Document and Entity Information	6 Months Ended
Document and Entity Information	Jun. 30, 2018
Document And Entity Information [Abstract]
Document Type	8-K
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Entity Registrant Name	Roan Resources, Inc.
Entity Central Index Key	0001326428

Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 24,376	$ 1,471	$ 6,853
Accounts receivable
Oil, natural gas and natural gas liquid sales	21,347	74,527	15,701
Oil, natural gas and natural gas liquid sales - Affiliates	8,136	4,695
Joint interest owners	84,336		36,086
Affiliates	31,728
Other		320	2,640
Prepaid drilling advances	37,019
Derivative contracts	281	152
Other current assets	6,190	930	2,966
Total current assets	213,413	82,095	64,246
Long-term assets
Oil and natural gas properties, successful efforts method	2,187,486	1,876,951	325,380
Accumulated depreciation, depletion, amortization and impairment	(137,564)	(78,307)	(27,002)
Oil and natural gas properties, net	2,049,922	1,798,644	298,378
Other property and equipment, net	3,150	1,147
Deferred financing costs	3,326	2,710
Derivative assets		996
Other assets			459
Total assets	2,269,811	1,885,592	363,083
Current liabilities
Accounts payable and accrued liabilities	122,278	10,245	28,222
Accounts payable and accrued liabilities - Affiliates	26,256	164,865
Accounts payable-Affiliates		13,102
Accrued capital expenditures-Affiliates		151,763
Revenue payable	74,128		13,009
Revenue payable - Affiliates		18,955
Drilling advances	47,605		25,363
Asset retirement obligations	416		3
Derivative contracts	49,424	9,279
Total current liabilities	320,107	203,344	66,594
Noncurrent liabilities
Long-term debt	284,639	85,339	20,000
Asset retirement obligations	12,158	10,769	2,242
Derivative contracts	10,664	1,371
Other	117
Total liabilities	627,685	300,823	88,836
Commitments and contingencies
Total members' equity	1,642,126	1,584,769	274,247
Total liabilities and members' equity	$ 2,269,811	$ 1,885,592	$ 363,083

Statements of Operations - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
Statements of Operations - USD ($) $ in Thousands	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues
(Loss) gain on derivative contracts	$ (64,216)	$ 2,254	$ (6,797)	$ 0	$ 0
Total revenues	127,321	61,269	159,588	54,965	5,685
Operating Expenses
Production expenses	15,374	6,114	16,872	5,090	549
Gathering, transportation and processing	0	6,470	18,602	5,920	273
Production taxes	4,682	1,210	3,685	1,087	190
Exploration expenses	18,483	246	32,629	5,258	121
Depreciation, depletion and amortization	46,466	11,352	37,012	24,909	2,060
Accretion of asset retirement obligations	403		364	87	31
General and administrative	27,106	17,573	31,357	5,581	2,074
Gain on sale of oil and natural gas properties			(838)
Total operating expenses	112,111	42,965	139,683	47,932	5,298
Total operating income	15,210	18,304	19,905	7,033	387
Other income (expense)
Interest expense	(2,886)	(177)	(1,461)	(86)
Other income			13		4
Total other (expense) income			(1,448)	(86)	4
Net income	$ 12,324	$ 18,127	$ 18,457	$ 6,947	$ 391
Earnings per unit
Basic	$ 0.00	$ 0.01	$ 0.01	$ 0.01	$ 0.00
Diluted	$ 0.00	$ 0.01	$ 0.01	$ 0.01	$ 0.00
Weighted average number of units outstanding
Basic	3,026,163	1,500,000	2,001,370	1,242,852	403,392
Diluted	3,026,163	1,500,000	2,001,370	1,242,852	403,392
Oil and Condensate
Revenues
Revenue from Contract with Customer, Including Assessed Tax	$ 122,369	$ 29,001	$ 76,876	$ 30,565	$ 3,972
Natural Gas, Production
Revenues
Revenue from Contract with Customer, Including Assessed Tax	21,458	18,039	46,303	16,093	1,055
Natural Gas, Production \| Affiliates
Revenues
Revenue from Contract with Customer, Including Assessed Tax	9,439
Natural Gas, Liquids Derived from Processing Gas
Revenues
Revenue from Contract with Customer, Including Assessed Tax	25,144	$ 11,975	35,217	$ 8,307	$ 658
Natural Gas, Liquids Derived from Processing Gas \| Affiliates
Revenues
Revenue from Contract with Customer, Including Assessed Tax	$ 13,127
Natural Gas and NGL [Member] \| Affiliates
Revenues
Revenue from Contract with Customer, Including Assessed Tax			$ 7,989

Statements of Changes in Members' Equity $ in Thousands	USD ($)
Beginning balance at Dec. 31, 2014	$ 15,126
Members' Equity [Abstract]
Contributions from Citizen Members	82,775
Net income	391
Ending balance at Dec. 31, 2015	98,292
Members' Equity [Abstract]
Contributions from Citizen Members	169,008
Net income	6,947
Ending balance at Dec. 31, 2016	274,247
Members' Equity [Abstract]
Contributions from Citizen Members	95,557
Distributions to Citizen Members	(85,614)
Acquisition of oil and natural gas properties in exchange for equity units	1,281,743
Equity-based compensation	379
Net income	18,457
Ending balance at Dec. 31, 2017	1,584,769
Members' Equity [Abstract]
Acquisition of oil and natural gas properties in exchange for equity units	39,906
Equity-based compensation	5,127
Net income	12,324
Ending balance at Jun. 30, 2018	$ 1,642,126

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
Statements of Cash Flows - USD ($) $ in Thousands	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities
Net income	$ 12,324	$ 18,127	$ 18,457	$ 6,947	$ 391
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	46,466	11,352	37,012	24,909	2,060
Accretion of asset retirement obligations	403		364	87	31
Unproved leasehold amortization and impairment and dry hole expense	14,471	246	25,377	5,258
Amortization of deferred financing costs	341		175
Amortization of deferred rent	117
Loss (gain) on derivative contracts	64,216	(2,254)	6,797	0	0
Net cash (paid) received for derivative settlements	(13,911)	130	2,705
Gain on sale of oil and natural gas property			(838)
Equity-based compensation	5,127		379
Other			(11)	(41)
Changes in operating assets and liabilities increasing (decreasing) cash:
Accounts receivable-Oil, natural gas and natural gas liquid sales	53,180	(423)	(62,170)	(12,473)	(3,009)
Accounts receivable-Oil, natural gas and natural gas liquid sales - Affiliates	(3,441)		(4,695)
Accounts receivable - Joint interest owners	(14,380)	(4,741)	(10,069)	(33,663)	(2,416)
Accounts receivable - Affiliates	(31,748)
Accounts receivable - Other	320	1,629	1,340	(1,735)	(847)
Prepaid drilling advances	(8,047)
Other current assets	(4,920)	(98)	(2,314)	(1,218)	(1,799)
Drilling advances	39,502	14,873	(25,363)	22,760	2,590
Accounts payable and accrued liabilities	34,611	(3,869)	47,801	14,409	5,558
Accounts payable - Affiliates	(32,078)		13,412
Revenue payable	21,335	(6,938)	(5,793)	10,900	2,078
Revenue payable - Affiliates	(18,955)		17,709
Net cash provided by operating activities	164,530	28,034	60,275	36,140	4,637
Cash flows from investing activities:
Acquisition of oil and natural gas properties	(22,935)	(38,824)	(42,701)	(144,774)	(47,874)
Development of oil and natural gas properties	(314,662)	(54,764)	(167,122)	(96,335)	(18,117)
Acquisition of other property and equipment	(2,371)	(113)	(1,332)
Proceeds from the sale of oil and natural gas properties			1,435
Purchase of investment		(3,000)
Other			(2,801)		(190)
Net cash used in investing activities	(339,968)	(96,701)	(212,521)	(241,109)	(66,181)
Cash flows from financing activities:
Proceeds from borrowings	199,300		105,339	20,000
Repayments of borrowings			(40,000)
Deferred financing costs	(957)		(2,885)
Distribution to Citizen members			(11,147)
Contributions from Citizen members		80,383	95,557	169,008	82,775
Net cash provided by financing activities	198,343	80,383	146,864	189,008	82,775
Net (decrease) increase in cash and cash equivalents	22,905	11,716	(5,382)	(15,961)	21,231
Cash and cash equivalents, beginning of period	1,471	6,853	6,853	22,814	1,583
Cash and cash equivalents, end of period	24,376	18,569	1,471	6,853	22,814
Supplemental disclosure of cash flow information:
Cash paid for interest, net of capitalized interest	2,078	177	1,036	86
Supplemental disclosure of non-cash investing activity:
Change in accrued capital expenditures	(34,614)	$ 12,549	147,142	$ 4,922	$ 2,298
Distribution to Citizen Members of assets and liabilities			(74,467)
Acquisition of oil and natural gas properties for equity	$ 39,906		$ 1,281,743

Business and Organization	6 Months Ended	12 Months Ended
Business and Organization	Jun. 30, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Business and Organization	Note 1 – Business and Organization Roan Resources LLC (the “Company” or “Roan”) was formed in May 2017 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. On August 31, 2017, the Companyexecuted a contribution agreement (the “Contribution Agreement”) by and among the Company, Citizen Energy II, 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 the Company. The contributions of oil and natural gas properties to Roan by Citizen and Linn were determined to meet the definition of a business. However, as Roan 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 (“ASC 805”). 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 properties located in Central Oklahoma. For the period following the Contribution, the information in the accompanying financial statements and footnotes reflects the results of Roan. 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 master services agreements with both Citizen and Linn (“MSAs”). 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. See Note 12 – Transactions with Affiliates for additional discussion of the MSAs and transactions with Citizen and Linn.	Note 1 – Business and Organization Roan Resources LLC (the “Company” or “Roan”) is a Delaware Limited Liability Company formed on May 30, 2017, to engage in the acquisition, development, production, exploration 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. On August 31, 2017, the Company executed a contribution agreement (the “Contribution Agreement”) by and among the Company, Citizen Energy II, 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 the Company. The contributions of oil and natural gas properties to Roan by Citizen and Linn were determined to meet the definition of a business. However, as Roan had no assets or operations prior to the Contribution, it was determined that Citizen was the acquirer for accounting purposes in accordance with ASC 805. 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, as Citizen is the predecessor. Citizen is a Delaware Limited Liability Company formed on July 18, 2014, to engage in the acquisition, development, production, exploration and sale of oil and natural gas properties located in Central Oklahoma. For the period following the Contribution, the information in the accompanying financial statements and footnotes reflects the results of Roan. See Note 4 – Acquisitions and Divestitures 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 Master Services Agreements with both Citizen and Linn (“MSAs”). Under the MSAs, Citizen and Linn provide certain services in respect to the oil and natural gas properties they contributed to the Company. Such services include 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 collect amounts due from joint interest owners for their share of costs and bills the Company for its share of costs. See Note 12 – Transactions with Affiliates for additional discussion of the MSAs and transactions with Citizen and Linn.

Basis of Presentation and Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation and Significant Accounting Policies

Note 2 – Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The accompanying financial statements were prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).

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 natural gas liquid (“NGLs”) 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 the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. The Company recognizes revenues from the sale of oil, natural gas and NGLs using the sales method, whereby revenue is recorded based on the Company’s share of volumes sold. If the Company’s aggregate sales volumes for a well are greater (or less) than its proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make up the overproduced (or under produced) imbalance. There were no material imbalances at December 31, 2017 or 2016.

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 on a units-of-production basis over the remaining estimated life of proved reserves. 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.

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.

Impairment of Oil and Natural Gas Properties

Proved oil and natural gas properties are evaluated for impairment annually or 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.

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. 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 lives 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.

Costs of expired or relinquished leases are charged against the valuation allowance.

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. Any drilling advances due to or from other joint interest owners are maintained by Citizen and Linn. See Note 12 – Transactions with Affiliates for additional discussion of the MSAs and transactions 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 accompany statements of operations.

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 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 loss on derivative contracts in the accompanying 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 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.

Cash and 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. No bad debt expense was recorded for the years ended December 31, 2017, 2016 or 2015 and the Company had no reserve for bad debts at December 31, 2017 or 2016.

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 on the accompanying balance sheets.

Equity-Based Compensation

In December 2017, the Company granted certain employees performance share units (“PSUs”) pursuant to the Roan Resources LLC Management Incentive Plan (the “Plan”). PSUs issued under this Plan were recognized as equity awards based on their characteristics. The compensation measurement was based on the grant date fair value of the award. Equity compensation is 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 statements of operations.

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 two 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, 2017, 2016, and 2015, the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues:


	Year Ended December 31,
	2017			2016			2015
Sunoco Inc.		40	%		55	%		61	%
EnLink Oklahoma Gas Processing, LP		39	%		31	%		*
Cimarex Energy Company		*			*			14	%

*	Revenue from customer was less than 10% in this year

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, 2017 are also lenders under its revolving credit facility entered into in September 2017. 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.

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.

Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers between levels during 2017 or 2016.

