RSP Permian (RSPP) 10-K 27 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2017	Feb. 23, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	RSP Permian, Inc.
Entity Central Index Key	1,588,216
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		159,441,447
Entity Voluntary Filer	No
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Public Float			$ 4.3

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 38,102	$ 690,776
Accounts receivable	111,157	73,671
Derivative instruments	64	11,815
Total current assets	149,323	776,262
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method	6,802,517	4,645,781
Accumulated depletion	(778,596)	(554,419)
Total oil and natural gas properties, net	6,023,921	4,091,362
Other property and equipment, net	56,798	38,273
Total property, plant and equipment	6,080,719	4,129,635
OTHER LONG-TERM ASSETS
Derivative instruments	37	0
Restricted cash	0	152
Other long-term assets	40,107	90,378
Total other long-term assets	40,144	90,530
TOTAL ASSETS	6,270,186	4,996,427
CURRENT LIABILITIES
Accounts payable	26,758	14,074
Accrued expenses	119,439	53,192
Interest payable	23,798	12,142
Derivative instruments	36,566	28,861
Total current liabilities	206,561	108,269
LONG-TERM LIABILITIES
Other long term liabilities	15,849	15,916
Derivative instruments	5,722	0
Long-term debt	1,509,128	1,132,275
Deferred taxes	210,568	322,655
Total long-term liabilities	1,741,267	1,470,846
Total liabilities	1,947,828	1,579,115
STOCKHOLDERS’ EQUITY
Common stock, $.01 par value; 300,000,000 shares authorized, 158,596,324 shares issued and outstanding at December 31, 2017; 141,923,591 shares issued and outstanding at December 31, 2016	1,586	1,419
Additional paid-in capital	4,128,659	3,455,916
Accumulated earnings (deficit)	192,113	(40,023)
Total stockholders’ equity	4,322,358	3,416,728
Total stockholders’ equity		3,417,312
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$ 6,270,186	$ 4,996,427

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	300,000,000	300,000,000
Common stock, shares issued (in shares)	158,596,324	141,923,591
Common stock, shares outstanding (in shares)	158,596,324	141,923,591

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
REVENUES
Oil sales	$ 704,838	$ 321,588	$ 263,286
Natural gas sales	36,206	13,945	10,517
NGL sales	62,664	18,324	10,189
Total revenues	803,708	353,857	283,992
OPERATING EXPENSES
Lease operating expenses	122,893	57,778	53,124
Production and ad valorem taxes	48,908	21,615	19,995
Depreciation, depletion and amortization	279,711	194,360	154,039
Asset retirement obligation accretion	605	472	336
Impairments of oil and natural gas properties	59,077	4,901	34,269
Exploration expenses	7,771	1,093	2,380
General and administrative expenses	47,408	36,170	27,317
Acquisition costs	4,525	6,374	0
Total operating expenses	570,898	322,763	291,460
Loss on sale of assets	0	0	306
OPERATING INCOME (EXPENSE)	232,810	31,094	(7,774)
OTHER INCOME (EXPENSE)
Other income, net	3,436	1,833	469
Net gain (loss) on derivative instruments	(39,279)	(23,760)	20,906
Interest expense	(82,459)	(52,724)	(43,538)
Total other expense	(118,302)	(74,651)	(22,163)
INCOME (LOSS) BEFORE TAXES	114,508	(43,557)	(29,937)
INCOME TAX BENEFIT	117,628	18,706	11,683
NET INCOME (LOSS)	$ 232,136	$ (24,851)	$ (18,254)
Earnings (loss) per common share:
Basic (in dollars per share)	$ 1.50	$ (0.23)	$ (0.21)
Diluted (in dollars per share)	$ 1.49	$ (0.23)	$ (0.21)
Weighted average shares outstanding:
Basic (in shares)	154,162	107,324	86,770
Diluted (in shares)	155,526	107,324	86,770

Consolidated Statements of Chan

Consolidated Statements of Changes in Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Accumulated Earnings (Deficit)
Beginning balance (in shares) at Dec. 31, 2014		77,904,000
Beginning balance at Dec. 31, 2014	$ 1,325,771	$ 779	$ 1,322,494	$ 2,498
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock issued during the period (in shares)		22,540,000
Stock issued during the period	543,524	$ 226	543,298
Repurchase and retirement of common stock (in shares)		(69,000)
Repurchase and retirement of common stock	(1,841)	$ (1)	(1,840)
Equity-based compensation (in shares)		432,000
Equity-based compensation	9,384	$ 4	9,380
Net income (loss)	(18,254)			(18,254)
Ending balance (in shares) at Dec. 31, 2015		100,807,000
Ending balance at Dec. 31, 2015	1,858,584	$ 1,008	1,873,332	(15,756)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock issued during the period (in shares)		25,300,000
Stock issued during the period	975,975	$ 253	975,722
Repurchase and retirement of common stock (in shares)		(98,000)
Repurchase and retirement of common stock	(2,662)	$ (1)	(2,661)
Equity-based compensation (in shares)		935,000
Equity-based compensation	13,763	$ 9	13,754
Net income (loss)	(24,851)			(24,851)
Shares of common stock issued for acquisition (in shares)		14,980,000
Shares of common stock issued for acquisition	$ 595,919	$ 150	595,769
Ending balance (in shares) at Dec. 31, 2016	141,923,591	141,924,000
Ending balance at Dec. 31, 2016	$ 3,416,728	$ 1,419	3,455,916	(40,607)
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Adjusted Balance	3,417,312	$ 1,419	3,455,916	(40,023)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Adoption of ASU 2016-09	584			584
Repurchase and retirement of common stock (in shares)		(179,000)
Repurchase and retirement of common stock	(7,745)	$ (1)	(7,744)
Equity-based compensation (in shares)		831,000
Equity-based compensation	17,150	$ 8	17,142
Net income (loss)	232,136			232,136
Shares of common stock issued for acquisition (in shares)		16,020,000
Shares of common stock issued for acquisition	663,854	$ 160	663,694
Equity issuance costs	$ (349)		(349)
Ending balance (in shares) at Dec. 31, 2017	158,596,324	158,596,000
Ending balance at Dec. 31, 2017	$ 4,322,358	$ 1,586	$ 4,128,659	$ 192,113

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
OPERATING ACTIVITIES:
Net income (loss)	$ 232,136	$ (24,851)	$ (18,254)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	279,711	194,360	154,039
Asset retirement obligation accretion	605	472	336
Impairments of oil and natural gas properties	59,077	4,901	34,269
Equity-based compensation	17,150	13,763	9,384
Amortization of loan fees and discount on debt issuance	4,181	2,675	2,219
Deferred income taxes	(112,087)	(14,633)	(17,179)
Other	(593)	(570)	(8)
Gain (Loss) on Disposition of Assets	0	0	306
Net (gain) loss on derivative instruments	39,279	23,760	(20,906)
Net cash (payments) receipts from settled derivatives	(11,907)	7,704	89,533
Changes in operating assets and liabilities:
Accounts receivable	(37,486)	(45,909)	6,698
Other assets	(8,396)	3,180	(13,570)
Accounts payable and accounts payable to related parties	10,454	(4,096)	(13,700)
Accrued expenses	14,587	5,464	2,717
Interest payable	11,656	(7)	2,921
Net cash provided by operating activities	498,367	166,213	218,805
INVESTING ACTIVITIES:
Development of oil and natural gas properties	(628,998)	(286,901)	(401,191)
Acquisitions of oil and natural gas properties	(866,855)	(673,946)	(454,552)
Acquisition deposit held in escrow	(1,812)	(64,109)	0
Acquisitions of infrastructure assets	(19,156)	0	0
Additions to other property and equipment	(1,772)	(2,123)	(17,126)
Investment in unconsolidated subsidiary	(188)	(2,344)	(2,704)
Proceeds from sale of assets	1,527	0	634
Net cash used in investing activities	(1,517,254)	(1,029,423)	(874,939)
FINANCING ACTIVITIES:
Issuance of common stock	0	975,975	543,524
Payment of deferred loan costs	(693)	(12,068)	2,400
Borrowings under long-term debt	375,000	253,826	65,000
Payments on long-term debt	0	(253,826)	(65,000)
Issuance of senior unsecured notes	0	450,000	198,500
Payments of equity issuance costs	(349)	0	0
Repurchase and retirement of common stock	(7,745)	(2,662)	(1,841)
Net cash provided by financing activities	366,213	1,411,245	742,583
NET CHANGE IN CASH	(652,674)	548,035	86,449
CASH AT BEGINNING OF PERIOD	690,776	142,741	56,292
CASH AT END OF PERIOD	38,102	690,776	142,741
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	66,622	50,010	42,960
Cash paid for taxes	0	2,000	3,450
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING ACTIVITIES
Change in accrued capital expenditures	46,405	8,496	(21,463)
Common stock issued for oil and gas properties	663,854	595,919	0
Release of deposit held in escrow for oil and gas properties	$ 64,122	$ 0	$ 0

Nature of Operations and Basis

Nature of Operations and Basis of Presentation	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations and Basis of Presentation	NATURE OF OPERATIONS AND BASIS OF PRESENTATION RSP Permian, Inc., a Delaware corporation (“RSP Inc.,” the “Company,” “we,” “our,” or “us”), is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. The vast majority of the Company’s acreage is located on large, contiguous acreage blocks in the core of the Midland Basin and the Delaware Basin, both sub-basins of the Permian Basin. The Midland Basin properties are primarily in the adjacent counties of Midland, Martin, Andrews, Ector and Glasscock. The Delaware Basin properties are in Loving and Winkler counties. The Company’s common stock is listed and traded on the NYSE under the ticker symbol “RSPP.” Basis of Presentation These consolidated financial statements have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and are presented in accordance with generally accepted accounting principles in the United States (“GAAP”). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation. The consolidated financial statements of the Company include the accounts of the Company and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. Subsequent Events During the first quarter of 2018, we entered into additional derivative contracts covering 698,000 barrels of oil for 2018 and 2.6 million barrels of oil for 2019. See Note 4 for a summary of derivative positions entered into subsequent to December 31, 2017.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the financial statements and accompanying notes. The more significant estimates pertain to proved oil, NGLs and natural gas reserves, asset retirement obligations (“AROs”), equity-based compensation, estimates relating to oil, natural gas liquids (“NGLs”) and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively. Significant assumptions are required in the valuation of proved oil, NGLs and natural gas reserves that may affect the amount at which oil and natural gas properties are recorded. Depletion of oil and natural gas properties are determined using estimates of proved oil, NGLs and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price estimates. It is possible that these estimates could be revised at future dates and these revisions could be material. Reclassifications Certain reclassifications have been made to prior periods to conform to current period presentation. None of these reclassifications impacted previously reported stockholders’ equity, cash flows, or operating income. Cash and Cash Equivalents The Company considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation; however, the Company believes that the counterparties risks are minimal based on the reputation and history of the financial institutions where the deposits are held. Accounts Receivable As of December 31, (in thousands) 2017 2016 Sale of oil, natural gas and NGLs $ 95,942 $ 54,422 Joint interest owners 14,880 16,681 Federal income tax receivable 335 2,568 Accounts receivable $ 111,157 $ 73,671 Accounts receivable, which are primarily from the sale of oil, NGLs and natural gas, are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. In addition, settled but uncollected derivative contracts, receivables related to joint interest billings and income tax receivables are included in accounts receivable. The Company routinely reviews outstanding balances, assesses the financial strength of its customers 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, historical losses, existing economic conditions and other pertinent factors. Bad debt expense was zero for each of the years ended December 31, 2017 , 2016 and 2015. Transactions with Related Parties There were no material related party transactions that occurred during the years ended December 31, 2017 or 2016. In the fourth quarter of 2015, the Company acquired undeveloped acreage and oil and gas producing properties from Wolfberry Partners Resources LLC (“WPR”). These properties are located in the core of the Midland Basin and had an aggregate purchase price of approximately $137 million . At the time of the transaction, the majority of WPR was owned both directly and indirectly by certain members of our board of directors and two of our largest shareholders. Due to the related party nature of the WPR acquisition, only the disinterested members of our board of directors, consistent with our related party transaction policy, reviewed and ultimately approved the transaction. The disinterested directors also chose to hire an investment banking firm to advise them and render an opinion as to the fairness of the acquisition to the Company. Additional details of this acquisition are included in Note 3. There were no other material related party transactions that occurred during the year ended December 31, 2015. Derivative Financial Instruments We use derivative financial instruments to reduce exposure to fluctuations in the prices of oil and natural gas. These derivative transactions are generally in the form of collars, swaps and puts. We report the fair value of derivatives on the consolidated balance sheets in derivative instrument assets and derivative instrument liabilities as either current or noncurrent and determines the current and noncurrent classification based on the timing of expected future cash flows of individual contracts. We report these amounts on a gross basis by contract. We do not designate our derivative financial instruments as hedging instruments for financial reporting purposes and, as a result, we recognize the change in the respective instruments’ fair value in earnings. Oil and Natural Gas Properties The Company uses the successful efforts method of accounting for its oil and natural gas exploration and production activities. Costs incurred by the Company related to the acquisition of oil and natural gas properties and the cost of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed when determined to be unsuccessful. The Company may capitalize interest on expenditures for significant exploration and development projects that last more than six months , while activities are in progress to bring the assets to their intended use. The Company has not capitalized any interest as projects generally lasted less than six months . Costs incurred to maintain wells and related equipment, lease and well operating costs and other exploration costs are expensed as incurred. Gains and losses arising from the sale of properties are generally included in operating income. Capitalized acquisition costs attributable to proved oil and natural gas properties and leasehold costs are depleted using the unit-of-production method based on proved reserves. Capitalized exploration well costs and development costs, including AROs, are depleted using the unit-of-production method based on proved developed reserves. For the years ended December 31, 2017 , 2016 , and 2015, depletion expense for oil and natural gas producing property was $277.0 million , $192.8 million , and $152.8 million , respectively. Depletion expense is included in depreciation, depletion and amortization in the accompanying consolidated statements of operations. The Company’s oil and natural gas properties as of December 31, 2017 and December 31, 2016 consisted of the following: (in thousands) December 31, 2017 December 31, 2016 Proved oil and natural gas properties $ 3,936,565 $ 2,811,853 Unproved oil and natural gas properties 2,865,952 1,833,928 Total oil and natural gas properties 6,802,517 4,645,781 Less: Accumulated depletion (778,596 ) (554,419 ) Total oil and natural gas properties, net $ 6,023,921 $ 4,091,362 In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well, and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of December 31, 2017 and December 31, 2016 , there were no costs capitalized in connection with exploratory wells in progress. Proved oil and natural gas properties are evaluated for impairment annually or whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows available which is the level at which depletion is calculated. To determine if an asset is impaired, the Company compares the carrying value of the asset to the undiscounted future net cash flows by applying estimates of future oil, NGLs and natural gas prices to the estimated future production of oil, NGLs and natural gas reserves over the economic life of the asset and deducting future costs. Future net cash flows are based upon our reservoir engineers’ estimates of proved reserves and risk-adjusted probable reserves. For a property determined to be impaired, an impairment loss equal to the difference between the asset’s carrying value and its estimated fair value is recognized. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value. No impairment of proved property was recorded for the years ended December 31, 2017 or 2016. For the year ended December 31, 2015, we impaired approximately $19.6 million of proved oil and natural gas properties, which related to properties whose discounted future net revenues were less than the property’s carrying value. The calculation of expected future net cash flows in impairment evaluations are primarily based on estimates of future oil and natural gas prices, proved reserves and risk-adjusted probable reserve quantities, and estimates of future production and capital costs associated with our proved and risk-adjusted probable reserves. The Company’s estimates for future oil and natural gas prices used in the impairment evaluations are based on observable prices for the next three years, and then held constant for the remaining lives of the properties. Unproved property costs and related leasehold expirations are assessed quarterly for potential impairment and when industry conditions dictate an impairment may be possible. For the years ended December 31, 2017 , 2016 , and 2015 we impaired approximately $59.1 million , $4.9 million , and $14.7 million , respectively, of unproved oil and natural gas properties, which primarily related to management’s expectation that certain leasehold interests would expire and not be renewed, along with certain leasehold interests that may expire or be sold in the future. Proceeds from the sales of individual oil and natural gas properties that are part of a depletion base are credited to accumulated depletion with no immediate impact on income until the entire depletion base is sold. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the depletion base. Accrued Expenses Accrued expenses consist of the following: As of December 31, (in thousands) 2017 2016 Accrued capital expenditures $ 82,748 $ 36,343 Other accrued expenses 36,691 16,849 Accrued expenses $ 119,439 $ 53,192 Asset Retirement Obligation The Company records AROs related to the retirement of long-lived assets at the time a legal obligation is incurred and the liability can be reasonably estimated. AROs are recorded as long-term liabilities with a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future down-hole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of the surface acreage to a condition similar to that existing before oil and natural gas extraction began. In general, the amount of ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes, an adjustment is recorded to both the ARO liability and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. After recording these amounts, the ARO liability is accreted to its future estimated value using the same assumed credit adjusted rate and the associated capitalized costs are depreciated on a unit-of-production basis. The ARO liability consisted of the following for the period indicated: Year Ended December 31, 2017 (in thousands) 2017 2016 Asset retirement obligation at beginning of period $ 10,659 $ 7,063 Liabilities incurred or assumed 4,780 3,154 Liabilities settled (195 ) (30 ) Accretion expense 605 472 Asset retirement obligation at end of period $ 15,849 $ 10,659 Equity-based Compensation Equity-based compensation expense is recognized in our consolidated statements of operations over the awards’ vesting period based on their estimated fair values on the dates of grant. The Company utilizes the grant date’s closing stock price for the fair value of restricted stock awards and the Monte Carlo simulation method for the fair value of performance-based restricted stock awards. See Note 8 for additional discussion of our equity-based compensation. Income Taxes On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) was enacted, which made significant changes to U.S. federal income tax law affecting RSP Inc. Beginning January 1, 2018, our income will be taxed at a 21% federal corporate tax rate, a reduction from the 35% federal corporate tax rate in place prior to the Tax Act. We recognized the effect of this rate change on our deferred tax assets and liabilities in 2017, which resulted in a non-cash decrease to the income tax provision of $144.4 million for the quarter ended December 31, 2017. This one-time adjustment was recorded as an income tax benefit in the “Income tax benefit” line item in our consolidated statements of operations, and reduced our deferred tax liability on our consolidated balance sheet by the same amount. The Tax Act also repealed the corporate alternative minimum tax (“AMT”) for tax years beginning January 1, 2018. AMT credit carryovers as of December 31, 2017 are refundable beginning in 2018. At December 31, 2017, we had no AMT credit carryovers that are expected to be refunded as a result of the Tax Act. In addition, the Tax Act reduces the maximum deduction for net operating loss (“NOL”) carryforward arising in tax years beginning after 2017 to 80% of our taxable income, and allows any NOLs generated in tax years beginning after December 31, 2017 to be carried forward indefinitely and generally repeals carrybacks. NOLs available for utilization as of December 31, 2017 were approximately $482.0 million . The Tax Act is a comprehensive bill containing several other provisions, such as limitations on the deductibility of interest expense, bonus depreciation and certain executive compensation changes, that are not expected to materially impact our financial statements. Staff Accounting Bulletin No. 118 (“SAB 118”) provides a one-year measurement period from a registrant’s reporting period that includes the Tax Act’s enactment date to allow the registrant sufficient time to obtain, prepare and analyze information to complete the required accounting under Accounting Standards Codification (“ASC”) Topic 740, Income Taxes (“ASC 740”). The ultimate impact of the Tax Act on our reported results in fiscal 2018 and beyond may differ from the estimates provided herein, possibly materially, due to, among other things, changes in interpretations and assumptions we have made, guidance that may be issued, and other actions we may take as a result of the Tax Act. See Note 10 for additional information. The following is an analysis of the Company’s consolidated income tax (benefit) expense for the periods indicated: Year Ended December 31, (in thousands) 2017 2016 2015 Current $ (5,541 ) $ (4,074 ) $ 5,184 Deferred (112,087 ) (14,632 ) (16,867 ) Income Tax Benefit $ (117,628 ) $ (18,706 ) $ (11,683 ) Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The Company’s policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 2016, the Company had a long-term tax payable related to uncertain tax positions totaling $5.3 million . This amount was recorded in other long term liabilities on the consolidated balance sheet. In the fourth quarter of 2017, the Company decreased the liability associated with uncertain tax positions to $0.4 million due to return to provision adjustments and current year positions, which resulted in a current tax benefit offset by deferred tax expense with no impact to total tax expense. We expect all taxes recorded related to uncertain tax positions to ultimately be refundable due to the Tax Act. The Company’s U.S. federal income tax returns for 2014 and beyond, and its Texas franchise tax returns for 2013 and beyond, remain subject to examination by the taxing authorities. No other jurisdiction’s returns are significant to the Company’s financial position. Revenue Recognition The Company records oil, NGLs and natural gas sales when title passes to the purchaser, which for the Company is primarily at the wellhead. Oil and natural gas production imbalances, which there were none, are accounted for using the sales method. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”). See below for additional discussion on the implementation of ASU 2014-09 and the anticipated impact on our financial statements. Segment Reporting The Company operates in only one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States. New Accounting Pronouncements In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. Under ASU 2017-01, an entity must first determine whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar assets. If this threshold is met, the set is not a business. If it’s not met, the entity then evaluates whether the set meets the requirement that a business include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs. We will apply the guidance in ASU 2017-07 for asset acquisitions occurring subsequent to January 1, 2018. The adoption of ASU 2017-01 will impact the process that the Company uses to evaluate whether the Company has acquired a business or an asset. This update will be applied prospectively and will not have an effect on prior acquisitions. In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 simplifies several aspects of the accounting for share-based payment award transactions. These simplifications include the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The Company adopted this guidance in the first quarter of 2017 using the modified retrospective approach. Accordingly, the deferred tax liability at December 31, 2016 was reduced by $0.6 million with a corresponding adjustment to accumulated deficit in the consolidated balance sheet. Additional tax deductions during 2017 from stock compensation under the guidance of ASU 2016-09 resulted in a reduction to income tax expense of $4.4 million . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”). ASU 2016-02 generally requires all lease transactions (with terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities. Public entities are required to apply ASU 2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. Revenue from Contracts with Customers (Topic 606) - ASU 2014-09 In May 2014, the FASB issued ASU 2014-09. ASU 2014-09 provides a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance including industry specific guidance. The new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We have selected the modified retrospective method. We are in the final stages of assessing the impact of adoption of the standard on our consolidated financial statements. We do not believe the adoption of ASU 2014-09 will have a material impact, if any, on our operating income, cash flows or stockholders’ equity. However, the adoption of this guidance is expected to result in certain reclassifications of gathering costs attributable to NGLs and natural gas revenues due to the conclusion that the Company meets the definition of an agent under the control model defined in ASU 2014-09 for certain of its gas processing and purchase contracts. Our conclusions are subject to change, and we continue to review our implementation documentation and finalize our impact assessment. Our evaluation of the new disclosure requirements is ongoing, and we expect that our disclosures surrounding revenue recognition will be more robust upon adoption of ASU 2014-09.

