RSP Permian (RSPP) 10-K 25 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 19, 2016	Jun. 30, 2015
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 Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	FY
Amendment Flag	false
Entity Public Float			$ 1,600,670,007
Entity Common Stock, Shares Outstanding		101,660,240

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash and cash equivalents	$ 142,741	$ 56,292
Accounts receivable	36,323	40,436
Other assets	24	24
Derivative instruments	8,452	76,990
Total current assets	187,540	173,742
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method	3,076,051	2,240,803
Accumulated depletion and impairment	(357,524)	(171,046)
Total oil and natural gas properties, net	2,718,527	2,069,757
Other property and equipment, net	40,103	24,861
Total property, plant and equipment	2,758,630	2,094,618
OTHER LONG-TERM ASSETS
Restricted cash	152	152
Other long-term assets	33,249	21,435
Total long-term assets	33,401	21,587
TOTAL ASSETS	2,979,571	2,289,947
CURRENT LIABILITIES
Accounts payable	15,569	35,728
Accounts payable, related party	6,459	0
Accrued expenses	39,231	57,977
Interest payable	12,149	9,227
Derivative instruments	3,994	1,320
Total current liabilities	77,402	104,252
LONG-TERM LIABILITIES
Asset retirement obligations	7,063	4,873
Long-term debt	698,650	500,000
Deferred taxes	337,872	355,051
Total long-term liabilities	1,043,585	859,924
Total liabilities	1,120,987	964,176
STOCKHOLDERS’/MEMBERS' EQUITY
Common stock, $.01 par value; 300,000,000 shares authorized, 100,807,286 shares issued and outstanding at December 31, 2015; 77,903,834 shares issued and outstanding at December 31, 2014	1,008	779
Additional paid-in capital	1,873,332	1,322,494
Retained earnings (accumulated deficit)	(15,756)	2,498
Total stockholders’ equity	1,858,584	1,325,771
TOTAL LIABILITIES AND STOCKHOLDERS’/MEMBERS' EQUITY	$ 2,979,571	$ 2,289,947

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	300,000,000	300,000,000
Common stock, shares issued	100,807,286	77,903,834
Common stock, shares outstanding	100,807,286	77,903,834

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES
Oil sales	$ 263,286	$ 253,371	$ 110,345
Natural gas sales	10,517	10,572	5,383
NGL sales	10,189	17,982	7,314
Total revenues	283,992	281,925	123,042
OPERATING EXPENSES
Lease operating expenses	53,124	34,704	14,113
Production and ad valorem taxes	19,995	19,758	8,326
Depreciation, depletion and amortization	154,039	87,844	47,158
Asset retirement obligation accretion	336	142	121
Impairments	34,269	4,344	0
Exploration	2,380	3,854	551
General and administrative expenses	27,317	38,357	3,852
Total operating expenses	291,460	189,003	74,121
Loss (gain) on sale of assets	306	13	(22,700)
OPERATING INCOME (LOSS)	(7,774)	92,909	71,621
OTHER INCOME (EXPENSE)
Other income (expense), net	469	(44)	1,202
Gain (loss) on derivative instruments	20,906	81,470	(2,607)
Interest expense	(43,538)	(14,031)	(5,216)
Total other income (expense)	(22,163)	67,395	(6,621)
INCOME (LOSS) BEFORE TAXES	(29,937)	160,304	65,000
INCOME TAX (EXPENSE) BENEFIT	11,683	(157,806)	(2,262)
NET INCOME (LOSS)	$ (18,254)	$ 2,498	$ 62,738
Income per common share:
Basic (in dollars per share)	$ (0.21)	$ 0.03
Diluted (in dollars per share)	$ (0.21)	$ 0.03
Weighted average shares outstanding:
Basic (in shares)	86,770	71,898
Diluted (in shares)	86,770	71,898

Consolidated Statements of Chan

Consolidated Statements of Changes In Stockholders'/Members' Equity - USD ($) $ in Thousands	Total	Members' Equity [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]
Total Stockholders' Equity/Members' Equity, beginning balance at Dec. 31, 2012	$ 353,843	$ 353,843	$ 0	$ 0	$ 0
Issued Shares of Common Stock, beginning balance, shares at Dec. 31, 2012			0
Stockholders' Equity [Roll Forward]
Contributions	300	300
Distributions	(30,000)	(30,000)
Net income (loss)	62,738	62,738
Total Stockholders' Equity/Members' Equity, ending balance at Dec. 31, 2013	386,881	386,881	$ 0	0	0
Issued Shares of Common Stock, ending balance, shares at Dec. 31, 2013			0
Stockholders' Equity [Roll Forward]
Distribution of net assets to predecessor owner, including cash of $1,663	(6,979)	(21,147)		14,168
The corporate reorganization	0	(365,734)		365,734
RSP Permian Holdco, L.L.C.’s contributions of interests in RSP Permian, L.L.C. in exchange for RSP Permian, Inc.’s common stock	0		$ 633	(633)
RSP Permian Holdco, L.L.C.’s contributions of interests in RSP Permian, L.L.C. in exchange for RSP Permian, Inc.’s common stock, shares			63,275,000
Ted Collins, Jr., Wallace Family Partnership, LP, Collins & Wallace Holdings, LLC, Pecos Energy Partners, L.P. and ACTOIL LLC’s contributions in exchange for RSP Permian, Inc.’s common stock	642,436			642,436
Shares of common stock issued in public offerings, net of offering costs	280,703		$ 140	280,563
Shares of common stock issued in public offerings net of offering costs (shares)			14,017,000
Equity-based compensation	20,232		$ 6	20,226
Equity-based compensation. shares			612,000
Net income (loss)	2,498				2,498
Total Stockholders' Equity/Members' Equity, ending balance at Dec. 31, 2014	$ 1,325,771	0	$ 779	1,322,494	2,498
Issued Shares of Common Stock, ending balance, shares at Dec. 31, 2014	77,903,834		77,904,000
Stockholders' Equity [Roll Forward]
Shares of common stock issued in public offerings, net of offering costs	$ 543,524		$ 226	543,298
Shares of common stock issued in public offerings net of offering costs (shares)			22,540,000
Repurchase and retirement of common stock	(1,841)		$ (1)	(1,840)
Repurchase and retirement of common stock, shares			(69,000)
Equity-based compensation	9,384		$ 4	9,380
Equity-based compensation. shares			432,000
Net income (loss)	(18,254)				(18,254)
Total Stockholders' Equity/Members' Equity, ending balance at Dec. 31, 2015	$ 1,858,584	$ 0	$ 1,008	$ 1,873,332	$ (15,756)
Issued Shares of Common Stock, ending balance, shares at Dec. 31, 2015	100,807,286		100,807,000

Consolidated Statements of Cha6

Consolidated Statements of Changes In Stockholders' Equity (Parenthetical) $ in Thousands	12 Months Ended
	Dec. 31, 2014USD ($)
Members' Equity [Member]
Cash distribution paid to predecessor owner	$ 1,663

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (18,254)	$ 2,498	$ 62,738
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	154,039	87,844	47,158
Impairments	34,269	4,344	0
Asset retirement obligation accretion	336	142	121
Equity-based compensation	9,384	20,232	0
Amortization of loan fees and note discount	2,219	1,202	1,746
Deferred income taxes	(17,179)	153,468	2,195
Other	(8)	98	(12)
Loss (gain) on sale of assets	306	13	(22,700)
(Gain) loss on derivative instruments	(20,906)	(81,470)	2,607
Net cash receipts (payments) on settled derivatives	89,533	(102)	(886)
Changes in operating assets and liabilities:
Accounts receivable and accounts receivable from related parties	6,698	(4,383)	(3,758)
Other assets	(13,570)	14,952	(17,739)
Interest payable	2,921	8,932	44
Accounts payable and accounts payable to related parties	(13,700)	17,180	(5,380)
Accrued expenses	2,717	(1,793)	7,211
Net cash provided by operating activities	218,805	223,157	73,345
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of assets	634	2	115,339
Acquisition of equity investment	(2,704)	(625)	0
Additions to other property and equipment	(17,126)	(5,475)	(3,265)
Additions to oil and natural gas properties	(855,743)	(810,827)	(231,665)
Net cash used in investing activities	(874,939)	(816,925)	(119,591)
CASH FLOWS FROM FINANCING ACTIVITIES
Contributions	0	0	300
Proceeds from issuance of common stock, net	543,524	280,703	0
Distributions	0	(1,663)	(30,000)
Payment of deferred loan costs	2,400	(14,059)	0
Borrowings under long-term debt	65,000	440,512	101,569
Restricted short-term investment	0	0	1,031
Payments on long-term debt	(65,000)	(568,667)	(85,000)
Issuance of senior unsecured notes	198,500	500,000	0
NPI payable	0	0	20,348
Repurchase and retirement of common stock	(1,841)	0	0
Net cash provided by financing activities	742,583	636,826	8,248
NET CHANGE IN CASH	86,449	43,058	(37,998)
CASH AT BEGINNING OF PERIOD	56,292	13,234	51,232
CASH AT END OF PERIOD	142,741	56,292	13,234
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	42,960	3,897	3,373
Cash paid for taxes	3,450	3,800	0
NON-CASH ACTIVITIES
Asset retirement obligation acquired	902	2,147	644
Common stock issued for oil and gas properties	0	677,402	0
Deferred tax liabilities recorded for oil and gas property acquisitions	0	199,389	0
Elimination of NPI payable	0	36,931	0
Change in accrued capital expenditures	$ (21,463)	$ 41,573	$ 4,921