The carrying values of the Company’s receivables, payables and long-term debt are estimated to be substantially the same as their fair values at December 31, 2017 and 2016. As noted above, the Company carries its derivative financial instruments at fair value.

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.

Earnings per Unit

The Company uses the treasury stock method to determine the potential dilutive effect of outstanding performance share units. Refer to Note 11 – Performance Share Units for details on the Company’s performance share units.

Income Taxes

The Company is organized as a Delaware limited liability company. The Company is treated as a flow-through entity for income tax purposes. As a result, the net taxable income or loss of the Company and any related tax credits, for federal income tax purposes, are deemed to pass to the members and are included in the Company’s tax returns even though such net taxable income or loss and tax credits may not have actually been distributed. Accordingly, no tax provision has been made in the financial statements of the Company since the income tax is an obligation of the members.

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	12 Months Ended
Recently Issued Accounting Standards	Dec. 31, 2017
Accounting Changes and Error Corrections [Abstract]
Recently Issued Accounting Standards	Note 3—Recently Issued Accounting Standards Recently Adopted Accounting Standards In January 2017, the Company adopted Accounting Standards Update (“ASU”) 2016-09, Compensation – Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 changes several aspects of how companies account for share-based payments, including the accounting for income taxes when awards vest or are settled, statutory withholding requirements and forfeitures. As a result of adoption, the Company will reflect forfeitures of share-based payments in the period forfeitures occur. In September 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”),which requires the acquirer in a business combination to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The standard is effective for private entities for fiscal years beginning after December 15, 2016, and interim periods within fiscal years beginning after December 15, 2017. The Company adopted this ASU effective January 2017. Adoption of ASU 2015-16 in 2017 did not have an impact on the Company’s financial statements. Recent Accounting Standards Issued Not Yet Adopted In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This update 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. The standard will be effective for fiscal years beginning after December 15, 2017, including interim reporting periods within those fiscal years, with early application permitted. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is currently evaluating the impact of this standard on its financial statements and related disclosures. The Company plans to use the modified retrospective method. In February 2016, the FASB issued ASU 2016-02, Leases. 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. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company enters into lease agreements to support its operations, such as office space, vehicles, and drilling rigs. This ASU will not impact the accounting or financial presentation of the Company’s mineral leases. The Company is evaluating the impact of the adoption of this guidance on its financial statements.

Acquisitions and Divestitures

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Business Combinations [Abstract]

Acquisitions and Divestitures

Note 4 – Acquisitions

Linn Acquisition

As noted in Note 1 – Business and Organization, in connection with the Contribution, the Company 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 the Company valued at approximately $1.3 billion based on the value of the business. At the time of the Linn Acquisition, the Company consisted of oil and natural gas properties contributed by Citizen and Linn. 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.

As 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 six months ended June 30, 2017 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.


	Six Months Ended June 30, 2018
	(in thousands)
Revenue	$	101,474
Net income	$	38,201

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 the Company’s behalf for $63.0 million, which was included in accounts payable and accrued liabilities – affiliates at December 31, 2017. In March 2018, the Company paid Linn $22.9 million in cash and issued equity units to both Citizen and Linn to settle the amount due.

Note 4 – Acquisitions and Divestitures

2017 Acquisitions and Divestitures

Linn Acquisition


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

Revenues of $34.1 million and revenues less direct operating expenses of $26.6 million associated with the assets from the Linn Acquisition are included in the accompanying statement of operations for the year ended December 31, 2017.

The following unaudited pro forma combined results of operations is provided for the year ended December 31, 2017, 2016, and 2015 as though the Linn Acquisition had been completed as of January 1, 2015. 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.


	(Unaudited)
	Year Ended December 31,
	2017		2016		2015
	(in thousands)
Revenue	$	215,588	$	90,238	$	28,139
Net income	$	44,269	$	26,378	$	6,299

Other 2017 Acquisitions

During the year ended December 31, 2017, the Company also 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 unproved acreage during 2017 on the Company’s behalf.

2016 Acquisitions

April 14, 2016 Acquisition

On April 14, 2016, the Company acquired an unrelated third party’s interests in approximately 5,791 net acres of leasehold, and related producing properties located in Central Oklahoma. The seller received aggregate consideration of approximately $8.9 million in cash. The effective date for the acquisition was February 1, 2016, with purchase price adjustments calculated as of the closing date on April 14, 2016.

The acquisition was accounted for using the acquisition method under ASC 805, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of April 14, 2016. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumes (in thousands):

Other 2016 Acquisitions


Consideration given
Total cash consideration	$	8,854

Allocation of purchase price
Proved oil and natural gas properties		1,128
Unproved oil and natural gas properties		7,774

Total oil and natural gas properties acquired		8,902
Asset retirement obligations		(48	)

Total fair value of net assets acquired	$	8,854

During the year ended December 31, 2016, the Company also acquired, from unrelated third parties, interests in approximately 62,461 net acres of unproved leasehold in separately negotiated transactions for aggregate cash consideration of $137.6 million, all of which were accounted for as asset acquisitions and recorded as additions to unproved oil and natural gas properties.

Oil and Natural Gas Properties

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

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:


	June 30, 2018			December 31, 2017
	(in thousands)
Oil and natural gas properties
Proved	$	1,068,937		$	750,492
Unproved		1,118,549			1,126,459
Less: accumulated depreciation, depletion, amortization and impairment		(137,564	)		(78,307	)

Oil and natural gas properties, net	$	2,049,922		$	1,798,644

The Company recorded depletion expense on capitalized oil and natural gas properties of $45.7 million and $11.3 million for the six months ended June 30, 2018 and 2017, respectively.

For the six months ended June 30, 2018, the Company recorded amortization expense on its unproved oil and natural gas properties of $14.5 million which is reflected in exploration expense on the accompanying statements of operations. There was no such expense recorded for the six months ended June 30, 2017. Unproved leasehold amortization for the six months ended June 30, 2018 reflects consideration of the Company’s drilling plans and the lease terms of our existing unproved properties. For the six months ended June 30, 2017, the Company recorded impairment expense on its unproved oil and natural gas properties of $0.2 million for leases which expired. No impairment of proved oil and natural gas properties was recorded for the six months ended June 30, 2018 and 2017.

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 includes the following:


	December 31,
	2017			2016
	(in thousands)
Oil and natural gas properties
Proved	$	750,492		$	184,376
Unproved		1,126,459			141,004
Less: accumulated depreciation, depletion, amortization and impairment		(78,307	)		(27,002	)

Oil and natural gas properties, net	$	1,798,644		$	298,378

There were no exploratory well costs pending determination of proved reserves at December 31, 2017 or 2016 nor any unsuccessful exploratory dry hole costs during the years ended December 31, 2016 and 2015. During the year ended December 31, 2017, there was $1.3 million associated with exploratory dry hole costs that is included in exploration costs in the accompanying statements of operations.

At December 31, 2017 and 2016, the Company’s estimate of undiscounted future cash flows attributable to its proved oil and natural gas properties indicated that the carrying amount was expected to be recovered. No impairment of proved oil and natural gas properties was recorded for the years ended December 31, 2017, 2016, and 2015. 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 statements of operations. There was no abandonment and impairment expense on unproved oil and natural gas properties during the year ended December 31, 2015.

Asset Retirement Obligations

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

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 asset retirement obligation (“ARO”) for the six months ended June 30, 2018 (in thousands):


Asset retirement obligation, December 31, 2017			$10,769
Liabilities incurred or acquired			1,402
Revisions in estimated cash flows			—
Liabilities settled			—
Accretion expense			403

Asset retirement obligation, June 30, 2018			12,574
Less: current portion of obligations			416

Asset retirement obligation – long term			$12,158

Accretion expense is included in depreciation, depletion and amortization in the accompanying statements of operations.

Note 6 – Asset Retirement Obligations

The following is a reconciliation of the changes in the Company’s ARO for the years ended December 31, 2017 and 2016:


	Year Ended December 31,
	2017		2016
	(in thousands)
Asset retirement obligation, beginning balance	$	2,245	$	1,161
Liabilities incurred or acquired		8,118		1,054
Revisions in estimated cash flows		42		(16	)
Liabilities settled		—		(41	)
Accretion expense		364		87

Asset retirement obligation, ending balance		10,769		2,245
Less: current portion of obligations		—		3

	$	10,769	$	2,242

For the year ended December 31, 2017, liabilities incurred or acquired includes $7.5 million assumed as part of the Linn Acquisition. The current portion of ARO is included in accounts payable and accrued liabilities in the accompanying balance sheets.

Long-Term Debt

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Debt Disclosure [Abstract]

Long-Term Debt

Note 7 – Long-Term Debt

In September 2016, the Company entered into a credit agreement with lender with an initial borrowing base of $20.0 million (the “2016 Credit Facility”). In October 2016, the Company amended the 2016 Credit Facility to increase the borrowing base to $35.0 million from $20.0 million. Amounts borrowed under the 2016 Credit Facility bore interest at London Interbank Offered Rate (“LIBOR”) plus an applicable margin, based on the utilization percentage of the facility as provided for in the credit agreement. Additionally, the 2016 Credit Facility provided for a commitment fee of 0.25% and that was payable at the end of each calendar quarter.

In April 2017, the Company replaced its 2016 Credit Facility and entered into a two-year, $500.0 million credit facility (“Citizen 2017 Credit Facility”), which had 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.

In September 2017, the Company entered into a $750 million credit agreement with an initial borrowing base of $200.0 million and maturity on September 5, 2022 (the “2017 Credit Facility”). In April 2018 the redetermination resulted in an increase to the borrowing base to $425.0 million. Redetermination of the borrowing base of the 2017 Credit Facility occurs semiannually on or about October 1 and April 1. As of June 30, 2018, the Company had $284.6 million of outstanding borrowings and no letters of credit outstanding under the 2017 Credit Facility.

Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the alternate base rate (“ABR”). 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 of 0.50%, which is payable at the end of each calendar quarter. The pricing grid below shows the applicable margin for LIBOR rate loans depending on the Utilization Level (as defined in the credit agreement):


Utilization Level	Utilization	LIBOR Margin			Applicable Margin			Commitment Fee
Level I	< 25%		2.25	%		1.25	%		0.500	%
Level II	>25% but <50%		2.50	%		1.50	%		0.500	%
Level III	>50% but <75%		2.75	%		1.75	%		0.500	%
Level IV	>75% but <90%		3.00	%		2.00	%		0.500	%
Level V	> 90%		3.25	%		2.25	%		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 limited from hedging in excess of 80% of its projected production per its internal forecast for the next two years. For periods after the next two years, the limit is based on proved reserves per the most recent 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, or annualized with available financial information until four fiscal quarters are available, 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) as of the fiscal quarter ended of not less than 1.00 to 1.00.

As of June 30, 2018, the Company was in compliance with the covenants under the 2017 Credit Facility.

Note 7 – Long-Term Debt

On September 1, 2016, the Company entered into a credit agreement with lender with an initial borrowing base of $20.0 million (the “2016 Credit Facility”). On October 20, 2016, the Company amended the 2016 Credit Facility to increase the borrowing base to $35.0 million. As of December 31, 2016, the Company had $20.0 million of outstanding borrowings under the 2016 Credit Facility. Amounts borrowed under the 2016 Credit Facility bore interest at London Interbank Offered Rate (“LIBOR”) plus an applicable margin, based on the utilization percentage of the facility as provided for in the credit agreement. Additionally, the 2016 Credit Facility provided for a commitment fee of 0.25% and that was payable at the end of each calendar quarter. At December 31, 2016, the 2016 Credit Facility had an interest rate of 2.37%.

On April 19, 2017, Citizen replaced its 2016 Credit Facility and entered into a two-year, $500.0 million credit facility (“Citizen 2017 Credit Facility”), which had an initial borrowing base of $82.5 million. On August 31, 2017, the Citizen 2017 Credit Facility was terminated and the outstanding balance of $20.3 million was repaid.

On September 5, 2017, the Company entered into a $750 million credit agreement with an initial borrowing base of $200.0 million and maturity on September 5, 2022 (the “2017 Credit Facility”). In November 2017, the Company increased the borrowing base to $275.0 million. Redetermination of the borrowing base of the 2017 Credit Facility occurs semiannually on October 1 and April 1. As of December 31, 2017, the Company had $85.3 million of outstanding borrowings under the 2017 Credit Facility.

Principal maturities of the Company’s borrowings, consistent of amounts outstanding under the 2017 Credit Facility, at December 31, 2017 are as follows (in thousands):


2018	$	—
2019		—
2020		—
2021		—
2022		85,339

	$	85,339

At December 31, 2017, the 2017 Credit Facility had an interest rate of 4.03%. Amounts borrowed under the 2017 Credit Facility bear interest at LIBOR or the alternate base rate (“ABR”). 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 of 0.50%, which is payable at the end of each calendar quarter. The pricing grid below shows the applicable margin for LIBOR rate loans depending on the Utilization Level (as defined in the credit agreement) as of the date of this filing:


Utilization Level	Utilization	LIBOR Margin	Applicable Margin	Commitment Fee
Level I	< 25%	2.25%	1.25%	0.500%
Level II	³25% but <50%	2.50%	1.50%	0.500%
Level III	³50% but <75%	2.75%	1.75%	0.500%
Level IV	³75% but <90%	3.00%	2.00%	0.500%
Level V	³90%	3.25%	2.25%	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 limited from hedging in excess of 85% of its future proved production for the next eight quarters per its most recent 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 to exceed 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) as of the fiscal quarter ended to be less than 1.00 to 1.00.