Acquisitions of Oil and Natural

Acquisitions of Oil and Natural Gas Property Interests	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions of Oil and Natural Gas Property Interests	ACQUISITIONS OF OIL AND NATURAL GAS PROPERTY INTERESTS Silver Hill Acquisitions On October 13, 2016, the Company entered into definitive agreements to acquire 100% of Silver Hill Energy Partners, LLC (“SHEP I”) and Silver Hill E&P II, LLC (“SHEP II”, and together with SHEP I, “Silver Hill”) for an aggregate of $1.25 billion in cash and 31.0 million shares of RSP Inc. common stock. Silver Hill was comprised of two privately-held entities that collectively own oil and gas producing properties and undeveloped acreage in Loving and Winkler counties in Texas and owned approximately 40,100 net acres. Silver Hill’s highly contiguous acreage position in the core of the Delaware Basin was complementary to the Company’s asset base and the acquisition creates substantial scale from a production and acreage standpoint. Substantially all of the value of the transaction was related to the value of the oil and gas assets acquired with minimal value ascribed to other assets. The SHEP I acquisition closed on November 28, 2016, with cash consideration of $604.0 million , including assumed debt obligations which were repaid, before purchase price adjustments, and approximately 15.0 million shares of RSP Inc. common stock. The SHEP II acquisition closed on March 1, 2017, with cash consideration of $646.0 million , before purchase price adjustments, and approximately 16.0 million shares of RSP Inc. common stock. During 2017, we recorded post-closing adjustments of $5.7 million for the Silver Hill acquisitions. A summary of the consideration transferred and the fair value of assets and liabilities acquired in the Silver Hill acquisitions is as follows: Purchase Price Allocation (in thousands) SHEP I SHEP II Total Value of the Company’s common stock issued (1) $ 595,919 $ 663,854 $ 1,259,773 Cash paid to sellers (including deposits) 531,196 641,577 1,172,773 Total consideration for the assets contributed $ 1,127,115 $ 1,305,431 $ 2,432,546 Fair value of oil and natural gas properties $ 1,200,632 $ 1,308,177 $ 2,508,809 Asset retirement obligation (666 ) (822 ) (1,488 ) Assumption of debt (63,826 ) — (63,826 ) Assumption of other liabilities (9,025 ) (1,924 ) (10,949 ) Total net assets acquired (2) $ 1,127,115 $ 1,305,431 $ 2,432,546 (1) The Company issued 14,980,362 shares of common stock at $39.78 per share (closing price) on November 28, 2016 in the SHEP I acquisition. The Company issued 16,019,638 shares of common stock at $41.44 per share (closing price) on March 1, 2017 in the SHEP II acquisition. (2) Approximately 85% and 77% of the acquisition date fair value of oil and natural gas properties was recorded as unproved property in the SHEP I and SHEP II acquisitions, respectively. The Silver Hill acquisitions were accounted for using the acquisition method of accounting with the Company as the acquirer. Under the acquisition method of accounting, the Company recorded all assets acquired and liabilities assumed at their respective acquisition date fair values at the closing date of the acquisition. The fair values of the assets acquired and liabilities assumed are based on a detailed analysis, using industry accepted methods of estimating the current fair value as described below. Oil and natural gas properties - Substantially all of the acquired value in the Silver Hill acquisitions was related to the value of the oil and gas assets acquired with minimal value ascribed to the other assets. The Company used two valuation methods in its determination of fair value for the oil and natural gas properties; the discounted cash flow analysis and comparable transaction analysis. The significant assumptions included in the discounted cash flow analysis include commodity price assumptions, costs and capital outlay to develop the acquired properties, pricing differentials, reserve risking, and discount rates. NYMEX strip pricing at the SHEP I and SHEP II acquisition dates of November 28, 2016 and March 1, 2017, respectively, less applicable pricing differentials, were utilized in the discounted cash flow analysis. Risking levels in the discounted cash flow analysis were determined based on a variety of factors, such as existing well performance, offset production and analogue wells. Discount rates used in the discounted cash flow analysis were determined by using the estimated weighted average cost of capital for the Company, discount rates published in third party publications, as well as industry knowledge and experience. The comparable transaction analysis was performed to establish a range of fair values for similarly-situated oil and gas properties that were recently bought or sold in arms-length, observable market transactions. The range of value observed from the Company’s analysis of recent market transactions and the fair value calculation via the discounted cash flow method was used as a basis to determine fair value of the assets. The Company’s fair value conclusion indicated that the discounted cash flow method valuation is substantially in the same range as the comparable transactions reviewed, when considering the comparable transactions on a median or average basis. Other current liabilities - Other current liabilities assumed in the Silver Hill acquisitions, which related to revenues held in suspense, were carried over at historical carrying values because the assets and liabilities are short term in nature and their carrying values are estimated to represent the best estimate of fair value. Asset retirement obligation - The fair value of asset retirement obligations was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate, and timing associated with the incurrence of these costs. Revenues and earnings of SHEP II acquisition recognized in 2017 subsequent to the acquisition were $66.4 million and $29.5 million , respectively. The Company recognized $4.5 million and $6.4 million of expenses during 2017 and 2016, respectively, primarily related to the Silver Hill acquisitions, and recorded these costs in “Acquisition costs” on the consolidated statement of operations. Other 2017 Acquisitions During the third quarter of 2017, the Company closed on two acquisitions of undeveloped acreage and additional mineral interests in the Delaware Basin for an aggregate purchase price of approximately $227.9 million , before purchase price adjustments. These acquisitions were funded with borrowings under our revolving credit facility (“Revolving Credit Facility”). We recorded purchase price adjustments of $3.3 million related to these acquisitions during 2017. In addition to the acquisitions discussed above, in 2017, the Company closed on bolt-on acquisitions of mostly undeveloped acreage for an aggregate total purchase price of approximately $47.8 million . The acquisitions included additional working interests in properties where the Company owned existing interests as well as other properties in the Company’s core areas. These acquisitions were funded with cash on hand and borrowings under our Revolving Credit Facility. On January 2, 2017, the Company closed on the acquisition of water infrastructure assets from Lone Wolf Resources and related entities for an aggregate total purchase price of $19.2 million . The acquisition was funded with cash on hand. Other 2016 Acquisitions During 2016, the Company also completed bolt-on acquisitions of mostly undeveloped acreage in the Midland Basin for an aggregate total purchase price of approximately $69.4 million . The acquisitions included additional working interests in properties where the Company owned existing interests as well as other properties in the Company’s core areas. These acquisitions were funded with cash on hand. WPR Acquisition In the fourth quarter of 2015, the Company acquired undeveloped acreage and oil and gas producing properties for an aggregate purchase price of approximately $137.0 million from WPR. Approximately $41.0 million was recorded as proved oil and gas properties. The acquisition included 4,100 largely contiguous net acres, in the core of the Midland Basin with production of approximately 1,900 Boe/d and 86 net horizontal drilling locations as of the effective date. Glass Ranch Acquisition In the third quarter of 2015, the Company acquired undeveloped acreage and oil and gas producing properties located in Martin and Glasscock counties for an aggregate purchase price of approximately $313.0 million . The aggregate acquisitions included 6,548 net acres in our core focus area. Pro Forma Results (unaudited) The Company’s summary pro forma results for the twelve months ended December 31, 2017 and 2016 were derived from the actual results of the Company adjusted to reflect the SHEP II acquisition, as if such transaction had occurred on January 1, 2016. The below information reflects pro forma adjustments for the issuance of RSP Inc. common stock to the sellers of SHEP II along with common stock issued in the October 2016 public offering that funded the cash portion of the SHEP II acquisition. Additional pro forma adjustments, based on available information and certain assumptions, include (i) the depletion of SHEP II fair-valued proved oil and gas properties, and (ii) the estimated tax impacts of the pro forma adjustments. Pro forma earnings for the year ended December 31, 2017 were adjusted to exclude $4.5 million of acquisition costs incurred by the Company. The pro forma financial information included below does not give effect to certain acquisitions that were immaterial to our actual and pro forma results for the periods reflected below and does not make any adjustments for non-recurring expenses associated with the SHEP II acquisition, except for the acquisition costs described above. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. Year Ended December 31, 2017 Year Ended December 31, 2016 (in thousands) Actual Pro Forma Actual Pro Forma Revenues $ 803,708 $ 822,427 $ 353,857 $ 415,945 Net income (loss) 232,136 240,596 (24,851 ) (16,757 ) Earnings (loss) per common share: Basic $ 1.50 $ 1.55 $ (0.23 ) $ (0.11 ) Diluted $ 1.49 $ 1.55 $ (0.23 ) $ (0.11 )

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	DERIVATIVE INSTRUMENTS Commodity Derivative Instruments The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its oil and natural gas production. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current period earnings. Our commodity derivatives have historically been comprised of the following instruments: Collars : Each collar transaction has an established price floor and ceiling, and certain collar transactions also include a short put. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is below the short put price, the Company receives from its counterparty an amount equal to the difference of the price floor and the short put price multiplied by the hedged contract volume. Swaps : Each swap transaction has an established fixed price. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. Deferred Premium Put : Each deferred premium put option has an established floor price. When the settlement price is below the floor price, the Company receives the difference between the floor price and the settlement price multiplied by the hedged contract volume less the cost of the premium for the option. When the settlement price is at or above the floor price, the Company receives no proceeds and pays the cost of the premium for the option. In either case, whether the settlement price is below or above the floor price, the Company pays the premium for the option at the expiration of the option. We had no open deferred premium put positions as of December 31, 2017. The following table summarizes all open positions as of December 31, 2017 : Contracts expiring in the period ending: March 31, 2018 June 30, 2018 September 30, 2018 December 31, 2018 2019 Oil Three-Way Collars: Notional volume (Bbl) 2,219,000 1,941,000 1,319,000 1,227,000 — Weighted average ceiling price ($/Bbl)(1) $ 58.81 $ 59.07 $ 60.56 $ 60.96 $ — Weighted average floor price ($/Bbl)(1) $ 46.96 $ 47.11 $ 47.79 $ 48.00 $ — Weighted average short put price ($/Bbl)(1) $ 36.96 $ 37.11 $ 37.79 $ 38.00 $ — Oil Costless Collars: Notional volume (Bbl) 571,000 516,000 1,212,000 1,058,000 1,277,500 Weighted average ceiling price ($/Bbl)(1) $ 60.19 $ 60.20 $ 60.10 $ 60.11 $ 55.99 Weighted average floor price ($/Bbl)(1) $ 45.00 $ 45.00 $ 46.33 $ 46.52 $ 50.00 Oil Swaps: Notional volume (Bbl) — — 322,000 322,000 1,277,500 Weighted average swap price ($/Bbl)(1) $ — $ — $ 55.77 $ 55.77 $ 53.42 Mid-Cush Differential (Basis) Swaps: Notional volume (Bbl) 1,859,000 1,911,000 1,932,000 1,932,000 730,000 Weighted average swap price ($/Bbl)(2) $ (0.60 ) $ (0.59 ) $ (0.59 ) $ (0.59 ) $ (0.25 ) (1) The oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. (2) The Mid-Cush swap contracts are settled based on the difference in the arithmetic average during the calculation period of WTI MIDLAND ARGUS and WTI ARGUS prices in the Argus Americas Crude publication for the relevant period. The following table summarizes all commodity derivative positions entered subsequent to December 31, 2017: Contracts expiring in the period ending: March 31, 2018 June 30, 2018 September 30, 2018 December 31, 2018 2019 Oil Costless Collars: Notional volume (Bbl) — — — — 1,277,500 Weighted average ceiling price ($/Bbl) $ — $ — $ — $ — $ 60.10 Weighted average floor price ($/Bbl) $ — $ — $ — $ — $ 55.00 Oil Swaps: Notional volume (Bbl) — 698,000 — — 1,277,500 Weighted average swap price ($/Bbl) $ — $ 62.97 $ — $ — $ 58.06 Mid-Cush Differential (Basis) Swaps: Notional volume (Bbl) 531,000 819,000 828,000 828,000 1,825,000 Weighted average swap price ($/Bbl) $ (0.01 ) $ (0.01 ) $ (0.01 ) $ (0.01 ) $ (0.30 ) Derivative Fair Values and Gains (Losses) The following table presents the fair value of our derivative instruments. Our derivatives are presented as separate line items in our consolidated balance sheets as current and noncurrent derivative instrument assets and liabilities based on the expected settlement dates of the instruments. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of the Company’s master netting arrangements. See Note 5 for further discussion related to the fair value of the Company’s derivatives. Assets Liabilities (in thousands) December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Derivative Instruments: Current amounts Commodity contracts $ 64 $ 11,815 $ 36,566 $ 28,861 Noncurrent amounts Commodity contracts 37 — 5,722 — Total derivative instruments $ 101 $ 11,815 $ 42,288 $ 28,861 Gains and losses on derivative instruments are reported in the consolidated statements of operations. The following table represents the Company’s reported gains (losses) on derivative instruments for the periods presented: Year Ended December 31, (in thousands) 2017 2016 2015 Net gain (loss) on derivative instruments $ (39,279 ) $ (23,760 ) $ 20,906 Offsetting of Derivative Assets and Liabilities The following table presents the Company’s gross and net derivative assets and liabilities. (in thousands) Gross Amount Netting Net December 31, 2017 Derivative instrument assets with right of offset or master netting agreements $ 101 $ (101 ) $ — Derivative instrument liabilities with right of offset or master netting agreements $ (42,288 ) $ 101 $ (42,187 ) December 31, 2016 Derivative instrument assets with right of offset or master netting agreements $ 11,815 $ (11,815 ) $ — Derivative instrument liabilities with right of offset or master netting agreements $ (28,861 ) $ 11,815 $ (17,046 ) (a) To mitigate our risk of loss due to default, we have entered into master netting agreements with counterparties to our commodity derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty. Credit-Risk Related Contingent Features in Derivatives None of the Company’s derivative instruments contain credit-risk related contingent features. No amounts of collateral were posted by the Company related to net positions as of December 31, 2017 and December 31, 2016 .