Nature of Operations and Basis

Nature of Operations and Basis of Presentation	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations and Basis of Presentation	NATURE OF OPERATIONS AND BASIS OF PRESENTATION Organization and Description of the Business RSP Permian, Inc. ("RSP Inc." or the "Company") was formed on September 30, 2013, pursuant to the laws of the state of Delaware to be a holding company for RSP Permian, L.L.C., a Delaware limited liability company (“RSP LLC”). RSP LLC was formed on October 18, 2010 by its management team and affiliates of Natural Gas Partners, a family of energy-focused private equity investment funds (“NGP”). The Company is engaged in the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin of West Texas. Until the Company's initial public offering ("IPO") in January 2014 as described below, affiliates of NGP owned over 90% of RSP LLC's outstanding equity. Rising Star Energy Development Co., L.L.C., a Delaware limited liability company (“Rising Star”), was formed in April 2006 and is engaged primarily in the acquisition, development and operation of oil and natural gas properties. Rising Star is wholly owned by Rising Star Energy Holdings Company, L.P. (“Rising Star LP”), which is managed by its general partner, Rising Star Energy GP, L.L.C. (“Rising Star GP”). An affiliate of NGP owns over 90% of the membership interests in Rising Star GP and over 80% of the limited partnership interests in Rising Star LP. Rising Star LP’s sole material assets are its interests in Rising Star and its interests in Rising Star Energy Operating Co., L.L.C., which has not conducted any operations for the past several years. Until the IPO, all power and authority to control the core functions of RSP LLC and Rising Star (collectively, the “Predecessor”) were controlled by affiliates of NGP. The historical results of RSP LLC and Rising Star were combined for all periods presented prior to the IPO date. On January 17, 2014, RSP Inc. sold 23 million shares at $19.50 per share to the public in an IPO and began trading on the New York Stock Exchange under the ticker symbol "RSPP." Of the 23 million shares, 9.2 million were shares sold by RSP Inc., resulting in approximately $180 million of gross proceeds ( $163 million in net proceeds), which were used to fully repay the Company’s $70 million term loan, repay outstanding borrowings of $56 million under its revolving credit facility, make cash payments to certain existing investors as partial consideration for the properties contributed to the Company by such persons, pay cash bonuses to certain of the Company’s employees in connection with the successful completion of the IPO, and fund a portion of its capital expenditure plan. The remaining 13.8 million shares sold in the IPO were sold by selling stockholders, and the Company did not receive any proceeds from the sale of those shares. In connection with the IPO, several transactions occurred that changed the structure and scope of the Company: • Corporate Reorganization : RSP LLC was contributed to RSP Permian Holdco, L.L.C., a newly formed limited liability company, which contributed all of its interests in RSP LLC to RSP Inc. in exchange for shares of RSP Inc.’s common stock, an assignment of RSP LLC’s pro rata share of an escrow related to the Resolute Sale (as defined and described in Note 3) and cash. As a result of this reorganization, RSP LLC became a wholly owned subsidiary of RSP Inc. • The Rising Star Acquisition : RSP Inc. acquired from Rising Star, working interests in certain acreage and wells in the Permian Basin in which RSP LLC already had working interests in exchange for shares of RSP Inc.’s common stock and cash. • The Collins and Wallace Contributions : Ted Collins, Jr. (“Collins”), Wallace Family Partnership, LP (“Wallace LP”) and Collins & Wallace Holdings, LLC, a newly formed entity that is jointly owned by Collins and Wallace LP, contributed certain working interests in the Permian Basin in which RSP LLC already had working interests in exchange for shares of RSP Inc.’s common stock and, in the case of Collins and Wallace LP, cash (such contributions, the “Collins and Wallace Contributions”). See Note 3 for additional information. • The Pecos Contribution : Pecos Energy Partners, L.P. (“Pecos”), an entity owned by certain members of the Company’s management team, contributed certain working interests in acreage and wells in the Permian Basin in which RSP LLC already had a working interest in exchange for shares of RSP Inc.’s common stock. • The ACTOIL NPI Repurchase : ACTOIL, LLC (“ACTOIL”), the owner of 25% net profits interests (“NPI”) in substantially all of RSP LLC’s oil and natural gas properties taken as a whole, contributed their 25% NPIs in exchange for shares of RSP Inc.’s common stock (such contribution, the “ACTOIL NPI Repurchase”). See Note 3 for more information. On August 12, 2014, RSP Inc. completed an underwritten public offering of 11.5 million shares of RSP Inc. common stock at $25.65 per share; the Company sold 4.8 million primary shares in the offering raising $118 million in net proceeds. On March 23, 2015, RSP Inc. completed an underwritten public offering of 9.0 million shares raising $127.9 million in net proceeds. On April 10, 2015, the underwriter exercised its option to purchase an additional 1.35 million shares, providing an additional $19.2 million in net proceeds. On August 7, 2015, RSP Inc. completed an underwritten public offering of 8.05 million shares, including the exercise of the underwriter's option to purchase additional shares, raising $178.3 million in net proceeds. On October 13, 2015, RSP Inc. completed an underwritten public offering of 8.74 million shares, including the exercise of the underwriter's option to purchase additional shares, raising $218.1 million in net proceeds. Basis of Presentation These financial statements have been prepared by the Company pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results. All such adjustments are of a normal recurring nature. Transfers of a business between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. The historical results of RSP LLC and Rising Star have been consolidated for all periods presented prior to the IPO date. The consolidated financial statements of the Company include the accounts of the Company and its wholly owned subsidiaries. Subsequent Events In the first quarter of 2016, the Company closed on the acquisitions of approximately $28.6 million of additional interests in properties the Company acquired in 2015. These acquisitions were funded by cash on hand.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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. 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 and natural gas reserves that may affect the amount at which oil and natural gas properties are recorded. Estimation of asset retirement obligations (“AROs”) and valuations of derivative instruments also require significant assumptions. It is possible that these estimates could be revised at future dates and these revisions could be material. Depletion of oil and natural gas properties are determined using estimates of proved oil 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. Reclassifications Certain reclassifications have been made to prior periods to conform to current period presentation. 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. Derivative and Other Financial Instruments The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil. These derivative transactions are generally in the form of collars, swaps and puts. In addition, the Company has previously entered into interest rate derivative contracts to minimize the effects of fluctuations in interest rates. The Company reports 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. The Company reports these amounts on a gross basis by contract. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Accounts Receivable As of December 31, 2015 2014 (In thousands) Sale of oil and natural gas and related products $ 22,166 $ 24,059 Joint interest owners 5,596 10,400 Derivatives - settled, but uncollected 8,561 5,977 Total accounts receivable $ 36,323 $ 40,436 Accounts receivable, which are primarily from the sale of oil, natural gas and natural gas liquids (“NGLs”), are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. In addition, settled but uncollected derivative contracts, and receivables related to joint interest billings 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 and management's expectations are that all material receivables at period-end will be collected. No bad debt expense was recorded for the years ended December 31, 2015, 2014 or 2013. Transactions with Related Parties Prior to the IPO, Collins, Wallace LP and Collins & Wallace Holdings, LLC had non-operated working interests in substantially all of the oil and natural gas assets that the Company operates, and an accounts receivable balance based on these activities. As of December 31, 2015 and 2014, all related party receivable balances have been collected and no amounts remain outstanding. In August 2014, the Company acquired from Pecos working interests in certain acreage and wells in Glasscock County, Texas for $4.5 million associated with the series of acquisitions in the amount of $257 million as further described in the recent acquisitions section of Note 3 - Acquisitions and Sales of Oil and Natural Gas Property Interests. 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 approximate aggregate purchase price of approximately $137 million , subject to certain purchase price adjustments. The majority of WPR is owned both directly, and indirectly, by Ted Collins, Jr. and Michael W. Wallace, who are also 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. 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 on a field level, based on proved reserves, using the unit-of-production method. Capitalized exploration well costs and development costs, including AROs, are depleted on a field level, based on proved developed reserves. Capitalized acquisition costs attributable to proved oil and natural gas properties and leasehold costs are depleted on a field basis based on proved reserves using the unit-of-production method. Depletion expense for oil and natural gas producing property was $152.8 million , $87.2 million , and $46.9 million , for the years ended December 31, 2015, 2014 and 2013, 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, 2015 and December 31, 2014 consisted of the following: As of December 31, 2015 2014 (In thousands) Proved oil and natural gas properties $ 2,197,056 $ 1,585,125 Unproved oil and natural gas properties 878,995 655,678 Total oil and natural gas properties 3,076,051 2,240,803 Less: accumulated depletion and impairment (357,524 ) (171,046 ) Total oil and natural gas properties, net $ 2,718,527 $ 2,069,757 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, 2015 , 2014 and 2013, there were no costs capitalized in connection with exploratory wells in progress. Capitalized costs are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. To determine if a field is impaired, the Company compares the carrying value of the field to the undiscounted future net cash flows by applying estimates of future oil and natural gas prices to the estimated future production of oil and natural gas reserves over the economic life of the property and deducting future costs. Future net cash flows are based upon reservoir engineers’ estimates of proved reserves. For a property determined to be impaired, an impairment loss equal to the difference between the property’s carrying value and its estimated fair value is recognized. Fair value, on a field basis, 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. For the year ended December 31, 2015, impairment expense for proved properties was $19.6 million , which related to properties whose future net revenues were less than the property's carrying value. No impairment of proved property was recorded for the years ended December 31, 2014 and 2013. The calculation of expected future net cash flows in impairment evaluations are mainly based on estimates of future oil and natural gas prices, proved reserves and risk-adjusted probable reserves quantities, and estimates of future production and capital costs associated with our proved and risk-adjusted 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. It is reasonably possible that oil and natural gas prices used in future impairment evaluations may decline, which would result in the need to further impair the carrying value of the Company's 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 year ended December 31, 2015, impairment expense for unproved property was $14.7 million , which primarily related to an 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. For the year ended December 31, 2014, impairment expense for unproved property was $4.3 million , which primarily related to an expectation that certain leasehold interests would expire and not be renewed. No impairment of unproved property was recorded for the year ended December 31, 2013. Natural gas volumes are converted to Boe at the rate of six Mcf of natural gas to one Bbl of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas. NGL volumes are stated in barrels. Other Property and Equipment Other property and equipment includes service wells, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition, and are depreciated using straight-line methods based on expected lives of the individual assets or group of assets ranging from 5 to 39 years. Depreciation expense related to such assets for the years ended December 31, 2015, 2014 and 2013 was $1.2 million , $0.9 million and $0.3 million , respectively, and is included in depreciation, depletion and amortization in the accompanying consolidated statements of operations. Investment in Unconsolidated Subsidiary The Company invested $3.3 million which is included in "Other long-term assets" on the accompanying consolidated balance sheet and has committed to invest $5 million in the aggregate. This entity will develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water on behalf of exploration and production companies operating in Midland, Martin, Andrews, and other counties in Texas approved by the board of this entity. Under the terms of the agreement, the Company owns a 25% interest and account for this investment using the equity method of accounting. Restricted Cash Restricted cash as of December 31, 2015 and 2014 consisted of certificates of deposit that mature in periods through 2017. Deferred Loan Costs Deferred loan costs, for both the revolving credit facility and 6.625% Senior Notes, are stated at cost, net of amortization, which is computed using the effective interest method over the life of the loan. Deferred loan costs of $15.7 million and $15.1 million as of December 31, 2015 and 2014, respectively, net of accumulated amortization, are included in other long-term assets in the accompanying consolidated balance sheets. Amortization of deferred loan costs of $2.2 million , $1.2 million and $1.7 million was recorded for the years ended December 31, 2015, 2014 and 2013, respectively. Asset Retirement Obligations 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 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 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 consisted of the following for the period indicated: Year Ended December 31, 2015 2014 (In thousands) Asset retirement obligation at beginning of period $ 4,873 $ 2,584 Liabilities incurred or assumed 1,857 2,147 Liabilities settled (3 ) — Accretion expense 336 142 Asset retirement obligation at end of period $ 7,063 $ 4,873 Income Taxes RSP LLC was organized as a limited liability company and treated as a flow-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed. Accordingly, provision for federal and state corporate income taxes has been made only for the operations of RSP Inc. beginning on January 23, 2014 in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the corporate reorganization in connection with the IPO, the Company established a $132.0 million provision for deferred income taxes, which was recognized as tax expense from continuing operations in the first quarter of 2014. This $132.0 million provision, related to our change in tax status, was subsequently adjusted to $95.2 million during the fourth quarter of 2014. The primary upward adjustments in the effective tax rate above the U.S. statutory rate are the adjustment related to the corporate reorganization noted above along with non-deductible incentive unit compensation. The following is an analysis of the Company’s consolidated income tax expense (benefit): Year Ended December 31, 2015 2014 2013 (In thousands) Current $ 5,184 $ 4,338 $ 68 Deferred (16,867 ) 153,468 2,194 Income Tax Expense (Benefit) $ (11,683 ) $ 157,806 $ 2,262 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, 2015, the Company did not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. The Company’s U.S. federal income tax returns for 2011 and beyond, and its Texas franchise tax returns for 2010 and beyond, remain subject to examination by the taxing authorities. No other jurisdiction’s returns are significant to the Company’s financial position. 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 November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes." which requires deferred tax liabilities and assets to be classified as non-current in the balance sheet. An entity is required to adopt ASU 2015-17 for annual and interim reporting periods beginning after December 15, 2016. Earlier adoption is permitted for all entities as of the beginning of an interim or annual reporting period, with prospective or retrospective application for all periods presented in the financial statements. We have elected to adopt this guidance as of the fourth quarter of fiscal year 2015. Accordingly, deferred tax liabilities in the amount of $25.8 million which were formerly classified as current liabilities at December 31, 2014 have been reclassified as long-term liabilities in the consolidated balance sheet. In September 2015, the FASB issued ASU 2015-16, “Simplifying the Accounting for Measurement-Period Adjustments," which requires the acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Public entities are required to apply ASU 2015-16 for annual and interim reporting periods beginning after December 15, 2015. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. In April 2015, the FASB issued ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs." which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying amount of the debt obligation, similar to debt discounts. An entity is required to apply ASU 2015-03 for annual and interim reporting periods beginning after December 15, 2015. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. In January 2015, the FASB issued ASU 2015-01, "Income Statement - Extraordinary and Unusual Items (Subtopic 225-20)," which eliminates the concept of extraordinary items in US GAAP. An entity is required to apply ASU 2015-01 for annual and interim reporting periods beginning after December 15, 2015. An entity may apply ASU 2015-01 prospectively or retrospectively for all periods presented in the financial statements. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which provides a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance including industry specific guidance. An entity is required to apply ASU 2014-09 for annual and interim reporting periods beginning after December 15, 2016. 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. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements.