As of December 31, 2017, the Company was in compliance with the covenants under the 2017 Credit Facility.

Derivative Instruments

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

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 forecasted sale of its oil and natural gas 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. 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 represents the Company’s open commodity contracts at June 30, 2018:


	2018		2019		2020		Total
Oil fixed price swaps
Volume (Mbbl)		2,576		4,608		410		7,594
Weighted-average price per bbl	$	57.45	$	58.66	$	60.19	$	58.33
Natural gas fixed price swaps
Volume (Bbtu)		16,284		21,900		5,005		43,189
Weighted-average price per mmbtu	$	2.94	$	2.90	$	2.69	$	2.89
Natural gas basis swaps
Volume (Bbtu)		9,200		10,950		—		20,150
Weighted-average price per mmbtu	$	0.54	$	0.55	$	—	$	0.55

The Company nets the fair value of derivative instruments by counterparty in the accompanying 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.

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 loss on derivative contracts included in the statement of operations. For the six months ended June 30, 2018, loss on derivative contracts was $64.2 million, which includes $13.9 million of net loss on derivatives settled in 2018. For the six months ended June 30, 2017, gain on derivative contracts was $2.25 million which includes $0.1 million of net gain on derivatives settled in 2017.

Note 8 – Derivative Instruments

The following table represents the Company’s open commodity contracts at December 31, 2017:


	Total
Oil fixed price swaps
2018
Volume (bbl)		2,374,000
Weighted-average price per bbl	$	54.47
2019
Volume (bbl)		1,140,250
Weighted-average price per bbl	$	54.09
Natural gas fixed price swaps
2018
Volume (mmbtu)		16,440,000
Weighted-average price per mmbtu	$	3.00
2019
Volume (mmbtu)		10,950,000
Weighted-average price per mmbtu	$	2.97
Natural gas basis swaps
2018
Volume (mmbtu)		16,440,000
Weighted-average price per mmbtu	$	0.55
2019
Volume (mmbtu)		10,950,000
Weighted-average price per mmbtu	$	0.55

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 loss on derivative contracts included in the statement of operations. For the year ended December 31, 2017, loss on derivatives was $6.8 million, which includes $2.7 million of net gain on derivatives settled in 2017. There were no commodity derivative contracts in 2016 or 2015.

Fair Value Measurements

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements

Note 9 – Fair Value Measurements

The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy:

Level 1— Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets 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.

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.

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. During the six months ended June 30, 2018, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

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 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 June 30, 2018 and December 31, 2017, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands):


	June 30, 2018
	Level 1		Level 2			Level 3		Gross Fair Value			Netting			Carrying Value
Assets
Current commodity derivatives	$	—	$	3,208		$	—	$	3,208		$	(2,927	)	$	281
Long-term commodity derivatives		—		2,064			—		2,064			(2,064	)		—

Total assets	$	—	$	5,272		$	—	$	5,272		$	(4,991	)	$	281

Liabilities
Current commodity derivatives	$	—	$	(52,351	)	$	—	$	(52,351	)	$	2,927		$	(49,424	)
Long-term commodity derivatives		—		(12,728	)		—		(12,728	)		2,064			(10,664	)

Total liabilities	$	—	$	(65,079	)	$	—	$	(65,079	)	$	4,991		$	(60,088	)


	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
Long-term 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	)
Long-term 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’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 – Performance Share Units 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.

Note 9 – Fair Value Measurements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Company’s recurring fair value measurements are performed for its commodity derivatives. 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.

Commodity Derivative Instruments

Commodity derivative contracts are stated at fair value in the accompanying 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, 2017, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands):


	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
Long-term 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	)
Long-term 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 applies the provisions of the fair value measurement standard on a non recurring basis to its non financial assets and liabilities, including proved property and assets acquired and liabilities assumed in a business combination. These assets and liabilities are not measured at fair value on a recurring basis, but are subject to fair value adjustments when facts are circumstances arise that indicate a need for measurement.

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 other non-recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 4 — Acquisitions and Divestitures for additional discussion, 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. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices, development costs, and operating costs, based on market participant assumptions. 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. Please refer to Note 11 – Performance Share Units for additional discussion.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Equity

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Equity [Abstract]

Equity

Note 10 – Equity

The Company’s operations are governed by the provisions of the Amended and Restated LLC Agreement (“LLC Agreement”), effective August 31, 2017, and the Company has one class of membership interests outstanding. The membership units (the “Units”) represent capital interests in the Company. Distributions are made pro rata in accordance with their membership interests. As of June 30, 2018, the Company had 10.0 billion Units authorized and 3.04 billion Units issued and outstanding. Pursuant to the LLC Agreement (and as is customary for limited liability companies), the liability of the Members is limited to their contributed capital.

In connection with the Contribution in August 2017, the Company issued 1.5 billion Units, which represents a 50% equity interest in the Company, 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, the Company issued 1.5 billion Units, which represents a 50% equity interest in the Company, to Citizen in exchange for the contribution of oil and natural gas properties. The fair value of the Units issued to Citizen was the same as the Units issued to Linn.

As discussed in Note 4 – Acquisitions, Citizen and Linn acquired acreage during 2017 on the Company’s behalf. In March 2018, the Company issued 19.2 million 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 (“Citizen Operating Agreement”), effective February 29, 2016, and Citizen had two classes of membership interests outstanding, Class A and Class B. Class A represented capital interests in Citizen and Class B represented interests in profits, losses and distributions. Distributions were made to the Series A and Series B Members pro rata in accordance with their membership interests; however, once the Class A received an internal rate of return threshold of 9% prior to distributions to any other class of interest, the Class B received a percentage of distributions in excess of their membership interests based on the terms of the Citizen Operating Agreement.

Citizen’s Class B units were considered profits interest and are accounted for in accordance with ASC Topic 710 (“ASC 710”), Compensation – general. No compensation expense has been recorded with respect to the Class B units because no distributions have occurred.

The Company’s Unit activity for the six months ended June 30, 2018 is as follows (in thousands):


Issued and outstanding units, December 31, 2017			3,000,000
Units issued in exchange for contribution of oil and natural gas properties			38,500

Issued and outstanding units, June 30, 2018			3,038,500

Note 10 – Equity

As of December 31, 2017, the Company’s operations were governed by the provisions of the Amended and Restated LLC Agreement (“LLC Agreement”), effective August 31, 2017, and the Company has one class of membership interests outstanding. The membership units (the “Units”) represent capital interests in the Company. Distributions are made pro rata in accordance with their membership interests. As of December 31, 2017, the Company had 10.0 billion Units authorized and 3.0 billion Units issued and outstanding. Pursuant to the LLC Agreement (and as is customary for limited liability companies), the liability of the Members is limited to their contributed capital.

In connection with the Contribution, the Company issued 1.5 billion units, which represents a 50% equity interest in the Company, to Linn in exchange for the contribution of oil and natural gas properties. See Note 4 – Acquisitions and Divestitures for additional discussion of the Linn Acquisition. Additionally, the Company issued 1.5 billion units, which represents a 50% equity interest in the Company, to Citizen in exchange for the contribution of oil and natural gas properties. The fair value of the units issued to Citizen was the same as the units issued to Linn.

As Citizen is deemed the historical acquirer, the issuance of 1.5 billion units to Citizen was reflected on a retroactive basis with Citizen having 1,398 Class A units issued and outstanding at the time of the Contribution.

For the period January 1, 2017 through August 31, 2017 and the years ended December 31, 2016 and 2015, Citizen’s operations were governed by the provisions of the Citizen Amended and Restated Operating Agreement (“Citizen Operating Agreement”), effective February 29, 2016, and Citizen had two classes of membership interests outstanding, Class A and Class B. Class A represented capital interests in Citizen and Class B represented interests in profits, losses and distributions. Distributions were made to the Series A and Series B Members pro rata in accordance with their membership interests; however, once the Class A received an internal rate of return threshold of 9% prior to distributions to any other class of interest, the Class B received a percentage of distributions in excess of their membership interests based on the terms of the Citizen Operating Agreement.

The Company’s unit activity for the years ended December 31, 2017, 2016, and 2015 is as follows:


	Year Ended December 31,
	2017		2016		2015
	(in thousands)
Issued and outstanding units, beginning of the year ⁽¹⁾		1,500,000		813,021		165,771
Issuance of units to Citizen Members ⁽¹⁾		—		686,979		647,250
Units issued in exchange for contribution of oil and natural gas properties		1,500,000		—		—

Issued and outstanding units, end of the year		3,000,000		1,500,000		813,021

⁽¹⁾	Reflects exchange of Citizen units for Roan units on retroactive basis

During the years ended December 31, 2017, 2016, and 2015, Citizen’s Members made contributions of $95.6 million, $169.0 million, and $82.8 million, respectively, to Citizen to fund its operations.

Assets and liabilities held by Citizen as of August 31, 2017 that were not contributed to the Company were deemed distributions to the Citizen Members, which totaled $85.6 million during the year ended December 31, 2017.

Performance Share Units

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Performance Share Units

Note 11 – Performance Share Units

The Company has adopted an equity-based compensation plan (“the Plan”), which provides for future grants of options, unit appreciation rights, restricted units, phantom units, unit awards, performance awards and other unit-based awards. The Company has reserved 105 million Units for delivery with respect to these awards.

The Company grants performance share units (“PSUs”) pursuant to the terms of the Plan and individual performance share unit agreements. The percent of awarded PSUs in which each recipient vests, if any, will range from 0% to 200% based on the Company’s value on December 31, 2020 (“Performance Period End Date”). The Company’s value on the Performance Period End Date will be determined by (a) if prior to an initial public offering, the value of the Company determined in good faith by a designated committee of the Board of Managers of the Company, or (b) if on or following an initial public offering, the market value of the public entity determined with reference to the volume-weighted average price of the publicly traded securities of the public entity for the 30 consecutive trading days immediately preceding the Performance Period End Date, as reported on the stock exchange composite tape. Each vested PSU is exchangeable for one Unit of the Company.

The following table summarizes information related to the total number of PSUs awarded as of June 30, 2018:


	Number of Units		Weighted Average Fair Value		Total Fair Value ($ in thousands)
Units outstanding at December 31, 2017		16,350,000	$	1.41	$	23,054
Units granted		6,325,000	$	2.05	$	12,966
Units vested		—	$	—	$	—

Units outstanding at June 30, 2018		22,675,000	$	1.59	$	36,020

Compensation expense associated with the PSU awards for the six months ended June 30, 2018 was $5.1 million and is included in general and administrative expenses on the accompany statement of operations. Unrecognized expense as of June 30, 2018 for all outstanding PSU awards was $30.6 million and will be recognized over a weighted-average remaining period of 2.50 years.

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 assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSU awards granted during the six months ended June 30, 2018:


Company enterprise value	$	4.56 billion
Equity volatility		34.0	%
Weighted average risk-free interest rate		1.96	%

Note 11 – Performance Share Units

The Company has adopted the Plan, which provides for future grants of options, unit appreciation rights, restricted units, phantom units, unit awards, performance awards and other unit-based awards. The Company has reserved 105 million Units for delivery with respect to these awards.

During December 2017, Roan made grants of approximately16.4 million PSUs pursuant to the terms of the Plan and individual Performance Share Unit Agreements. The percent of awarded PSUs in which each recipient vests, if any, will range from 0% to 200% based on the Company’s value on December 31, 2020 (“Performance Period End Date”). The Company’s value on the Performance Period End Date will be determined by (a) if prior to an initial public offering, the value of the Company determined in good faith by a designated committee of the Board of Managers of the Company, or (b) if on or following an initial public offering, the market value of the public entity determined with reference to the volume-weighted average price of the publicly traded securities of the public entity for the 30 consecutive trading days immediately preceding the Performance Period End Date, as reported on the stock exchange composite tape. Each vested PSU is exchangeable for one Unit of the Company.

The following table summarizes information related to the Company’s PSU awards:


	Number of Units		Weighted Average Fair Value		Total Fair Value ($ in thousands)
Units outstanding at December 31, 2016		—	$	—	$	—
Units granted		16,350,000	$	1.41	$	23,054
Units vested		—	$	—	$	—

Units outstanding at December 31, 2017		16,350,000	$	1.41	$	23,054

Compensation expense associated with the PSU awards for the year ended December 31, 2017 was $0.4 million and is included in general and administrative expenses on the accompany statement of operations. Unrecognized expense as of December 31, 2017 for all outstanding PSU awards was $22.7 million and will be recognized over a weighted-average remaining period of 3.0 years.