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS We value our derivatives and other financial instruments according to FASB ASC 820, Fair Value Measurements and Disclosures , which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (“exit price”) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows: • Level 1—Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. • Level 2—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. • Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs that are not corroborated by market data and may reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Fair Value Measurement on a Recurring Basis Fair value of commodity derivative instruments The fair value of derivative financial instruments is determined utilizing industry standard models incorporating assumptions and inputs, most of 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 a summary of the estimated fair value of our commodity derivative instruments as of December 31, 2017 and 2016. (in thousands) Level 1 Level 2 Level 3 Total fair value As of December 31, 2017: Commodity derivative instruments $ — $ (42,187 ) $ — $ (42,187 ) (in thousands) Level 1 Level 2 Level 3 Total fair value As of December 31, 2016: Commodity derivative instruments $ — $ (17,046 ) $ — $ (17,046 ) Fair value of other financial instruments Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued liabilities. The carrying amount of these instruments approximates fair value because of their short-term nature. The carrying value of our borrowings under our Revolving Credit Facility approximate fair value as these are subject to short-term floating interest rates that approximate the rates available to us for those periods. The estimated fair values of our senior notes are presented below. The estimated fair value of our senior unsecured notes due January 15, 2025 (“2025 Senior Notes”) and senior unsecured notes due October 1, 2022 (“2022 Senior Notes”) have been calculated based on quoted prices in active markets and are classified as Level 1 on December 31, 2017 . As described in Note 6, the 2025 Senior Notes were initially issued through a private placement, and were exchanged for registered notes with the same terms in November 2017. As such, prior to November 2017, the estimated fair value of the 2025 Senior Notes were classified as Level 2 as these notes did not trade in active markets. Reclassifications of fair value among 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 among Level 1, Level 2 or Level 3 during the years ended December 31, 2017 and 2016 , except that the 2025 Senior Notes were reclassified to Level 1. The following table presents a summary of the estimated fair value of our senior notes as of December 31, 2017 and 2016. December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Total fair value 2025 Senior Notes $ 464,022 $ — $ — $ 464,022 2022 Senior Notes 734,706 — — 734,706 December 31, 2016 Level 1 Level 2 Level 3 Total fair value 2025 Senior Notes $ 452,300 $ — $ — $ 452,300 2022 Senior Notes — 735,000 — 735,000 Nonfinancial Assets and Liabilities Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon assumptions of the estimated current abandonment costs, discount rate, inflation rate and timing associated with the incurrence of these costs. Our estimated abandonment costs are obtained primarily from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition or costs incurred historically for similar work. Additions to the Company’s AROs represent a nonrecurring Level 3 measurement. The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Long-Term Debt	LONG-TERM DEBT Long-term debt consists of the following: (in thousands) December 31, 2017 December 31, 2016 Revolving Credit Facility $ 375,000 $ — 5.25% Senior Notes due 2025 450,000 450,000 6.625% Senior Notes due 2022 700,000 700,000 Less: Discount (950 ) (1,150 ) Less: Debt issuance costs (14,922 ) (16,575 ) Total long-term debt $ 1,509,128 $ 1,132,275 Revolving Credit Facility On October 19, 2017, we entered into a first amendment to our credit agreement to, among other things, (a) increase the borrowing base to $1.5 billion from $1.1 billion and maintain our elected commitment at $900.0 million and (b) decrease the applicable margins for interest rates applicable to amounts outstanding under the Revolving Credit Facility from a range of 200 basis points to 300 basis points above the applicable reference rate for Eurodollar loans and 100 basis points to 200 basis points above the applicable reference rate for alternate base rate (“ABR”) loans to ranges of 150 basis points to 250 basis points for Eurodollar loans and 50 basis points to 150 basis points for ABR loans. As of December 31, 2017, we had $375.0 million in borrowings, $1.9 million of letters of credit outstanding and $523.1 million of borrowing capacity under our Revolving Credit Facility. The maturity date of the Revolving Credit Facility is December 19, 2021. The borrowing base under the Revolving Credit Facility remains subject to semi-annual review and redetermination by the lenders pursuant to the term of the credit agreement. The redetermination of the borrowing base occurs in May and November of each year and, among other things, depends on the volumes of proved oil, NGLs and natural gas reserves and an estimate of associated cash flows, and commodity hedge positions. As of December 31, 2017, the borrowing base under the Company’s amended and restated credit agreement was $1.5 billion , with an elected commitment of $900.0 million , and lender commitments of $2.5 billion . The Company’s credit agreement requires that we maintain the following two financial ratios: • a working capital ratio, which is the ratio of consolidated current assets (includes unused commitments under its revolving credit facility and excludes restricted cash and derivative assets) to consolidated current liabilities (excluding the current portion of long-term debt under the credit facility and derivative liabilities), of not less than 1.0 to 1.0; • a leverage ratio, which is the ratio of the sum of all of the Company’s debt to the consolidated EBITDAX (as defined in the credit agreement) for the four fiscal quarters then ended, of not greater than 4.25 to 1.0. Our credit agreement also contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, make loans to others, make investments, enter into mergers, make or declare dividends, enter into commodity hedges exceeding a specified percentage or our expected production, enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness, incur liens, sell assets, enter into transactions with affiliates or engage in certain other transactions without the prior consent of the lenders. The Company was in compliance with such covenants and ratios as of December 31, 2017 . Principal amounts borrowed under our Revolving Credit Facility are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. We have a choice of borrowing at a Eurodollar rate or at the adjusted base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted London Interbank Offered Rate (“LIBOR”) (equal to the quotient of: (i) the LIBOR rate; divided by (ii) a percentage equal to 100% minus the maximum rate on such date at which the administrative agent is required to maintain reserves on “Eurocurrency Liabilities,” as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 150 basis points to 250 basis points , as amended, depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s referenced rate; (ii) the federal funds effective rate plus 50 basis points ; and (iii) the adjusted LIBOR rate plus 100 basis points , plus an applicable margin ranging from 50 basis points to 150 basis points , as amended, depending on the percentage of our borrowing base utilized, plus a commitment fee ranging from 37.5 basis points to 50 basis points charged on the undrawn commitment amount. On December 31, 2017 , our weighted average interest rate was approximately 3.6% . 2025 Senior Notes On December 27, 2016, the Company issued $450.0 million of 5.25% senior unsecured notes at par through a private placement. The 2025 Senior Notes will mature on January 15, 2025. The notes are senior unsecured obligations that rank equally with all of our future senior indebtedness, are effectively subordinated in rights to our assets constituting collateral held by all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including indebtedness under our Credit Facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on the 2025 Senior Notes is payable semi-annually on January 15 and July 15, commencing on July 15, 2017. On or after January 15, 2020, the Company may redeem some or all of the 2025 Senior Notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 103.938% of principal, declining in twelve-month intervals to 100% in 2023 and thereafter. In addition, prior to January 15, 2020, on any one or more occasions, the Company may redeem all or part of the notes at a redemption price of 100% of the principal amount of the notes redeemed, plus an applicable make-whole premium along with accrued and unpaid interest. We incurred approximately $6.4 million of debt issuance costs related to the issuance of the 2025 Senior Notes during 2016, which are reductions to “Long-term debt” on our consolidated balance sheets and will be amortized to “Interest expense” on our consolidated statements of operation over the life of the notes using the effective interest method. In the event of certain changes in control of the Company, each holder of notes will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The 2025 Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. The subsidiary guarantees are full and unconditional and joint and several, and any of our subsidiaries other than the subsidiary guarantors are minor. RSP Inc. does not have independent assets or operations. The terms of the notes include, among other restrictions, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. In November 2017, the Company exchanged $450.0 million of the 2025 Senior Notes for registered notes with the same terms. The Company was in compliance with the provisions of the indenture governing the 2025 Senior Notes as of December 31, 2017. 2022 Senior Notes On September 26, 2014, the Company issued $500.0 million of 6.625% senior unsecured notes at par through a private placement. On August 10, 2015, the Company issued an additional $200.0 million of the 2022 Senior Notes at 99.25% of the principal amount through a private placement. The notes will mature on October 1, 2022. The notes are senior unsecured obligations that rank equally with all of our future senior indebtedness, are effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our Credit Facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on the 2022 Senior Notes is payable semi-annually on April 1 and October 1. The Company may redeem some or all of the notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 104.969% of principal, declining in twelve-month intervals to 100% in 2020 and thereafter. We incurred approximately $11.3 million of debt issuance costs related to the issuance of the 2022 Senior Notes during 2014 and $2.4 million during 2015, which are reductions to “Long-term debt” on our consolidated balance sheets and will be amortized to “Interest expense” on our consolidated statements of operations over the life of the notes using the effective interest method. In the event of certain changes in control of the Company, each holder of notes will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. RSP Inc. does not have independent assets or operations. The terms of the notes include, among other restrictions, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. In June 2015, the Company exchanged $500.0 million of the 2022 Senior Notes for registered notes with the same terms. In March 2016, the Company exchanged an additional $200.0 million of the 2022 Senior Note for registered notes with the same terms. The Company was in compliance with the provisions of the indenture governing the 2022 Senior Notes as of December 31, 2017 .

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Legal and Environmental Matters 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. 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. Environmental expenditures are expensed as incurred. We have established procedures for the ongoing evaluation of our operations to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when we determine the potential exposure related to, but not limited to, legal matters, environmental assessments and/or clean-ups, is probable and estimable. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both December 31, 2017 and 2016 , we had no legal or environmental matters that we deemed to be probable and estimable or any legal or environmental matters requiring specific disclosure. Leases The Company leases office space in Midland and Dallas Texas. These leases run through 2022. Rent expense for the years ended December 31, 2017 , 2016 , and 2015 was $1.1 million and $0.9 million , and $0.9 million respectively. Contractual Obligations A summary of our contractual obligations as of December 31, 2017 is provided in the following table. Payments Due by Period For the Year Ended December 31, (in thousands) 2018 2019 2020 2021 2022 Thereafter Total Revolving Credit Facility (1) $ — $ — $ — $ 375,000 $ — $ — $ 375,000 5.25% Senior Notes due 2025 (1) — — — — — 450,000 450,000 6.625% Senior Notes due 2022 (1) — — — — 700,000 — 700,000 Interest cost (2) 70,000 70,000 70,000 70,000 58,406 48,221 386,627 Drilling rig commitments (3) 14,375 — — — — — 14,375 Purchase obligations (4) 45,013 16,346 9,180 9,180 1,752 8,654 90,125 Operating lease obligations (5) 2,163 2,032 1,257 1,077 1,119 — 7,648 Asset retirement obligations (6) — — — — — 15,849 15,849 Total $ 131,551 $ 88,378 $ 80,437 $ 455,257 $ 761,277 $ 522,724 $ 2,039,624 (1) The amounts presented in the table above are outstanding principal balances only. The Revolving Credit Facility amount is based on the outstanding borrowing as of December 31, 2017. Principal amount borrowed under the Revolving Credit Facility must be repaid prior to the maturity date of December 19, 2021. Any future advances or repayments could change the total amount outstanding under the Revolving Credit Facility. (2) The amounts include interest costs related to our fixed rate senior notes. The annual interest obligation on the 2025 Senior Notes is $23.6 million , based on the interest rate of 5.25% . The annual interest obligation on the 2022 Senior Notes is $46.4 million , based on the interest rate of 6.625% . The table above does not include interest costs, future commitment fees or other fees on our revolving credit facility, as these obligations are based on floating rates as more fully described in Note 6. (3) Drilling rig commitments represent the contractual rate for our operated drilling rigs through the term of the contracts as of December 31, 2017. The amounts presented in the table represent our gross commitments under these contracts. (4) Purchase obligations include our sand commitments, water commitments and throughput volume delivery commitments. Subsequent to December 31, 2017, we entered into a fixed-price power purchase contract to manage the volatility of the price of power needed for ongoing operations. This contract will increase our purchase obligations by approximately $72 million over twelve years. (5) Operating lease obligations include office and vehicle leases. (6) Costs related to asset retirement obligations typically extend many years into the future. Our calculation of asset retirement obligations uses numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, changes in technology and changes in the legal, regulatory, environmental and political environments.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Based Compensation	EQUITY-BASED COMPENSATION The Company adopted the RSP Permian, Inc. 2014 Long Term Incentive Plan (“LTIP”) for the employees, consultants and directors of the Company and its affiliates who perform services for the Company. A total of 10.0 million shares of common stock have been authorized for issuance under the LTIP. At December 31, 2017, there were 7.2 million shares of common stock available for future grant. Equity-based payments, including grants of restricted stock awards and performance-based restricted stock awards are recognized in our consolidated statements of operations based on their estimated fair values. We recognize expense on a straight-line basis over the vesting period of the awards. Equity-based compensation expense, which was recorded in general and administrative expenses, was $17.2 million , $13.8 million , and $9.4 million for the years ended December 31, 2017 , 2016 and 2015, respectively. Restricted Stock Awards The compensation expense for these awards was determined based on the market price of the Company’s common stock at the date of grant. Equity-based compensation expense for restricted stock awards was $10.2 million , $7.9 million and $6.4 million for the years ended December 31, 2017 , 2016 and 2015, respectively. As of December 31, 2017 , the Company had unrecognized compensation expense of $13.6 million related to restricted stock awards which is expected to be recognized over a weighted average period of 1.5 years . The following table represents restricted stock award activity for the years ended December 31, 2017, 2016 and 2015 : 2017 2016 2015 Shares Weighted Average Fair Value Shares Weighted Average Fair Value Shares Weighted Average Fair Value Restricted shares outstanding, beginning of period 656,895 $ 22.21 499,529 $ 25.99 477,767 $ 23.71 Restricted shares granted 379,579 41.39 442,835 19.78 279,181 27.18 Restricted shares canceled (27,400 ) 31.74 (13,551 ) 21.61 (6,640 ) 26.43 Restricted shares vested (321,797 ) 23.01 (271,918 ) 25.22 (250,779 ) 22.97 Restricted shares outstanding, end of period 687,277 $ 32.04 656,895 $ 22.21 499,529 $ 25.99 Performance-Based Restricted Stock Awards We granted performance-based restricted stock awards to certain officers of the Company. The payout of these awards varies depending on the Company’s total shareholder return in comparison to an identified peer group. We granted 380,174 and 484,650 performance-based restricted stock awards in 2017 and 2016, respectively, that allow for a payout between 0% and 100% . We granted 159,932 performance-based restricted stock awards in 2015 that allow for a payout between 0% and 200% . Our performance-based restricted stock awards are valued on the date of grant with a cliff vesting period of approximately three years, subject to the achievement of certain criteria. Total compensation expense is recognized over the vesting period using the straight-line method. Equity-based compensation for these awards was $7.0 million , $5.9 million , and $3.0 million for the years ended December 31, 2017 , 2016 and 2015, respectively. The grant date fair values of the performance-based restricted stock awards were determined using a Monte Carlo model which uses company-specific inputs to generate different stock price paths. The range of assumptions used in the Monte Carlo model for the awards granted in 2017, 2016 and 2015 are as follows: Assumptions 2017 2016 2015 Risk-free rate of return 1.52 % 0.95 % 0.98 % Volatility 28.5 % 54.6 % 49.2 % The unrecognized compensation expense related to these shares is approximately $ 9.4 million as of December 31, 2017 and is expected to be recognized over the next 1.3 years . The following table represents performance-based restricted stock award activity for the years ended December 31, 2017, 2016 and 2015 : 2017 2016 2015 Shares Weighted Average Fair Value Shares Weighted Average Fair Value Shares Weighted Average Fair Value Restricted shares outstanding, beginning of period 747,874 $ 19.82 294,332 $ 31.41 134,400 $ 28.14 Restricted shares granted (1) 380,174 26.96 484,650 13.53 159,932 31.74 Restricted shares canceled (7,569 ) 26.96 — — — — Restricted shares vested (1) (119,400 ) 31.01 (31,108 ) 31.39 — — Restricted shares outstanding, end of period 1,001,079 $ 21.14 747,874 $ 19.82 294,332 $ 31.41 (1) Performance-based restricted shares granted or vested during each period reflect the number of shares granted or vested at a 100% of the target payout. The actual payout of the shares granted may be between 0% and 200% depending on the Company’s total shareholder return in comparison to an identified peer group. Awards granted in 2015 allow for a payout of between 0% and 200% , while awards granted in 2016 and 2017 allow for a payout of between 0% and 100% .

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Earnings Per Share	EARNINGS PER SHARE The Company’s basic earnings per share amounts have been computed using the two-class method based on the weighted-average number of shares of common stock outstanding for the period. Because the Company recognized a net loss for the years ended December 31, 2016 and 2015, all unvested restricted stock awards and performance-based restricted stock awards were excluded from the diluted earnings per share calculations as they would be antidilutive. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: Year Ended December 31, (in thousands, except per share data) 2017 2016 2015 Numerator: Net income (loss) available to stockholders $ 232,136 $ (24,851 ) $ (18,254 ) Basic net income allocable to participating securities (1) 1,161 — — Income available to stockholders $ 230,975 $ (24,851 ) $ (18,254 ) Denominator: Weighted average number of common shares outstanding - basic 154,162 107,324 86,770 Effect of dilutive securities: Restricted stock 1,364 — — Weighted average number of common shares outstanding - diluted 155,526 107,324 86,770 Net earnings (loss) per share: Basic $ 1.50 $ (0.23 ) $ (0.21 ) Diluted $ 1.49 $ (0.23 ) $ (0.21 ) (1) Restricted stock awards that contain non-forfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.