Acquisitions and Sales of Oil a

Acquisitions and Sales of Oil and Natural Gas Property Interests	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions and Sales of Oil and Natural Gas Property Interests	ACQUISITIONS AND SALES OF OIL AND NATURAL GAS PROPERTY INTERESTS 2015 Acquisitions Glass Ranch Acquisition In the third quarter of 2015, in separate transactions with multiple sellers, t he Company acquired undeveloped acreage and oil and gas producing properties located in Martin and Glasscock counties for an aggregate purchase price of approximately $274 million , subject to certain purchase price adjustments. Subsequent to the initial closing, certain non-operated working interest owners in these properties elected to sell us their interests for an additional $39 million . Approximately $61.3 million was recorded as proved oil and natural gas properties. The aggregate acquisitions include 6,548 net acres in our core focus area with an average royalty burden of approximately 23% , with production of approximately 1,680 Boe/d and 191 net horizontal drilling locations as of the effective date. A portion of the acquisitions were initially funded through cash on hand and $50 million drawn on the Company’s revolving credit facility, with the remaining amounts funded with proceeds from both an underwritten public offering of RSP Inc. common stock in August 2015 and the issuance of senior unsecured notes in August 2015. 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 million , subject to certain purchase price adjustments, from WPR, an entity partly owned by affiliates of the Company. Approximately $6.5 million of the purchase price is included in accounts payable on the consolidated balance sheet as of December 31, 2015. This remaining amount will be paid when all title issues related to the acquisition have been satisfied. The acquisition includes 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. The acquisition was funded with proceeds from an underwritten public offering of RSP Inc. common stock that was completed in October 2015. The majority of WPR is owned both directly, and indirectly, by Ted Collins, Jr. and Michael W. Wallace, who are also members of our board of directors and two of our three largest shareholders. 2014 Acquisitions During the first quarter of 2014, the Company acquired additional acreage prospective for horizontal development in Martin, Glasscock and Dawson counties for an aggregate purchase price of approximately $79 million in three separate transactions with approximately $45 million recorded as proved oil and natural gas properties. The transactions were financed with borrowings under the Company’s revolving credit facility. In August 2014, in separate transactions with multiple sellers, the Company acquired predominantly undeveloped acreage and certain oil and gas producing properties located in Glasscock County, Texas, for an aggregate purchase price of $257 million , with approximately $124 million recorded as proved oil and natural gas properties. The transactions were financed with borrowings under the Company’s revolving credit facility, and the amount of historical revenues and cash flow were immaterial compared to our historical results. Collins and Wallace Contributions Collins, Wallace LP and Collins & Wallace Holdings, LLC contributed to RSP Inc. certain working interests in the Permian Basin in which RSP LLC already had working interests. In exchange, (i) Collins received shares of RSP Inc.’s common stock and the right to receive approximately $1.6 million in cash, (ii) Wallace LP received shares of RSP Inc.’s common stock and the right to receive $0.6 million in cash, and (iii) Collins & Wallace Holdings, LLC received shares of RSP Inc.’s common stock. The Collins and Wallace Contributions occurred in connection with the IPO. These contributed working interests consist of the following: (i) Collins’ non-operated working interest in substantially all of the oil and natural gas properties that RSP LLC owned prior to the Spanish Trail Acquisition; (ii) Wallace LP’s non-operated working interest in substantially all of the oil and natural gas properties that RSP LLC owned prior to the Spanish Trail Acquisition; and (iii) Collins & Wallace Holdings, LLC’s non-operated working interest in the Spanish Trail Assets (as defined below). A summary of the consideration transferred and the fair value of assets and liabilities acquired in connection with the Collins and Wallace Contributions is as follows (in thousands): Value of the 22,023,654 shares of the Company’s common stock issued in the Collins and Wallace Contributions $ 429,461 Cash paid in the Collins and Wallace Contributions 2,219 Total consideration for the assets contributed in the Collins and Wallace Contributions $ 431,680 Fair value of oil and natural gas properties $ 653,431 Asset retirement obligation (1,063 ) Deferred tax liability* (215,609 ) Total net assets acquired ** $ 436,759 _______________________________________ * Amount represents the estimated book to tax difference in oil and natural gas properties as of the acquisition date on a tax-effected basis of approximately 36% . ** Approximately 56% of acquired acreage was unproved. ACTOIL NPI Repurchase In July 2011, RSP LLC sold to ACTOIL a 25% NPI in substantially all of its oil and natural gas properties taken as a whole. In addition, RSP LLC sold to ACTOIL a 25% NPI in the oil and natural gas properties acquired by RSP LLC in the Spanish Trail Acquisition. In connection with the IPO, ACTOIL contributed both 25% NPIs to the Company in exchange for shares of RSP Inc.’s common stock. The 25% NPIs exchanged for shares in the Company had a value of approximately $ 210.9 million and were accounted for as asset acquisitions. The Company’s predecessor’s sale of properties to Resolute Natural Resources Southwest LLC (“Resolute”) in December 2012 and March 2013 resulted in ACTOIL earning cash proceeds through its NPI in the properties sold. ACTOIL reduced its NPI account cumulative deficit balance with these proceeds, rather than receiving a cash distribution. As such, the Company’s predecessor applied the NPI proceeds dollar-for-dollar to reduce the NPI deficit balance and recorded the amount as a long-term NPI payable on its balance sheet. This amount was eliminated upon ACTOIL contributing its NPI in exchange for common shares in connection with the IPO. A summary of the consideration transferred and the assets acquired and liabilities acquired in connection with the ACTOIL NPI Repurchase is as follows (in thousands): Value of the 10,816,626 shares of the Company’s common stock issued in the ACTOIL NPI Repurchase $ 210,924 Elimination of NPI payable (36,931 ) Total consideration for the assets contributed in the ACTOIL NPI Repurchase $ 173,993 Oil and natural gas properties cost $ 157,382 Asset retirement obligation (639 ) Deferred tax asset* 17,250 Total net assets acquired** $ 173,993 _______________________________________ * Amount represents the estimated book to tax difference in oil and natural gas properties as of the acquisition date on a tax-effected basis of approximately 36% . ** Approximately 56% of acquired acreage was unproved. 2013 Acquisitions and Dispositions Spanish Trail Acquisition On September 10, 2013, RSP LLC acquired additional working interests in certain of its existing properties in the Permian Basin (the “Spanish Trail Acquisition”) from Summit Petroleum, LLC (“Summit”) and EGL Resources, Inc. (“EGL”). The aggregate purchase price for the assets acquired in the Spanish Trail Acquisition (the “Spanish Trail Assets”) agreed to by RSP LLC and the sellers was $155 million . Subsequent to the signing of the purchase agreement and prior to the closing of the Spanish Trail Acquisition, Collins and Wallace LP, non-operating working interest owners in the Spanish Trail Assets, exercised preferential purchase rights granted under a joint operating agreement among the working interest owners in the Spanish Trail Assets. The preferential purchase rights gave Collins and Wallace LP the right to purchase a portion of the working interests sold by Summit and EGL. Collins and Wallace LP completed this acquisition through Collins & Wallace Holdings, LLC, a newly formed entity that is jointly owned by Collins and Wallace LP, which contributed these acquired assets to RSP Inc. in exchange for shares of RSP Inc.’s common stock in connection with the IPO. The exercise of the preferential purchase rights reduced RSP LLC’s purchase price from $155 million to $121 million . Simultaneously with the closing of the Spanish Trail Acquisition, pursuant to ACTOIL’s exercise of a right of first refusal granted by RSP LLC in the agreement that governs ACTOIL’s NPI investment, RSP LLC conveyed a 25% NPI in the Spanish Trail Assets taken as a whole, excluding the portion acquired by Collins & Wallace Holdings, LLC, to ACTOIL in exchange for cash equal to 25% of RSP LLC’s $121 million purchase price. The exercise of the right of first refusal by ACTOIL and issuance of the 25% NPI reduced RSP LLC's purchase price from $121 million to $91 million with a majority of that amount recorded to proved property. RSP LLC allocated the net purchase price to the oil and natural gas properties acquired and asset retirement obligation assumed as follows (in thousands): Net purchase price $ 120,521 25% NPI Sale to ACTOIL (30,131 ) Oil and natural gas properties acquired $ 90,390 Asset retirement obligation assumed 296 Proved oil and natural gas properties $ 90,686 The Spanish Trail Acquisition was funded with a $70 million term loan, borrowings under the Company’s revolving credit facility (described below in Note 6) and the issuance of the NPI to ACTOIL described above. Resolute Sale Effective October 1, 2012, RSP LLC, ACTOIL and other minority non-operating working interest owners entered into a Purchase, Sale, and Option Agreement (“PSA”) to sell an undivided 32.35% interest in certain assets for an aggregate purchase price of $110 million to Resolute (the “Resolute Sale”). The Company’s share of the purchase price was $69 million and was recorded as a reduction to the basis of the underlying oil and natural gas properties. To the extent that the proceeds received exceeded the cost basis of the oil and natural gas properties, the Company recorded a gain on the sale. In addition, RSP LLC and the other sellers sold Resolute an option (the “Option”) for $5 million , $2.4 million of which was the Company’s share. The Option allowed Resolute to acquire the remaining 67.65% interest in these certain assets. The Option was non-refundable and only entitled Resolute to a limited time period during which it could exercise the right to acquire the remaining interest in these certain assets, and therefore the Option fee was included in the consideration transferred in computing the gain on disposition of the assets described above. The Company recorded a gain in connection with the sale of the 32.35% interest in these assets and the option fee in the amount of $6.7 million for the year ended December 31, 2012. In March 2013, Resolute exercised the right to acquire the 67.65% remaining interest in these assets from RSP LLC, ACTOIL and other working interest owners for an additional purchase price of approximately $230.0 million . RSP LLC’s share of the purchase price was $144.2 million . In connection with the transaction closing in March 2013, RSP LLC recorded a gain of approximately $6 million . The PSA contained customary closing conditions and included a $5 million title and environmental escrow (net to RSP LLC) and an $11 million indemnity escrow (net to RSP LLC) which were held back from the initial purchase price to provide for these contingencies. Amounts held in escrow for potential indemnity matters were not initially considered in the computation of the gain in connection with the sale of these certain assets because the Company could not reasonably estimate the potential outcome of any such matters at the time of the initial closing of the transaction. Subsequent to the initial closing, in October 2013, RSP LLC received the first two scheduled escrow payments under the terms of the PSA totaling approximately $12 million . The receipt of these funds substantially resolved any uncertainty associated with the ability to collect the remaining portion of the amounts held in escrow and, therefore, the Company recorded the gain associated with all funds received and the remaining escrow amounts not yet received as collectability of such amounts was deemed probable. For the twelve months ended December 31, 2013, the total gain recognized on the Resolute Sale was approximately $22.7 million . Pro Forma Results The Company’s summary pro forma results for the twelve months ended December 31, 2013 were derived from the actual results of the Company’s accounting predecessor, which reflects the combined results of RSP LLC and Rising Star, and have been adjusted to reflect the Collins and Wallace Contributions and the ACTOIL NPI Repurchase, both of which were completed in connection with the IPO on January 23, 2014, as if such transactions had occurred on January 1, 2013. Additionally, the pro forma results for the 2013 periods include the estimated activity associated with the Spanish Trail Acquisition (as defined above), which was completed in September 2013, and the Resolute Sale, which was completed in March 2013, as if each of these transactions had occurred on January 1, 2013. Our pro forma results for the twelve months ended December 31, 2014 were derived from our actual results and have been adjusted to reflect the Collins and Wallace Contributions and the ACTOIL NPI Repurchase, both of which were completed in connection with the IPO on January 23, 2014, as if such transactions had occurred on January 1, 2013. 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 IPO. 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, 2014 Year Ended December 31, 2013 Actual Pro Forma Actual Pro Forma (In thousands) (In thousands) Revenues $ 281,925 $ 286,910 $ 123,042 $ 197,309 Net income $ 2,498 $ 2,743 $ 62,738 $ 73,228

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
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 crude oil and natural gas production. These include over-the-counter (“OTC”) swaps and collars. The derivative instruments are recorded at fair value on the consolidated balance sheets and any gains and losses are recognized in current period earnings. 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. Each collar transaction has an established price floor and ceiling, and certain collar transactions also include a short put as well. 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 pays its counterparty an amount equal to the difference between the settlement price and the short put price. The following table summarizes all open positions as of December 31, 2015 : Contracts Maturing During 2016 Crude Oil Collars: Notional volume (Bbl) 555,000 Weighted average ceiling price ($/Bbl)(1) $ 74.08 Weighted average floor price ($/Bbl)(1) $ 55.00 Weighted average short put price ($/Bbl)(1) $ 45.00 _______________________________________ (1) The crude oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude. Derivative Fair Values and Gains (Losses) The following table presents the fair value of derivative instruments. The Company’s derivatives are presented as separate line items in its consolidated balance sheets as current and noncurrent derivative instrument assets and liabilities. 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 As of December 31, As of December 31, 2015 2014 2015 2014 (In thousands) Derivative Instruments: Current amounts Commodity contracts $ 8,452 $ 76,990 $ (3,994 ) $ (1,320 ) Total derivative instruments $ 8,452 $ 76,990 $ (3,994 ) $ (1,320 ) Gains and losses on derivatives are reported in the consolidated statements of operations. The following represents the Company’s reported gains and losses on derivative instruments for the periods presented: For the Year Ended December 31, 2015 2014 2013 (In thousands) Gain (loss) on derivative instruments: Commodity derivative instruments $ 20,906 $ 81,470 $ (2,583 ) Interest rate derivative instruments — — (24 ) Total $ 20,906 $ 81,470 $ (2,607 ) Offsetting of Derivative Assets and Liabilities The following table presents the Company’s gross and net derivative assets and liabilities. Gross Amount Presented on Balance Sheet Netting Adjustments(a) Net Amount (In thousands) December 31, 2015 Derivative instrument assets with right of offset or master netting agreements $ 8,452 $ (3,994 ) $ 4,458 Derivative instrument liabilities with right of offset or master netting agreements $ (3,994 ) $ 3,994 $ — December 31, 2014 Derivative instrument assets with right of offset or master netting agreements $ 76,990 $ (1,320 ) $ 75,670 Derivative instrument liabilities with right of offset or master netting agreements $ (1,320 ) $ 1,320 $ — _______________________________________ (a) With all of the Company’s financial trading counterparties, the Company has agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Credit-Risk Related Contingent Features in Derivatives None of the Company’s derivative instruments contains credit-risk related contingent features. No amounts of collateral were posted by the Company related to net positions as of December 31, 2015 and 2014.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The book values of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short-term nature of these instruments. The book value of the Company’s credit facilities approximate fair value as the interest rates are variable. The book value of the Company's senior notes approximates the fair value as the current trading value of the notes approximates par value. If the Company recorded the notes at fair value they would be Level 1 in our fair value hierarchy as they are traded in an active market with quoted prices for identical instruments. The fair value of derivative financial instruments is determined utilizing industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The Company has 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. These inputs 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 The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. Level 1 Level 2 Level 3 Total fair value (In thousands) As of December 31, 2015: Commodity derivative instruments $ — $ 4,458 $ — $ 4,458 Total $ — $ 4,458 $ — $ 4,458 Level 1 Level 2 Level 3 Total fair value (In thousands) As of December 31, 2014: Commodity derivative instruments $ — $ 75,670 $ — $ 75,670 Total $ — $ 75,670 $ — $ 75,670 Significant Level 2 assumptions used to measure the fair value of the commodity derivative instruments include current market and contractual commodity prices, implied volatility factors, appropriate risk adjusted discount rates, as well as other relevant data. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. There were no transfers between Level 1, Level 2 or Level 3 during the years ended December 31, 2015 and 2014. 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 costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. 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, 2015
Debt Disclosure [Abstract]
Long-Term Debt	LONG-TERM DEBT Long-term debt, including the effects of issuance discounts, consists of the following: As of December 31, 2015 2014 (In millions) Revolving credit facility $ — $ — 6.625% Senior notes 698.7 500.0 Total long-term debt $ 698.7 $ 500.0 Credit Agreement On August 24, 2015, the Company amended the revolving credit facility to increase the borrowing base to $600 million along with other updates. The Company's revolving credit facility requires it to maintain the following three 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 4.5 to 1.0 , • a senior secured leverage ratio, which is the ratio of the sum of all the Company's debt that is (i) secured and (ii) not subordinated to obligations under the revolving credit facility to the consolidated EBITDAX (as defined in the credit agreement) for the four fiscal quarters then ended, of not greater than 3.5 to 1.0 . The Company's revolving credit facility contains restrictive covenants that may limit its 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 its expected production, enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness, incur liens, sell assets 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, 2015. Principal amounts borrowed 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. The Company has a choice of borrowing in Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate (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 100 to 200 basis points, depending on the percentage of its 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 100 basis points; and (iii) the adjusted LIBOR rate plus 100 basis points, plus an applicable margin ranging from 0 to 100 basis points, depending on the percentage of its borrowing base utilized, plus a facility fee of 0.50% charged on the borrowing base amount. At December 31, 2015, the prime borrowing rate of interest under the Company’s revolving credit facility was 3.50% . RSP LLC may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. As of December 31, 2015, the revolving credit facility has a margin of 1.00% to 2.00% plus LIBOR, plus a facility fee of 0.50% charged on the borrowing base amount. The amount available to be borrowed under the revolving credit facility is subject to a borrowing base that is re-determined semiannually each May and November and depends on the volumes of proved oil and natural gas reserves and estimated cash flows from these reserves and commodity hedge positions. The borrowing base under the Company’s amended and restated credit agreement is $600 million as of December 31, 2015, with lender commitments of $1 billion . The maturity date of the Company's revolving credit facility is August 29, 2019. Senior Notes Due 2022 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 these 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 RSP LLC's revolving credit facility, and will rank senior to any future subordinated indebtedness of the Company. Interest on these notes is payable semi-annually on April 1 and October 1 and commenced on April 1, 2015. On or after October 1, 2017, 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. In addition, prior to October 1, 2017, the Company may redeem up to 35% of the principal amount of the notes with the net proceeds of qualified offerings of our equity at a redemption price of 106.625% of the principal amount of the notes, plus accrued and unpaid interest. The Company incurred approximately $11.3 million of debt issuance costs related to the 2014 note issuance and $2.4 million related to the 2015 note issuance, which is included in “Other long-term assets” on the Company's consolidated balance sheets and will be amortized to interest expense, net, 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. RSP LLC, our 100% owned and only subsidiary, has fully and unconditionally guaranteed the notes. 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 these notes for registered notes with the same terms. In February 2016, the Company exchanged $200.0 million of these notes for registered notes with the same terms. The Company was in compliance with the provisions of the indenture governing the senior unsecured notes as of December 31, 2015.