The Monte Carlo simulation process is a generally accepted statistical technique used, in this instance, to simulate the future Unit price and overall market value of the Company. The simulation uses a risk-neutral framework along with the risk-free rate of return, and an estimate for equity volatility of the Company based on peer companies. A Unit price path is simulated for the Company and is used to determine the payout percentages and the Unit price of the Company’s Units as of the Performance Period End Date. The ending Unit price is multiplied by the payout percentage to determine the projected payout, which is then discounted using the risk-free rate of return to the grant date to determine the grant date fair value of the PSUs for that iteration. When enough iterations are generated within a Monte Carlo simulation model, the resulting distribution gives a reasonable estimate of the range of future expected Unit prices and grant date fair value of the PSUs.

The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSU awards granted in December 2017:


Company enterprise value	$	3.76 billion
Equity volatility		35.00	%
Weighted average risk-free interest rate		1.94	%

Transactions with Affiliates	6 Months Ended	12 Months Ended
Transactions with Affiliates	Jun. 30, 2018	Dec. 31, 2017
Related Party Transactions [Abstract]
Transactions with Affiliates	Note 12 –Transactions with Affiliates Management Service Agreements For the six months ended June 30, 2018, the Company incurred approximately $10.0 million in charges related to the services provided under the MSAs which are recorded in general and administrative expenses in the accompanying 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 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 gas properties contributed to the Company. In April 2018, the services provided by Citizen and Linn under the MSAs ended and the Company took over as operator for the oil and natural gas properties contributed by Citizen and Linn. Accounts receivable – affiliates at June 30, 2018, of $31.7 million primarily related to the Company’s share of revenue less direct operating expenses associated with production from oil and natural gas properties during the period Citizen and Linn served as operator. In conjunction with the conclusion of the MSAs, the Company assumed certain working capital accounts, totaling $112.6 million, associated with the properties contributed from Citizen and Linn. At June 30, 2018, amounts due to Linn of $26.3 million were included in accounts payable and accrued liabilities – affiliates in the accompanying balance sheets and reflect amounts owed to Linn for the working capital accounts acquired, partially offset by amounts due to the Company for revenue associated with production from oil and natural gas properties Linn operated on the Company’s behalf. 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 Midstream LLC (“Blue Mountain”), which is a subsidiary of Linn. Amounts due from Blue Mountain at June 30, 2018 and December 31, 2017 are reflected as accounts receivable – oil, natural gas, and natural gas liquids sales – affiliates in the accompanying balance sheets and represent accrued revenue for the Company’s portion of the production sold to Blue Mountain due to the Company. Sales to Blue Mountain are reflected as natural gas sales—affiliates and natural gas liquids sales – affiliates in the accompanying statements of operations. There were no such sales to Blue Mountain during the six months ended June 30, 2017. See further discussion of this gas dedication agreement in Note 13 – Commitments and Contingencies.	Note 12 –Transactions with Affiliates Management Service Agreements For the year ended December 31, 2017, the Company incurred approximately $10.0 million in charges related to the services provided under the MSAs which are recorded in general and administrative expenses in the accompanying statements of operations. Citizen and Linn bill the Company for its share of operating costs in accordance with the MSAs. At December 31, 2017, the Company had $46.5 million and $55.5 million due to Citizen and Linn, respectively. These amounts are included in accounts payable – affiliates and accrued capital expenditures—affiliates in the accompany 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 has reflected the amount due to Citizen and Linn in accrued capital expenditures – affiliates. See Note 14 – Subsequent Events 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 Midstream LLC (“Blue Mountain”), which is a subsidiary of Linn. Amounts due from Blue Mountain at December 31, 2017 of $4.7 million are reflected as Accounts Receivable – Oil, natural gas, and natural gas liquids sales – Affiliates and sales to Blue Mountain of $8.0 million for the year ended December 31, 2017 are reflected as Natural gas and natural gas liquids sales – Affiliates. See further discussion of this gas dedication agreement in Note 13 – Commitments and Contingencies. Consulting Services Atlas, LLC (“Atlas”) provides the Company supervisory services throughout drilling and completion operations. Atlas is wholly owned jointly by a director and an employee of Citizen. For the years ended December 31, 2017, 2016, and 2015, the Company incurred $2.3 million, $2.0 million, and $0.3 million respectively, in charges related to services provided which are recorded in the balance sheet within oil and natural gas properties, successful efforts on the accompanying balance sheet. As of December 31, 2017 and 2016, the Company had no amounts payable to Atlas.

Commitments and Contingencies	6 Months Ended	12 Months Ended
Commitments and Contingencies	Jun. 30, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 13 – Commitments and Contingencies 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 June 30, 2018, 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 a geographic 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 all of its natural gas production from its oil and natural gas properties in the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement. Volume Commitment The Company has a minimum volume delivery commitment of natural gas of 18,250,000 mcf by November 2021. Under this commitment, the Company is required to deliver natural gas from a specified area, as defined in the agreement. As of June 30, 2018, the Company has delivered 3,989,236 mcf under this commitment. In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees of $0.625 per mcf.	Note 13 – Commitments and Contingencies 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, 2017, 2016 and 2015, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability. Rig Commitments The Company has drilling rig contracts with terms extending through 2018. These drilling commitments at December 31, 2017 were approximately $5.1 million. As discussed in Note 12 – Transactions with Affiliates, Citizen and Linn are serving as operator of the contributed as assets. As operator, they have contracted drilling rigs on the Company’s behalf. Such rigs are committed on a well-by-well basis. 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 a geographic 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 all of its natural gas production from its oil and natural gas properties in the contract area, as defined in the agreement, through November 2030. There is no specified volume or volume penalty in the agreement. Volume Commitment The Company has a minimum volume delivery commitment of natural gas of 18,250,000 mcf by November 2021. Under this commitment, the Company is required to delivery natural gas from a specified area, as defined in the agreement. As of December 31, 2017, the Company has delivered 3,037,500 mcf under this commitment. In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees of $0.625 per mcf.

Subsequent Events	6 Months Ended	12 Months Ended
Subsequent Events	Jun. 30, 2018	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Note 14 – Subsequent Events Management has evaluated subsequent events through September 17, 2018, which is the date the financial statements were available to be issued. No events or transactions other than those already disclosed have occurred subsequent to the balance sheet date that might require recognition or disclosure in the financial statements.	Note 14 – Subsequent Events Management has evaluated subsequent events through June 29, 2018, which is the date the financial statements were available to be issued. No events or transactions other than those already disclosed have occurred subsequent to the balance sheet date that might require recognition or disclosure in the financial statements. As discussed in Note 12 – Transactions with Affiliates, Citizen and Linn acquired acreage during 2017 on the Company’s behalf. In March 2018, the Company paid Linn $22.9 million and issued equity units to both Citizen and Linn with a total value of $40.0 million for the additional acreage. The MSAs with Citizen and Linn ended in April 2018 with the Company taking over operations of the oil and natural gas properties as of May 2018. In May 2018, the Company amended its 2017 Credit Facility, which provided additional time for the Company to remit its annual financial statements.

Supplemental Information on Oil, Natural Gas, and NGL Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2017

Extractive Industries [Abstract]

Supplemental Information on Oil, Natural Gas, and NGL Producing Activities (Unaudited)

Note 15 – Supplemental Information on Oil, Natural Gas, and NGL Producing Activities (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.

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:


	Year Ended December 31,
	2017		2016		2015
	(in thousands)
Acquisition costs of properties:
Proved properties	$	214,647	$	1,079	$	2,291
Unproved properties		1,018,978		93,705		42,266
Exploratory		8,538		—		—
Development costs		390,991		152,284		24,446

Costs incurred	$	1,633,154	$	247,068	$	69,003

Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities

Capitalized costs related to the Company’s oil, natural gas and NGL producing activities are summarized as follows:


	December 31,
	2017			2016
	(in thousands)
Oil and natural gas properties
Proved	$	750,492		$	184,376
Unproved		1,126,459			141,004
Less: accumulated depreciation, depletion, amortization and impairment		(78,307	)		(27,002	)

Oil and natural gas properties, net	$	1,798,644		$	298,378

Oil, Natural Gas and NGL Reserves

Proved oil, natural gas and NGL estimates at December 31, 2017 were prepared by DeGolyer and MacNaughton, independent petroleum engineers. Proved oil, natural gas and NGL estimates at December 31, 2016 and 2015 were prepared by Ralph E. Davis, independent petroleum engineers. 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 (mbbl)			Natural Gas (mmcf)			NGLs (mbbl)			Total (Mboe)
Proved reserves at December 31, 2014		81			1,798			38			419
Purchase of reserves		45			608			14			160
Extensions and discoveries		279			6,504			632			1,995
Revisions of previous estimates		79			41			42			128
Production		(97	)		(434	)		(48	)		(217	)

Proved reserves at December 31, 2015		387			8,517			678			2,484
Purchase 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
Purchase 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

At December 31, 2017, the Company had approximately 231,309 mboe of proved reserves. The purchase of reserves for the year ended December 31, 2017 includes reserves acquired in the Linn Acquisition. Extensions and discoveries reflect the Company’s 2017 drilling activity in Central Oklahoma. Partially offsetting the additions of reserves was production.

At December 31, 2016, the Company had approximately 13,057 mboe of proved reserves. Extensions and discoveries were partially offset by production in 2016. As Citizen acquired approximately 62,500 net acres of unproved leasehold in 2016, the addition of reserves, resulting from drilling activity in 2016, related to this acquired unproved leasehold was included as extensions and discoveries.

At December 31, 2015, the Company had approximately 2,484 mboe of proved reserves. Extensions and discoveries, resulting from Citizen’s 2015 drilling results, were partially offset by production for 2015.

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, 2017, 2016, and 2015:


	December 31,
	2017		2016		2015
Proved Developed Reserves
Oil (mbbl)		12,352		2,900		387
Natural gas (mmcf)		259,193		39,831		8,517
NGL (mbbl)		24,034		3,519		678

Total (mboe)		79,585		13,057		2,484

Proved Undeveloped Reserves
Oil (mbbl)		25,068		—		—
Natural gas (mmcf)		426,676		—		—
NGL (mbbl)		55,544		—		—

Total (mboe)		151,724		—		—

Total Proved Reserves
Oil (mbbl)		37,420		2,900		387
Natural gas (mmcf)		685,869		39,831		8,517
NGL (mbbl)		79,578		3,519		678

Total (mboe)		231,309		13,057		2,484

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, 2017, 2016, and 2015 were $51.34, $42.64, and $50.16 per barrel of oil, respectively, $2.98, $2.48, and $2.59 per mmbtu of natural gas, respectively. The NGL prices used in computing the Company’s reserves as of December 31, 2107, 2016, and 2015 were $19.00, $15.26, and $17.53 per barrel, respectively.

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.

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, 2017, 2016 and 2015:


	For the Years Ended December 31,
	2017		2016		2015
	(in thousands)
Oil, natural gas, and NGL sales	$	166,385	$	54,965	$	5,685
Production expenses		16,872		5,090		549
Gathering, transportation and processing		18,602		5,920		273
Production taxes		3,685		1,087		190
Exploration expenses		28,154		—		121
Depreciation, depletion and amortization		36,979		24,909		2,060
Accretion of asset retirement obligations		364		87		31
Impairment		4,475		5,258		121

Results of operations	$	57,254	$	12,614	$	2,461

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.


	For the Years Ended December 31,
	2017			2016			2015
	(in thousands)
Future cash inflows	$	5,270,465		$	271,428		$	47,310
Future production costs		(1,664,724	)		(102,817	)		(21,289	)
Future development costs		(745,769	)		—			—
Future income tax expense (1)		—			—			—

Future net cash flows		2,859,972			168,611			26,021
Discount to present value at 10% annual rate		(1,664,303	)		(50,339	)		(7,111	)

Standardized measure of discounted future net cash flows	$	1,195,669		$	118,272		$	18,910

(1)	The Company is a limited liability company treated as a disregarded entity for income tax purposes.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in the Company’s standardized measure of discounted future net cash flows relating from its proved oil, natural gas and NGL reserves:


	For the Years Ended December 31,
	2017			2016			2015
	(in thousands)
Standardized measure, beginning of year	$	118,272		$	18,910		$	6,500
Sales of oil, natural gas and NGLs produced, net of production costs		(124,526	)		(42,868	)		(4,673	)
Net changes in prices and production costs		36,233			18,256			(2,614	)
Extensions and discoveries, net of production and development costs		877,846			104,581			15,235
Changes in estimated future development costs		(17,970	)		—			—
Development costs incurred during the period that reduce future costs		148,505			—			—
Revisions of previous quantity estimates		(5,676	)		15,573			985
Purchases of reserves		279,026			462			1,428
Accretion of discount		11,827			1,891			650
Changes in production rates and other		(127,868	)		1,467			1,399

Standardized measure, end of year	$	1,195,669		$	118,272		$	18,910

Summary of Significant Accounting Policies	6 Months Ended
Summary of Significant Accounting Policies	Jun. 30, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2 – Summary of Significant Accounting Policies For a description of the Company’s significant accounting policies, refer to Note 2 to the financial statements included in its 2017 annual financial report. The accompanying financial statements were prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Interim Financial Statements The accompanying condensed financial statements as of December 31, 2017 were derived from the audited financial statements contained in the Company’s 2017 annual financial report. The unaudited interim condensed financial statements for the six months ended June 30, 2018 and 2017 were prepared by the Company in accordance with the accounting policies stated in the audited financial statements included in its 2017 annual financial report. In the opinion of management, the Company’s unaudited condensed financial statements reflect all known adjustments necessary to fairly state the financial position of the Company and its results of operations and cash flows for such periods. All such adjustments are of a normal, recurring nature. Certain information and disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. These unaudited condensed financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Company’s 2017 annual financial report. 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 natural gas liquid (“NGLs”) 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. Recently Adopted 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), 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. Recent Accounting Standards Issued Not Yet Adopted In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). 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. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company enters into lease agreements to support its operations, such as office space, vehicles, and drilling rigs. This ASU will not impact the accounting or financial presentation of the Company’s mineral leases. The Company is evaluating the impact of the adoption of this guidance on its financial statements.