Income Taxes (Notes)

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES On December 22, 2017, the Tax Act was enacted, which made significant changes to U.S. federal income tax law affecting RSP Inc. See Note 2 for a summary of changes and discussion of certain provisions of the Tax Act and the impact of such provisions on our results of operations and consolidated financial statements. At December 31, 2017, we have made a reasonable estimate of the effects of the Tax Act on our existing deferred tax balances based on our understanding of the guidance available as of the date of this filing. We will continue to monitor for any new administrative guidance or interpretations of the Tax Act. The components of the provision for income taxes for the year ended December 31, 2017, 2016, and 2015 is as follows: For the year ended December 31, (in thousands) 2017 2016 2015 Current Income Tax Expense (Benefit): Federal $ (5,541 ) $ (4,074 ) $ 5,504 State — — (320 ) Total income tax expense (benefit) (5,541 ) (4,074 ) 5,184 Deferred Income Tax Expense (Benefit): Federal (1) $ (119,925 ) $ (19,195 ) $ (9,649 ) State 2,297 489 (1,714 ) Federal alternative minimum tax 5,541 4,074 (5,504 ) Total deferred income tax benefit (112,087 ) (14,632 ) (16,867 ) Total Income Tax Benefit $ (117,628 ) $ (18,706 ) $ (11,683 ) (1) Beginning January 1, 2018, our income will be taxed at a 21% federal corporate rate, a reduction from the 35% federal corporate rate in place prior to the Tax Act. We recognized the effect of this rate change as a result of the Tax Act on our deferred tax assets and liabilities in 2017, which resulted in a federal deferred income tax benefit of $144.4 million for the quarter ended December 31, 2017. A reconciliation of tax expense (benefit) based upon the statutory federal income tax rate to the actual income tax expense (benefit)is as follows: For the year ended December 31, (in thousands) 2017 2016 2015 Income tax expense (benefit) at the federal statutory rate (35%) $ 40,078 $ (15,245 ) $ (10,478 ) State income tax expense (benefit), net of federal tax benefit 1,493 318 (1,322 ) Impact of enacted legislation (144,361 ) — — Equity-based compensation (4,386 ) — — Research and development credit (10,478 ) (3,804 ) — Other 26 25 117 Provision for (benefit from) income taxes $ (117,628 ) $ (18,706 ) $ (11,683 ) The components of the Company’s deferred tax assets and liabilities are as follows: For the year ended December 31, (in thousands) 2017 2016 (2) Non-current deferred tax assets: Net operating loss carryforwards (subject to 20 year expiration) (1) $ 101,220 $ 88,632 Tax credit carryforwards 16,856 9,320 Other 14,615 13,185 Total noncurrent deferred tax assets 132,691 111,137 Non-current deferred tax liabilities: Oil and natural gas properties and equipment (343,259 ) (433,792 ) Total noncurrent deferred tax liabilities (343,259 ) (433,792 ) Net noncurrent deferred tax liabilities $ (210,568 ) $ (322,655 ) (1) Federal NOL carryforwards totaled $482.0 million and $251.6 million at December 31, 2017 and 2016 , respectively, and will begin to expire in 2034. As a result of the Tax Act, maximum deduction allowed for NOL carryforwards arising in tax years beginning after December 31, 2017 will be reduced to 80% of our taxable income, and any NOLs generated in tax years beginning after December 31, 2017 will be carried forward indefinitely. (2) The deferred tax liability at December 31, 2016 was reduced by $0.6 million from the previously reported amount as a result of the adoption of ASU 2016-09. See Note 2 for additional discussion of ASU 2016-09. We have not recognized any interest and penalties relating to unrecognized tax benefits in our consolidated financial statements. Changes in the balance of unrecognized tax benefits on uncertain positions were as follows: For the year ended December 31, (in thousands) 2017 2016 2015 Unrecognized tax benefits at beginning of period $ 9,035 $ — $ — Increase resulting from prior period tax positions 6,653 8,483 — Increase resulting from current period tax positions 7,370 552 — Unrecognized tax benefits at the end of period 23,058 9,035 — Less: Effects of temporary items (3,729 ) (5,256 ) — Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year $ 19,329 $ 3,779 $ —

Major Customers and Suppliers

Major Customers and Suppliers	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Major Customers and Suppliers	MAJOR CUSTOMERS AND SUPPLIERS The Company believes, due to the competitive nature of goods and services supporting the oil and natural gas industry, plus access to several marketing alternatives, that it is not significantly dependent on any single purchaser. The following purchasers accounted for 10% or greater of total revenues for the periods indicated: Percentage of Total Revenues for the Year Ended December 31, 2017 2016 2015 Western Refining 21 % * * Enterprise Crude Oil LLC 21 % 27 % 12 % Shell Trading (US) Company 14 % 23 % 37 % Phillips 66 Company * * 22 % Diamondback E&P, LLC * * 13 % * These purchasers did not account for 10% or more of total revenues for the periods indicated. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company’s purchasers are credit worthy and that the loss of any single purchaser would not significantly impact the Company due to the presence of a large number of additional potential purchasers.

Supplemental Disclosure of Oil

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited)	SUPPLEMENTAL DISCLOSURE OF OIL AND NATURAL GAS OPERATIONS (UNAUDITED) Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the years ended December 31: (in thousands) 2017 (1) 2016 (1) 2015 Property acquisition costs: Proved $ 339,895 $ 210,977 $ 104,532 Unproved 1,253,326 1,063,109 351,806 Exploration costs — 1,811 — Development costs 675,988 293,833 378,910 Total costs incurred $ 2,269,209 $ 1,569,730 $ 835,248 (1) Includes acquisition costs related to the issuance of stock directly to the sellers in the SHEP I acquisition in 2016 and SHEP II acquisition in 2017. See Note 3 for further discussion of the SHEP I and SHEP II acquisitions. Capitalized Oil and Natural Gas Costs Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are presented below for the years ended December 31: (in thousands) 2017 2016 Capitalized costs: Proved $ 3,936,565 $ 2,811,853 Unproved 2,865,952 1,833,928 Total capitalized costs $ 6,802,517 $ 4,645,781 Less accumulated depreciation, depletion, amortization and impairment (778,596 ) (554,419 ) Net capitalized costs $ 6,023,921 $ 4,091,362 Net Proved Oil and Natural Gas Reserves The Company’s proved oil, NGLs and natural gas reserves as of December 31, 2017 and December 31, 2015 were audited by independent third party engineers. The Company’s proved oil, NGLs and natural gas reserves as of December 31, 2016 were prepared by independent third party reserve engineers. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates may change as future information becomes available. In accordance with SEC regulations, reserves at December 31, 2017, 2016, and 2015 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Prices were adjusted for quality, transportation fees and regional differentials. The following table summarizes the average first-day-of-the-month prices utilized in the reserve estimates for 2017, 2016 and 2015. Year Ended December 31, 2017 2016 2015 Oil per Bbl $ 51.34 $ 42.75 $ 50.28 Natural gas per MMBtu $ 2.98 $ 2.48 $ 2.59 NGLs per Bbl $ 17.74 $ 11.19 $ 10.56 An analysis of the change in estimated quantities of oil, NGLs and natural gas reserves, all of which are located within the United States, for the years ended December 31, 2017, 2016, and 2015 is as follows: Oil Natural Gas (MMcf) NGLs (MBbls) MBoe Proved developed and undeveloped reserves: As of January 1, 2015 69,273 92,422 21,739 106,416 Revisions of previous estimates (12,886 ) (20,205 ) (4,251 ) (20,505 ) Extensions and discoveries 50,375 55,313 6,971 66,565 Purchases of minerals in place 10,178 10,968 2,373 14,379 Production (5,805 ) (4,991 ) (1,045 ) (7,682 ) As of December 31, 2015 111,135 133,507 25,787 159,173 Revisions of previous estimates (14,115 ) (30,284 ) 1,412 (17,750 ) Extensions and discoveries 46,017 45,541 11,631 65,238 Purchases of minerals in place 29,481 35,210 5,551 40,900 Production (7,790 ) (7,188 ) (1,685 ) (10,673 ) As of December 31, 2016 164,728 176,786 42,696 236,888 Revisions of previous estimates 11,130 25,889 3,075 18,520 Extensions and discoveries 64,925 73,698 16,009 93,217 Purchases of minerals in place 34,997 33,772 6,859 47,485 Production (14,445 ) (15,126 ) (3,202 ) (20,168 ) As of December 31, 2017 261,335 295,019 65,437 375,942 Proved developed reserves: December 31, 2015 44,128 56,640 11,020 64,588 December 31, 2016 65,025 76,255 18,759 96,493 December 31, 2017 106,668 133,116 30,162 159,016 Proved undeveloped reserves: December 31, 2015 67,007 76,867 14,767 94,585 December 31, 2016 99,703 100,531 23,937 140,395 December 31, 2017 154,667 161,903 35,275 216,926 The tables above include changes in estimated quantities of oil, NGLs and natural gas reserves shown in MBbl equivalents (“MBoe”) at a rate of six MMcf per one MBbl. For the year ended December 31, 2017, our extensions and discoveries of 93,217 Mboe were primarily the result of our continued horizontal drilling program in both the Midland Basin and Delaware Basin. This includes 65,657 Mboe of new proved undeveloped locations added during the year. The purchases of minerals in place of 47,485 Mboe were primarily related to the SHEP II acquisition that closed in March 2017, as further described in Note 3. Positive revisions of previous estimates of 18,520 Mboe were primarily related to modified spacing in certain sections, improved performance on certain wells based on additional historical results incorporated to our reserve estimates and higher prices. For the year ended December 31, 2016, our negative revisions of previously estimated quantities of 17,750 MBoe were primarily due to the removal of certain vertical PUDs as these locations will be replaced with horizontal wells when drilled in the future. The negative revisions of previously estimated quantities due to pricing were 2,131 MBoe. Extensions and discoveries of 65,238 MBoe during 2016 resulted primarily from the drilling of new wells during the year to delineate our acreage position. The purchase of minerals in place of 40,900 MBoe during 2016 included our acquisition of SHEP I that closed in November 2016, as further described in Note 3. For the year ended December 31, 2015, our negative revisions of previously estimated quantities of 20,505 MBoe were primarily due to negative revisions of 19,641 MBoe due to pricing. Extensions and discoveries of 66,565 MBoe during 2015 resulted primarily from the drilling of new wells during the year and from new proved undeveloped locations added during the year. The purchase of minerals in place of 14,379 MBoe during 2015 were related to several acquisitions during the year, as described in Note 3. Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGLs and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2017, 2016, and 2015 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12 -month period. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10% . The standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves is as follows at December 31: (in thousands) 2017 2016 2015 Future cash inflows $ 14,634,925 $ 7,433,650 $ 5,964,332 Future production costs (3,867,816 ) (2,352,287 ) (1,855,044 ) Future development costs (1,893,108 ) (1,315,835 ) (1,187,244 ) Future income tax expense (1,553,250 ) (659,105 ) (699,070 ) Future net cash flows 7,320,751 3,106,423 2,222,974 10% discount for estimated timing of cash flows (4,289,975 ) (1,913,027 ) (1,426,958 ) Standardized measure of discounted future net cash flows $ 3,030,776 $ 1,193,396 $ 796,016 It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. Changes in the standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves are as follows: (in thousands) 2017 2016 2015 Standardized measure of discounted future net cash flows, beginning of year $ 1,193,396 $ 796,016 $ 876,131 Changes in the year resulting from: Sales, less production costs (631,907 ) (279,603 ) (210,874 ) Revisions of previous quantity estimates 200,298 (142,956 ) (192,081 ) Extensions and discoveries 967,933 390,752 440,744 Net change in prices and production costs 803,662 (251,166 ) (537,613 ) Changes in estimated future development costs 43,130 156,162 14,480 Previously estimated development costs incurred during the period 162,759 68,238 107,829 Purchases of minerals in place 377,822 244,977 95,207 Accretion of discount 141,887 86,109 131,764 Net change in income taxes (381,109 ) 15,059 164,377 Timing differences and other 152,905 109,808 (93,948 ) Standardized measure of discounted future net cash flows, end of year $ 3,030,776 $ 1,193,396 $ 796,016 Estimates of economically recoverable oil, NGLs and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	QUARTERLY FINANCIAL DATA (Unaudited) The following are summarized quarterly financial data for the years ended December 31, 2017 and 2016: First Second Third Fourth (in thousands, except per share amounts) Quarter Quarter Quarter Quarter 2017 Revenues $ 169,931 $ 183,100 $ 201,654 $ 249,023 Operating income (1) 55,389 54,887 67,077 55,457 Net gain (loss) on derivative instruments 17,121 12,194 (21,626 ) (46,968 ) Income tax (expense) benefit (15,072 ) (17,072 ) (3,678 ) 153,450 Net income $ 38,934 $ 31,090 $ 21,326 $ 140,786 Earnings per share: Basic $ 0.27 $ 0.20 $ 0.14 $ 0.89 Diluted $ 0.26 $ 0.20 $ 0.14 $ 0.89 2016 Revenues $ 55,815 $ 81,485 $ 93,621 $ 122,934 Operating income (loss) (2) (14,342 ) 2,295 13,248 29,892 Net gain (loss) on derivative instruments 396 (3,684 ) (2,934 ) (17,538 ) Income tax benefit 9,298 4,438 3,507 1,464 Net income (loss) $ (17,416 ) $ (9,801 ) $ 985 $ 1,381 Earnings (loss) per share: Basic $ (0.17 ) $ (0.10 ) $ 0.01 $ 0.01 Diluted $ (0.17 ) $ (0.10 ) $ 0.01 $ 0.01 (1) Operating income for the second and fourth quarters of 2017 includes $5.3 million and $ 52.9 million , respectively, of impairments of unproved properties. Operating income for the first quarter of 2017 also includes $4.1 million of acquisition costs primarily related to the SHEP II acquisition. (2) Operating income (loss) includes $6.4 million of acquisition costs recorded during the fourth quarter of 2016 primarily related to the Silver Hill acquisitions.

Summary of Significant Accoun20

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These consolidated financial statements have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and are presented in accordance with generally accepted accounting principles in the United States (“GAAP”). They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation. The consolidated financial statements of the Company include the accounts of the Company and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. Subsequent Events During the first quarter of 2018, we entered into additional derivative contracts covering 698,000 barrels of oil for 2018 and 2.6 million barrels of oil for 2019. See Note 4 for a summary of derivative positions entered into subsequent to December 31, 2017.
Use of Estimates	Use of Estimates The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities in the financial statements and accompanying notes. The more significant estimates pertain to proved oil, NGLs and natural gas reserves, asset retirement obligations (“AROs”), equity-based compensation, estimates relating to oil, natural gas liquids (“NGLs”) and natural gas revenues and expenses, accrued liabilities, the fair market value of assets and liabilities acquired in business combinations, derivatives and income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. Changes in estimates are recorded prospectively. Significant assumptions are required in the valuation of proved oil, NGLs and natural gas reserves that may affect the amount at which oil and natural gas properties are recorded. Depletion of oil and natural gas properties are determined using estimates of proved oil, NGLs and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price estimates. It is possible that these estimates could be revised at future dates and these revisions could be material.
Reclassifications	Reclassifications Certain reclassifications have been made to prior periods to conform to current period presentation.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that exceed the insurance limits of the Federal Deposit Insurance Corporation; however, the Company believes that the counterparties risks are minimal based on the reputation and history of the financial institutions where the deposits are held.
Accounts Receivable	Accounts receivable, which are primarily from the sale of oil, NGLs and natural gas, are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. In addition, settled but uncollected derivative contracts, receivables related to joint interest billings and income tax receivables are included in accounts receivable. The Company routinely reviews outstanding balances, assesses the financial strength of its customers 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, historical losses, existing economic conditions and other pertinent factors.
Oil and Natural Gas Properties	In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well, and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. As of December 31, 2017 and December 31, 2016 , there were no costs capitalized in connection with exploratory wells in progress. Proved oil and natural gas properties are evaluated for impairment annually or whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows available which is the level at which depletion is calculated. To determine if an asset is impaired, the Company compares the carrying value of the asset to the undiscounted future net cash flows by applying estimates of future oil, NGLs and natural gas prices to the estimated future production of oil, NGLs and natural gas reserves over the economic life of the asset and deducting future costs. Future net cash flows are based upon our reservoir engineers’ estimates of proved reserves and risk-adjusted probable reserves. For a property determined to be impaired, an impairment loss equal to the difference between the asset’s carrying value and its estimated fair value is recognized. Fair value is estimated to be the present value of the aforementioned expected future net cash flows. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future net cash flows and fair value. No impairment of proved property was recorded for the years ended December 31, 2017 or 2016. For the year ended December 31, 2015, we impaired approximately $19.6 million of proved oil and natural gas properties, which related to properties whose discounted future net revenues were less than the property’s carrying value. The calculation of expected future net cash flows in impairment evaluations are primarily based on estimates of future oil and natural gas prices, proved reserves and risk-adjusted probable reserve quantities, and estimates of future production and capital costs associated with our proved and risk-adjusted probable reserves. The Company’s estimates for future oil and natural gas prices used in the impairment evaluations are based on observable prices for the next three years, and then held constant for the remaining lives of the properties. Unproved property costs and related leasehold expirations are assessed quarterly for potential impairment and when industry conditions dictate an impairment may be possible. Oil and Natural Gas Properties The Company uses the successful efforts method of accounting for its oil and natural gas exploration and production activities. Costs incurred by the Company related to the acquisition of oil and natural gas properties and the cost of drilling development wells and successful exploratory wells are capitalized, while the costs of unsuccessful exploratory wells are expensed when determined to be unsuccessful. The Company may capitalize interest on expenditures for significant exploration and development projects that last more than six months , while activities are in progress to bring the assets to their intended use. The Company has not capitalized any interest as projects generally lasted less than six months . Costs incurred to maintain wells and related equipment, lease and well operating costs and other exploration costs are expensed as incurred. Gains and losses arising from the sale of properties are generally included in operating income. Capitalized acquisition costs attributable to proved oil and natural gas properties and leasehold costs are depleted using the unit-of-production method based on proved reserves. Capitalized exploration well costs and development costs, including AROs, are depleted using the unit-of-production method based on proved developed reserves. For the years ended December 31, 2017 , 2016 , and 2015, depletion expense for oil and natural gas producing property was $277.0 million , $192.8 million , and $152.8 million , respectively. Depletion expense is included in depreciation, depletion and amortization in the accompanying consolidated statements of operations.
Asset Retirement Obligation	Asset Retirement Obligation The Company records AROs related to the retirement of long-lived assets at the time a legal obligation is incurred and the liability can be reasonably estimated. AROs are recorded as long-term liabilities with a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related asset is allocated to expense through depletion of the asset. Changes in the liability due to passage of time are generally recognized as an increase in the carrying amount of the liability and as corresponding accretion expense. The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future down-hole plugging, dismantlement and removal of production equipment and facilities, and the restoration and reclamation of the surface acreage to a condition similar to that existing before oil and natural gas extraction began. In general, the amount of ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an estimated credit adjusted rate. If the estimated ARO changes, an adjustment is recorded to both the ARO liability and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. After recording these amounts, the ARO liability is accreted to its future estimated value using the same assumed credit adjusted rate and the associated capitalized costs are depreciated on a unit-of-production basis.
Equity-based Compensation	Equity-based Compensation Equity-based compensation expense is recognized in our consolidated statements of operations over the awards’ vesting period based on their estimated fair values on the dates of grant. The Company utilizes the grant date’s closing stock price for the fair value of restricted stock awards and the Monte Carlo simulation method for the fair value of performance-based restricted stock awards. See Note 8 for additional discussion of our equity-based compensation.
Income Taxes	Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of enacted tax laws. Tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. The Company’s policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At December 31, 2016, the Company had a long-term tax payable related to uncertain tax positions totaling $5.3 million . This amount was recorded in other long term liabilities on the consolidated balance sheet. In the fourth quarter of 2017, the Company decreased the liability associated with uncertain tax positions to $0.4 million due to return to provision adjustments and current year positions, which resulted in a current tax benefit offset by deferred tax expense with no impact to total tax expense. We expect all taxes recorded related to uncertain tax positions to ultimately be refundable due to the Tax Act. The Company’s U.S. federal income tax returns for 2014 and beyond, and its Texas franchise tax returns for 2013 and beyond, remain subject to examination by the taxing authorities. No other jurisdiction’s returns are significant to the Company’s financial position. Income Taxes On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) was enacted, which made significant changes to U.S. federal income tax law affecting RSP Inc. Beginning January 1, 2018, our income will be taxed at a 21% federal corporate tax rate, a reduction from the 35% federal corporate tax rate in place prior to the Tax Act. We recognized the effect of this rate change on our deferred tax assets and liabilities in 2017, which resulted in a non-cash decrease to the income tax provision of $144.4 million for the quarter ended December 31, 2017. This one-time adjustment was recorded as an income tax benefit in the “Income tax benefit” line item in our consolidated statements of operations, and reduced our deferred tax liability on our consolidated balance sheet by the same amount. The Tax Act also repealed the corporate alternative minimum tax (“AMT”) for tax years beginning January 1, 2018. AMT credit carryovers as of December 31, 2017 are refundable beginning in 2018. At December 31, 2017, we had no AMT credit carryovers that are expected to be refunded as a result of the Tax Act. In addition, the Tax Act reduces the maximum deduction for net operating loss (“NOL”) carryforward arising in tax years beginning after 2017 to 80% of our taxable income, and allows any NOLs generated in tax years beginning after December 31, 2017 to be carried forward indefinitely and generally repeals carrybacks. NOLs available for utilization as of December 31, 2017 were approximately $482.0 million . The Tax Act is a comprehensive bill containing several other provisions, such as limitations on the deductibility of interest expense, bonus depreciation and certain executive compensation changes, that are not expected to materially impact our financial statements. Staff Accounting Bulletin No. 118 (“SAB 118”) provides a one-year measurement period from a registrant’s reporting period that includes the Tax Act’s enactment date to allow the registrant sufficient time to obtain, prepare and analyze information to complete the required accounting under Accounting Standards Codification (“ASC”) Topic 740, Income Taxes (“ASC 740”). The ultimate impact of the Tax Act on our reported results in fiscal 2018 and beyond may differ from the estimates provided herein, possibly materially, due to, among other things, changes in interpretations and assumptions we have made, guidance that may be issued, and other actions we may take as a result of the Tax Act. See Note 10 for additional information.
Revenue Recognition	Revenue Recognition The Company records oil, NGLs and natural gas sales when title passes to the purchaser, which for the Company is primarily at the wellhead. Oil and natural gas production imbalances, which there were none, are accounted for using the sales method. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”).
Segment Reporting	Segment Reporting The Company operates in only one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
New Accounting Pronouncements	New Accounting Pronouncements In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. Under ASU 2017-01, an entity must first determine whether substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar assets. If this threshold is met, the set is not a business. If it’s not met, the entity then evaluates whether the set meets the requirement that a business include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs. We will apply the guidance in ASU 2017-07 for asset acquisitions occurring subsequent to January 1, 2018. The adoption of ASU 2017-01 will impact the process that the Company uses to evaluate whether the Company has acquired a business or an asset. This update will be applied prospectively and will not have an effect on prior acquisitions. In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 simplifies several aspects of the accounting for share-based payment award transactions. These simplifications include the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The Company adopted this guidance in the first quarter of 2017 using the modified retrospective approach. Accordingly, the deferred tax liability at December 31, 2016 was reduced by $0.6 million with a corresponding adjustment to accumulated deficit in the consolidated balance sheet. Additional tax deductions during 2017 from stock compensation under the guidance of ASU 2016-09 resulted in a reduction to income tax expense of $4.4 million . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”). ASU 2016-02 generally requires all lease transactions (with terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities. Public entities are required to apply ASU 2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. Revenue from Contracts with Customers (Topic 606) - ASU 2014-09 In May 2014, the FASB issued ASU 2014-09. ASU 2014-09 provides a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance including industry specific guidance. The new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We have selected the modified retrospective method. We are in the final stages of assessing the impact of adoption of the standard on our consolidated financial statements. We do not believe the adoption of ASU 2014-09 will have a material impact, if any, on our operating income, cash flows or stockholders’ equity. However, the adoption of this guidance is expected to result in certain reclassifications of gathering costs attributable to NGLs and natural gas revenues due to the conclusion that the Company meets the definition of an agent under the control model defined in ASU 2014-09 for certain of its gas processing and purchase contracts. Our conclusions are subject to change, and we continue to review our implementation documentation and finalize our impact assessment. Our evaluation of the new disclosure requirements is ongoing, and we expect that our disclosures surrounding revenue recognition will be more robust upon adoption of ASU 2014-09.
Derivatives	Commodity Derivative Instruments The Company uses derivative instruments to manage its exposure to cash-flow variability from commodity-price risk inherent in its oil and natural gas production. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current period earnings. Our commodity derivatives have historically been comprised of the following instruments: Collars : Each collar transaction has an established price floor and ceiling, and certain collar transactions also include a short put. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is below the short put price, the Company receives from its counterparty an amount equal to the difference of the price floor and the short put price multiplied by the hedged contract volume.
Fair Value Measurement	Fair value of other financial instruments Our financial instruments include cash and cash equivalents, accounts receivable and payable and accrued liabilities. The carrying amount of these instruments approximates fair value because of their short-term nature. The carrying value of our borrowings under our Revolving Credit Facility approximate fair value as these are subject to short-term floating interest rates that approximate the rates available to us for those periods. The estimated fair values of our senior notes are presented below. The estimated fair value of our senior unsecured notes due January 15, 2025 (“2025 Senior Notes”) and senior unsecured notes due October 1, 2022 (“2022 Senior Notes”) have been calculated based on quoted prices in active markets and are classified as Level 1 on December 31, 2017 . As described in Note 6, the 2025 Senior Notes were initially issued through a private placement, and were exchanged for registered notes with the same terms in November 2017. As such, prior to November 2017, the estimated fair value of the 2025 Senior Notes were classified as Level 2 as these notes did not trade in active markets. Reclassifications of fair value among 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 among Level 1, Level 2 or Level 3 during the years ended December 31, 2017 and 2016 , except that the 2025 Senior Notes were reclassified to Level 1. The following table presents a summary of the estimated fair value of our senior notes as of December 31, 2017 and 2016. December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Total fair value 2025 Senior Notes $ 464,022 $ — $ — $ 464,022 2022 Senior Notes 734,706 — — 734,706 December 31, 2016 Level 1 Level 2 Level 3 Total fair value 2025 Senior Notes $ 452,300 $ — $ — $ 452,300 2022 Senior Notes — 735,000 — 735,000 Nonfinancial Assets and Liabilities Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. The inputs used to determine such fair value are primarily based upon assumptions of the estimated current abandonment costs, discount rate, inflation rate and timing associated with the incurrence of these costs. Our estimated abandonment costs are obtained primarily from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition or costs incurred historically for similar work. Additions to the Company’s AROs represent a nonrecurring Level 3 measurement. The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows: • Level 1—Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. • Level 2—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. • Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs that are not corroborated by market data and may reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Fair value of commodity derivative instruments The fair value of derivative financial instruments is determined utilizing industry standard models incorporating assumptions and inputs, most of 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.