Net Profits Interest

Net Profits Interest	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Net Profits Interest	NET PROFITS INTEREST In July 2011, RSP LLC entered into a $175.0 million financing agreement to convey a 25% net profits interest (“NPI”) to ACTOIL. The NPI conveys 25% of the oil and natural gas sales less associated direct capital expenditures and lease operating expenses from substantially all the oil and natural gas properties held by RSP LLC effective January 1, 2011. RSP maintains a separate net profits interest account (“NPI Account”) maintained on a cash basis, as defined in the agreement governing the NPI. The calculation to determine if amounts were to be distributed to ACTOIL for its interest was determined on a quarterly basis by RSP LLC. ACTOIL did not fund its proportionate share of direct capital expenditures or lease operating expenses as the expenses were funded by the Company and reimbursed through the NPI calculation. When the cumulative oil and natural gas sales, net of associated direct capital expenditures and lease operating expenses attributable to the NPI was a negative number, then the distribution was zero for such calendar quarter and such cumulative negative amount was carried forward. When the cumulative NPI calculation became a positive number at the end of a calendar quarter, a distribution would be made to ACTOIL for its share of net profits. If the NPI Account had a deficit balance at the end of a calendar quarter, ACTOIL incurred interest to RSP LLC on the cumulative deficit balance at varying annual rates depending on the amount of the deficit balance. This interest was added to the cumulative deficit balance. In December 2012, RSP, ACTOIL and other minority non-operating working interest owners sold an undivided 32.35% interest in certain assets for an aggregate purchase price of $110.0 million to Resolute. In addition, RSP and the other sellers sold Resolute the Option for $5.0 million as described in Note 3. ACTOIL’s share of the proceeds, after escrowed items, was approximately $15.8 million . ACTOIL used these proceeds, along with subsequent escrow releases, to reduce the cumulative deficit balance of the NPI Account. The proceeds were applied dollar for dollar to reduce the NPI deficit balance as of the date of the sale and recorded as a long-term NPI payable. In March 2013, Resolute exercised the right to acquire the 67.65% remaining interest in these assets from RSP, ACTOIL and other working interest owners for an additional purchase price before adjustments of $230.0 million . ACTOIL’s share of the proceeds, after escrowed items and adjustments, was approximately $31.8 million . ACTOIL used $21.1 million of these proceeds to first reduce the cumulative deficit balance of the NPI Account to zero . The Predecessor recorded the $21.1 million proceeds as a long-term NPI payable in the accompanying balance sheet. The remaining proceeds of $10.7 million were distributed to ACTOIL. In January 2014, ACTOIL contributed their 25% NPI in exchange for shares of RSP Inc.’s common stock. See Note 1 for additional information.

Major Customers and Suppliers

Major Customers and Suppliers	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Major Customers and Suppliers	MAJOR CUSTOMERS AND SUPPLIERS Dependence on Major Customers 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, 2015 2014 2013 Shell Trading (US) Company 37 % 31 % 40 % Phillips 66 Company 22 % — % — % Enterprise Crude Oil LLC 12 % 24 % 14 % Diamondback E&P, LLC 13 % 14 % 11 % Plains Marketing, L.P. — % — % 13 % Permian Transport & Trading 5 % 21 % — % Management believes that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships or that those relationships will result in an increased number of purchasers. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company’s purchasers are credit worthy.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Based Compensation	Equity-based compensation expense, which was recorded in General and administrative expenses, was $9.4 million and $20.2 million for the twelve months ended December 31, 2015 and 2014, respectively. Equity-based compensation expense in the 2014 period includes expense related to incentive units. Expenses related to incentive units are described in more detail below. Incentive unit expense, which was also recorded in General and administrative expenses, was $14.7 million for the twelve months ended December 31, 2014. Restricted Stock Awards In connection with the IPO, the Company adopted the RSP Permian, Inc. 2014 Long Term Incentive Plan (the “LTIP”) for the employees, consultants and directors of the Company and its affiliates who perform services for the Company. Equity-based compensation expense for awards under the LTIP was $6.4 million and $4.7 million for the twelve months ended December 31, 2015 and 2014, respectively. The Company views restricted stock awards with graded vesting as single awards with an expected life equal to the average expected life and amortize the awards on a straight-line basis over the life of the 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 applied to the total number of shares that were anticipated to fully vest. As of December 31, 2015, the Company had unrecognized compensation expense of $7.9 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 twelve months ended December 31: 2015 2014 Shares Weighted Average Fair Value Shares Weighted Average Fair Value Restricted shares outstanding, beginning of period 477,767 $ 23.71 — $ — Restricted shares granted 279,181 27.18 489,544 23.69 Restricted shares canceled (6,640 ) 26.43 (11,777 ) 23.03 Restricted shares vested (250,779 ) 22.97 — — Restricted shares outstanding, end of period 499,529 $ 25.99 477,767 $ 23.71 Performance-Based Restricted Stock Awards In June 2014, performance-based restricted stock awards were granted containing predetermined market conditions with a cliff vesting period of 2.75 years . The Company granted 134,400 of these shares at a 100% of target payout while the conditions of the grants allow for a payout ranging between no payout and 200% of target. In March 2015, an additional grant of performance-based restricted stock awards were granted containing predetermined market conditions with a cliff vesting period of 2.83 years . We granted 159,932 of these shares at a 100% of target payout while the conditions of the grants allow for a payout ranging between no payout and 200% of target. Equity-based compensation for these awards was $3.0 million and $0.8 million for the twelve months ended December 31, 2015 and 2014, respectively. The compensation expense for the market conditions is based on a per share value using a Monte-Carlo simulation. The unrecognized compensation expense related to these shares is approximately $6.3 million as of December 31, 2015 and is expected to be recognized over the next 1.87 years . The payout level is calculated based on actual total shareholder return performance achieved during the performance period compared to a defined peer group of comparable public companies. The following table represents performance-based restricted stock award activity for the twelve months ended December 31: 2015 2014 Shares Weighted Average Fair Value Shares Weighted Average Fair Value Restricted shares outstanding, beginning of period 134,400 $ 28.14 — $ — Restricted shares granted 159,932 31.74 134,400 28.14 Restricted shares outstanding, end of period 294,332 $ 31.41 134,400 $ 28.14 Incentive Units Pursuant to the LLC Agreement of RSP LLC, certain incentive units were available to be issued to the Company’s management and employees. After successful completion of the IPO, the performance conditions associated with certain incentive units were deemed probable of reaching payout. For the twelve months ended December 31, 2014, the Company recognized non-cash compensation expense of $14.7 million , respectively, related to these incentive units. In December 2014, the incentive unit plan was concluded and all awards remaining under the incentive unit plans were allocated according to performance criteria established at the adoption of the plan. These incentive units determined the stock allocation of shares held by RSP Permian Holdco, between management and NGP and had no dilutive impact, or cash impact, to shareholders of RSP Permian, Inc. In periods subsequent to 2014, there will be no additional expense recognized related to these incentive units.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Legal 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. Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed as incurred. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. The Company accounts for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. 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 environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. At both December 31, 2015 and 2014, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability. Leases The Company leases office space in Midland and Dallas Texas. These leases run through 2019 and 2021, respectively. Rent expense for the year ended December 31, 2015, 2014, and 2013 was $0.9 million and $0.5 million , and $0.2 million respectively. Contractual Obligations A summary of the Company's contractual obligations as of December 31, 2015 is provided in the following table (in thousands). Payments Due by Period For the Year Ended December 31, 2016 2017 2018 2019 2020 Thereafter Total (In thousands) Revolving credit facility (1) $ — $ — $ — $ — $ — $ — $ — 6.625% Senior Notes (2) — — — — — 700,000 700,000 Interest cost (3) 46,375 46,375 46,375 46,375 46,375 92,750 324,625 Drilling rig commitments (4) 19,933 3,035 — — — — 22,968 Office and equipment leases 1,316 1,201 1,018 844 138 70 4,587 Asset retirement obligations (5) — — — — — 7,063 7,063 Total $ 67,624 $ 50,611 $ 47,393 $ 47,219 $ 46,513 $ 799,883 $ 1,059,243 (1) This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on our revolving credit facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. Any borrowings under the revolving credit facility must be repaid by August 2019. (2) Includes principal only. (3) Related to fixed rate debt only, which is the 6.625% Senior Notes. (4) The values in the table represent the gross amounts that the Company is committed to pay. (5) Amounts represent estimates of our future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment.

Earnings per Share

Earnings per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings per Share	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 year ended December 31, 2015, unvested restricted share awards were not recognized in 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: As of December 31, 2015 2014 Numerator: Net income (loss) available to stockholders $ (18,254 ) $ 2,498 Basic net income allocable to participating securities (1) — 15 Income (loss) available to stockholders $ (18,254 ) $ 2,483 Denominator: Weighted average number of common shares outstanding - basic 86,770 71,898 Effect of dilutive securities: Restricted stock — — Weighted average number of common shares outstanding - diluted 86,770 71,898 Net income (loss) per share: Basic $ (0.21 ) $ 0.03 Diluted $ (0.21 ) $ 0.03 _______________________________________ (1) Restricted share 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. Pro Forma Earnings per Share The Company computed a pro forma income tax provision as if the Company was subject to income taxes since January 1, 2014. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, and excludes the non-recurring tax adjustment related to the corporate reorganization of the Company on January 23, 2014, as further described in Note 2 under “Income Taxes.” The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued in the IPO were outstanding for the entire year. A reconciliation of the components of pro forma basic and diluted earnings per common share is presented in the table below: Year Ended December 31, 2014 Numerator: Income before taxes, as reported $ 160,304 Pro forma provision for income taxes 57,709 Pro forma net income available to stockholders 102,595 Basic net income allocable to participating securities 599 Pro forma net income available to stockholders $ 101,996 Denominator: Weighted average number of common shares outstanding - basic 74,297 Effect of dilutive securities: Restricted stock — Weighted average number of common shares outstanding - diluted 74,297 Net income per share: Basic $ 1.37 Diluted $ 1.37 For the year ended December 31, 2014, our actual earnings per share was less than our pro forma earnings per share.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES As a result of the corporate reorganization in connection with the IPO transaction, the Company established a $132 million provision for deferred income taxes, which was recognized as tax expense from continuing operations in the first quarter of 2014. This $132 million provision, related to our change in tax status, was subsequently adjusted to $95 million during the fourth quarter of 2014. The primary upward adjustments in the effective tax rate above the U.S. statutory rate are the adjustment related to the corporate reorganization noted above along with non-deductible incentive unit compensation. The components of the provision for income taxes for the year ended December 31, 2015 is as follows: For the year ended December 31, 2015 2014 (In thousands) Current Income Tax Provision (Benefit): Federal $ 5,504 $ 4,111 State (320 ) 227 Total income tax provision (benefit) 5,184 4,338 Deferred Income Tax Provision (Benefit): Federal $ (9,649 ) $ 157,806 State (1,714 ) (227 ) Federal alternative minimum tax (5,504 ) (4,111 ) Total deferred income tax provision (benefit) (16,867 ) 153,468 Total Provision for (benefit from) Income Taxes $ (11,683 ) $ 157,806 Included in the deferred federal income tax provision for 2014 above is $95.2 million related to the Company's change in tax status. A reconciliation of the statutory federal income tax amount to the recorded expense is as follows: For the year ended December 31, 2015 2014 (In thousands) Income tax expense (benefit) at the federal statutory rate (35%) $ (10,478 ) $ 56,106 Income tax expense relating to change in tax status — 95,162 State income tax expense (benefit), net of federal tax benefit (1,322 ) 1,081 Non-deductible expenses 69 5,457 Other 48 — Provision for (benefit from) income taxes $ (11,683 ) $ 157,806 Prior to the Company's change in tax status in January 2014, income taxes did not significantly impact the results of operations for 2013 or 2012. The components of the Company’s deferred tax assets and liabilities are as follows: For the year ended December 31, 2015 2014 (In thousands) Noncurrent: Deferred tax assets Net operating loss carryforwards (subject to 20 year expiration) 58,590 13,604 Alternative minimum tax credit carryforward 9,615 4,111 Other 4,858 3,111 Total noncurrent deferred tax assets 73,063 20,826 Deferred tax liabilities Oil and natural gas properties and equipment (409,380 ) (348,928 ) Other (1,555 ) (26,949 ) Total noncurrent deferred tax liabilities (410,935 ) (375,877 ) Net noncurrent deferred tax liabilities $ (337,872 ) $ (355,051 ) Federal net operating loss carryforwards totaled $168.3 million and $38.9 million at December 31, 2015 and 2014, respectively, and will begin to expire in 2034.