Revenue from Contracts with Customers

6 Months Ended

Jun. 30, 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”):


	Six months ended June 30, 2018
In thousands	Under ASC 606		Under ASC 605		Increase/ (decrease)
Revenues:
Oil sales	$	122,369	$	122,369	$	—
Natural gas sales		30,897		39,181		(8,284	)
Natural gas liquid sales		38,271		48,539		(10,268	)

Operating expenses:
Gathering, transportation and processing		—		18,552		(18,552	)
Net income	$	12,324	$	12,324	$	—

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 New York Mercantile Exchange (“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 natural gas liquid 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’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 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For the Company’s natural gas and NGL sales contracts that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606-10-50-14(A) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

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 $29.5 million as of June 30, 2018 which represent this unconditional right to receive payment.

Prior Period Performance Obligations

To record revenues for oil, natural gas and natural gas liquid sales, 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 six months ended June 30, 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

Basis of Presentation and Significant Accounting Policies (Policies)

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Accounting Policies [Abstract]

Use of Estimates

Use of Estimates

Revenue Recognition

Revenue Recognition

Business Combinations

Business Combinations

Oil and Natural Gas Properties

Oil and Natural Gas Properties

Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property.

Impairment of Oil and Natural Gas Properties

Impairment of Oil and Natural Gas Properties

Costs of expired or relinquished leases are charged against the valuation allowance.

Drilling Advances

Drilling Advances

Asset Retirement Obligation

Asset Retirement Obligation

Derivative Instruments

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.

Cash and Cash Equivalents

Cash and Cash Equivalents

Accounts Receivable

Accounts Receivable

Deferred Financing Costs

Deferred Financing Costs

Equity-Based Compensation

Equity-Based Compensation

Comprehensive Income

Comprehensive Income

The Company has no elements of comprehensive income other than net income.

Concentrations of Credit Risk

Concentrations of Credit Risk

For the years ended December 31, 2017, 2016, and 2015, the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues:


	Year Ended December 31,
	2017			2016			2015
Sunoco Inc.		40	%		55	%		61	%
EnLink Oklahoma Gas Processing, LP		39	%		31	%		*
Cimarex Energy Company		*			*			14	%

*	Revenue from customer was less than 10% in this year

Fair Value Measurements

Fair Value Measurements

Level 1— Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets 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.

Commitments and Contingencies

Commitments and Contingencies

Earnings per Unit

Earnings per Unit

Income Taxes

Income Taxes

Risks and Uncertainties

Risks and Uncertainties

Recently Issued Accounting Standards

Recently Adopted 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), 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.

Recent Accounting Standards Issued Not Yet Adopted

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). 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. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company enters into lease agreements to support its operations, such as office space, vehicles, and drilling rigs. This ASU will not impact the accounting or financial presentation of the Company’s mineral leases. The Company is evaluating the impact of the adoption of this guidance on its financial statements.

Recently Adopted Accounting Standards

In January 2017, the Company adopted Accounting Standards Update (“ASU”) 2016-09, Compensation – Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting. ASU 2016-09 changes several aspects of how companies account for share-based payments, including the accounting for income taxes when awards vest or are settled, statutory withholding requirements and forfeitures. As a result of adoption, the Company will reflect forfeitures of share-based payments in the period forfeitures occur.

In September 2015, the Financial Accounting Standards Board (“FASB”) issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”),which requires the acquirer in a business combination to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The standard is effective for private entities for fiscal years beginning after December 15, 2016, and interim periods within fiscal years beginning after December 15, 2017. The Company adopted this ASU effective January 2017. Adoption of ASU 2015-16 in 2017 did not have an impact on the Company’s financial statements.

Recent Accounting Standards Issued Not Yet Adopted

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This update 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. The standard will be effective for fiscal years beginning after December 15, 2017, including interim reporting periods within those fiscal years, with early application permitted. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is currently evaluating the impact of this standard on its financial statements and related disclosures. The Company plans to use the modified retrospective method.

In February 2016, the FASB issued ASU 2016-02, Leases. 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. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company enters into lease agreements to support its operations, such as office space, vehicles, and drilling rigs. This ASU will not impact the accounting or financial presentation of the Company’s mineral leases. The Company is evaluating the impact of the adoption of this guidance on its financial statements.

Interim Financial Statements

Interim Financial Statements

The accompanying condensed financial statements as of December 31, 2017 were derived from the audited financial statements contained in the Company’s 2017 annual financial report. The unaudited interim condensed financial statements for the six months ended June 30, 2018 and 2017 were prepared by the Company in accordance with the accounting policies stated in the audited financial statements included in its 2017 annual financial report. In the opinion of management, the Company’s unaudited condensed financial statements reflect all known adjustments necessary to fairly state the financial position of the Company and its results of operations and cash flows for such periods. All such adjustments are of a normal, recurring nature. Certain information and disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. These unaudited condensed financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Company’s 2017 annual financial report.

Basis of Presentation and Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Major Customers that Exceeded 10% of Total Oil, Natural Gas and NGL Revenues

For the years ended December 31, 2017, 2016, and 2015, the Company had the following major customers that exceeded 10% of total oil, natural gas and NGL revenues:


	Year Ended December 31,
	2017			2016			2015
Sunoco Inc.		40	%		55	%		61	%
EnLink Oklahoma Gas Processing, LP		39	%		31	%		*
Cimarex Energy Company		*			*			14	%

*	Revenue from customer was less than 10% in this year

Acquisitions and Divestitures (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

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

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

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

Other 2016 Acquisitions


Consideration given
Total cash consideration	$	8,854

Allocation of purchase price
Proved oil and natural gas properties		1,128
Unproved oil and natural gas properties		7,774

Total oil and natural gas properties acquired		8,902
Asset retirement obligations		(48	)

Total fair value of net assets acquired	$	8,854

Schedule of Supplemental Proforma 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.


	Six Months Ended June 30, 2018
	(in thousands)
Revenue	$	101,474
Net income	$	38,201


	(Unaudited)
	Year Ended December 31,
	2017		2016		2015
	(in thousands)
Revenue	$	215,588	$	90,238	$	28,139
Net income	$	44,269	$	26,378	$	6,299

Supplemental Information on Oil, Natural Gas, and NGL Producing Activities (Unaudited) (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities

The Company’s oil and natural gas properties are in the continental United States. The oil and natural gas properties include the following:


	June 30, 2018			December 31, 2017
	(in thousands)
Oil and natural gas properties
Proved	$	1,068,937		$	750,492
Unproved		1,118,549			1,126,459
Less: accumulated depreciation, depletion, amortization and impairment		(137,564	)		(78,307	)

Oil and natural gas properties, net	$	2,049,922		$	1,798,644

The oil and natural gas properties includes the following:


	December 31,
	2017			2016
	(in thousands)
Oil and natural gas properties
Proved	$	750,492		$	184,376
Unproved		1,126,459			141,004
Less: accumulated depreciation, depletion, amortization and impairment		(78,307	)		(27,002	)

Oil and natural gas properties, net	$	1,798,644		$	298,378

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:


	Year Ended December 31,
	2017		2016		2015
	(in thousands)
Acquisition costs of properties:
Proved properties	$	214,647	$	1,079	$	2,291
Unproved properties		1,018,978		93,705		42,266
Exploratory		8,538		—		—
Development costs		390,991		152,284		24,446

Costs incurred	$	1,633,154	$	247,068	$	69,003

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities

The following table sets forth proved reserves during the periods indicated:


	Oil (mbbl)			Natural Gas (mmcf)			NGLs (mbbl)			Total (Mboe)
Proved reserves at December 31, 2014		81			1,798			38			419
Purchase of reserves		45			608			14			160
Extensions and discoveries		279			6,504			632			1,995
Revisions of previous estimates		79			41			42			128
Production		(97	)		(434	)		(48	)		(217	)

Proved reserves at December 31, 2015		387			8,517			678			2,484
Purchase 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
Purchase 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


	December 31,
	2017		2016		2015
Proved Developed Reserves
Oil (mbbl)		12,352		2,900		387
Natural gas (mmcf)		259,193		39,831		8,517
NGL (mbbl)		24,034		3,519		678

Total (mboe)		79,585		13,057		2,484

Proved Undeveloped Reserves
Oil (mbbl)		25,068		—		—
Natural gas (mmcf)		426,676		—		—
NGL (mbbl)		55,544		—		—

Total (mboe)		151,724		—		—

Total Proved Reserves
Oil (mbbl)		37,420		2,900		387
Natural gas (mmcf)		685,869		39,831		8,517
NGL (mbbl)		79,578		3,519		678

Total (mboe)		231,309		13,057		2,484

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, 2017, 2016 and 2015:


	For the Years Ended December 31,
	2017		2016		2015
	(in thousands)
Oil, natural gas, and NGL sales	$	166,385	$	54,965	$	5,685
Production expenses		16,872		5,090		549
Gathering, transportation and processing		18,602		5,920		273
Production taxes		3,685		1,087		190
Exploration expenses		28,154		—		121
Depreciation, depletion and amortization		36,979		24,909		2,060
Accretion of asset retirement obligations		364		87		31
Impairment		4,475		5,258		121

Results of operations	$	57,254	$	12,614	$	2,461

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.


	For the Years Ended December 31,
	2017			2016			2015
	(in thousands)
Future cash inflows	$	5,270,465		$	271,428		$	47,310
Future production costs		(1,664,724	)		(102,817	)		(21,289	)
Future development costs		(745,769	)		—			—
Future income tax expense (1)		—			—			—

Future net cash flows		2,859,972			168,611			26,021
Discount to present value at 10% annual rate		(1,664,303	)		(50,339	)		(7,111	)

Standardized measure of discounted future net cash flows	$	1,195,669		$	118,272		$	18,910

(1)	The Company is a limited liability company treated as a disregarded entity for income tax purposes.

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in the Company’s standardized measure of discounted future net cash flows relating from its proved oil, natural gas and NGL reserves:


	For the Years Ended December 31,
	2017			2016			2015
	(in thousands)
Standardized measure, beginning of year	$	118,272		$	18,910		$	6,500
Sales of oil, natural gas and NGLs produced, net of production costs		(124,526	)		(42,868	)		(4,673	)
Net changes in prices and production costs		36,233			18,256			(2,614	)
Extensions and discoveries, net of production and development costs		877,846			104,581			15,235
Changes in estimated future development costs		(17,970	)		—			—
Development costs incurred during the period that reduce future costs		148,505			—			—
Revisions of previous quantity estimates		(5,676	)		15,573			985
Purchases of reserves		279,026			462			1,428
Accretion of discount		11,827			1,891			650
Changes in production rates and other		(127,868	)		1,467			1,399

Standardized measure, end of year	$	1,195,669		$	118,272		$	18,910

Oil, Gas and NGL

Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities

Capitalized costs related to the Company’s oil, natural gas and NGL producing activities are summarized as follows:


	December 31,
	2017			2016
	(in thousands)
Oil and natural gas properties
Proved	$	750,492		$	184,376
Unproved		1,126,459			141,004
Less: accumulated depreciation, depletion, amortization and impairment		(78,307	)		(27,002	)

Oil and natural gas properties, net	$	1,798,644		$	298,378

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details

- Definition

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

+ References + Details

- Definition

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

+ References

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+ Details

Asset Retirement Obligations (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Reconciliation of Asset Retirement Obligations

The following is a reconciliation of the changes in the Company’s asset retirement obligation (“ARO”) for the six months ended June 30, 2018 (in thousands):


Asset retirement obligation, December 31, 2017			$10,769
Liabilities incurred or acquired			1,402
Revisions in estimated cash flows			—
Liabilities settled			—
Accretion expense			403

Asset retirement obligation, June 30, 2018			12,574
Less: current portion of obligations			416

Asset retirement obligation – long term			$12,158

The following is a reconciliation of the changes in the Company’s ARO for the years ended December 31, 2017 and 2016:


	Year Ended December 31,
	2017		2016
	(in thousands)
Asset retirement obligation, beginning balance	$	2,245	$	1,161
Liabilities incurred or acquired		8,118		1,054
Revisions in estimated cash flows		42		(16	)
Liabilities settled		—		(41	)
Accretion expense		364		87

Asset retirement obligation, ending balance		10,769		2,245
Less: current portion of obligations		—		3