Summary of Significant Accoun21

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Schedule of Accounts Receivable	As of December 31, (in thousands) 2017 2016 Sale of oil, natural gas and NGLs $ 95,942 $ 54,422 Joint interest owners 14,880 16,681 Federal income tax receivable 335 2,568 Accounts receivable $ 111,157 $ 73,671
Schedule of Oil and Natural Gas Properties	The Company’s oil and natural gas properties as of December 31, 2017 and December 31, 2016 consisted of the following: (in thousands) December 31, 2017 December 31, 2016 Proved oil and natural gas properties $ 3,936,565 $ 2,811,853 Unproved oil and natural gas properties 2,865,952 1,833,928 Total oil and natural gas properties 6,802,517 4,645,781 Less: Accumulated depletion (778,596 ) (554,419 ) Total oil and natural gas properties, net $ 6,023,921 $ 4,091,362 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are presented below for the years ended December 31: (in thousands) 2017 2016 Capitalized costs: Proved $ 3,936,565 $ 2,811,853 Unproved 2,865,952 1,833,928 Total capitalized costs $ 6,802,517 $ 4,645,781 Less accumulated depreciation, depletion, amortization and impairment (778,596 ) (554,419 ) Net capitalized costs $ 6,023,921 $ 4,091,362
Schedule of Accounts Payable and Accrued Liabilities	Accrued expenses consist of the following: As of December 31, (in thousands) 2017 2016 Accrued capital expenditures $ 82,748 $ 36,343 Other accrued expenses 36,691 16,849 Accrued expenses $ 119,439 $ 53,192
Schedule of Changes in Asset Retirement Obligation	The ARO liability consisted of the following for the period indicated: Year Ended December 31, 2017 (in thousands) 2017 2016 Asset retirement obligation at beginning of period $ 10,659 $ 7,063 Liabilities incurred or assumed 4,780 3,154 Liabilities settled (195 ) (30 ) Accretion expense 605 472 Asset retirement obligation at end of period $ 15,849 $ 10,659
Schedule of Income Tax Expense	The following is an analysis of the Company’s consolidated income tax (benefit) expense for the periods indicated: Year Ended December 31, (in thousands) 2017 2016 2015 Current $ (5,541 ) $ (4,074 ) $ 5,184 Deferred (112,087 ) (14,632 ) (16,867 ) Income Tax Benefit $ (117,628 ) $ (18,706 ) $ (11,683 ) The components of the provision for income taxes for the year ended December 31, 2017, 2016, and 2015 is as follows: For the year ended December 31, (in thousands) 2017 2016 2015 Current Income Tax Expense (Benefit): Federal $ (5,541 ) $ (4,074 ) $ 5,504 State — — (320 ) Total income tax expense (benefit) (5,541 ) (4,074 ) 5,184 Deferred Income Tax Expense (Benefit): Federal (1) $ (119,925 ) $ (19,195 ) $ (9,649 ) State 2,297 489 (1,714 ) Federal alternative minimum tax 5,541 4,074 (5,504 ) Total deferred income tax benefit (112,087 ) (14,632 ) (16,867 ) Total Income Tax Benefit $ (117,628 ) $ (18,706 ) $ (11,683 )

Acquisitions of Oil and Natur22

Acquisitions of Oil and Natural Gas Property Interests Acquisitions of Oil and Natural Gas Property Interests (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Summary of considerations transferred and fair value of assets and liabilities acquired	A summary of the consideration transferred and the fair value of assets and liabilities acquired in the Silver Hill acquisitions is as follows: Purchase Price Allocation (in thousands) SHEP I SHEP II Total Value of the Company’s common stock issued (1) $ 595,919 $ 663,854 $ 1,259,773 Cash paid to sellers (including deposits) 531,196 641,577 1,172,773 Total consideration for the assets contributed $ 1,127,115 $ 1,305,431 $ 2,432,546 Fair value of oil and natural gas properties $ 1,200,632 $ 1,308,177 $ 2,508,809 Asset retirement obligation (666 ) (822 ) (1,488 ) Assumption of debt (63,826 ) — (63,826 ) Assumption of other liabilities (9,025 ) (1,924 ) (10,949 ) Total net assets acquired (2) $ 1,127,115 $ 1,305,431 $ 2,432,546 (1) The Company issued 14,980,362 shares of common stock at $39.78 per share (closing price) on November 28, 2016 in the SHEP I acquisition. The Company issued 16,019,638 shares of common stock at $41.44 per share (closing price) on March 1, 2017 in the SHEP II acquisition. (2) Approximately 85% and 77% of the acquisition date fair value of oil and natural gas properties was recorded as unproved property in the SHEP I and SHEP II acquisitions, respectively.
Schedule of Pro Forma Results (Unaudited)	The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. Year Ended December 31, 2017 Year Ended December 31, 2016 (in thousands) Actual Pro Forma Actual Pro Forma Revenues $ 803,708 $ 822,427 $ 353,857 $ 415,945 Net income (loss) 232,136 240,596 (24,851 ) (16,757 ) Earnings (loss) per common share: Basic $ 1.50 $ 1.55 $ (0.23 ) $ (0.11 ) Diluted $ 1.49 $ 1.55 $ (0.23 ) $ (0.11 )

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions	The following table summarizes all commodity derivative positions entered subsequent to December 31, 2017: Contracts expiring in the period ending: March 31, 2018 June 30, 2018 September 30, 2018 December 31, 2018 2019 Oil Costless Collars: Notional volume (Bbl) — — — — 1,277,500 Weighted average ceiling price ($/Bbl) $ — $ — $ — $ — $ 60.10 Weighted average floor price ($/Bbl) $ — $ — $ — $ — $ 55.00 Oil Swaps: Notional volume (Bbl) — 698,000 — — 1,277,500 Weighted average swap price ($/Bbl) $ — $ 62.97 $ — $ — $ 58.06 Mid-Cush Differential (Basis) Swaps: Notional volume (Bbl) 531,000 819,000 828,000 828,000 1,825,000 Weighted average swap price ($/Bbl) $ (0.01 ) $ (0.01 ) $ (0.01 ) $ (0.01 ) $ (0.30 ) The following table summarizes all open positions as of December 31, 2017 : Contracts expiring in the period ending: March 31, 2018 June 30, 2018 September 30, 2018 December 31, 2018 2019 Oil Three-Way Collars: Notional volume (Bbl) 2,219,000 1,941,000 1,319,000 1,227,000 — Weighted average ceiling price ($/Bbl)(1) $ 58.81 $ 59.07 $ 60.56 $ 60.96 $ — Weighted average floor price ($/Bbl)(1) $ 46.96 $ 47.11 $ 47.79 $ 48.00 $ — Weighted average short put price ($/Bbl)(1) $ 36.96 $ 37.11 $ 37.79 $ 38.00 $ — Oil Costless Collars: Notional volume (Bbl) 571,000 516,000 1,212,000 1,058,000 1,277,500 Weighted average ceiling price ($/Bbl)(1) $ 60.19 $ 60.20 $ 60.10 $ 60.11 $ 55.99 Weighted average floor price ($/Bbl)(1) $ 45.00 $ 45.00 $ 46.33 $ 46.52 $ 50.00 Oil Swaps: Notional volume (Bbl) — — 322,000 322,000 1,277,500 Weighted average swap price ($/Bbl)(1) $ — $ — $ 55.77 $ 55.77 $ 53.42 Mid-Cush Differential (Basis) Swaps: Notional volume (Bbl) 1,859,000 1,911,000 1,932,000 1,932,000 730,000 Weighted average swap price ($/Bbl)(2) $ (0.60 ) $ (0.59 ) $ (0.59 ) $ (0.59 ) $ (0.25 ) (1) The oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. (2) The Mid-Cush swap contracts are settled based on the difference in the arithmetic average during the calculation period of WTI MIDLAND ARGUS and WTI ARGUS prices in the Argus Americas Crude publication for the relevant period.
Schedule of Fair Value of Derivative Instruments	The following table presents the fair value of our derivative instruments. Our derivatives are presented as separate line items in our consolidated balance sheets as current and noncurrent derivative instrument assets and liabilities based on the expected settlement dates of the instruments. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of the Company’s master netting arrangements. See Note 5 for further discussion related to the fair value of the Company’s derivatives. Assets Liabilities (in thousands) December 31, 2017 December 31, 2016 December 31, 2017 December 31, 2016 Derivative Instruments: Current amounts Commodity contracts $ 64 $ 11,815 $ 36,566 $ 28,861 Noncurrent amounts Commodity contracts 37 — 5,722 — Total derivative instruments $ 101 $ 11,815 $ 42,288 $ 28,861
Derivative Instruments, Gains (Losses)	The following table represents the Company’s reported gains (losses) on derivative instruments for the periods presented: Year Ended December 31, (in thousands) 2017 2016 2015 Net gain (loss) on derivative instruments $ (39,279 ) $ (23,760 ) $ 20,906
Gross and Net Derivative Assets	The following table presents the Company’s gross and net derivative assets and liabilities. (in thousands) Gross Amount Netting Net December 31, 2017 Derivative instrument assets with right of offset or master netting agreements $ 101 $ (101 ) $ — Derivative instrument liabilities with right of offset or master netting agreements $ (42,288 ) $ 101 $ (42,187 ) December 31, 2016 Derivative instrument assets with right of offset or master netting agreements $ 11,815 $ (11,815 ) $ — Derivative instrument liabilities with right of offset or master netting agreements $ (28,861 ) $ 11,815 $ (17,046 ) (a) To mitigate our risk of loss due to default, we have entered into master netting agreements with counterparties to our commodity derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty.
Gross and Net Derivative Liabilities	The following table presents the Company’s gross and net derivative assets and liabilities. (in thousands) Gross Amount Netting Net December 31, 2017 Derivative instrument assets with right of offset or master netting agreements $ 101 $ (101 ) $ — Derivative instrument liabilities with right of offset or master netting agreements $ (42,288 ) $ 101 $ (42,187 ) December 31, 2016 Derivative instrument assets with right of offset or master netting agreements $ 11,815 $ (11,815 ) $ — Derivative instrument liabilities with right of offset or master netting agreements $ (28,861 ) $ 11,815 $ (17,046 ) (a) To mitigate our risk of loss due to default, we have entered into master netting agreements with counterparties to our commodity derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table presents a summary of the estimated fair value of our commodity derivative instruments as of December 31, 2017 and 2016. (in thousands) Level 1 Level 2 Level 3 Total fair value As of December 31, 2017: Commodity derivative instruments $ — $ (42,187 ) $ — $ (42,187 ) (in thousands) Level 1 Level 2 Level 3 Total fair value As of December 31, 2016: Commodity derivative instruments $ — $ (17,046 ) $ — $ (17,046 ) The following table presents a summary of the estimated fair value of our senior notes as of December 31, 2017 and 2016. December 31, 2017 (in thousands) Level 1 Level 2 Level 3 Total fair value 2025 Senior Notes $ 464,022 $ — $ — $ 464,022 2022 Senior Notes 734,706 — — 734,706 December 31, 2016 Level 1 Level 2 Level 3 Total fair value 2025 Senior Notes $ 452,300 $ — $ — $ 452,300 2022 Senior Notes — 735,000 — 735,000

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long-term debt consists of the following: (in thousands) December 31, 2017 December 31, 2016 Revolving Credit Facility $ 375,000 $ — 5.25% Senior Notes due 2025 450,000 450,000 6.625% Senior Notes due 2022 700,000 700,000 Less: Discount (950 ) (1,150 ) Less: Debt issuance costs (14,922 ) (16,575 ) Total long-term debt $ 1,509,128 $ 1,132,275

Commitments and Contingencies T

Commitments and Contingencies Tables (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Summary of Contractual Obligations	A summary of our contractual obligations as of December 31, 2017 is provided in the following table. Payments Due by Period For the Year Ended December 31, (in thousands) 2018 2019 2020 2021 2022 Thereafter Total Revolving Credit Facility (1) $ — $ — $ — $ 375,000 $ — $ — $ 375,000 5.25% Senior Notes due 2025 (1) — — — — — 450,000 450,000 6.625% Senior Notes due 2022 (1) — — — — 700,000 — 700,000 Interest cost (2) 70,000 70,000 70,000 70,000 58,406 48,221 386,627 Drilling rig commitments (3) 14,375 — — — — — 14,375 Purchase obligations (4) 45,013 16,346 9,180 9,180 1,752 8,654 90,125 Operating lease obligations (5) 2,163 2,032 1,257 1,077 1,119 — 7,648 Asset retirement obligations (6) — — — — — 15,849 15,849 Total $ 131,551 $ 88,378 $ 80,437 $ 455,257 $ 761,277 $ 522,724 $ 2,039,624 (1) The amounts presented in the table above are outstanding principal balances only. The Revolving Credit Facility amount is based on the outstanding borrowing as of December 31, 2017. Principal amount borrowed under the Revolving Credit Facility must be repaid prior to the maturity date of December 19, 2021. Any future advances or repayments could change the total amount outstanding under the Revolving Credit Facility. (2) The amounts include interest costs related to our fixed rate senior notes. The annual interest obligation on the 2025 Senior Notes is $23.6 million , based on the interest rate of 5.25% . The annual interest obligation on the 2022 Senior Notes is $46.4 million , based on the interest rate of 6.625% . The table above does not include interest costs, future commitment fees or other fees on our revolving credit facility, as these obligations are based on floating rates as more fully described in Note 6.