Supplemental Disclosure of Oil

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 (1) 2013 (In thousands) Property acquisition costs: Proved $ 104,532 $ 581,307 $ 86,958 Unproved 351,806 622,210 7,875 Exploration costs — 16,762 — Development costs 378,910 462,063 136,832 Total costs incurred $ 835,248 $ 1,682,342 $ 231,665 (1) Includes non-cash additions in connection with the Company's IPO in 2014 of approximately $842 million . 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: 2015 2014 (In thousands) Capitalized costs: Proved $ 2,197,056 $ 1,585,125 Unproved 878,995 655,678 $ 3,076,051 $ 2,240,803 Less accumulated depreciation, depletion, amortization and impairment (357,524 ) (171,046 ) Net capitalized costs $ 2,718,527 $ 2,069,757 Results of Oil and Natural Gas Producing Activities The results of operations of oil and natural gas producing activities (excluding corporate overhead and interest costs) are presented below for the years ended December 31: 2015 2014 2013 (In thousands) Revenues: Oil and natural gas sales $ 283,992 $ 281,925 $ 123,042 Costs: Lease operating expenses 53,124 34,704 14,113 Production and ad valorem taxes 19,995 19,758 8,326 Depreciation, depletion, and amortization 154,039 87,844 47,158 Asset retirement obligation accretion 336 142 121 Impairments 34,269 4,344 — Exploration 2,380 3,854 551 Income tax expense (benefit) (11,683 ) 157,806 2,262 Results of operations $ 31,532 $ (26,527 ) $ 50,511 Net Proved Oil and Natural Gas Reserves The Company’s proved oil and natural gas reserves as of December 31, 2015 were audited by independent third party reserve engineers. The Company's proved oil and natural gas reserves as of December 31, 2014, and the Predecessor’s proved oil and natural gas reserves as of December 31, 2013, were prepared by independent third party reserve engineers. In accordance with SEC regulations, reserves at December 31, 2015, 2014, and 2013 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. 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. An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, for the years ended December 31, 2015, 2014, and 2013 is as follows: Natural Gas (MMcf) Oil (MBbls) NGLs (MBbls) MBoe Proved developed and undeveloped reserves: As of January 1, 2013 40,692 20,863 4,956 32,600 Revisions of previous estimates (2,628 ) (941 ) (2,465 ) (3,844 ) Extensions, discoveries and other additions 8,151 6,301 3,440 11,099 Divestitures (14,687 ) (5,156 ) — (7,603 ) Purchases of minerals in place 5,872 3,832 1,232 6,044 Production (1,597 ) (1,167 ) (250 ) (1,683 ) As of December 31, 2013 35,803 23,732 6,913 36,613 Revisions of previous estimates (5,477 ) 223 2,219 1,529 Extensions, discoveries and other additions 25,229 30,023 5,897 40,125 Purchases of minerals in place 39,841 18,344 7,428 32,412 Production (2,974 ) (3,049 ) (718 ) (4,263 ) As of December 31, 2014 92,422 69,273 21,739 106,416 Revisions of previous estimates (20,205 ) (12,886 ) (4,251 ) (20,505 ) Extensions, discoveries and other additions 55,313 50,375 6,971 66,565 Purchases of minerals in place 10,968 10,178 2,373 14,379 Production (4,991 ) (5,805 ) (1,045 ) (7,682 ) As of December 31, 2015 133,507 111,135 25,787 159,173 Proved developed reserves: December 31, 2013 14,396 9,533 2,703 14,636 December 31, 2014 35,921 27,716 8,221 41,924 December 31, 2015 56,640 44,128 11,020 64,588 Proved undeveloped reserves: December 31, 2013 21,407 14,199 4,210 21,977 December 31, 2014 56,501 41,557 13,518 64,492 December 31, 2015 76,867 67,007 14,767 94,585 The tables above include changes in estimated quantities of oil and natural gas reserves shown in MBbl equivalents (“MBoe”) at a rate of six MMcf per one MBbl. For the year ended December 31, 2015, the Company’s negative revision of previous estimated quantities of 20,505 MBoe is primarily due to negative revisions due to pricing of 19,641 MBoe. Extensions, discoveries and other additions of 66,565 MBoe during 2015, result 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. For the year ended December 31, 2014, the Company’s positive revision of previous estimated quantities of 1,529 MBoe is primarily due to the change in estimates and type curves, which more than offset negative revisions due to pricing of 4,053 MBoe. Extensions, discoveries and other additions of 40,125 MBoe during 2014, result 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 32,412 MBoe during 2014 were related to the Collins and Wallace contributions in connection with our IPO, and the Glasscock County acquisition. For the year ended December 31, 2013, the Predecessor’s negative revision of 3,844 MBoe of previous estimated quantities is primarily due to the change in estimates and type curves. Extensions, discoveries and other additions of 11,099 MBoe during the year ended December 31, 2013, result 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 places of 6,044 MBoe during the year ended December 31, 2013 were directly related to the wells acquired through the Spanish Trail Acquisition. The divestiture of 7,603 MBoe during the year ended December 31, 2013 was due to the sale of the Western Assets. 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 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, 2015, 2014, and 2013 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12 -month period. 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 and natural gas reserves is as follows at December 31: 2015 2014 2013 (In thousands) Future cash inflows $ 5,964,332 $ 7,015,504 $ 2,547,566 Future production costs (1,855,044 ) (2,025,302 ) (727,939 ) Future development costs (1,187,244 ) (1,182,981 ) (378,695 ) Future income tax expenses(1) (699,070 ) (1,154,808 ) — Future net cash flows 2,222,974 2,652,413 1,440,932 10% discount for estimated timing of cash flows (1,426,958 ) (1,776,282 ) (890,217 ) Standardized measure of discounted future net cash flows $ 796,016 $ 876,131 $ 550,715 (1) Future net cash flows for 2013 do not include the effects of income taxes on future revenues because the Predecessor was a limited liability company not subject to entity-level income taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Predecessor’s equity holders. Following our change in tax status in January 2014, the Company is a subchapter C corporation subject to U.S. federal and state income taxes. If the Predecessor had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2013 would have been $247.4 million. In the foregoing determination of future cash inflows, sales prices used for gas and oil for December 31, 2015, 2014 and 2013 were estimated using the average price during the 12 -month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month. Prices were adjusted by lease for quality, transportation fees and regional price differentials. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing economic conditions. It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Predecessor’s 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 and natural gas reserves are as follows: 2015 2014 2013 (In thousands) Standardized measure of discounted future net cash flows, beginning of year $ 876,131 $ 550,715 $ 454,173 Changes in the year resulting from: Sales, less production costs (210,874 ) (223,608 ) (100,052 ) Revisions of previous quantity estimates (192,081 ) 20,892 (53,557 ) Extensions, discoveries and other additions 440,744 646,855 157,086 Net change in prices and production costs (537,613 ) (74,081 ) 45,388 Changes in estimated future development costs 14,480 (7,858 ) 2,318 Previously estimated development costs incurred during the period 107,829 44,925 46,938 Divestiture of reserves — — (151,440 ) Purchases of minerals in place 95,207 366,106 94,751 Accretion of discount 131,764 55,072 45,417 Net change in income taxes 164,377 (441,506 ) — Timing differences and other (93,948 ) (61,381 ) 9,693 Standardized measure of discounted future net cash flows, end of year $ 796,016 $ 876,131 $ 550,715 Estimates of economically recoverable oil 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, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	QUARTERLY FINANCIAL DATA (Unaudited) The Company’s unaudited quarterly financial data for 2015 and 2014 is summarized below. 2015 First Second Third Fourth Quarter Quarter Quarter Quarter Revenues $ 51,375 $ 78,465 $ 80,644 $ 73,508 Operating income (loss) (4,568 ) 10,912 7,443 (21,564 ) Income tax (expense) benefit 330 6,001 (4,953 ) 10,307 Net income (loss) $ (1,024 ) $ (5,453 ) $ 8,974 $ (20,751 ) Earnings (loss) per share: Basic and diluted $ (0.01 ) $ (0.07 ) $ 0.10 $ (0.21 ) 2014 First Second Third Fourth Quarter Quarter Quarter Quarter Revenues $ 57,758 $ 74,062 $ 70,645 $ 79,458 Operating income (loss) 12,657 30,576 33,160 16,512 Income tax (expense) benefit (135,213 ) (4,948 ) (20,704 ) 3,060 Net income (loss) $ (127,530 ) $ 8,226 $ 32,297 $ 89,503 Earnings (loss) per share: Basic and diluted $ (2.03 ) $ 0.11 $ 0.43 $ 1.15 In the first quarter of 2014, the Company established a $132 million provision for deferred income taxes related to the corporate reorganization, which occurred in connection with the IPO. This $132 million provision, related to our change in tax status, was then reduced by $37 million in the fourth quarter of 2014 as a result of correcting an error associated with the initial tax basis utilized in the computation of deferred tax liabilities associated with oil and gas properties. As a result of an evaluation of both quantitative and qualitative factors associated with this adjustment to deferred tax liabilities and the related income tax expense, the Company concluded that this correction was not material to any interim period that was affected. The $37 million was recorded as an adjustment of our fourth quarter income tax provision. In the fourth quarter of 2014, the third quarter of 2015, and the fourth quarter of 2015, impairment expense was $4.3 million , $4.2 million , and $30.0 million , respectively.

Summary of Significant Accoun22

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These financial statements have been prepared by the Company pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results. All such adjustments are of a normal recurring nature. Transfers of a business between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. The historical results of RSP LLC and Rising Star have been consolidated for all periods presented prior to the IPO date. The consolidated financial statements of the Company include the accounts of the Company and its wholly owned subsidiaries.
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. 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 and natural gas reserves that may affect the amount at which oil and natural gas properties are recorded. Estimation of asset retirement obligations (“AROs”) and valuations of derivative instruments also require significant assumptions. It is possible that these estimates could be revised at future dates and these revisions could be material. Depletion of oil and natural gas properties are determined using estimates of proved oil 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.
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.
Derivative and Other Financial Instruments	Derivative and Other Financial Instruments The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of oil. These derivative transactions are generally in the form of collars, swaps and puts. In addition, the Company has previously entered into interest rate derivative contracts to minimize the effects of fluctuations in interest rates. The Company reports 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. The Company reports these amounts on a gross basis by contract. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities.
Accounts Receivable	Accounts receivable, which are primarily from the sale of oil, natural gas and natural gas liquids (“NGLs”), are accrued based on estimates of the volumetric sales and prices the Company believes it will receive. In addition, settled but uncollected derivative contracts, and receivables related to joint interest billings 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 and management's expectations are that all material receivables at period-end will be collected.
Oil and Natural Gas Properties	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 on a field level, based on proved reserves, using the unit-of-production method. Capitalized exploration well costs and development costs, including AROs, are depleted on a field level, based on proved developed reserves. Capitalized acquisition costs attributable to proved oil and natural gas properties and leasehold costs are depleted on a field basis based on proved reserves using the unit-of-production method. Depletion expense for oil and natural gas producing property was $152.8 million , $87.2 million , and $46.9 million , for the years ended December 31, 2015, 2014 and 2013, 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, 2015 and December 31, 2014 consisted of the following: As of December 31, 2015 2014 (In thousands) Proved oil and natural gas properties $ 2,197,056 $ 1,585,125 Unproved oil and natural gas properties 878,995 655,678 Total oil and natural gas properties 3,076,051 2,240,803 Less: accumulated depletion and impairment (357,524 ) (171,046 ) Total oil and natural gas properties, net $ 2,718,527 $ 2,069,757 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, 2015 , 2014 and 2013, there were no costs capitalized in connection with exploratory wells in progress. Capitalized costs are evaluated for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. To determine if a field is impaired, the Company compares the carrying value of the field to the undiscounted future net cash flows by applying estimates of future oil and natural gas prices to the estimated future production of oil and natural gas reserves over the economic life of the property and deducting future costs. Future net cash flows are based upon reservoir engineers’ estimates of proved reserves. For a property determined to be impaired, an impairment loss equal to the difference between the property’s carrying value and its estimated fair value is recognized. Fair value, on a field basis, 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. For the year ended December 31, 2015, impairment expense for proved properties was $19.6 million , which related to properties whose future net revenues were less than the property's carrying value. No impairment of proved property was recorded for the years ended December 31, 2014 and 2013. The calculation of expected future net cash flows in impairment evaluations are mainly based on estimates of future oil and natural gas prices, proved reserves and risk-adjusted probable reserves quantities, and estimates of future production and capital costs associated with our proved and risk-adjusted 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. It is reasonably possible that oil and natural gas prices used in future impairment evaluations may decline, which would result in the need to further impair the carrying value of the Company's 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 year ended December 31, 2015, impairment expense for unproved property was $14.7 million , which primarily related to an 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. For the year ended December 31, 2014, impairment expense for unproved property was $4.3 million , which primarily related to an expectation that certain leasehold interests would expire and not be renewed. No impairment of unproved property was recorded for the year ended December 31, 2013. Natural gas volumes are converted to Boe at the rate of six Mcf of natural gas to one Bbl of oil. This convention is not an equivalent price basis and there may be a large difference in value between an equivalent volume of oil versus an equivalent volume of natural gas. NGL volumes are stated in barrels.
Other Property and Equipment	Other Property and Equipment Other property and equipment includes service wells, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition, and are depreciated using straight-line methods based on expected lives of the individual assets or group of assets ranging from 5 to 39 years.
Deferred Loan Costs	Deferred Loan Costs Deferred loan costs, for both the revolving credit facility and 6.625% Senior Notes, are stated at cost, net of amortization, which is computed using the effective interest method over the life of the loan.
Asset Retirement Obligation	Asset Retirement Obligations 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 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 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.
Income Taxes	Income Taxes RSP LLC was organized as a limited liability company and treated as a flow-through entity for federal income tax purposes. As such, taxable income and any related tax credits were passed through to its members and are included in their tax returns even though such net taxable income or tax credits may not have actually been distributed. Accordingly, provision for federal and state corporate income taxes has been made only for the operations of RSP Inc. beginning on January 23, 2014 in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the corporate reorganization in connection with the IPO, the Company established a $132.0 million provision for deferred income taxes, which was recognized as tax expense from continuing operations in the first quarter of 2014. This $132.0 million provision, related to our change in tax status, was subsequently adjusted to $95.2 million during the fourth quarter of 2014. The primary upward adjustments in the effective tax rate above the U.S. statutory rate are the adjustment related to the corporate reorganization noted above along with non-deductible incentive unit compensation. The following is an analysis of the Company’s consolidated income tax expense (benefit): Year Ended December 31, 2015 2014 2013 (In thousands) Current $ 5,184 $ 4,338 $ 68 Deferred (16,867 ) 153,468 2,194 Income Tax Expense (Benefit) $ (11,683 ) $ 157,806 $ 2,262 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, 2015, the Company did not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. The Company’s U.S. federal income tax returns for 2011 and beyond, and its Texas franchise tax returns for 2010 and beyond, remain subject to examination by the taxing authorities. No other jurisdiction’s returns are significant to the Company’s financial position.
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 November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes." which requires deferred tax liabilities and assets to be classified as non-current in the balance sheet. An entity is required to adopt ASU 2015-17 for annual and interim reporting periods beginning after December 15, 2016. Earlier adoption is permitted for all entities as of the beginning of an interim or annual reporting period, with prospective or retrospective application for all periods presented in the financial statements. We have elected to adopt this guidance as of the fourth quarter of fiscal year 2015. Accordingly, deferred tax liabilities in the amount of $25.8 million which were formerly classified as current liabilities at December 31, 2014 have been reclassified as long-term liabilities in the consolidated balance sheet. In September 2015, the FASB issued ASU 2015-16, “Simplifying the Accounting for Measurement-Period Adjustments," which requires the acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Public entities are required to apply ASU 2015-16 for annual and interim reporting periods beginning after December 15, 2015. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. In April 2015, the FASB issued ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs." which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying amount of the debt obligation, similar to debt discounts. An entity is required to apply ASU 2015-03 for annual and interim reporting periods beginning after December 15, 2015. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. In January 2015, the FASB issued ASU 2015-01, "Income Statement - Extraordinary and Unusual Items (Subtopic 225-20)," which eliminates the concept of extraordinary items in US GAAP. An entity is required to apply ASU 2015-01 for annual and interim reporting periods beginning after December 15, 2015. An entity may apply ASU 2015-01 prospectively or retrospectively for all periods presented in the financial statements. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which provides a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance including industry specific guidance. An entity is required to apply ASU 2014-09 for annual and interim reporting periods beginning after December 15, 2016. 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. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements.