	$	10,769	$	2,242

Long-Term Debt (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Debt Disclosure [Abstract]

Summary of Principal Maturities if the Company's Borrowings

Principal maturities of the Company’s borrowings, consistent of amounts outstanding under the 2017 Credit Facility, at December 31, 2017 are as follows (in thousands):


2018	$	—
2019		—
2020		—
2021		—
2022		85,339

	$	85,339

Summary of Pricing Grid of Applicable Margin for LIBOR Rate Loans Depending on the Utilization Level

The pricing grid below shows the applicable margin for LIBOR rate loans depending on the Utilization Level (as defined in the credit agreement) as of the date of this filing:


Utilization Level	Utilization	LIBOR Margin	Applicable Margin	Commitment Fee
Level I	< 25%	2.25%	1.25%	0.500%
Level II	³25% but <50%	2.50%	1.50%	0.500%
Level III	³50% but <75%	2.75%	1.75%	0.500%
Level IV	³75% but <90%	3.00%	2.00%	0.500%
Level V	³90%	3.25%	2.25%	0.500%

Schedule of Applicable Margin for LIBOR Rate Loans Depending on the Utilization Level

The pricing grid below shows the applicable margin for LIBOR rate loans depending on the Utilization Level (as defined in the credit agreement):


Utilization Level	Utilization	LIBOR Margin			Applicable Margin			Commitment Fee
Level I	< 25%		2.25	%		1.25	%		0.500	%
Level II	>25% but <50%		2.50	%		1.50	%		0.500	%
Level III	>50% but <75%		2.75	%		1.75	%		0.500	%
Level IV	>75% but <90%		3.00	%		2.00	%		0.500	%
Level V	> 90%		3.25	%		2.25	%		0.500	%

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

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+ Details

Derivative Instruments (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Company's Open Commodity Contracts

The following table represents the Company’s open commodity contracts at June 30, 2018:


	2018		2019		2020		Total
Oil fixed price swaps
Volume (Mbbl)		2,576		4,608		410		7,594
Weighted-average price per bbl	$	57.45	$	58.66	$	60.19	$	58.33
Natural gas fixed price swaps
Volume (Bbtu)		16,284		21,900		5,005		43,189
Weighted-average price per mmbtu	$	2.94	$	2.90	$	2.69	$	2.89
Natural gas basis swaps
Volume (Bbtu)		9,200		10,950		—		20,150
Weighted-average price per mmbtu	$	0.54	$	0.55	$	—	$	0.55

The following table represents the Company’s open commodity contracts at December 31, 2017:


	Total
Oil fixed price swaps
2018
Volume (bbl)		2,374,000
Weighted-average price per bbl	$	54.47
2019
Volume (bbl)		1,140,250
Weighted-average price per bbl	$	54.09
Natural gas fixed price swaps
2018
Volume (mmbtu)		16,440,000
Weighted-average price per mmbtu	$	3.00
2019
Volume (mmbtu)		10,950,000
Weighted-average price per mmbtu	$	2.97
Natural gas basis swaps
2018
Volume (mmbtu)		16,440,000
Weighted-average price per mmbtu	$	0.55
2019
Volume (mmbtu)		10,950,000
Weighted-average price per mmbtu	$	0.55

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

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+ Details

Fair Value Measurements (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements, Recurring Basis

The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of June 30, 2018 and December 31, 2017, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands):


	June 30, 2018
	Level 1		Level 2			Level 3		Gross Fair Value			Netting			Carrying Value
Assets
Current commodity derivatives	$	—	$	3,208		$	—	$	3,208		$	(2,927	)	$	281
Long-term commodity derivatives		—		2,064			—		2,064			(2,064	)		—

Total assets	$	—	$	5,272		$	—	$	5,272		$	(4,991	)	$	281

Liabilities
Current commodity derivatives	$	—	$	(52,351	)	$	—	$	(52,351	)	$	2,927		$	(49,424	)
Long-term commodity derivatives		—		(12,728	)		—		(12,728	)		2,064			(10,664	)

Total liabilities	$	—	$	(65,079	)	$	—	$	(65,079	)	$	4,991		$	(60,088	)


	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
Long-term 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	)
Long-term commodity derivatives		—		(2,557	)		—		(2,557	)		1,186			(1,371	)

Total liabilities	$	—	$	(14,540	)	$	—	$	(14,540	)	$	3,890		$	(10,650	)

The following table presents the amounts and classifications of the Company’s derivative assets and liabilities as of December 31, 2017, as well as the potential effect of netting arrangements on contracts with the same counterparty (in thousands):


	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
Long-term 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	)
Long-term commodity derivatives		—		(2,557	)		—		(2,557	)		1,186			(1,371	)

Total liabilities	$	—	$	(14,540	)	$	—	$	(14,540	)	$	3,890		$	(10,650	)

Equity (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Equity [Abstract]

Summary of Unit activity

The Company’s Unit activity for the six months ended June 30, 2018 is as follows (in thousands):


Issued and outstanding units, December 31, 2017			3,000,000
Units issued in exchange for contribution of oil and natural gas properties			38,500

Issued and outstanding units, June 30, 2018			3,038,500

The Company’s unit activity for the years ended December 31, 2017, 2016, and 2015 is as follows:


	Year Ended December 31,
	2017		2016		2015
	(in thousands)
Issued and outstanding units, beginning of the year ⁽¹⁾		1,500,000		813,021		165,771
Issuance of units to Citizen Members ⁽¹⁾		—		686,979		647,250
Units issued in exchange for contribution of oil and natural gas properties		1,500,000		—		—

Issued and outstanding units, end of the year		3,000,000		1,500,000		813,021

⁽¹⁾	Reflects exchange of Citizen units for Roan units on retroactive basis

Performance Share Units (Tables)

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Share-based Compensation [Abstract]

Summary of Information Related to PSUs

The following table summarizes information related to the total number of PSUs awarded as of June 30, 2018:


	Number of Units		Weighted Average Fair Value		Total Fair Value ($ in thousands)
Units outstanding at December 31, 2017		16,350,000	$	1.41	$	23,054
Units granted		6,325,000	$	2.05	$	12,966
Units vested		—	$	—	$	—

Units outstanding at June 30, 2018		22,675,000	$	1.59	$	36,020

The following table summarizes information related to the Company’s PSU awards:


	Number of Units		Weighted Average Fair Value		Total Fair Value ($ in thousands)
Units outstanding at December 31, 2016		—	$	—	$	—
Units granted		16,350,000	$	1.41	$	23,054
Units vested		—	$	—	$	—

Units outstanding at December 31, 2017		16,350,000	$	1.41	$	23,054

Schedule of Assumptions Used to Determine Grand Date Fair Value and Associated Compensation Expense for PSU Awards Granted


Company enterprise value	$	4.56 billion
Equity volatility		34.0	%
Weighted average risk-free interest rate		1.96	%

The following assumptions were used for the Monte Carlo simulation model to determine the grant date fair value and associated compensation expense for the PSU awards granted in December 2017:


Company enterprise value	$	3.76 billion
Equity volatility		35.00	%
Weighted average risk-free interest rate		1.94	%

Revenue from Contracts with Customers (Tables)

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Schedule of New Accounting Pronouncements and Changes in Accounting Principles


	Six months ended June 30, 2018
In thousands	Under ASC 606		Under ASC 605		Increase/ (decrease)
Revenues:
Oil sales	$	122,369	$	122,369	$	—
Natural gas sales		30,897		39,181		(8,284	)
Natural gas liquid sales		38,271		48,539		(10,268	)

Operating expenses:
Gathering, transportation and processing		—		18,552		(18,552	)
Net income	$	12,324	$	12,324	$	—

Business and Organization - Additional information (Detail)	Aug. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Ownership percentage	50.00%

Basis of Presentation and Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Bad debt expense	$ 0	$ 0	$ 0
Reserve for bad debt	0	$ 0
Provision for income tax	$ 0

Basis of Presentation and Significant Accounting Policies - Major Customers that Exceeded 10% of Total Oil, Natural Gas and NGL Revenues (Detail) - Customer Concentration Risk - Sales Revenue, Net

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Sunoco Inc.

Concentration risk percentage

40.00%

55.00%

61.00%

EnLink Oklahoma Gas Processing, LP

Concentration risk percentage

39.00%

31.00%

^[1]

Cimarex Energy Company

Concentration risk percentage

^[1]

14.00%

[1]	Revenue from customer was less than 10% in this year

Acquisitions and Divestitures - Additional Information (Detail) $ in Thousands			1 Months Ended	6 Months Ended		12 Months Ended
	Aug. 31, 2017 USD ($)	Apr. 14, 2016 USD ($) a	Mar. 31, 2018 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Dec. 31, 2017 USD ($) a	Dec. 31, 2016 USD ($) a	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Ownership percentage	50.00%
Revenues				$ 127,321	$ 61,269	$ 159,588	$ 54,965	$ 5,685
Total operating income				$ 15,210	$ 18,304	$ 19,905	$ 7,033	387
Area acquired in leasehold property \| a		5,791				23,400	62,461
Cash consideration for interest acquired in leasehold property		$ 8,900	$ 22,900			$ 49,700	$ 137,600
Effective date for acquisition		Feb. 01, 2016
Cost incurred for acquisition of acreage						1,018,978	$ 93,705	$ 42,266
Accounts Payable and Accrued Liabilities
Business Acquisition [Line Items]
Cost incurred for acquisition of acreage						63,000
Linn Acquisition
Business Acquisition [Line Items]
Ownership percentage	50.00%
Equity units issued in acquisition	$ 1,281,743
Revenues						34,100
Total operating income						$ 26,600

Acquisitions and Divestitures - Schedule of Assumptions to Determine Fair value of the Oil and Natural Gas (Detail)

Aug. 31, 2017

Measurement Input, Discount Rate

Business Acquisition [Line Items]

Acquisition, measurement input

0.0950

Measurement Input Reserve Risk Factor | Minimum

Business Acquisition [Line Items]

Acquisition, measurement input

0.35

^[1]

Measurement Input Reserve Risk Factor | Maximum

Business Acquisition [Line Items]

Acquisition, measurement input

1.00

^[1]

Measurement Input, Price Escalation

Business Acquisition [Line Items]

Acquisition, measurement input

0.0200

^[2]

Oil (mbbl) | Measurement Input, Appraised Value

Business Acquisition [Line Items]

Acquisition, measurement input description

three years NYMEX WTI forward curve

Natural Gas (mmcf) | Measurement Input, Appraised Value

Business Acquisition [Line Items]

Acquisition, measurement input description

three years NYMEX Henry Hub forward curve

NGLs (mbbl) | Measurement Input, Appraised Value

Business Acquisition [Line Items]

Acquisition, measurement input description

39% of oil price

[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

Acquisitions and Divestitures - Schedule of Assumptions to Determine Fair value of the Oil and Natural Gas (Parenthetical) (Detail) - Measurement Input Reserve Risk Factor	Aug. 31, 2017
Possible Reserves
Business Acquisition [Line Items]
Percentage of risk factor	35.00%
Probable Reserve
Business Acquisition [Line Items]
Percentage of risk factor	75.00%
Proved Undeveloped Reserves
Business Acquisition [Line Items]
Percentage of risk factor	90.00%

Acquisitions and Divestitures - Summary of Purchase Price and Allocation of Fair value of Assets Acquired And Liabilities Assumed (Detail) - USD ($) $ in Thousands			1 Months Ended	12 Months Ended
	Aug. 31, 2017	Apr. 14, 2016	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Consideration given
Total cash consideration		$ 8,900	$ 22,900	$ 49,700	$ 137,600
Linn Acquisition
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
Linn Acquisition \| Proved Oil and Gas Reserves
Allocation of purchase price
Properties	214,647
Linn Acquisition \| Unproved Oil and Gas Reserves
Allocation of purchase price
Properties	$ 1,086,600
Other 2016 acquisitions
Consideration given
Total cash consideration		8,854
Allocation of purchase price
Total assets acquired		8,902
Asset retirement obligations		(48)
Total fair value of net assets acquired		8,854
Other 2016 acquisitions \| Proved Oil and Gas Reserves
Allocation of purchase price
Properties		1,128
Other 2016 acquisitions \| Unproved Oil and Gas Reserves
Allocation of purchase price
Properties		$ 7,774

Acquisitions and Divestitures - Schedule of Supplemental Proforma Results of Operations (Detail) - Linn Acquisition - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition, Pro Forma Information [Line Items]
Revenue	$ 101,474	$ 215,588	$ 90,238	$ 28,139
Net income	$ 38,201	$ 44,269	$ 26,378	$ 6,299

Oil and Natural Gas Properties - Schedule of Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Property [Abstract]
Proved	$ 1,068,937	$ 750,492	$ 184,376
Unproved	1,118,549	1,126,459	141,004
Less: accumulated depreciation, depletion, amortization and impairment	(137,564)	(78,307)	(27,002)
Oil and natural gas properties, net	$ 2,049,922	$ 1,798,644	$ 298,378