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Restricted Stock Award Activity	The following table represents restricted stock award activity for the years ended December 31, 2017, 2016 and 2015 : 2017 2016 2015 Shares Weighted Average Fair Value Shares Weighted Average Fair Value Shares Weighted Average Fair Value Restricted shares outstanding, beginning of period 656,895 $ 22.21 499,529 $ 25.99 477,767 $ 23.71 Restricted shares granted 379,579 41.39 442,835 19.78 279,181 27.18 Restricted shares canceled (27,400 ) 31.74 (13,551 ) 21.61 (6,640 ) 26.43 Restricted shares vested (321,797 ) 23.01 (271,918 ) 25.22 (250,779 ) 22.97 Restricted shares outstanding, end of period 687,277 $ 32.04 656,895 $ 22.21 499,529 $ 25.99
Schedule of Stock Award Assumptions	The range of assumptions used in the Monte Carlo model for the awards granted in 2017, 2016 and 2015 are as follows: Assumptions 2017 2016 2015 Risk-free rate of return 1.52 % 0.95 % 0.98 % Volatility 28.5 % 54.6 % 49.2 %
Schedule of Performance-Based Restricted Stock Award Activity	The following table represents performance-based restricted stock award activity for the years ended December 31, 2017, 2016 and 2015 : 2017 2016 2015 Shares Weighted Average Fair Value Shares Weighted Average Fair Value Shares Weighted Average Fair Value Restricted shares outstanding, beginning of period 747,874 $ 19.82 294,332 $ 31.41 134,400 $ 28.14 Restricted shares granted (1) 380,174 26.96 484,650 13.53 159,932 31.74 Restricted shares canceled (7,569 ) 26.96 — — — — Restricted shares vested (1) (119,400 ) 31.01 (31,108 ) 31.39 — — Restricted shares outstanding, end of period 1,001,079 $ 21.14 747,874 $ 19.82 294,332 $ 31.41

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Reconciliation of Basic and Diluted Earnings Per Common Share	A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: Year Ended December 31, (in thousands, except per share data) 2017 2016 2015 Numerator: Net income (loss) available to stockholders $ 232,136 $ (24,851 ) $ (18,254 ) Basic net income allocable to participating securities (1) 1,161 — — Income available to stockholders $ 230,975 $ (24,851 ) $ (18,254 ) Denominator: Weighted average number of common shares outstanding - basic 154,162 107,324 86,770 Effect of dilutive securities: Restricted stock 1,364 — — Weighted average number of common shares outstanding - diluted 155,526 107,324 86,770 Net earnings (loss) per share: Basic $ 1.50 $ (0.23 ) $ (0.21 ) Diluted $ 1.49 $ (0.23 ) $ (0.21 ) (1) Restricted stock awards that contain non-forfeitable rights to dividends are participating securities and, therefore, are included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Income Tax Expense	The following is an analysis of the Company’s consolidated income tax (benefit) expense for the periods indicated: Year Ended December 31, (in thousands) 2017 2016 2015 Current $ (5,541 ) $ (4,074 ) $ 5,184 Deferred (112,087 ) (14,632 ) (16,867 ) Income Tax Benefit $ (117,628 ) $ (18,706 ) $ (11,683 ) The components of the provision for income taxes for the year ended December 31, 2017, 2016, and 2015 is as follows: For the year ended December 31, (in thousands) 2017 2016 2015 Current Income Tax Expense (Benefit): Federal $ (5,541 ) $ (4,074 ) $ 5,504 State — — (320 ) Total income tax expense (benefit) (5,541 ) (4,074 ) 5,184 Deferred Income Tax Expense (Benefit): Federal (1) $ (119,925 ) $ (19,195 ) $ (9,649 ) State 2,297 489 (1,714 ) Federal alternative minimum tax 5,541 4,074 (5,504 ) Total deferred income tax benefit (112,087 ) (14,632 ) (16,867 ) Total Income Tax Benefit $ (117,628 ) $ (18,706 ) $ (11,683 )
Reconciliation of the Statutory Federal Income Tax Amount	A reconciliation of tax expense (benefit) based upon the statutory federal income tax rate to the actual income tax expense (benefit)is as follows: For the year ended December 31, (in thousands) 2017 2016 2015 Income tax expense (benefit) at the federal statutory rate (35%) $ 40,078 $ (15,245 ) $ (10,478 ) State income tax expense (benefit), net of federal tax benefit 1,493 318 (1,322 ) Impact of enacted legislation (144,361 ) — — Equity-based compensation (4,386 ) — — Research and development credit (10,478 ) (3,804 ) — Other 26 25 117 Provision for (benefit from) income taxes $ (117,628 ) $ (18,706 ) $ (11,683 )
Schedule of Components of Deferred Tax Assets and Liabilities	The components of the Company’s deferred tax assets and liabilities are as follows: For the year ended December 31, (in thousands) 2017 2016 (2) Non-current deferred tax assets: Net operating loss carryforwards (subject to 20 year expiration) (1) $ 101,220 $ 88,632 Tax credit carryforwards 16,856 9,320 Other 14,615 13,185 Total noncurrent deferred tax assets 132,691 111,137 Non-current deferred tax liabilities: Oil and natural gas properties and equipment (343,259 ) (433,792 ) Total noncurrent deferred tax liabilities (343,259 ) (433,792 ) Net noncurrent deferred tax liabilities $ (210,568 ) $ (322,655 ) (1) Federal NOL carryforwards totaled $482.0 million and $251.6 million at December 31, 2017 and 2016 , respectively, and will begin to expire in 2034. As a result of the Tax Act, maximum deduction allowed for NOL carryforwards arising in tax years beginning after December 31, 2017 will be reduced to 80% of our taxable income, and any NOLs generated in tax years beginning after December 31, 2017 will be carried forward indefinitely. (2) The deferred tax liability at December 31, 2016 was reduced by $0.6 million from the previously reported amount as a result of the adoption of ASU 2016-09. See Note 2 for additional discussion of ASU 2016-09.
Schedule of Unrecognized Tax Benefits	Changes in the balance of unrecognized tax benefits on uncertain positions were as follows: For the year ended December 31, (in thousands) 2017 2016 2015 Unrecognized tax benefits at beginning of period $ 9,035 $ — $ — Increase resulting from prior period tax positions 6,653 8,483 — Increase resulting from current period tax positions 7,370 552 — Unrecognized tax benefits at the end of period 23,058 9,035 — Less: Effects of temporary items (3,729 ) (5,256 ) — Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year $ 19,329 $ 3,779 $ —

Major Customers and Suppliers (

Major Customers and Suppliers (Tables)	12 Months Ended
	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Schedule of Revenue by Major Customer	The following purchasers accounted for 10% or greater of total revenues for the periods indicated: Percentage of Total Revenues for the Year Ended December 31, 2017 2016 2015 Western Refining 21 % * * Enterprise Crude Oil LLC 21 % 27 % 12 % Shell Trading (US) Company 14 % 23 % 37 % Phillips 66 Company * * 22 % Diamondback E&P, LLC * * 13 %

Supplemental Disclosure of Oi31

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Extractive Industries [Abstract]
Cost Incurred in Acquisition and Development of Oil and Natural Gas Assets	Costs incurred in the acquisition and development of oil and natural gas assets are presented below for the years ended December 31: (in thousands) 2017 (1) 2016 (1) 2015 Property acquisition costs: Proved $ 339,895 $ 210,977 $ 104,532 Unproved 1,253,326 1,063,109 351,806 Exploration costs — 1,811 — Development costs 675,988 293,833 378,910 Total costs incurred $ 2,269,209 $ 1,569,730 $ 835,248 (1) Includes acquisition costs related to the issuance of stock directly to the sellers in the SHEP I acquisition in 2016 and SHEP II acquisition in 2017. See Note 3 for further discussion of the SHEP I and SHEP II acquisitions.
Capitalized Costs Related to Oil and Natural Gas Production Activities	The Company’s oil and natural gas properties as of December 31, 2017 and December 31, 2016 consisted of the following: (in thousands) December 31, 2017 December 31, 2016 Proved oil and natural gas properties $ 3,936,565 $ 2,811,853 Unproved oil and natural gas properties 2,865,952 1,833,928 Total oil and natural gas properties 6,802,517 4,645,781 Less: Accumulated depletion (778,596 ) (554,419 ) Total oil and natural gas properties, net $ 6,023,921 $ 4,091,362 Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are presented below for the years ended December 31: (in thousands) 2017 2016 Capitalized costs: Proved $ 3,936,565 $ 2,811,853 Unproved 2,865,952 1,833,928 Total capitalized costs $ 6,802,517 $ 4,645,781 Less accumulated depreciation, depletion, amortization and impairment (778,596 ) (554,419 ) Net capitalized costs $ 6,023,921 $ 4,091,362
Results of Operations of Oil and Natural Gas Producing Activities	The following table summarizes the average first-day-of-the-month prices utilized in the reserve estimates for 2017, 2016 and 2015. Year Ended December 31, 2017 2016 2015 Oil per Bbl $ 51.34 $ 42.75 $ 50.28 Natural gas per MMBtu $ 2.98 $ 2.48 $ 2.59 NGLs per Bbl $ 17.74 $ 11.19 $ 10.56
Schedule of Changes in Estimated Quantities of Oil and Natural Gas Reserves	An analysis of the change in estimated quantities of oil, NGLs and natural gas reserves, all of which are located within the United States, for the years ended December 31, 2017, 2016, and 2015 is as follows: Oil Natural Gas (MMcf) NGLs (MBbls) MBoe Proved developed and undeveloped reserves: As of January 1, 2015 69,273 92,422 21,739 106,416 Revisions of previous estimates (12,886 ) (20,205 ) (4,251 ) (20,505 ) Extensions and discoveries 50,375 55,313 6,971 66,565 Purchases of minerals in place 10,178 10,968 2,373 14,379 Production (5,805 ) (4,991 ) (1,045 ) (7,682 ) As of December 31, 2015 111,135 133,507 25,787 159,173 Revisions of previous estimates (14,115 ) (30,284 ) 1,412 (17,750 ) Extensions and discoveries 46,017 45,541 11,631 65,238 Purchases of minerals in place 29,481 35,210 5,551 40,900 Production (7,790 ) (7,188 ) (1,685 ) (10,673 ) As of December 31, 2016 164,728 176,786 42,696 236,888 Revisions of previous estimates 11,130 25,889 3,075 18,520 Extensions and discoveries 64,925 73,698 16,009 93,217 Purchases of minerals in place 34,997 33,772 6,859 47,485 Production (14,445 ) (15,126 ) (3,202 ) (20,168 ) As of December 31, 2017 261,335 295,019 65,437 375,942 Proved developed reserves: December 31, 2015 44,128 56,640 11,020 64,588 December 31, 2016 65,025 76,255 18,759 96,493 December 31, 2017 106,668 133,116 30,162 159,016 Proved undeveloped reserves: December 31, 2015 67,007 76,867 14,767 94,585 December 31, 2016 99,703 100,531 23,937 140,395 December 31, 2017 154,667 161,903 35,275 216,926
Standardized Measure of Discounted Future Cash Flows Relating to Proved Oil and Natural Gas Reserves	The standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves is as follows at December 31: (in thousands) 2017 2016 2015 Future cash inflows $ 14,634,925 $ 7,433,650 $ 5,964,332 Future production costs (3,867,816 ) (2,352,287 ) (1,855,044 ) Future development costs (1,893,108 ) (1,315,835 ) (1,187,244 ) Future income tax expense (1,553,250 ) (659,105 ) (699,070 ) Future net cash flows 7,320,751 3,106,423 2,222,974 10% discount for estimated timing of cash flows (4,289,975 ) (1,913,027 ) (1,426,958 ) Standardized measure of discounted future net cash flows $ 3,030,776 $ 1,193,396 $ 796,016
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows	Changes in the standardized measure of discounted future net cash flows relating to proved oil, NGLs and natural gas reserves are as follows: (in thousands) 2017 2016 2015 Standardized measure of discounted future net cash flows, beginning of year $ 1,193,396 $ 796,016 $ 876,131 Changes in the year resulting from: Sales, less production costs (631,907 ) (279,603 ) (210,874 ) Revisions of previous quantity estimates 200,298 (142,956 ) (192,081 ) Extensions and discoveries 967,933 390,752 440,744 Net change in prices and production costs 803,662 (251,166 ) (537,613 ) Changes in estimated future development costs 43,130 156,162 14,480 Previously estimated development costs incurred during the period 162,759 68,238 107,829 Purchases of minerals in place 377,822 244,977 95,207 Accretion of discount 141,887 86,109 131,764 Net change in income taxes (381,109 ) 15,059 164,377 Timing differences and other 152,905 109,808 (93,948 ) Standardized measure of discounted future net cash flows, end of year $ 3,030,776 $ 1,193,396 $ 796,016

Quarterly Financial Data (Una32

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Data (Unaudited)	The following are summarized quarterly financial data for the years ended December 31, 2017 and 2016: First Second Third Fourth (in thousands, except per share amounts) Quarter Quarter Quarter Quarter 2017 Revenues $ 169,931 $ 183,100 $ 201,654 $ 249,023 Operating income (1) 55,389 54,887 67,077 55,457 Net gain (loss) on derivative instruments 17,121 12,194 (21,626 ) (46,968 ) Income tax (expense) benefit (15,072 ) (17,072 ) (3,678 ) 153,450 Net income $ 38,934 $ 31,090 $ 21,326 $ 140,786 Earnings per share: Basic $ 0.27 $ 0.20 $ 0.14 $ 0.89 Diluted $ 0.26 $ 0.20 $ 0.14 $ 0.89 2016 Revenues $ 55,815 $ 81,485 $ 93,621 $ 122,934 Operating income (loss) (2) (14,342 ) 2,295 13,248 29,892 Net gain (loss) on derivative instruments 396 (3,684 ) (2,934 ) (17,538 ) Income tax benefit 9,298 4,438 3,507 1,464 Net income (loss) $ (17,416 ) $ (9,801 ) $ 985 $ 1,381 Earnings (loss) per share: Basic $ (0.17 ) $ (0.10 ) $ 0.01 $ 0.01 Diluted $ (0.17 ) $ (0.10 ) $ 0.01 $ 0.01

Nature of Operations and Basi33

Nature of Operations and Basis of Presentation (Narrative) (Details) - Subsequent event - Forecast - bbl	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Oil Swaps
Derivative [Line Items]
Notional volume (Bbl)	1,277,500
Oil Swaps and Collars
Derivative [Line Items]
Notional volume (Bbl)	2,555,000	698,000

Summary of Significant Accoun34

Summary of Significant Accounting Policies (Narrative) (Details)	3 Months Ended		12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2017USD ($)segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Bad debt expense			$ 0	$ 0	$ 0
Minimum project term to capitalize interest			6 months
Depletion expense			$ 277,000,000	192,800,000	152,800,000
Costs capitalized in connection with exploratory wells in progress	$ 0		0	0
Impairment of proved oil and gas properties			0	0	19,600,000
Impairment of unproved oil and gas properties			$ 59,100,000	4,900,000	14,700,000
Accrued liability for uncertain tax positions				5,300,000
Decrease to liability for uncertain tax positions	400,000
Number of segments | segment			1
Operating loss carryforwards	482,000,000		$ 482,000,000	251,600,000
New accounting pronouncement or change in accounting principle, effect of adoption, quantification				584,000
Reduction to deferred taxes	$ (210,568,000)		(210,568,000)	(322,655,000)
Equity-based compensation			$ 4,386,000	0	$ 0
Accounting Standards Update 2016-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reduction to deferred taxes				600,000
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New accounting pronouncement or change in accounting principle, effect of adoption, quantification				584,000
Retained Earnings | Accounting Standards Update 2016-09
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New accounting pronouncement or change in accounting principle, effect of adoption, quantification				$ (600,000)
Board of Directors and Large Shareholders | Wolfberry Partners Resources LLC
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Aggregate purchase price		$ 137,000,000

Summary of Significant Accoun35

Summary of Significant Accounting Policies (Accounts Receivable) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Sale of oil, natural gas and NGLs	$ 95,942	$ 54,422
Joint interest owners	14,880	16,681
Federal income tax receivable	335	2,568
Accounts receivable	$ 111,157	$ 73,671

Summary of Significant Accoun36

Summary of Significant Accounting Policies (Oil and Natural Gas) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Oil and Natural Gas Properties [Abstract]
Proved oil and natural gas properties	$ 3,936,565	$ 2,811,853
Unproved oil and natural gas properties	2,865,952	1,833,928
Oil and natural gas properties, successful efforts method	6,802,517	4,645,781
Less accumulated depreciation, depletion, amortization and impairment	(778,596)	(554,419)
Total oil and natural gas properties, net	$ 6,023,921	$ 4,091,362

Summary of Significant Accoun37

Summary of Significant Accounting Policies (Asset Retirement Obligation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of period	$ 10,659	$ 7,063
Liabilities incurred or assumed	4,780	3,154
Liabilities settled	(195)	(30)
Accretion expense	605	472	$ 336
Asset retirement obligation at end of period	$ 15,849	$ 10,659	$ 7,063

Summary of Significant Accoun38

Summary of Significant Accounting Policies (Income Taxes) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Expense (Benefit) [Abstract]
Current									$ (5,541)	$ (4,074)	$ 5,184
Deferred									(112,087)	(14,632)	(16,867)
Provision for (benefit from) income taxes	$ (153,450)	$ 3,678	$ 17,072	$ 15,072	$ (1,464)	$ (3,507)	$ (4,438)	$ (9,298)	$ (117,628)	$ (18,706)	$ (11,683)

Summary of Significant Accoun39

Summary of Significant Accounting Policies (Accrued Expenses) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Accrued capital expenditures	$ 82,748	$ 36,343
Other accrued expenses	36,691	16,849
Accrued expenses	$ 119,439	$ 53,192