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Schedule of Accounts Receivable	Accounts Receivable As of December 31, 2015 2014 (In thousands) Sale of oil and natural gas and related products $ 22,166 $ 24,059 Joint interest owners 5,596 10,400 Derivatives - settled, but uncollected 8,561 5,977 Total accounts receivable $ 36,323 $ 40,436
Schedule of Oil and Natural Gas Properties	The Company’s oil and natural gas properties as of December 31, 2015 and December 31, 2014 consisted of the following: As of December 31, 2015 2014 (In thousands) Proved oil and natural gas properties $ 2,197,056 $ 1,585,125 Unproved oil and natural gas properties 878,995 655,678 Total oil and natural gas properties 3,076,051 2,240,803 Less: accumulated depletion and impairment (357,524 ) (171,046 ) Total oil and natural gas properties, net $ 2,718,527 $ 2,069,757 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: 2015 2014 (In thousands) Capitalized costs: Proved $ 2,197,056 $ 1,585,125 Unproved 878,995 655,678 $ 3,076,051 $ 2,240,803 Less accumulated depreciation, depletion, amortization and impairment (357,524 ) (171,046 ) Net capitalized costs $ 2,718,527 $ 2,069,757
Schedule of Changes in Asset Retirement Obligation	The ARO consisted of the following for the period indicated: Year Ended December 31, 2015 2014 (In thousands) Asset retirement obligation at beginning of period $ 4,873 $ 2,584 Liabilities incurred or assumed 1,857 2,147 Liabilities settled (3 ) — Accretion expense 336 142 Asset retirement obligation at end of period $ 7,063 $ 4,873
Schedule of Income Tax Expense	The following is an analysis of the Company’s consolidated income tax expense (benefit): Year Ended December 31, 2015 2014 2013 (In thousands) Current $ 5,184 $ 4,338 $ 68 Deferred (16,867 ) 153,468 2,194 Income Tax Expense (Benefit) $ (11,683 ) $ 157,806 $ 2,262 The components of the provision for income taxes for the year ended December 31, 2015 is as follows: For the year ended December 31, 2015 2014 (In thousands) Current Income Tax Provision (Benefit): Federal $ 5,504 $ 4,111 State (320 ) 227 Total income tax provision (benefit) 5,184 4,338 Deferred Income Tax Provision (Benefit): Federal $ (9,649 ) $ 157,806 State (1,714 ) (227 ) Federal alternative minimum tax (5,504 ) (4,111 ) Total deferred income tax provision (benefit) (16,867 ) 153,468 Total Provision for (benefit from) Income Taxes $ (11,683 ) $ 157,806

Acquisitions and Sales of Oil24

Acquisitions and Sales of Oil and Natural Gas Property Interests (Tables)	12 Months Ended
	Dec. 31, 2015
Business Acquisition [Line Items]
Unaudited Pro Forma Financial Information	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, 2014 Year Ended December 31, 2013 Actual Pro Forma Actual Pro Forma (In thousands) (In thousands) Revenues $ 281,925 $ 286,910 $ 123,042 $ 197,309 Net income $ 2,498 $ 2,743 $ 62,738 $ 73,228
ACTOIL NPI Repurchase [Member]
Business Acquisition [Line Items]
Schedule of Significant Asset Acquisition	A summary of the consideration transferred and the assets acquired and liabilities acquired in connection with the ACTOIL NPI Repurchase is as follows (in thousands): Value of the 10,816,626 shares of the Company’s common stock issued in the ACTOIL NPI Repurchase $ 210,924 Elimination of NPI payable (36,931 ) Total consideration for the assets contributed in the ACTOIL NPI Repurchase $ 173,993 Oil and natural gas properties cost $ 157,382 Asset retirement obligation (639 ) Deferred tax asset* 17,250 Total net assets acquired** $ 173,993 _______________________________________ * Amount represents the estimated book to tax difference in oil and natural gas properties as of the acquisition date on a tax-effected basis of approximately 36% . ** Approximately 56% of acquired acreage was unproved.
Collins and Wallace Contributions [Member]
Business Acquisition [Line Items]
Schedule of Consideration Transferred, Assets Acquired and Liabilities Assumed	A summary of the consideration transferred and the fair value of assets and liabilities acquired in connection with the Collins and Wallace Contributions is as follows (in thousands): Value of the 22,023,654 shares of the Company’s common stock issued in the Collins and Wallace Contributions $ 429,461 Cash paid in the Collins and Wallace Contributions 2,219 Total consideration for the assets contributed in the Collins and Wallace Contributions $ 431,680 Fair value of oil and natural gas properties $ 653,431 Asset retirement obligation (1,063 ) Deferred tax liability* (215,609 ) Total net assets acquired ** $ 436,759 _______________________________________ * Amount represents the estimated book to tax difference in oil and natural gas properties as of the acquisition date on a tax-effected basis of approximately 36% . ** Approximately 56% of acquired acreage was unproved.
Spanish Trail Acquisition [Member]
Business Acquisition [Line Items]
Schedule of Consideration Transferred, Assets Acquired and Liabilities Assumed	RSP LLC allocated the net purchase price to the oil and natural gas properties acquired and asset retirement obligation assumed as follows (in thousands): Net purchase price $ 120,521 25% NPI Sale to ACTOIL (30,131 ) Oil and natural gas properties acquired $ 90,390 Asset retirement obligation assumed 296 Proved oil and natural gas properties $ 90,686

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions	The following table summarizes all open positions as of December 31, 2015 : Contracts Maturing During 2016 Crude Oil Collars: Notional volume (Bbl) 555,000 Weighted average ceiling price ($/Bbl)(1) $ 74.08 Weighted average floor price ($/Bbl)(1) $ 55.00 Weighted average short put price ($/Bbl)(1) $ 45.00 _______________________________________ (1) The crude oil derivative contracts are settled based on the month’s average daily NYMEX price of West Texas Intermediate Light Sweet Crude.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value, Gross Basis	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 As of December 31, As of December 31, 2015 2014 2015 2014 (In thousands) Derivative Instruments: Current amounts Commodity contracts $ 8,452 $ 76,990 $ (3,994 ) $ (1,320 ) Total derivative instruments $ 8,452 $ 76,990 $ (3,994 ) $ (1,320 )
Derivative Instruments, Gains (Losses)	The following represents the Company’s reported gains and losses on derivative instruments for the periods presented: For the Year Ended December 31, 2015 2014 2013 (In thousands) Gain (loss) on derivative instruments: Commodity derivative instruments $ 20,906 $ 81,470 $ (2,583 ) Interest rate derivative instruments — — (24 ) Total $ 20,906 $ 81,470 $ (2,607 )
Gross and Net Derivative Assets	The following table presents the Company’s gross and net derivative assets and liabilities. Gross Amount Presented on Balance Sheet Netting Adjustments(a) Net Amount (In thousands) December 31, 2015 Derivative instrument assets with right of offset or master netting agreements $ 8,452 $ (3,994 ) $ 4,458 Derivative instrument liabilities with right of offset or master netting agreements $ (3,994 ) $ 3,994 $ — December 31, 2014 Derivative instrument assets with right of offset or master netting agreements $ 76,990 $ (1,320 ) $ 75,670 Derivative instrument liabilities with right of offset or master netting agreements $ (1,320 ) $ 1,320 $ — _______________________________________ (a) With all of the Company’s financial trading counterparties, the Company has agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.
Gross and Net Derivative Liabilities	The following table presents the Company’s gross and net derivative assets and liabilities. Gross Amount Presented on Balance Sheet Netting Adjustments(a) Net Amount (In thousands) December 31, 2015 Derivative instrument assets with right of offset or master netting agreements $ 8,452 $ (3,994 ) $ 4,458 Derivative instrument liabilities with right of offset or master netting agreements $ (3,994 ) $ 3,994 $ — December 31, 2014 Derivative instrument assets with right of offset or master netting agreements $ 76,990 $ (1,320 ) $ 75,670 Derivative instrument liabilities with right of offset or master netting agreements $ (1,320 ) $ 1,320 $ — _______________________________________ (a) With all of the Company’s financial trading counterparties, the Company has agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. Level 1 Level 2 Level 3 Total fair value (In thousands) As of December 31, 2015: Commodity derivative instruments $ — $ 4,458 $ — $ 4,458 Total $ — $ 4,458 $ — $ 4,458 Level 1 Level 2 Level 3 Total fair value (In thousands) As of December 31, 2014: Commodity derivative instruments $ — $ 75,670 $ — $ 75,670 Total $ — $ 75,670 $ — $ 75,670

Long-Term Debt Long-Term Debt (

Long-Term Debt Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	Long-term debt, including the effects of issuance discounts, consists of the following: As of December 31, 2015 2014 (In millions) Revolving credit facility $ — $ — 6.625% Senior notes 698.7 500.0 Total long-term debt $ 698.7 $ 500.0

Major Customers and Suppliers (

Major Customers and Suppliers (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 Shell Trading (US) Company 37 % 31 % 40 % Phillips 66 Company 22 % — % — % Enterprise Crude Oil LLC 12 % 24 % 14 % Diamondback E&P, LLC 13 % 14 % 11 % Plains Marketing, L.P. — % — % 13 % Permian Transport & Trading 5 % 21 % — %

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Share-based Compensation, Restricted Stock Award Activity	The following table represents restricted stock award activity for the twelve months ended December 31: 2015 2014 Shares Weighted Average Fair Value Shares Weighted Average Fair Value Restricted shares outstanding, beginning of period 477,767 $ 23.71 — $ — Restricted shares granted 279,181 27.18 489,544 23.69 Restricted shares canceled (6,640 ) 26.43 (11,777 ) 23.03 Restricted shares vested (250,779 ) 22.97 — — Restricted shares outstanding, end of period 499,529 $ 25.99 477,767 $ 23.71
Share-based Compensation, Performance Shares Award Outstanding Activity	The following table represents performance-based restricted stock award activity for the twelve months ended December 31: 2015 2014 Shares Weighted Average Fair Value Shares Weighted Average Fair Value Restricted shares outstanding, beginning of period 134,400 $ 28.14 — $ — Restricted shares granted 159,932 31.74 134,400 28.14 Restricted shares outstanding, end of period 294,332 $ 31.41 134,400 $ 28.14

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Contractual Obligations, Annual Maturity Schedule	A summary of the Company's contractual obligations as of December 31, 2015 is provided in the following table (in thousands). Payments Due by Period For the Year Ended December 31, 2016 2017 2018 2019 2020 Thereafter Total (In thousands) Revolving credit facility (1) $ — $ — $ — $ — $ — $ — $ — 6.625% Senior Notes (2) — — — — — 700,000 700,000 Interest cost (3) 46,375 46,375 46,375 46,375 46,375 92,750 324,625 Drilling rig commitments (4) 19,933 3,035 — — — — 22,968 Office and equipment leases 1,316 1,201 1,018 844 138 70 4,587 Asset retirement obligations (5) — — — — — 7,063 7,063 Total $ 67,624 $ 50,611 $ 47,393 $ 47,219 $ 46,513 $ 799,883 $ 1,059,243 (1) This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on our revolving credit facility because obligations thereunder are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. Any borrowings under the revolving credit facility must be repaid by August 2019. (2) Includes principal only. (3) Related to fixed rate debt only, which is the 6.625% Senior Notes. (4) The values in the table represent the gross amounts that the Company is committed to pay. (5) Amounts represent estimates of our future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment.

