PUD") Oil, Natural Gas and NGL Reserves of the Company (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands	Dec. 31, 2018MBoeMBblsMMcf	Dec. 31, 2017MBoeMBblsMMcf	Dec. 31, 2016MBoeMBblsMMcf	Dec. 31, 2015MBoeMBblsMMcf
Reserve Quantities [Line Items]
Total Proved Developed Reserves | MBoe	120,192	79,585	13,057
Total Proved Undeveloped Reserves | MBoe	185,767	151,724	0
Total proved reserves | MBoe	305,959	231,309	13,057	2,484
Oil (mbbl)
Reserve Quantities [Line Items]
Proved Developed Reserves	18,652	12,352	2,900
Proved Undeveloped Reserves	37,031	25,068	0
Proved Reserves	55,683	37,420	2,900	387
Natural Gas (mmcf)
Reserve Quantities [Line Items]
Proved Developed Reserves | MMcf	369,677	259,193	39,831
Proved Undeveloped Reserves | MMcf	541,505	426,676	0
Proved Reserves | MMcf	911,182	685,869	39,831	8,517
NGLs (mbbl)
Reserve Quantities [Line Items]
Proved Developed Reserves	39,927	24,034	3,519
Proved Undeveloped Reserves	58,485	55,544	0
Proved Reserves	98,412	79,578	3,519	678

Supplemental Information on O_9

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Summary of Company's Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Future cash inflows	$ 7,325,386	$ 5,270,465	$ 271,428
Future production costs	(1,773,779)	(1,664,724)	(102,817)
Future development costs	(1,294,565)	(745,769)	0
Future income tax expense	(797,247)	0	0
Future net cash flows	3,459,795	2,859,972	168,611
Discount to present value at 10% annual rate	(1,760,094)	(1,664,303)	(50,339)
Standardized measure of discounted future net cash flows	$ 1,699,701	$ 1,195,669	$ 118,272	$ 18,910

Supplemental Information on _10

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Summary of Company's Standardized Measure of Discounted Future Net Cash Flows - Supplemental Information on Oil, Natural Gas, and NGL Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Extractive Industries [Abstract]
Standardized measure of discounted future net cash flows at the beginning of the period	$ 1,195,669	$ 118,272	$ 18,910
Sales of oil and natural gas, net of production costs	(374,588)	(124,526)	(42,868)
Acquisition of reserves	0	279,026	462
Extensions and discoveries, net of future development costs	1,126,713	877,846	104,581
Previously estimated development costs incurred during the period	124,822	148,505	0
Net changes in prices and production costs	172,928	36,233	18,256
Changes in estimated future development costs	(13,160)	(17,970)	0
Revisions of previous quantity estimates	(281,054)	(5,676)	15,573
Accretion of discount	119,567	11,827	1,891
Net change in income taxes	(391,808)	0	0
Net changes in timing of production and other	20,612	(127,868)	1,467
Standardized measure of discounted future net cash flows at the end of the period	$ 1,699,701	$ 1,195,669	$ 118,272

Quarterly Financial Data (Una_3

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, shares in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Total revenues	$ 307,052,000	$ 83,448,000	$ 35,965,000	$ 91,356,000	$ 58,568,000	$ 39,751,000	$ 30,290,000	$ 30,979,000	$ 517,821,000		$ 159,588,000	$ 54,965,000
Operating Income (Loss)	208,819,000	514,000	(21,670,000)	36,880,000	(9,373,000)	10,974,000	1,867,000	16,437,000	224,543,000		19,905,000	7,033,000
Net (loss) income	$ 148,245,000	$ (301,240,000)	$ (22,757,000)	$ 35,081,000	$ (10,380,000)	$ 10,710,000	$ 1,817,000	$ 16,310,000	$ (140,671,000)	[1]	$ 18,457,000	$ 6,947,000
Earnings (loss) per share
Basic (usd per share)	$ 0.97	$ (1.97)	$ (0.15)	$ 0.23	$ (0.07)	$ 0.11	$ 0.02	$ 0.22	$ (0.92)		$ 0.18	$ 0.11
Diluted (usd per share)	$ 0.97	$ (1.97)	$ (0.15)	$ 0.23	$ (0.07)	$ 0.11	$ 0.02	$ 0.22	$ (0.92)		$ 0.18	$ 0.11
Weighted average number of shares outstanding (shares)	152,540	152,540	152,540	151,294	150,607	99,859	75,303	75,303
Income tax expense		$ (299,700,000)							$ (356,862,000)		$ 0	$ 0
Bonuses paid							$ 9,000,000
Abandonment and impairment expense						$ 4,200,000			0		4,500,000	5,300,000
Leasehold impairment					$ 19,600,000				$ 36,000,000		$ 19,600,000	$ 0
[1]	Amounts are allocated to stockholders’ equity and members’ equity to reflect the Reorganization. See Note 10 – Equity for discussion of the Reorganization.