Oil and Natural Gas Properties - Additional Information (Detail) - USD ($)	6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploratory well costs			$ 0	$ 0
Exploratory dry hole costs			1,300,000	0	$ 0
Abandonment and impairment expense			4,500,000	5,300,000	0
Impaired expense	$ 0	$ 200,000	$ 0	$ 0	$ 0
Depletion expense on capitalized oil and natural gas properties	45,700,000	11,300,000
Exploration Expense
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Amortization expense	$ 14,500,000	$ 0

Asset Retirement Obligations - Schedule of Reconciliation of Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, beginning balance	$ 10,769	$ 2,245	$ 1,161
Liabilities incurred or acquired	1,402	8,118	1,054
Revisions in estimated cash flows		42	(16)
Liabilities settled			(41)
Accretion expense	403	364	87	$ 31
Asset retirement obligation, ending balance	12,574	10,769	2,245	$ 1,161
Less: current portion of obligations	416		3
Asset retirement obligation - long term	$ 12,158	$ 10,769	$ 2,242

Asset Retirement Obligations - Additional Information (Detail) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Changes in Asset Retirement Obligations [Line Items]
Liabilities incurred or acquired	$ 1,402	$ 8,118	$ 1,054
Linn Acquisition
Reconciliation of Changes in Asset Retirement Obligations [Line Items]
Liabilities incurred or acquired		$ 7,500

Long-Term Debt - Additional Information (Detail) - USD ($)			1 Months Ended	6 Months Ended	12 Months Ended
	Aug. 31, 2017	Apr. 19, 2017	Sep. 30, 2016	Jun. 30, 2018	Dec. 31, 2017	Apr. 30, 2018	Nov. 30, 2017	Sep. 30, 2017	Sep. 05, 2017	Dec. 31, 2016	Oct. 20, 2016	Sep. 01, 2016
Line of Credit Facility [Line Items]
Line of credit facility, covenants terms				The Company is limited from hedging in excess of 80% of its projected production per its internal forecast for the next two years. For periods after the next two years, the limit is based on proved reserves per the most recent reserve report.	The Company is limited from hedging in excess of 85% of its future proved production for the next eight quarters per its most recent 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.
Maximum
Line of Credit Facility [Line Items]
Percentage of projected production hedged				80.00%	85.00%
2016 Credit Facility
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity											$ 35,000,000	$ 20,000,000
Line of credit facility, outstanding borrowings										$ 20,000,000
Line of credit facility, unused capacity, commitment fee percentage			0.25%
Line of credit facility,Interest rate										2.37%
Citizen 2017 Credit Facility
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity		$ 500,000,000
Line of credit facility, expiration period		2 years
Line of credit facility, current borrowing capacity		$ 82,500,000
Outstanding borrowing, amount repaid	$ 20,300,000
2017 Credit Facility
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity								$ 750,000,000	$ 750,000,000
Line of credit facility, outstanding borrowings				$ 284,600,000	$ 85,300,000
Line of credit facility, unused capacity, commitment fee percentage				0.50%	0.50%
Line of credit facility,Interest rate					4.03%
Line of credit facility, current borrowing capacity						$ 425,000,000	$ 275,000,000	$ 200,000,000	$ 200,000,000
Line of credit facility, maturity date				Sep. 05, 2022	Sep. 05, 2022
2017 Credit Facility \| Maximum
Line of Credit Facility [Line Items]
Debt to EBITDAX Ratio				400.00%
Current Ratio					100.00%
2017 Credit Facility \| Minimum
Line of Credit Facility [Line Items]
Debt to EBITDAX Ratio					400.00%
Current Ratio				100.00%

Long-Term Debt - Summary of Principal Maturities of Borrowings (Detail) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
2018		$ 0
2019		0
2020		0
2021		0
2022		85,339
Long-term debt, total	$ 284,639	$ 85,339	$ 20,000

Schedule of Applicable Margin for LIBOR Rate Loans Depending on the Utilization Level (Detail) - 2017 Credit Facility	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Commitment Fee	0.50%	0.50%
Level I
Line of Credit Facility [Line Items]
Utilization	< 25%	< 25%
Commitment Fee	0.50%	0.50%
Level II
Line of Credit Facility [Line Items]
Utilization	>25% but <50%	³25% but <50%
Commitment Fee	0.50%	0.50%
Level III
Line of Credit Facility [Line Items]
Utilization	>50% but <75%	³50% but <75%
Commitment Fee	0.50%	0.50%
Level IV
Line of Credit Facility [Line Items]
Utilization	>75% but <90%	³75% but <90%
Commitment Fee	0.50%	0.50%
Level V
Line of Credit Facility [Line Items]
Utilization	> 90%	³90%
Commitment Fee	0.50%	0.50%
LIBOR \| Level I
Line of Credit Facility [Line Items]
Line of credit Margin	2.25%	2.25%
LIBOR \| Level II
Line of Credit Facility [Line Items]
Line of credit Margin	2.50%	2.50%
LIBOR \| Level III
Line of Credit Facility [Line Items]
Line of credit Margin	2.75%	2.75%
LIBOR \| Level IV
Line of Credit Facility [Line Items]
Line of credit Margin	3.00%	3.00%
LIBOR \| Level V
Line of Credit Facility [Line Items]
Line of credit Margin	3.25%	3.25%
Applicable \| Level I
Line of Credit Facility [Line Items]
Line of credit Margin	1.25%	1.25%
Applicable \| Level II
Line of Credit Facility [Line Items]
Line of credit Margin	1.50%	1.50%
Applicable \| Level III
Line of Credit Facility [Line Items]
Line of credit Margin	1.75%	1.75%
Applicable \| Level IV
Line of Credit Facility [Line Items]
Line of credit Margin	2.00%	2.00%
Applicable \| Level V
Line of Credit Facility [Line Items]
Line of credit Margin	2.25%	2.25%

Derivative Instrument - Schedule of Company's Open Commodity Contracts (Detail) - Fixed price/basis swaps	Jun. 30, 2018 MBbls MMBTU $ / bbl $ / MMBTU	Dec. 31, 2017 MMBTU bbl $ / bbl $ / MMBTU
Crude oil commodity contracts
Derivative Instruments [Line Items]
Volume \| MBbls	7,594
Weighted-average price per bbl/mmbtu \| $ / bbl	58.33
Natural Gas Commodity Contracts
Derivative Instruments [Line Items]
Volume \| MMBTU	43,189,000
Weighted-average price per bbl/mmbtu \| $ / MMBTU	2.89
Natural Gas Basis Commodity Contracts
Derivative Instruments [Line Items]
Volume \| MMBTU	20,150,000
Weighted-average price per bbl/mmbtu \| $ / MMBTU	0.55
2018 \| Crude oil commodity contracts
Derivative Instruments [Line Items]
Volume	2,576	2,374,000
Weighted-average price per bbl/mmbtu \| $ / bbl	57.45	54.47
2018 \| Natural Gas Commodity Contracts
Derivative Instruments [Line Items]
Volume \| MMBTU	16,284,000	16,440,000
Weighted-average price per bbl/mmbtu \| $ / MMBTU	2.94	3.00
2018 \| Natural Gas Basis Commodity Contracts
Derivative Instruments [Line Items]
Volume \| MMBTU	9,200,000	16,440,000
Weighted-average price per bbl/mmbtu \| $ / MMBTU	0.54	0.55
2019 \| Crude oil commodity contracts
Derivative Instruments [Line Items]
Volume	4,608	1,140,250
Weighted-average price per bbl/mmbtu \| $ / bbl	58.66	54.09
2019 \| Natural Gas Commodity Contracts
Derivative Instruments [Line Items]
Volume \| MMBTU	21,900,000	10,950,000
Weighted-average price per bbl/mmbtu \| $ / MMBTU	2.90	2.97
2019 \| Natural Gas Basis Commodity Contracts
Derivative Instruments [Line Items]
Volume \| MMBTU	10,950,000	10,950,000
Weighted-average price per bbl/mmbtu \| $ / MMBTU	0.55	0.55
2020 \| Crude oil commodity contracts
Derivative Instruments [Line Items]
Volume \| MBbls	410
Weighted-average price per bbl/mmbtu \| $ / bbl	60.19
2020 \| Natural Gas Commodity Contracts
Derivative Instruments [Line Items]
Volume \| MMBTU	5,005,000
Weighted-average price per bbl/mmbtu \| $ / MMBTU	2.69

Derivative Instrument - Additional Information (Detail) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net gain (loss) on settled derivatives	$ (13,900)	$ 100	$ 2,700
Net gain (loss) on derivatives	$ (64,216)	$ 2,254	$ (6,797)	$ 0	$ 0

Equity - Additional Information (Detail)

1 Months Ended

6 Months Ended

8 Months Ended

12 Months Ended

Mar. 31, 2018

Aug. 31, 2017

Class

Jun. 30, 2018

USD ($)

Class

Aug. 31, 2017

Class

Dec. 31, 2017

USD ($)

Class

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

^[1]

Capital Unit [Line Items]

Units authorized

10,000,000,000

Units issued

3,038,500,000

3,000,000,000

Units outstanding

3,038,500,000

3,000,000,000

1,500,000,000

^[1]

813,021,000

^[1]

165,771,000

Number of membership interests outstanding | Class

Number of unit issued

38,500,000

1,500,000,000

Equity Method Investment, Ownership Percentage

50.00%

Contribution amount | $

$ 95,600,000

$ 169,000,000

$ 82,800,000

Deemed distribution | $

$ 85,600,000

Linn Energy Holdings

Capital Unit [Line Items]

Number of unit issued

19,200,000

1,500,000,000

Equity Method Investment, Ownership Percentage

50.00%

Citizen Energy LLC

Capital Unit [Line Items]

Number of membership interests outstanding | Class

Number of unit issued

19,200,000

1,500,000,000

Equity Method Investment, Ownership Percentage

50.00%

Internal rate of return threshold of prior to distributions

9.00%

Citizen Energy LLC | Class A Units

Capital Unit [Line Items]

Number of unit issued and outstanding

1,398

Citizen Energy LLC | Class B Unit

Capital Unit [Line Items]

Compensation expense | $

$ 0

[1]	Reflects exchange of Citizen units for Roan units on retroactive basis

Equity - Summary of Unit Activity (Detail) - shares
shares in Thousands

6 Months Ended

12 Months Ended

Jun. 30, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Equity [Abstract]

Issued and outstanding units, beginning balance

3,000,000

1,500,000

^[1]

813,021

^[1]

165,771

^[1]

Issuance of units to Citizen Members

^[1]

686,979

647,250

Units issued in exchange for contribution of oil and natural gas properties

38,500

1,500,000

Issued and outstanding units, end balance

3,038,500

3,000,000

1,500,000

^[1]

813,021

^[1]

[1]	Reflects exchange of Citizen units for Roan units on retroactive basis

Performance Share Units - Additional Information (Detail) - USD ($) $ in Thousands		6 Months Ended	12 Months Ended
	Dec. 31, 2020	Jun. 30, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense		$ 5,127	$ 379
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units reserved for awards		105,000,000	105,000,000
Grant in period		6,325,000	16,350,000
Performance share description		Each vested PSU is exchangeable for one Unit of the Company.	Each vested PSU is exchangeable for one Unit of the Company.
Compensation expense		$ 5,100	$ 400
Unrecognized expense		$ 30,600	$ 22,700
Weighted average remaining period		2 years 6 months	3 years
Minimum \| Performance Shares \| Scenario, Forecast
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of award	0.00%
Maximum \| Performance Shares \| Scenario, Forecast
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of award	200.00%

Performance Share Units - Summary of Information Related to PSUs (Detail) - Performance Shares - USD ($) $ / shares in Units, $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units beginning balance	16,350,000
Number of units granted	6,325,000	16,350,000
Number of units vested	0	0
Number of units ending balance	22,675,000	16,350,000
Weighted average fair value beginning balance	$ 1.41
Weighted average fair value units granted	2.05	$ 1.41
Weighted average fair value units vested	0	0
Weighted average fair value ending balance	$ 1.59	$ 1.41
Total fair value beginning balance	$ 23,054
Total fair value units granted	12,966	$ 23,054
Total fair value units vested	0	0
Total fair value ending balance	$ 36,020	$ 23,054

Performance Share Units - Schedule of Assumptions Used to Determine the Grant Date Fair Value and Associated Compensation Expense (Detail) - Performance Shares - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Company enterprise value	$ 4,560	$ 3,760
Equity volatility	34.00%	35.00%
Weighted average risk-free interest rate	1.96%	1.94%