Earnings per Share (Tables)

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: As of December 31, 2015 2014 Numerator: Net income (loss) available to stockholders $ (18,254 ) $ 2,498 Basic net income allocable to participating securities (1) — 15 Income (loss) available to stockholders $ (18,254 ) $ 2,483 Denominator: Weighted average number of common shares outstanding - basic 86,770 71,898 Effect of dilutive securities: Restricted stock — — Weighted average number of common shares outstanding - diluted 86,770 71,898 Net income (loss) per share: Basic $ (0.21 ) $ 0.03 Diluted $ (0.21 ) $ 0.03 _______________________________________ (1) Restricted share 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.
Schedule of Pro Forma Earnings Per Share, Basic and Diluted	A reconciliation of the components of pro forma basic and diluted earnings per common share is presented in the table below: Year Ended December 31, 2014 Numerator: Income before taxes, as reported $ 160,304 Pro forma provision for income taxes 57,709 Pro forma net income available to stockholders 102,595 Basic net income allocable to participating securities 599 Pro forma net income available to stockholders $ 101,996 Denominator: Weighted average number of common shares outstanding - basic 74,297 Effect of dilutive securities: Restricted stock — Weighted average number of common shares outstanding - diluted 74,297 Net income per share: Basic $ 1.37 Diluted $ 1.37

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of Components, Provision for Income Taxes	The following is an analysis of the Company’s consolidated income tax expense (benefit): Year Ended December 31, 2015 2014 2013 (In thousands) Current $ 5,184 $ 4,338 $ 68 Deferred (16,867 ) 153,468 2,194 Income Tax Expense (Benefit) $ (11,683 ) $ 157,806 $ 2,262 The components of the provision for income taxes for the year ended December 31, 2015 is as follows: For the year ended December 31, 2015 2014 (In thousands) Current Income Tax Provision (Benefit): Federal $ 5,504 $ 4,111 State (320 ) 227 Total income tax provision (benefit) 5,184 4,338 Deferred Income Tax Provision (Benefit): Federal $ (9,649 ) $ 157,806 State (1,714 ) (227 ) Federal alternative minimum tax (5,504 ) (4,111 ) Total deferred income tax provision (benefit) (16,867 ) 153,468 Total Provision for (benefit from) Income Taxes $ (11,683 ) $ 157,806
Schedule of Income Tax Rate Reconciliation	A reconciliation of the statutory federal income tax amount to the recorded expense is as follows: For the year ended December 31, 2015 2014 (In thousands) Income tax expense (benefit) at the federal statutory rate (35%) $ (10,478 ) $ 56,106 Income tax expense relating to change in tax status — 95,162 State income tax expense (benefit), net of federal tax benefit (1,322 ) 1,081 Non-deductible expenses 69 5,457 Other 48 — Provision for (benefit from) income taxes $ (11,683 ) $ 157,806
Schedule 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, 2015 2014 (In thousands) Noncurrent: Deferred tax assets Net operating loss carryforwards (subject to 20 year expiration) 58,590 13,604 Alternative minimum tax credit carryforward 9,615 4,111 Other 4,858 3,111 Total noncurrent deferred tax assets 73,063 20,826 Deferred tax liabilities Oil and natural gas properties and equipment (409,380 ) (348,928 ) Other (1,555 ) (26,949 ) Total noncurrent deferred tax liabilities (410,935 ) (375,877 ) Net noncurrent deferred tax liabilities $ (337,872 ) $ (355,051 )

Supplemental Disclosure of Oi33

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
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: 2015 2014 (1) 2013 (In thousands) Property acquisition costs: Proved $ 104,532 $ 581,307 $ 86,958 Unproved 351,806 622,210 7,875 Exploration costs — 16,762 — Development costs 378,910 462,063 136,832 Total costs incurred $ 835,248 $ 1,682,342 $ 231,665 (1) Includes non-cash additions in connection with the Company's IPO in 2014 of approximately $842 million .
Capitalized Costs Related to Oil and Natural Gas Production Activities	The Company’s oil and natural gas properties as of December 31, 2015 and December 31, 2014 consisted of the following: As of December 31, 2015 2014 (In thousands) Proved oil and natural gas properties $ 2,197,056 $ 1,585,125 Unproved oil and natural gas properties 878,995 655,678 Total oil and natural gas properties 3,076,051 2,240,803 Less: accumulated depletion and impairment (357,524 ) (171,046 ) Total oil and natural gas properties, net $ 2,718,527 $ 2,069,757 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: 2015 2014 (In thousands) Capitalized costs: Proved $ 2,197,056 $ 1,585,125 Unproved 878,995 655,678 $ 3,076,051 $ 2,240,803 Less accumulated depreciation, depletion, amortization and impairment (357,524 ) (171,046 ) Net capitalized costs $ 2,718,527 $ 2,069,757
Results of Operations of Oil and Natural Gas Producing Activities	The results of operations of oil and natural gas producing activities (excluding corporate overhead and interest costs) are presented below for the years ended December 31: 2015 2014 2013 (In thousands) Revenues: Oil and natural gas sales $ 283,992 $ 281,925 $ 123,042 Costs: Lease operating expenses 53,124 34,704 14,113 Production and ad valorem taxes 19,995 19,758 8,326 Depreciation, depletion, and amortization 154,039 87,844 47,158 Asset retirement obligation accretion 336 142 121 Impairments 34,269 4,344 — Exploration 2,380 3,854 551 Income tax expense (benefit) (11,683 ) 157,806 2,262 Results of operations $ 31,532 $ (26,527 ) $ 50,511
Schedule of Changes in Estimated Quantities of Oil and Natural Gas Reserves	An analysis of the change in estimated quantities of oil and natural gas reserves, all of which are located within the United States, for the years ended December 31, 2015, 2014, and 2013 is as follows: Natural Gas (MMcf) Oil (MBbls) NGLs (MBbls) MBoe Proved developed and undeveloped reserves: As of January 1, 2013 40,692 20,863 4,956 32,600 Revisions of previous estimates (2,628 ) (941 ) (2,465 ) (3,844 ) Extensions, discoveries and other additions 8,151 6,301 3,440 11,099 Divestitures (14,687 ) (5,156 ) — (7,603 ) Purchases of minerals in place 5,872 3,832 1,232 6,044 Production (1,597 ) (1,167 ) (250 ) (1,683 ) As of December 31, 2013 35,803 23,732 6,913 36,613 Revisions of previous estimates (5,477 ) 223 2,219 1,529 Extensions, discoveries and other additions 25,229 30,023 5,897 40,125 Purchases of minerals in place 39,841 18,344 7,428 32,412 Production (2,974 ) (3,049 ) (718 ) (4,263 ) As of December 31, 2014 92,422 69,273 21,739 106,416 Revisions of previous estimates (20,205 ) (12,886 ) (4,251 ) (20,505 ) Extensions, discoveries and other additions 55,313 50,375 6,971 66,565 Purchases of minerals in place 10,968 10,178 2,373 14,379 Production (4,991 ) (5,805 ) (1,045 ) (7,682 ) As of December 31, 2015 133,507 111,135 25,787 159,173 Proved developed reserves: December 31, 2013 14,396 9,533 2,703 14,636 December 31, 2014 35,921 27,716 8,221 41,924 December 31, 2015 56,640 44,128 11,020 64,588 Proved undeveloped reserves: December 31, 2013 21,407 14,199 4,210 21,977 December 31, 2014 56,501 41,557 13,518 64,492 December 31, 2015 76,867 67,007 14,767 94,585
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 and natural gas reserves is as follows at December 31: 2015 2014 2013 (In thousands) Future cash inflows $ 5,964,332 $ 7,015,504 $ 2,547,566 Future production costs (1,855,044 ) (2,025,302 ) (727,939 ) Future development costs (1,187,244 ) (1,182,981 ) (378,695 ) Future income tax expenses(1) (699,070 ) (1,154,808 ) — Future net cash flows 2,222,974 2,652,413 1,440,932 10% discount for estimated timing of cash flows (1,426,958 ) (1,776,282 ) (890,217 ) Standardized measure of discounted future net cash flows $ 796,016 $ 876,131 $ 550,715 (1) Future net cash flows for 2013 do not include the effects of income taxes on future revenues because the Predecessor was a limited liability company not subject to entity-level income taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Predecessor’s equity holders. Following our change in tax status in January 2014, the Company is a subchapter C corporation subject to U.S. federal and state income taxes. If the Predecessor had been subject to entity-level income taxation, the unaudited pro forma future income tax expense at December 31, 2013 would have been $247.4 million.
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 and natural gas reserves are as follows: 2015 2014 2013 (In thousands) Standardized measure of discounted future net cash flows, beginning of year $ 876,131 $ 550,715 $ 454,173 Changes in the year resulting from: Sales, less production costs (210,874 ) (223,608 ) (100,052 ) Revisions of previous quantity estimates (192,081 ) 20,892 (53,557 ) Extensions, discoveries and other additions 440,744 646,855 157,086 Net change in prices and production costs (537,613 ) (74,081 ) 45,388 Changes in estimated future development costs 14,480 (7,858 ) 2,318 Previously estimated development costs incurred during the period 107,829 44,925 46,938 Divestiture of reserves — — (151,440 ) Purchases of minerals in place 95,207 366,106 94,751 Accretion of discount 131,764 55,072 45,417 Net change in income taxes 164,377 (441,506 ) — Timing differences and other (93,948 ) (61,381 ) 9,693 Standardized measure of discounted future net cash flows, end of year $ 796,016 $ 876,131 $ 550,715

Quarterly Financial Data (Una34

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Data (Unaudited)	The Company’s unaudited quarterly financial data for 2015 and 2014 is summarized below. 2015 First Second Third Fourth Quarter Quarter Quarter Quarter Revenues $ 51,375 $ 78,465 $ 80,644 $ 73,508 Operating income (loss) (4,568 ) 10,912 7,443 (21,564 ) Income tax (expense) benefit 330 6,001 (4,953 ) 10,307 Net income (loss) $ (1,024 ) $ (5,453 ) $ 8,974 $ (20,751 ) Earnings (loss) per share: Basic and diluted $ (0.01 ) $ (0.07 ) $ 0.10 $ (0.21 ) 2014 First Second Third Fourth Quarter Quarter Quarter Quarter Revenues $ 57,758 $ 74,062 $ 70,645 $ 79,458 Operating income (loss) 12,657 30,576 33,160 16,512 Income tax (expense) benefit (135,213 ) (4,948 ) (20,704 ) 3,060 Net income (loss) $ (127,530 ) $ 8,226 $ 32,297 $ 89,503 Earnings (loss) per share: Basic and diluted $ (2.03 ) $ 0.11 $ 0.43 $ 1.15

Nature of Operations and Basi35

Nature of Operations and Basis of Presentation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands

Oct. 13, 2015

Aug. 07, 2015

Apr. 10, 2015

Mar. 23, 2015

Aug. 12, 2014

Jan. 17, 2014

Feb. 24, 2016

Dec. 31, 2015

Sep. 30, 2015

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Jan. 16, 2014

Subsidiary, Sale of Stock [Line Items]

Shares of common stock issued in public offerings net of offering costs (shares)

8,740

8,050

Proceeds from issuance of common stock

$ 218,100

$ 178,300

$ 543,524

$ 280,703

$ 0

IPO and Secondary Offering [Member]

Subsidiary, Sale of Stock [Line Items]

Total number of shares sold in the IPO (shares)

11,500

23,000

Sale of common stock in IPO (in dollars per share)

$ 25.65

$ 19.50

Shares of common stock issued in public offerings net of offering costs (shares)

4,800

Proceeds from issuance of common stock

$ 118,000

IPO [Member]

Subsidiary, Sale of Stock [Line Items]

Shares of common stock issued in public offerings net of offering costs (shares)

9,000

9,200

Proceeds from issuance of common stock

$ 180,000

Proceeds from common stock issuance, net

$ 163,000

Secondary Offering [Member]

Subsidiary, Sale of Stock [Line Items]

Number of shares sold in IPO by existing stockholders

13,800

Primary Offering [Member]

Subsidiary, Sale of Stock [Line Items]

Proceeds from issuance of common stock

$ 127,900

Over-Allotment Option [Member]

Subsidiary, Sale of Stock [Line Items]

Shares of common stock issued in public offerings net of offering costs (shares)

1,350

Proceeds from issuance of common stock

$ 19,200

Revolving credit facility [Member] | IPO [Member]

Subsidiary, Sale of Stock [Line Items]

Repayment of revolving credit facility

$ 56,000

Term loan [Member] | IPO [Member]

Subsidiary, Sale of Stock [Line Items]

Repayment of term loan

$ 70,000

Natural Gas Partners and affiliates [Member] | RSP Permian, Inc. [Member]

Subsidiary, Sale of Stock [Line Items]

Ownership percentage in Company (percent)

90.00%

Natural Gas Partners and affiliates [Member] | Rising Star GP [Member]

Subsidiary, Sale of Stock [Line Items]

Ownership percentage in Company (percent)