Acquisitions of Oil and Natur40

Acquisitions of Oil and Natural Gas Property Interests - Silver Hill Acquisitions (Details) $ in Thousands	Mar. 01, 2017USD ($)shares	Nov. 28, 2016USD ($)shares	Oct. 13, 2016USD ($)aentityshares	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Cash paid to sellers (including deposits)						$ 19,156	$ 0	$ 0
Acquisition costs						4,525	$ 6,374	$ 0
Silver Hill
Business Acquisition [Line Items]
Percentage of voting interests acquired			100.00%
Cash paid to sellers (including deposits)			$ 1,250,000			1,172,773
Consideration transferred, common stock issued (in shares) | shares			31,000,000
Number of entities held by acquired company | entity			2
Number of developed and undeveloped acres | a			40,100
Acquisition costs					$ 6,400
Post-closing adjustment						5,700
Silver Hill Energy Partners, LLC
Business Acquisition [Line Items]
Cash paid to sellers (including deposits)		$ 531,196
Consideration transferred, common stock issued (in shares) | shares		14,980,362
Payments to acquire businesses, before purchase price adjustments		$ 604,000
Silver Hill E&P II, LLC
Business Acquisition [Line Items]
Cash paid to sellers (including deposits)	$ 641,577
Consideration transferred, common stock issued (in shares) | shares	16,019,638
Payments to acquire businesses, before purchase price adjustments	$ 646,000
Revenue of SHEP II since acquisition date						66,400
Earnings of SHEP II since acquisition date, actual						$ 29,500
Acquisition costs				$ 4,100

Acquisitions of Oil and Natur41

Acquisitions of Oil and Natural Gas Property Interests - Silver Hill Acquisitions Purchase Price Allocation (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 01, 2017	Nov. 28, 2016	Oct. 13, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Cash paid to sellers (including deposits)				$ 19,156	$ 0	$ 0
Silver Hill Energy Partners, LLC
Business Acquisition [Line Items]
Value of the Company’s common stock issued in the SHEP I acquisition		$ 595,919
Cash paid to sellers (including deposits)		531,196
Total consideration for the assets contributed		1,127,115
Fair value of oil and natural gas properties		1,200,632
Asset retirement obligation		(666)
Assumption of debt		(63,826)
Assumption of other liabilities		(9,025)
Total net assets acquired		$ 1,127,115
Consideration transferred, common stock issued (in shares)		14,980,362
Consideration transferred, common stock USD per share		$ 39.78
Percentage of acreage acquired, unproved		85.00%
Silver Hill E&P II, LLC
Business Acquisition [Line Items]
Value of the Company’s common stock issued in the SHEP I acquisition	$ 663,854
Cash paid to sellers (including deposits)	641,577
Total consideration for the assets contributed	1,305,431
Fair value of oil and natural gas properties	1,308,177
Asset retirement obligation	(822)
Assumption of debt	0
Assumption of other liabilities	(1,924)
Total net assets acquired	$ 1,305,431
Consideration transferred, common stock issued (in shares)	16,019,638
Consideration transferred, common stock USD per share	$ 41.44
Percentage of acreage acquired, unproved	77.00%
Silver Hill
Business Acquisition [Line Items]
Value of the Company’s common stock issued in the SHEP I acquisition				1,259,773
Cash paid to sellers (including deposits)			$ 1,250,000	1,172,773
Total consideration for the assets contributed				2,432,546
Fair value of oil and natural gas properties				2,508,809
Asset retirement obligation				(1,488)
Assumption of debt				(63,826)
Assumption of other liabilities				(10,949)
Total net assets acquired				$ 2,432,546
Consideration transferred, common stock issued (in shares)			31,000,000

Acquisitions of Oil and Natur42

Acquisitions of Oil and Natural Gas Property Interests - Other 2017 Acquisitions (Details) $ in Millions	Jan. 02, 2017USD ($)	Sep. 30, 2017USD ($)acqusition	Dec. 31, 2017USD ($)
Delaware Basin
Business Acquisition [Line Items]
Number of businesses acquired | acqusition		2
Aggregate purchase price		$ 227.9
Post-closing adjustment			$ 3.3
Bolt-on Acquisitions
Business Acquisition [Line Items]
Aggregate purchase price			$ 47.8
Lone Wolf Resources
Business Acquisition [Line Items]
Aggregate purchase price	$ 19.2

Acquisitions of Oil and Natur43

Acquisitions of Oil and Natural Gas Property Interests - Other 2016 Acquisitions (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Midland Basin
Business Acquisition [Line Items]
Aggregate purchase price	$ 69.4

Acquisitions of Oil and Natur44

Acquisitions of Oil and Natural Gas Property Interests - WPR Acquisition (Details) - Wolfberry Partners Resources $ in Millions	3 Months Ended
	Dec. 31, 2015USD ($)aBoedrilling_location
Business Acquisition [Line Items]
Aggregate purchase price	$ 137
Costs to acquire proved oil and natural gas properties	$ 41
Number of developed and undeveloped acres | a	4,100
Approximate barrels per day | Boe	1,900
Number of drilling locations | drilling_location	86

Acquisitions of Oil and Natur45

Acquisitions of Oil and Natural Gas Property Interests - Glass Ranch Acquisition (Details) - Martin and Glasscock $ in Millions	3 Months Ended
	Sep. 30, 2015USD ($)a
Business Acquisition [Line Items]
Aggregate purchase price | $	$ 313
Number of undeveloped acres | a	6,548

Acquisitions of Oil and Natur46

Acquisitions of Oil and Natural Gas Property Interests - Pro Forma Results (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Revenues	$ 249,023	$ 201,654	$ 183,100	$ 169,931	$ 122,934	$ 93,621	$ 81,485	$ 55,815	$ 803,708	$ 353,857	$ 283,992
Net income (loss) available to stockholders	$ 140,786	$ 21,326	$ 31,090	$ 38,934	$ 1,381	$ 985	$ (9,801)	$ (17,416)	$ 232,136	$ (24,851)	$ (18,254)
Basic (in dollars per share)	$ 0.89	$ 0.14	$ 0.20	$ 0.27	$ 0.01	$ 0.01	$ (0.10)	$ (0.17)	$ 1.50	$ (0.23)	$ (0.21)
Diluted (in dollars per share)	$ 0.89	$ 0.14	$ 0.20	$ 0.26	$ 0.01	$ 0.01	$ (0.10)	$ (0.17)	$ 1.49	$ (0.23)	$ (0.21)
Pro Forma
Business Acquisition [Line Items]
Pro forma revenues									$ 822,427	$ 415,945
Pro forma net income (loss)									$ 240,596	$ (16,757)
Pro forma earnings per share, basic (USD per share)									$ 1.55	$ (0.11)
Pro forma earnings per share, diluted (USD per share)									$ 1.55	$ (0.11)

Derivative Instruments (Outstan

Derivative Instruments (Outstanding Positions) (Details) - Forecast	3 Months Ended				12 Months Ended
	Dec. 31, 2018$ / bblbbl	Sep. 30, 2018$ / bblbbl	Jun. 30, 2018$ / bblbbl	Mar. 31, 2018$ / bblbbl	Dec. 31, 2019$ / bblbbl
Crude Oil | Oil Collars
Derivative [Line Items]
Notional volume (Bbl) | bbl					0
Weighted average ceiling price (in dollars per Bbl and MMBtu)					0
Weighted average floor price (in dollars per Bbl and MMBtu)					0
Weighted average short put price (in dollars per Bbl)					0
Crude Oil | Oil Collars Maturing in Next Fiscal Year
Derivative [Line Items]
Notional volume (Bbl) | bbl	1,227,000	1,319,000	1,941,000	2,219,000
Weighted average ceiling price (in dollars per Bbl and MMBtu)	60.96	60.56	59.07	58.81
Weighted average floor price (in dollars per Bbl and MMBtu)	48	47.79	47.11	46.96
Weighted average short put price (in dollars per Bbl)	38	37.79	37.11	36.96
Crude Oil | Oil Costless Collars
Derivative [Line Items]
Notional volume (Bbl) | bbl					1,277,500
Weighted average ceiling price (in dollars per Bbl and MMBtu)					55.99
Weighted average floor price (in dollars per Bbl and MMBtu)					50
Crude Oil | Oil Costless Collars Maturing in Next Fiscal Year
Derivative [Line Items]
Notional volume (Bbl) | bbl	1,058,000	1,212,000	516,000	571,000
Weighted average ceiling price (in dollars per Bbl and MMBtu)	60.11	60.10	60.20	60.19
Weighted average floor price (in dollars per Bbl and MMBtu)	46.52	46.33	45	45
Crude Oil | Oil Swaps
Derivative [Line Items]
Notional volume (Bbl) | bbl					1,277,500
Weighted average swap price ($/Bbl)					53.42
Crude Oil | Oil Swaps Maturing in Next Fiscal Year
Derivative [Line Items]
Notional volume (Bbl) | bbl	322,000	322,000	0	0
Weighted average swap price ($/Bbl)	55.77	55.77	0	0
Crude Oil | Mid-Cush Swaps
Derivative [Line Items]
Notional volume (Bbl) | bbl					730,000
Weighted average swap price ($/Bbl)					(0.25)
Crude Oil | Mid-Cush Swaps Maturing in Next Fiscal Year
Derivative [Line Items]
Notional volume (Bbl) | bbl	1,932,000	1,932,000	1,911,000	1,859,000
Weighted average swap price ($/Bbl)	(0.59)	(0.59)	(0.59)	(0.60)
Subsequent event | Oil Costless Collars
Derivative [Line Items]
Notional volume (Bbl) | bbl					1,277,500
Weighted average ceiling price (in dollars per Bbl and MMBtu)					60.10
Weighted average floor price (in dollars per Bbl and MMBtu)					55
Subsequent event | Oil Costless Collars Maturing in Next Fiscal Year
Derivative [Line Items]
Notional volume (Bbl) | bbl	0	0	0	0
Weighted average ceiling price (in dollars per Bbl and MMBtu)	0	0	0	0
Weighted average floor price (in dollars per Bbl and MMBtu)	0	0	0	0
Subsequent event | Oil Swaps
Derivative [Line Items]
Notional volume (Bbl) | bbl					1,277,500
Weighted average swap price ($/Bbl)					58.06
Subsequent event | Oil Swaps Maturing in Next Fiscal Year
Derivative [Line Items]
Notional volume (Bbl) | bbl	0	0	698,000	0
Weighted average swap price ($/Bbl)	0	0	62.97	0
Subsequent event | Mid-Cush Swaps
Derivative [Line Items]
Notional volume (Bbl) | bbl					1,825,000
Weighted average swap price ($/Bbl)					0.30
Subsequent event | Mid-Cush Swaps Maturing in Next Fiscal Year
Derivative [Line Items]
Notional volume (Bbl) | bbl	828,000	828,000	819,000	531,000
Weighted average swap price ($/Bbl)	0.01	0.01	0.01	0.01

Derivative Instruments (Gross A

Derivative Instruments (Gross Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current derivative asset	$ 64	$ 11,815
Current derivative liabilities	36,566	28,861
Non-current derivative asset	37	0
Non-current derivative liabilities	5,722	0
Derivative assets	101	11,815
Derivative liabilities	$ 42,288	$ 28,861

Derivative Instruments (Gain Lo

Derivative Instruments (Gain Loss) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on derivative instruments	$ (46,968)	$ (21,626)	$ 12,194	$ 17,121	$ (17,538)	$ (2,934)	$ (3,684)	$ 396	$ (39,279)	$ (23,760)	$ 20,906
Commodity derivative instruments
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on derivative instruments									$ (39,279)	$ (23,760)	$ 20,906

Derivative Instruments (Offsett

Derivative Instruments (Offsetting Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Offsetting of Derivative Assets and Liabilities [Abstract]
Derivative assets	$ 101	$ 11,815
Derivative asset, netting adjustments	(101)	(11,815)
Derivative asset, net amount	0	0
Derivative liability, gross amount presented on balance sheet	(42,288)	(28,861)
Derivative liability, netting adjustments	101	11,815
Derivative liability, net amount	$ (42,187)	$ (17,046)

Derivative Instruments (Narrati

Derivative Instruments (Narrative) (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Collateral posted for derivative instruments with credit-risk related contingent features	$ 0	$ 0

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) - Senior Notes - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 27, 2016
2022 Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Stated interest rate (percentage)	6.625%
Long-term debt, fair value	$ 734,706	$ 735,000
5.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Stated interest rate (percentage)	5.25%		5.25%
Long-term debt, fair value	$ 464,022	$ 452,300

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Fair Value Meaurement on a Recurring Basis (Details) - Recurring basis - Commodity derivative instruments - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets (liabilities)	$ (42,187)	$ (17,046)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets (liabilities)	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets (liabilities)	(42,187)	(17,046)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets (liabilities)	$ 0	$ 0

Fair Value Measurements - Summa

Fair Value Measurements - Summary of the Estimated Fair Value of Senior Notes (Details) - Senior Notes - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
2025 Senior Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	$ 464,022	$ 452,300
2025 Senior Notes | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	464,022	452,300
2025 Senior Notes | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	0	0
2025 Senior Notes | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	0	0
2022 Senior Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	734,706	735,000
2022 Senior Notes | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	734,706	0
2022 Senior Notes | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	0	735,000
2022 Senior Notes | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, fair value	$ 0	$ 0

Long-Term Debt - Schedule of Lo

Long-Term Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 27, 2016	Sep. 26, 2014
Debt Instrument [Line Items]
Less: Discount	$ (950)	$ (1,150)
Less: Debt issuance costs	(14,922)	(16,575)
Total long-term debt	1,509,128	1,132,275
5.25% Senior Notes due 2025 | Senior Notes
Debt Instrument [Line Items]
Long term debt	$ 450,000	450,000
Stated interest rate (percentage)	5.25%		5.25%
6.625% Senior Notes due 2022 | Senior Notes
Debt Instrument [Line Items]
Stated interest rate (percentage)	6.625%
6.625% Senior Notes due 2022 | Senior Unsecured Notes
Debt Instrument [Line Items]
Long term debt	$ 700,000	700,000
Stated interest rate (percentage)				6.625%
Revolving credit facility | Line of Credit
Debt Instrument [Line Items]
Long term debt	$ 375,000	$ 0

Long-Term Debt - Revolving Cred

Long-Term Debt - Revolving Credit Facility (Details) $ in Thousands	Oct. 18, 2017USD ($)	Dec. 31, 2017USD ($)financial_ratio	Oct. 19, 2017USD ($)	Dec. 31, 2016USD ($)
Line of Credit Facility [Line Items]
Letters of credit outstanding		$ 1,900
Revolving credit facility
Line of Credit Facility [Line Items]
Credit agreement, maximum borrowing capacity	$ 1,100,000	1,500,000	$ 1,500,000
Maximum borrowing capacity, elected commitment		900,000
Credit agreement, remaining borrowing capacity		$ 523,100
Number of financial ratios | financial_ratio		2
Credit agreement, maximum borrowing capacity, lender commitments		$ 2,500,000
Working capital ratio, required		1
Leverage ratio, required		4.25
Weighted average interest rate (percentage)		3.60%
Revolving credit facility | Line of Credit
Line of Credit Facility [Line Items]
Long term debt		$ 375,000		$ 0
Revolving credit facility | Eurodollar
Line of Credit Facility [Line Items]
Variable rate basis, base percentage prior to adjustments		100.00%
Revolving credit facility | Federal Funds Rate
Line of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate		0.50%
Revolving credit facility | Adjusted LIBOR rate
Line of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate		1.00%
Revolving credit facility | Minimum
Line of Credit Facility [Line Items]
Unused capacity, commitment fee percent		0.375%
Revolving credit facility | Minimum | Eurodollar
Line of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate	2.00%	1.50%
Revolving credit facility | Minimum | Base rate
Line of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate	1.00%	0.50%
Revolving credit facility | Maximum
Line of Credit Facility [Line Items]
Unused capacity, commitment fee percent		0.50%
Revolving credit facility | Maximum | Eurodollar
Line of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate	3.00%	2.50%
Revolving credit facility | Maximum | Base rate
Line of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate	2.00%	2.00%

Long-Term Debt - Senior Notes D

Long-Term Debt - Senior Notes Due 2025 (Details) - 5.25% Senior Notes due 2025 - USD ($)	12 Months Ended
	Dec. 31, 2017	Nov. 30, 2017	Dec. 27, 2016
Debt Instrument [Line Items]
Debt issuance costs			$ 6,400,000
Senior Notes
Debt Instrument [Line Items]
Debt issued, face amount			$ 450,000,000
Stated interest rate (percentage)	5.25%		5.25%
Senior Notes | January 15, 2020
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	103.938%
Senior Notes | January 1, 2023
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	100.00%
Senior Notes | Prior To January 15, 2020
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	100.00%
Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt issued, face amount		$ 450,000,000
Unsecured Debt [Member] | Event of change in control
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	101.00%

Long-Term Debt - Senior Notes58

Long-Term Debt - Senior Notes Due 2022 (Details) - Senior Unsecured Notes - USD ($)	12 Months Ended
	Dec. 31, 2017	Mar. 31, 2016	Aug. 10, 2015	Jun. 30, 2015	Sep. 26, 2014
After October 1, 2017
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	104.969%
January 1, 2020
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	100.00%
6.625% Notes due 2022
Debt Instrument [Line Items]
Debt issued, face amount			$ 200,000,000		$ 500,000,000
Stated interest rate (percentage)					6.625%
Percentage of principal amount issued			99.25%
Debt issuance costs			$ 2,400,000		$ 11,300,000
Debt instrument, face amount exchanged		$ 200,000,000		$ 500,000,000
6.625% Notes due 2022 | Event of change in control
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	101.00%

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Rent expense	$ 1.1	$ 0.9	$ 0.9