Transactions with Affiliates - Additional Information (Detail) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jun. 30, 2017
Related Party Transaction [Line Items]
Accounts payable-Affiliates		$ 13,102,000
Cost incurred for acquisition of acreage		1,018,978,000	$ 93,705,000	$ 42,266,000
Accounts receivable affiliates	$ 31,700,000
Working capital accounts	112,600,000
Additional acreage acquired		63,000,000
Blue Mountain Midstream LLC
Related Party Transaction [Line Items]
Oil, natural gas, and natural gas liquids sales - affiliates					$ 0
Accounts Payable and Accrued Liabilities
Related Party Transaction [Line Items]
Cost incurred for acquisition of acreage		63,000,000
Citizen Energy LLC \| Accounts Payable and Accrued Liabilities
Related Party Transaction [Line Items]
Accounts payable-Affiliates		46,500,000
Linn Energy Holdings \| Accounts Payable and Accrued Liabilities
Related Party Transaction [Line Items]
Accounts payable-Affiliates	26,300,000	55,500,000
Linn Energy Holdings and Citizen Energy LLC \| Revenue Suspense
Related Party Transaction [Line Items]
Accounts payable-Affiliates		19,000,000
Affiliates \| Oil and Gas
Related Party Transaction [Line Items]
Accounts Receivable - Oil, natural gas, and natural gas liquids sales - Affiliates		4,700,000
Revenue from Contract with Customer, Including Assessed Tax		8,000,000
Atlas LLC
Related Party Transaction [Line Items]
Charges related to services		2,300,000	2,000,000	$ 300,000
Accounts payable-Affiliates		0	$ 0
Management Services Agreement \| Citizen Energy LLC
Related Party Transaction [Line Items]
Accounts payable-Affiliates		46,500,000
Management Services Agreement \| Linn Energy Holdings
Related Party Transaction [Line Items]
Accounts payable-Affiliates		55,500,000
Management Services Agreement \| General and Administrative Expense
Related Party Transaction [Line Items]
Charges related to services	$ 10,000,000	$ 10,000,000

Commitments and Contingencies - Additional Information (Detail) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2018 Mcf $ / Mcf	Dec. 31, 2017 USD ($) Mcf $ / Mcf
Commitment And Contingencies [Line Items]
Environmental remediation costs recognized disclosure	At June 30, 2018, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.	At December 31, 2017, 2016 and 2015, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.
Volume delivery commitment	18,250,000	18,250,000
Delivery commitment period	2021-11	2021-11
Volume delivered	3,989,236	3,037,500
Delivery commitment term	In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees of $0.625 per mcf.	In the event that the Company is unable to meet this natural gas volume delivery commitment, it would incur deficiency fees of $0.625 per mcf.
Deficiency fees per unit \| $ / Mcf	0.625	0.625
Drilling Rig Commitments
Commitment And Contingencies [Line Items]
Drilling Commitment \| $		$ 5.1

Subsequent Events - Additional Information (Detail) $ in Millions	1 Months Ended
	Mar. 31, 2018 USD ($)
Subsequent Events [Abstract]
Cash Consideration paid for acquiring acreage	$ 22.9
Equity Issued Unit	$ 40.0

Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Acquisition costs of properties:
Proved properties	$ 214,647	$ 1,079	$ 2,291
Unproved properties	1,018,978	93,705	42,266
Exploratory	8,538
Development costs	390,991	152,284	24,446
Costs incurred	$ 1,633,154	$ 247,068	$ 69,003

Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Oil and natural gas properties
Proved	$ 750,492	$ 184,376
Unproved	1,126,459	141,004
Less: accumulated depreciation, depletion, amortization and impairment	(78,307)	(27,002)
Oil and natural gas properties, net	$ 1,798,644	$ 298,378

Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Detail)	12 Months Ended
	Dec. 31, 2017 MBoe MBbls MMcf	Dec. 31, 2016 MBoe MBbls MMcf	Dec. 31, 2015 MBoe MBbls MMcf
Reserve Quantities [Line Items]
Balance, beginning \| MBoe	13,057	2,484	419
Purchase of reserves \| MBoe	53,986	111	160
Extensions and discoveries \| MBoe	173,238	11,124	1,995
Revisions of previous estimates \| MBoe	(369)	1,687	128
Production \| MBoe	(8,603)	(2,350)	(217)
Balance, ending \| MBoe	231,309	13,057	2,484
Oil (mbbl)
Reserve Quantities [Line Items]
Balance, beginning	2,900	387	81
Purchase of reserves	9,843	22	45
Extensions and discoveries	30,554	2,632	279
Revisions of previous estimates	(3,583)	598	79
Production	(2,294)	(740)	(97)
Balance, ending	37,420	2,900	387
Natural Gas (mmcf)
Reserve Quantities [Line Items]
Balance, beginning \| MMcf	39,831	8,517	1,798
Purchase of reserves \| MMcf	163,638	333	608
Extensions and discoveries \| MMcf	486,510	33,218	6,504
Revisions of previous estimates \| MMcf	20,844	4,145	41
Production \| MMcf	(24,953)	(6,382)	(434)
Balance, ending \| MMcf	685,869	39,831	8,517
NGLs (mbbl)
Reserve Quantities [Line Items]
Balance, beginning	3,519	678	38
Purchase of reserves	16,870	33	14
Extensions and discoveries	61,599	2,956	632
Revisions of previous estimates	(260)	398	42
Production	(2,150)	(546)	(48)
Balance, ending	79,578	3,519	678

Supplemental Information On Oil, Natural Gas, And NGL Producing Activities - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017 a MBoe $ / bbl $ / MMBTU	Dec. 31, 2016 a MBoe $ / bbl $ / MMBTU	Dec. 31, 2015 MBoe $ / bbl $ / MMBTU	Apr. 14, 2016 a	Dec. 31, 2014 MBoe
Reserve Quantities [Line Items]
Total proved reserves \| MBoe	231,309	13,057	2,484		419
Proved reserves \| MBoe	79,585	13,057	2,484
Unproved leashold acquired, net \| a	23,400	62,461		5,791
Oil (mbbl)
Reserve Quantities [Line Items]
Prices used in computing the Company's reserves \| $ / bbl	51.34	42.64	50.16
Natural Gas (mmcf)
Reserve Quantities [Line Items]
Prices used in computing the Company's reserves \| $ / MMBTU	2.98	2.48	2.59
NGLs (mbbl)
Reserve Quantities [Line Items]
Prices used in computing the Company's reserves \| $ / bbl	19.00	15.26	17.53

Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Schedule of Estimated Quantities of Proved Developed and Proved Undeveloped ("PUD") Oil, Natural Gas and NGL Reserves of the Company (Detail)	Dec. 31, 2017 MBoe MBbls MMcf	Dec. 31, 2016 MBoe MBbls MMcf	Dec. 31, 2015 MBoe MBbls MMcf	Dec. 31, 2014 MBoe MBbls MMcf
Reserve Quantities [Line Items]
Total Proved Developed Reserves \| MBoe	79,585	13,057	2,484
Total Proved Undeveloped Reserves \| MBoe	151,724
Total proved reserves \| MBoe	231,309	13,057	2,484	419
Oil (mbbl)
Reserve Quantities [Line Items]
Proved Developed Reserves	12,352	2,900	387
Proved Undeveloped Reserves	25,068
Proved Reserves	37,420	2,900	387	81
Natural Gas (mmcf)
Reserve Quantities [Line Items]
Proved Developed Reserves \| MMcf	259,193	39,831	8,517
Proved Undeveloped Reserves \| MMcf	426,676
Proved Reserves \| MMcf	685,869	39,831	8,517	1,798
NGLs (mbbl)
Reserve Quantities [Line Items]
Proved Developed Reserves	24,034	3,519	678
Proved Undeveloped Reserves	55,544
Proved Reserves	79,578	3,519	678	38

Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Results of Operations for Oil and Gas Producing Activities (Detail) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Results of Operations, Income before Income Taxes [Abstract]
Oil, natural gas, and NGL sales			$ 166,385	$ 54,965	$ 5,685
Production expenses	$ 15,374	$ 6,114	16,872	5,090	549
Gathering, transportation and processing	$ 0	$ 6,470	18,602	5,920	273
Production taxes			3,685	1,087	190
Exploration expenses			28,154		121
Depreciation, depletion and amortization			36,979	24,909	2,060
Accretion of asset retirement obligations			364	87	31
Impairment			4,475	5,258	121
Results of operations			$ 57,254	$ 12,614	$ 2,461

Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Summary of Company's Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($)
$ in Thousands

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Abstract]

Future cash inflows

$ 5,270,465

$ 271,428

$ 47,310

Future production costs

(1,664,724)

(102,817)

(21,289)

Future development costs

(745,769)

Future income tax expense

^[1]

Future net cash flows

2,859,972

168,611

26,021

Discount to present value at 10% annual rate

(1,664,303)

(50,339)

(7,111)

Standardized measure of discounted future net cash flows

$ 1,195,669

$ 118,272

$ 18,910

$ 6,500

[1]	The Company is a limited liability company treated as a disregarded entity for income tax purposes.

Supplemental Information on Oil, Natural Gas, and NGL Producing Activities - Summary of Company's Standardized Measure of Discounted Future Net Cash Flows - Supplemental Information on Oil, Natural Gas, and NGL Producing Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Principal Sources of Change in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Abstract]
Standardized measure, beginning of year	$ 118,272	$ 18,910	$ 6,500
Sales of oil, natural gas and NGLs produced, net of production costs	(124,526)	(42,868)	(4,673)
Net changes in prices and production costs	36,233	18,256	(2,614)
Extensions and discoveries, net of production and development costs	877,846	104,581	15,235
Changes in estimated future development costs	(17,970)
Development costs incurred during the period that reduce future costs	148,505
Revisions of previous quantity estimates	(5,676)	15,573	985
Purchases of reserves	279,026	462	1,428
Accretion of discount	11,827	1,891	650
Changes in production rates and other	(127,868)	1,467	1,399
Standardized measure, end of year	$ 1,195,669	$ 118,272	$ 18,910

Revenue from Contracts with Customers - Summary of New Accounting Pronouncements and Changes in Accounting Principles (Detail) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating expenses:
Gathering, transportation and processing	$ 0	$ 6,470	$ 18,602	$ 5,920	$ 273
Net income	12,324	18,127	18,457	6,947	391
Oil and Condensate
Revenues:
Revenue from Contract with Customer, Including Assessed Tax	122,369	$ 29,001	$ 76,876	$ 30,565	$ 3,972
Natural gas sales Including Related Party [Member]
Revenues:
Revenue from Contract with Customer, Including Assessed Tax	30,897
Natural gas liquid sales Including Related Party [Member]
Revenues:
Revenue from Contract with Customer, Including Assessed Tax	38,271
Accounting Standards Update 2014-09 \| Calculated under Revenue Guidance in Effect before Topic 606
Operating expenses:
Gathering, transportation and processing	18,552
Net income	12,324
Accounting Standards Update 2014-09 \| Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Operating expenses:
Gathering, transportation and processing	(18,552)
Accounting Standards Update 2014-09 \| Oil and Condensate \| Calculated under Revenue Guidance in Effect before Topic 606
Revenues:
Revenue from Contract with Customer, Including Assessed Tax	122,369
Accounting Standards Update 2014-09 \| Natural gas sales Including Related Party [Member] \| Calculated under Revenue Guidance in Effect before Topic 606
Revenues:
Revenue from Contract with Customer, Including Assessed Tax	39,181
Accounting Standards Update 2014-09 \| Natural gas sales Including Related Party [Member] \| Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Revenues:
Revenue from Contract with Customer, Including Assessed Tax	(8,284)
Accounting Standards Update 2014-09 \| Natural gas liquid sales Including Related Party [Member] \| Calculated under Revenue Guidance in Effect before Topic 606
Revenues:
Revenue from Contract with Customer, Including Assessed Tax	48,539
Accounting Standards Update 2014-09 \| Natural gas liquid sales Including Related Party [Member] \| Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Revenues:
Revenue from Contract with Customer, Including Assessed Tax	$ (10,268)

Revenue from Contracts with Customers - Additional Information (Detail) $ in Millions	Jun. 30, 2018 USD ($)
Revenue from Contract with Customer [Abstract]
Contract with customer accounts receivable	$ 29.5

Fair Value Measurements - Additional Information (Detail)	Jun. 30, 2018 USD ($)
Fair Value Measurements Textuals [Abstract]
Fair value transfer	$ 0

Fair Value Instrument - Summary of Classifications of the Company's Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Assets
Current commodity derivatives	$ 281	$ 152
Long-term commodity derivatives		996
Total assets	281	1,148
Liabilities
Current commodity derivatives	49,424	9,279
Long-term commodity derivatives	10,664	1,371
Total liabilities	60,088	10,650
Netting
Assets
Current commodity derivatives	(2,927)	(2,704)
Long-term commodity derivatives	(2,064)	(1,186)
Total assets	(4,991)	(3,890)
Liabilities
Current commodity derivatives	2,927	2,704
Long-term commodity derivatives	2,064	1,186
Total liabilities	4,991	3,890
Fair Value, Measurements, Recurring
Assets
Current commodity derivatives	3,208	2,856
Long-term commodity derivatives	2,064	2,182
Total assets	5,272	5,038
Liabilities
Current commodity derivatives	52,351	11,983
Long-term commodity derivatives	12,728	2,557
Total liabilities	65,079	14,540
Fair Value, Measurements, Recurring \| Level 2
Assets
Current commodity derivatives	3,208	2,856
Long-term commodity derivatives	2,064	2,182
Total assets	5,272	5,038
Liabilities
Current commodity derivatives	52,351	11,983
Long-term commodity derivatives	12,728	2,557
Total liabilities	$ 65,079	$ 14,540