Commitments and Contingencies60

Commitments and Contingencies - Contractual Obligations (Details) - USD ($) $ in Thousands	Feb. 28, 2018	Dec. 31, 2017	Dec. 27, 2016
Other Commitments [Line Items]
2,018		$ 131,551
2,019		88,378
2,020		80,437
2,021		455,257
2,022		761,277
Thereafter		522,724
Total		2,039,624
Interest Cost
Other Commitments [Line Items]
2,018		70,000
2,019		70,000
2,020		70,000
2,021		70,000
2,022		58,406
Thereafter		48,221
Total		386,627
Drilling Rig Commitments
Other Commitments [Line Items]
2,018		14,375
2,019		0
2,020		0
2,021		0
2,022		0
Thereafter		0
Total		14,375
Purchase Obligations
Other Commitments [Line Items]
2,018		45,013
2,019		16,346
2,020		9,180
2,021		9,180
2,022		1,752
Thereafter		8,654
Total		90,125
Operating Lease Obligations
Other Commitments [Line Items]
2,018		2,163
2,019		2,032
2,020		1,257
2,021		1,077
2,022		1,119
Thereafter		0
Total		7,648
Asset Retirement Obligations
Other Commitments [Line Items]
2,018		0
2,019		0
2,020		0
2,021		0
2,022		0
Thereafter		15,849
Total		15,849
5.25% Senior Notes due 2025 | Senior Notes
Other Commitments [Line Items]
2,018		0
2,019		0
2,020		0
2,021		0
2,022		0
Thereafter		450,000
Total		$ 450,000
Stated interest rate (percentage)		5.25%	5.25%
5.25% Senior Notes due 2025 | Senior Notes | Interest Cost
Other Commitments [Line Items]
Total		$ 23,600
2022 Senior Notes | Senior Notes
Other Commitments [Line Items]
2,018		0
2,019		0
2,020		0
2,021		0
2,022		700,000
Thereafter		0
Total		$ 700,000
Stated interest rate (percentage)		6.625%
2022 Senior Notes | Senior Notes | Interest Cost
Other Commitments [Line Items]
Total		$ 46,400
Revolving credit facility
Other Commitments [Line Items]
2,018		0
2,019		0
2,020		0
2,021		375,000
2,022		0
Thereafter		0
Total		$ 375,000
Subsequent event
Other Commitments [Line Items]
Increase in purchase obligation	$ 72,000
Contractual obligation, term	12 years

Equity-Based Compensation - Nar

Equity-Based Compensation - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	$ 17,150	$ 13,763	$ 9,384
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense	10,200	7,900	6,400
Unrecognized compensation expense	$ 13,600
Unrecognized compensation expense, weighted average recognition period	1 year 6 months
Performance-based restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense	$ 7,000	$ 5,900	$ 3,000
Unrecognized compensation expense	$ 9,400
Unrecognized compensation expense, weighted average recognition period	1 year 3 months 18 days
Stock awards granted during the period (in shares)	380,174	484,650	159,932
Target payout percentage	100.00%
Performance-based restricted stock awards | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout percentage	0.00%
Performance-based restricted stock awards | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout percentage	200.00%
General and administrative expenses
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense	$ 17,200	$ 13,800	$ 9,400
LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock authorized (in shares)	10,000,000
Common stock available for grant (in shares)	7,200,000
Awards In 2017 | Performance-based restricted stock awards | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout percentage	0.00%
Awards In 2017 | Performance-based restricted stock awards | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout percentage	100.00%
Awards In 2016 | Performance-based restricted stock awards | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout percentage	0.00%
Awards In 2016 | Performance-based restricted stock awards | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout percentage	100.00%
Awards In 2015 | Performance-based restricted stock awards | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout percentage	0.00%
Awards In 2015 | Performance-based restricted stock awards | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout percentage	200.00%

Equity-Based Compensation - Sch

Equity-Based Compensation - Schedule of Restricted Stock Award Activity (Details) - Restricted stock awards - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Shares (in shares)
Restricted shares outstanding, beginning of period (in shares)	656,895	499,529	477,767
Restricted shares granted (in shares)	379,579	442,835	279,181
Restricted shares canceled (in shares)	(27,400)	(13,551)	(6,640)
Restricted shares vested (in shares)	(321,797)	(271,918)	(250,779)
Restricted shares outstanding, end of period (in shares)	687,277	656,895	499,529
Weighted Average Fair Value (in dollars per share)
Restricted shares outstanding, beginning of period (in dollars per share)	$ 22.21	$ 25.99	$ 23.71
Restricted shares granted (in dollars per share)	41.39	19.78	27.18
Restricted shares canceled (in dollars per share)	31.74	21.61	26.43
Restricted shares vested (in dollars per share)	23.01	25.22	22.97
Restricted shares outstanding, end of period (in dollars per share)	$ 32.04	$ 22.21	$ 25.99

Equity-Based Compensation - S63

Equity-Based Compensation - Schedule of Stock Award Assumptions (Details) - Performance-based restricted stock awards	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free rate of return	1.52%	0.95%	0.98%
Volatility	28.52%	54.60%	49.20%

Equity-Based Compensation - S64

Equity-Based Compensation - Schedule of Performance-Based Restricted Stock Award Activity (Details) - Performance-based restricted stock awards - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Shares (in shares)
Restricted shares outstanding, beginning of period (in shares)	747,874	294,332	134,400
Stock awards granted during the period (in shares)	380,174	484,650	159,932
Restricted shares canceled (in shares)	(7,569)	0	0
Restricted shares vested (in shares)	(119,400)	(31,108)	0
Restricted shares outstanding, end of period (in shares)	1,001,079	747,874	294,332
Weighted Average Fair Value (in dollars per share)
Restricted shares outstanding, beginning of period (in dollars per share)	$ 19.82	$ 31.41	$ 28.14
Restricted shares granted (in dollars per share)	26.96	13.53	31.74
Restricted shares canceled (in dollars per share)	26.96	0	0
Restricted shares vested (in dollars per share)	31.01	31.39	0
Restricted shares outstanding, end of period (in dollars per share)	$ 21.14	$ 19.82	$ 31.41
Target payout percentage	100.00%
Minimum
Weighted Average Fair Value (in dollars per share)
Target payout percentage	0.00%
Maximum
Weighted Average Fair Value (in dollars per share)
Target payout percentage	200.00%
Awards In 2017 | Minimum
Weighted Average Fair Value (in dollars per share)
Target payout percentage	0.00%
Awards In 2017 | Maximum
Weighted Average Fair Value (in dollars per share)
Target payout percentage	100.00%
Awards In 2016 | Minimum
Weighted Average Fair Value (in dollars per share)
Target payout percentage	0.00%
Awards In 2016 | Maximum
Weighted Average Fair Value (in dollars per share)
Target payout percentage	100.00%
Awards In 2015 | Minimum
Weighted Average Fair Value (in dollars per share)
Target payout percentage	0.00%
Awards In 2015 | Maximum
Weighted Average Fair Value (in dollars per share)
Target payout percentage	200.00%

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Numerator:
Net income (loss) available to stockholders	$ 140,786	$ 21,326	$ 31,090	$ 38,934	$ 1,381	$ 985	$ (9,801)	$ (17,416)	$ 232,136	$ (24,851)	$ (18,254)
Basic net income (loss) allocable to participating securities									1,161	0	0
Income (loss) available to stockholders									$ 230,975	$ (24,851)	$ (18,254)
Denominator:
Weighted average number of common shares outstanding - basic (in shares)									154,162	107,324	86,770
Effect of dilutive securities:
Restricted stock (in shares)									1,364	0	0
Weighted average number of common shares outstanding - diluted (in shares)									155,526	107,324	86,770
Net income (loss) per share:
Basic (in dollars per share)	$ 0.89	$ 0.14	$ 0.20	$ 0.27	$ 0.01	$ 0.01	$ (0.10)	$ (0.17)	$ 1.50	$ (0.23)	$ (0.21)
Diluted (in dollars per share)	$ 0.89	$ 0.14	$ 0.20	$ 0.26	$ 0.01	$ 0.01	$ (0.10)	$ (0.17)	$ 1.49	$ (0.23)	$ (0.21)

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Federal net operating loss carryforwards	$ 482	$ 251.6

Income Taxes - Components of th

Income Taxes - Components of the Provision for Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current Income Tax Expense (Benefit):
Federal									$ (5,541)	$ (4,074)	$ 5,504
State									0	0	(320)
Total income tax expense (benefit)									(5,541)	(4,074)	5,184
Deferred Income Tax Expense (Benefit):
Federal									(119,925)	(19,195)	(9,649)
State									2,297	489	(1,714)
Federal alternative minimum tax									5,541	4,074	(5,504)
Total deferred income tax benefit									(112,087)	(14,632)	(16,867)
Income tax expense (benefit)	$ (153,450)	$ 3,678	$ 17,072	$ 15,072	$ (1,464)	$ (3,507)	$ (4,438)	$ (9,298)	$ (117,628)	$ (18,706)	$ (11,683)
Tax cuts and jobs act of 2017, Income tax expense (benefit)	$ (144,400)

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Federal Tax Expense (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Federal statutory income tax rate									35.00%	35.00%	35.00%
Income tax expense (benefit) at the federal statutory rate (35%)									$ 40,078	$ (15,245)	$ (10,478)
State income tax expense (benefit), net of federal tax benefit									1,493	318	(1,322)
Impact of enacted legislation									(144,361)	0	0
Equity-based compensation									(4,386)	0	0
Research and development credit									(10,478)	(3,804)	0
Other									26	25	117
Provision for (benefit from) income taxes	$ (153,450)	$ 3,678	$ 17,072	$ 15,072	$ (1,464)	$ (3,507)	$ (4,438)	$ (9,298)	$ (117,628)	$ (18,706)	$ (11,683)

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards [Line Items]
New accounting pronouncement or change in accounting principle, effect of adoption, quantification		$ 584
Non-current deferred tax assets:
Net operating loss carryforwards (subject to 20 year expiration)	$ 101,220	88,632
Tax credit carryforwards	16,856	9,320
Other	14,615	13,185
Total noncurrent deferred tax assets	132,691	111,137
Non-current deferred tax liabilities:
Oil and natural gas properties and equipment	(343,259)	(433,792)
Total noncurrent deferred tax liabilities	(343,259)	(433,792)
Net noncurrent deferred tax liabilities	$ (210,568)	(322,655)
Retained Earnings
Operating Loss Carryforwards [Line Items]
New accounting pronouncement or change in accounting principle, effect of adoption, quantification		584
Accounting Standards Update 2016-09 | Retained Earnings
Operating Loss Carryforwards [Line Items]
New accounting pronouncement or change in accounting principle, effect of adoption, quantification		$ (600)

Income Taxes - Summary of Unrec

Income Taxes - Summary of Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits at beginning of period	$ 9,035	$ 0	$ 0
Increase resulting from prior period tax positions	6,653	8,483	0
Increase resulting from current period tax positions	7,370	552	0
Unrecognized tax benefits at the end of period	23,058	9,035	0
Less: Effects of temporary items	(3,729)	(5,256)	0
Total unrecognized tax benefits that, if recognized, would impact the effective income tax rate as of the end of the year	$ 19,329	$ 3,779	$ 0

Major Customers and Suppliers -

Major Customers and Suppliers - Schedule of Revenue by Major Customer (Details) - Net sales revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Western Refining
Concentration Risk [Line Items]
Percentage of total revenues (percentage)	21.00%
Enterprise Crude Oil LLC
Concentration Risk [Line Items]
Percentage of total revenues (percentage)	21.00%	27.00%	12.00%
Shell Trading (US) Company
Concentration Risk [Line Items]
Percentage of total revenues (percentage)	14.00%	23.00%	37.00%
Phillips 66 Company
Concentration Risk [Line Items]
Percentage of total revenues (percentage)			22.00%
Diamondback E&P, LLC
Concentration Risk [Line Items]
Percentage of total revenues (percentage)			13.00%

Supplemental Disclosure of Oi72

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Costs Incurred on Oil and Natural Gas Properties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Extractive Industries [Abstract]
Proved	$ 339,895	$ 210,977	$ 104,532
Unproved	1,253,326	1,063,109	351,806
Exploration costs	0	1,811	0
Development costs	675,988	293,833	378,910
Total costs incurred	$ 2,269,209	$ 1,569,730	$ 835,248

Supplemental Disclosure of Oi73

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Capitalized Oil and Natural Gas Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Extractive Industries [Abstract]
Proved oil and natural gas properties	$ 3,936,565	$ 2,811,853
Unproved oil and natural gas properties	2,865,952	1,833,928
Oil and natural gas properties, successful efforts method	6,802,517	4,645,781
Less accumulated depreciation, depletion, amortization and impairment	(778,596)	(554,419)
Net capitalized costs	$ 6,023,921	$ 4,091,362

Supplemental Disclosure of Oi74

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Net Proved Oil and Natural Gas Reserves (Details)	12 Months Ended
	Dec. 31, 2017$ / bbl$ / MMBTU	Dec. 31, 2016$ / bbl$ / MMBTU	Dec. 31, 2015$ / bbl$ / MMBTU
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Reference prices per Bbl of oil	51.34	42.75	50.28
Reference prices per MMBtu of natural gas | $ / MMBTU	2.98	2.48	2.59
Reference Prices Per Bbl Of NGLs	17.74	11.19	10.56

Supplemental Disclosure of Oi75

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Proved Reserves (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2017BoebblMcf	Dec. 31, 2016BoebblMcf	Dec. 31, 2015BoebblMcf
Proved Developed and Undeveloped Reserves, Energy [Roll Forward]
Beginning of year | Boe	236,888	159,173	106,416
Revisions of previous estimates | Boe	18,520	(17,750)	(20,505)
Extensions and discoveries | Boe	93,217	65,238	66,565
Purchases of minerals in place | Boe	47,485	40,900	14,379
Production | Boe	(20,168)	(10,673)	(7,682)
End of year | Boe	375,942	236,888	159,173
Proved Developed Reserves, Energy [Abstract]
Proved developed reserves | Boe	159,016	96,493	64,588
Proved Undeveloped Reserves, Energy [Abstract]
Proved undeveloped reserves | Boe	216,926	140,395	94,585
Oil (MBbls)
Proved Developed and Undeveloped Reserves, Volume [Roll Forward]
Beginning of year	164,728	111,135	69,273
Revisions of previous estimates	11,130	(14,115)	(12,886)
Extensions and discoveries	64,925	46,017	50,375
Purchases of minerals in place	34,997	29,481	10,178
Production	(14,445)	(7,790)	(5,805)
End of year	261,335	164,728	111,135
Proved Developed Reserves, Volume [Abstract]
Proved developed reserves	106,668	65,025	44,128
Proved Undeveloped Reserves, Volume [Abstract]
Proved undeveloped reserves	154,667	99,703	67,007
Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves, Volume [Roll Forward]
Beginning of year | Mcf	176,786	133,507	92,422
Revisions of previous estimates | Mcf	25,889	(30,284)	(20,205)
Extensions and discoveries | Mcf	73,698	45,541	55,313
Purchases of minerals in place | Mcf	33,772	35,210	10,968
Production | Mcf	(15,126)	(7,188)	(4,991)
End of year | Mcf	295,019	176,786	133,507
Proved Developed Reserves, Volume [Abstract]
Proved developed reserves | Mcf	133,116	76,255	56,640
Proved Undeveloped Reserves, Volume [Abstract]
Proved undeveloped reserves | Mcf	161,903	100,531	76,867
NGLs (MBbls)
Proved Developed and Undeveloped Reserves, Volume [Roll Forward]
Beginning of year	42,696	25,787	21,739
Revisions of previous estimates	3,075	1,412	(4,251)
Extensions and discoveries	16,009	11,631	6,971
Purchases of minerals in place	6,859	5,551	2,373
Production	(3,202)	(1,685)	(1,045)
End of year	65,437	42,696	25,787
Proved Developed Reserves, Volume [Abstract]
Proved developed reserves	30,162	18,759	11,020
Proved Undeveloped Reserves, Volume [Abstract]
Proved undeveloped reserves	35,275	23,937	14,767

Supplemental Disclosure of Oi76

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Natural Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows, beginning of year	$ 1,193,396	$ 796,016	$ 876,131
Sales, less production costs	(631,907)	(279,603)	(210,874)
Revisions of previous quantity estimates	200,298	(142,956)	(192,081)
Extensions and discoveries	967,933	390,752	440,744
Net change in prices and production costs	803,662	(251,166)	(537,613)
Changes in estimated future development costs	43,130	156,162	14,480
Previously estimated development costs incurred during the period	162,759	68,238	107,829
Purchases of minerals in place	377,822	244,977	95,207
Accretion of discount	141,887	86,109	131,764
Net change in income taxes	(381,109)	15,059	164,377
Timing differences and other	152,905	109,808	(93,948)
Standardized measure of discounted future net cash flows, end of year	$ 3,030,776	$ 1,193,396	$ 796,016

Supplemental Disclosure of Oi77

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Discounted Future Net Cash Flows, Proved Reserves (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Future cash inflows	$ 14,634,925	$ 7,433,650	$ 5,964,332
Future production costs	(3,867,816)	(2,352,287)	(1,855,044)
Future development costs	(1,893,108)	(1,315,835)	(1,187,244)
Future income tax expense	(1,553,250)	(659,105)	(699,070)
Future net cash flows	7,320,751	3,106,423	2,222,974
10% discount for estimated timing of cash flows	(4,289,975)	(1,913,027)	(1,426,958)
Standardized measure of discounted future net cash flows	$ 3,030,776	$ 1,193,396	$ 796,016	$ 876,131

Supplemental Disclosure of Oi78

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Narrative (Details) - Boe Boe in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reserve Quantities [Line Items]
Revisions of previous estimates	18,520	(17,750)	(20,505)
Negative revisions of previous estimates		2,131	19,641
Extensions and discoveries	93,217	65,238	66,565
Proved undeveloped reserves	65,657
Purchases of minerals in place	47,485	40,900	14,379
Discounted future net cash flows relating to oil and gas activities, term	12 months
Silver Hill Energy Partners, LLC
Reserve Quantities [Line Items]
Purchases of minerals in place		40,900

Quarterly Financial Data (Una79

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Revenues	$ 249,023	$ 201,654	$ 183,100	$ 169,931	$ 122,934	$ 93,621	$ 81,485	$ 55,815	$ 803,708	$ 353,857	$ 283,992
Operating income	55,457	67,077	54,887	55,389	29,892	13,248	2,295	(14,342)	232,810	31,094	(7,774)
Net gain (loss) on derivative instruments	(46,968)	(21,626)	12,194	17,121	(17,538)	(2,934)	(3,684)	396	(39,279)	(23,760)	20,906
Income tax (expense) benefit	153,450	(3,678)	(17,072)	(15,072)	1,464	3,507	4,438	9,298	117,628	18,706	11,683
Net income (loss)	$ 140,786	$ 21,326	$ 31,090	$ 38,934	$ 1,381	$ 985	$ (9,801)	$ (17,416)	$ 232,136	$ (24,851)	$ (18,254)
Basic (in dollars per share)	$ 0.89	$ 0.14	$ 0.20	$ 0.27	$ 0.01	$ 0.01	$ (0.10)	$ (0.17)	$ 1.50	$ (0.23)	$ (0.21)
Diluted (in dollars per share)	$ 0.89	$ 0.14	$ 0.20	$ 0.26	$ 0.01	$ 0.01	$ (0.10)	$ (0.17)	$ 1.49	$ (0.23)	$ (0.21)
Impairment expense	$ 52,900		$ 5,300						$ 59,077	$ 4,901	$ 34,269
Acquisition costs									$ 4,525	$ 6,374	$ 0
Silver Hill E&P II, LLC
Business Acquisition [Line Items]
Acquisition costs				$ 4,100
Silver Hill
Business Acquisition [Line Items]
Acquisition costs					$ 6,400