90.00%

90.00%

Natural Gas Partners and affiliates [Member] | Rising Star LP [Member]

Subsidiary, Sale of Stock [Line Items]

Ownership percentage in Company (percent)

80.00%

80.00%

ACTOIL, LLC [Member] | IPO [Member]

Subsidiary, Sale of Stock [Line Items]

Net profits interest (percent)

25.00%

Oil and Gas Properties, Martin and Glasscock Counties [Member]

Subsidiary, Sale of Stock [Line Items]

Net purchase price

$ 39,000

$ 274,000

Oil and Gas Properties, Martin and Glasscock Counties [Member] | Subsequent Event [Member]

Subsidiary, Sale of Stock [Line Items]

Net purchase price

$ 28,600

Summary of Significant Accoun36

Summary of Significant Accounting Policies - Accounts Receivable, Related Parties (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Sale of oil and natural gas and related products	$ 22,166	$ 24,059
Joint interest owners	5,596	10,400
Derivatives - settled, but uncollected	8,561	5,977
Total accounts receivable	$ 36,323	$ 40,436

Summary of Significant Accoun37

Summary of Significant Accounting Policies - Oil and Natural Gas (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Oil and Natural Gas Properties [Abstract]
Proved oil and natural gas properties	$ 2,197,056	$ 1,585,125
Unproved oil and natural gas properties	878,995	655,678
Total oil and natural gas properties	3,076,051	2,240,803
Less: accumulated depletion and impairment	(357,524)	(171,046)
Total oil and natural gas properties, net	$ 2,718,527	$ 2,069,757

Summary of Significant Accoun38

Summary of Significant Accounting Policies - Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of period	$ 4,873	$ 2,584
Liabilities incurred or assumed	1,857	2,147
Liabilities settled	(3)	0
Accretion expense	336	142	$ 121
Asset retirement obligation at end of period	$ 7,063	$ 4,873	$ 2,584

Summary of Significant Accoun39

Summary of Significant Accounting Policies - Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Expense (Benefit) [Abstract]
Current									$ 5,184	$ 4,338	$ 68
Deferred									(16,867)	153,468	2,194
Total Provision for (benefit from) Income Taxes	$ (10,307)	$ 4,953	$ (6,001)	$ (330)	$ (3,060)	$ 20,704	$ 4,948	$ 135,213	$ (11,683)	$ 157,806	$ 2,262

Summary of Significant Accoun40

Summary of Significant Accounting Policies - Narrative (Details)	Oct. 07, 2015shareholder	Aug. 31, 2014USD ($)	Dec. 31, 2015USD ($)shareholder	Dec. 31, 2015USD ($)Boesegment	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Sep. 26, 2014	Jan. 23, 2014USD ($)
Property, Plant and Equipment [Line Items]
Minimum project term to capitalize interest				6 months
Purchase price to acquire oil and gas properties				$ 855,743,000	$ 810,827,000	$ 231,665,000
Stated interest rate (percent)			6.625%	6.625%	6.625%
Number of operating segments | segment				1
Bad debt expense				$ 0	$ 0	0
Depletion expense				152,800,000	87,200,000	46,900,000
Costs capitalized in connection with exploratory wells in progress			$ 0	0	0	0
Impairment of proved properties				19,600,000	0	0
Impairment of proved properties				$ 14,700,000	4,300,000	0
Conversion of natural gas volumes to barrel of oil equivalent | Boe				6
Depreciation expense				$ 1,200,000	900,000	300,000
Investment in unconsolidated subsidiary			3,300,000	3,300,000
Commitment to invest in unconsolidated subsidiary			$ 5,000,000	$ 5,000,000
Ownership interest in unconsolidated subsidiary (percent)			25.00%	25.00%
Deferred loan costs			$ 15,700,000	$ 15,700,000	15,100,000
Amortization of loan fees and note discount				$ 2,219,000	1,202,000	$ 1,746,000
Provision for deferred income taxes					95,200,000			$ 132,000,000
Other property and equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Expected life				5 years
Other property and equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Expected life				39 years
Six Point Six Two Five Percent Notes Due 2022 [Member] | Unsecured Debt [Member]
Property, Plant and Equipment [Line Items]
Stated interest rate (percent)			6.625%	6.625%			6.625%
Pecos [Member]
Property, Plant and Equipment [Line Items]
Acquisition of working interests in acreage and wells		$ 4,500,000
Director [Member]
Property, Plant and Equipment [Line Items]
Number of largest shareholders referenced | shareholder	2		2
Glasscock County [Member]
Property, Plant and Equipment [Line Items]
Purchase price to acquire oil and gas properties		$ 257,000,000
UNITED STATES
Property, Plant and Equipment [Line Items]
Number of operating segments | segment				1
Oil and Gas Properties from Wolfberry Partners Resources LLC [Member]
Property, Plant and Equipment [Line Items]
Net purchase price			$ 137,000,000
Number of largest shareholders referenced | shareholder	3		3
New Accounting Pronouncement, Early Adoption, Effect [Member]
Property, Plant and Equipment [Line Items]
Reclassified deferred tax liabilities					$ (25,800,000)

Acquisitions and Sales of Oil41

Acquisitions and Sales of Oil and Natural Gas Property Interests - (Narrative) (Details)

Oct. 07, 2015shareholder

Jan. 23, 2014USD ($)

Jan. 17, 2014USD ($)

Sep. 10, 2013USD ($)

Aug. 31, 2014USD ($)

Jan. 31, 2014

Oct. 31, 2013USD ($)escrow_payment

Mar. 31, 2013USD ($)

Jul. 31, 2011

Dec. 31, 2015USD ($)aBoedrilling_locationshareholder

Sep. 30, 2015USD ($)aBoedrilling_location

Mar. 31, 2014USD ($)transaction

Dec. 31, 2015USD ($)a

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Dec. 31, 2012USD ($)

Oct. 01, 2012USD ($)

Business Acquisition [Line Items]

Purchase price to acquire oil and gas properties

$ 855,743,000

$ 810,827,000

$ 231,665,000

Costs to acquire proved oil and natural gas properties

104,532,000

581,307,000

86,958,000

Escrow held back from initial purchase price

$ 24,000

$ 24,000

$ 24,000

ACTOIL NPI Repurchase [Member]

Business Acquisition [Line Items]

Aggregate purchase price

$ 173,993,000

Asset acquisitions, value

210,924,000

Proved oil and natural gas properties

$ 173,993,000

Sale of Oil and Natural Gas Properties [Member]

Business Acquisition [Line Items]

Sale price

$ 144,200,000

$ 69,000,000

Option fee expense

$ 6,700,000

Gain (loss) from disposal, before tax

$ 6,000,000

Option to acquire additional interests

$ 2,400,000

Number of escrow payments received | escrow_payment

2

Proceeds from collection of funds held in escrow

$ 12,000,000

Resolute Sale [Member]

Business Acquisition [Line Items]

Gain (loss) from disposal, before tax

$ 22,700,000

Director [Member]

Business Acquisition [Line Items]

Number of largest shareholders referenced | shareholder

2

2

Martin, Glasscock and Dawson Counties [Member]

Business Acquisition [Line Items]

Purchase price to acquire oil and gas properties

$ 79,000,000

Number of oil and gas property acquisitions | transaction

3

Capitalized costs, proved oil and natural gas properties

$ 45,000,000

Glasscock County [Member]

Business Acquisition [Line Items]

Purchase price to acquire oil and gas properties

$ 257,000,000

Costs to acquire proved oil and natural gas properties

$ 124,000,000

ACTOIL, LLC [Member] | IPO [Member]

Business Acquisition [Line Items]

Percentage of net profit interest transferred

25.00%

ACTOIL, LLC [Member] | ACTOIL NPI Repurchase [Member]

Business Acquisition [Line Items]

Percentage of net profit interest transferred

25.00%

25.00%

Oil and Gas Properties, Martin and Glasscock Counties [Member]

Business Acquisition [Line Items]

Aggregate purchase price

$ 39,000,000

$ 274,000,000

Costs to acquire proved oil and natural gas properties

$ 61,300,000

Number of acres | a

6,548

Average royalty burden (percent)

23.00%

Approximate barrels per day | Boe

1,680

Number of drilling locations | drilling_location

191

Portion of acquisition funded with cash on hand

$ 50,000,000

Oil and Gas Properties from Wolfberry Partners Resources LLC [Member]

Business Acquisition [Line Items]

Aggregate purchase price

$ 137,000,000

Number of acres | a

4,100

4,100

Approximate barrels per day | Boe

1,900

Number of drilling locations | drilling_location

86

Accounts payable

$ 6,500,000

$ 6,500,000

Number of largest shareholders referenced | shareholder

3

3

Collins and Wallace Contributions [Member]

Business Acquisition [Line Items]

Aggregate purchase price

$ 431,680,000

Cash paid in the Collins and Wallace Contributions

2,219,000

Proved oil and natural gas properties

436,759,000

Collins and Wallace Contributions [Member] | Collins [Member]

Business Acquisition [Line Items]

Cash paid in the Collins and Wallace Contributions

1,600,000

Collins and Wallace Contributions [Member] | Wallace LP [Member]

Business Acquisition [Line Items]

Cash paid in the Collins and Wallace Contributions

$ 600,000

Spanish Trail Acquisition [Member]

Business Acquisition [Line Items]

Aggregate purchase price

$ 155,000,000

Proved oil and natural gas properties

90,686,000

Spanish Trail Acquisition [Member] | IPO [Member]

Business Acquisition [Line Items]

Aggregate purchase price

120,521,000

Spanish Trail Acquisition [Member] | ACTOIL, LLC [Member]

Business Acquisition [Line Items]

Aggregate purchase price

$ 121,000,000

Percentage of net profit interest transferred

25.00%

25.00%

Proved oil and natural gas properties

$ 91,000,000

Loans Payable [Member] | Spanish Trail Acquisition [Member]

Business Acquisition [Line Items]

Term loan, face amount

$ 70,000,000

RSP LLC, ACTOIL and Other Minority Non-operating Working Interest Owners [Member] | Sale of Oil and Natural Gas Properties [Member]

Business Acquisition [Line Items]

Interest in oil and natural gas assets sold (percent)

67.65%

67.65%

32.35%

32.35%

Sale price

$ 230,000,000

$ 230,000,000

$ 110,000,000

$ 110,000,000

Option to acquire additional interests

$ 5,000,000

$ 5,000,000

Title and Environmental Escrow [Member] | Sale of Oil and Natural Gas Properties [Member]

Business Acquisition [Line Items]

Escrow held back from initial purchase price

5,000,000

Indemnity Escrow [Member] | Sale of Oil and Natural Gas Properties [Member]

Business Acquisition [Line Items]

Escrow held back from initial purchase price

$ 11,000,000

Acquisitions and Sales of Oil42

Acquisitions and Sales of Oil and Natural Gas Property Interests - (Collins and Wallace) (Details) - Collins and Wallace Contributions [Member] - USD ($) $ in Thousands	Jan. 23, 2014	Jan. 17, 2014
Consideration Transferred [Abstract]
Number of common shares issued in acquisition	22,023,654
Value of the 22,023,654 shares of the Company’s common stock issued in the Collins and Wallace Contributions		$ 429,461
Cash paid in the Collins and Wallace Contributions		2,219
Total consideration for the assets contributed in the Collins and Wallace Contributions		431,680
Fair Value of Assets Acquired and Liabilities Assumed [Abstract]
Fair value of oil and natural gas properties		653,431
Asset retirement obligation		(1,063)
Deferred tax liability		(215,609)
Total consideration for the assets contributed in the ACTOIL NPI Repurchase		$ 436,759
Tax percentage used to estimate book to tax differences for oil and gas properties acquired		36.00%
Acreage acquired, unproved (percent)		56.00%

Acquisitions and Sales of Oil43

Acquisitions and Sales of Oil and Natural Gas Property Interests - (ACTOIL NPI Repurchase) (Details) - ACTOIL NPI Repurchase [Member] $ in Thousands	Jan. 23, 2014USD ($)shares
Business Acquisition [Line Items]
Number of shares issued for ACTOIL NPI Repurchase | shares	10,816,626
Value of the 10,816,626 shares of the Company’s common stock issued in the ACTOIL NPI Repurchase	$ 210,924
Elimination of NPI payable	(36,931)
Net purchase price	173,993
Oil and natural gas properties cost	157,382
Asset retirement obligation	(639)
Deferred tax asset	17,250
Total consideration for the assets contributed in the ACTOIL NPI Repurchase	$ 173,993
Tax percentage used to estimate book to tax differences for oil and gas properties acquired	36.00%
Acreage acquired, unproved (percent)	56.00%

Acquisitions and Sales of Oil44

Acquisitions and Sales of Oil and Natural Gas Property Interests Acquisitions and Sales of Oil and Natural Gas Property Interests - (Spanish Trail) (Details) - Spanish Trail Acquisition [Member] $ in Thousands	Sep. 10, 2013USD ($)
Business Acquisition [Line Items]
Net purchase price	$ 155,000
25% NPI Sale to ACTOIL	(30,131)
Oil and natural gas properties acquired	90,390
Asset retirement obligation assumed	296
Total consideration for the assets contributed in the ACTOIL NPI Repurchase	90,686
IPO [Member]
Business Acquisition [Line Items]
Net purchase price	$ 120,521

Acquisitions and Sales of Oil45

Acquisitions and Sales of Oil and Natural Gas Property Interests - (Pro Forma Results) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition, Pro Forma Information [Line Items]
Revenues	$ 73,508	$ 80,644	$ 78,465	$ 51,375	$ 79,458	$ 70,645	$ 74,062	$ 57,758	$ 283,992	$ 281,925	$ 123,042
Net income (loss)	$ (20,751)	$ 8,974	$ (5,453)	$ (1,024)	$ 89,503	$ 32,297	$ 8,226	$ (127,530)	$ (18,254)	2,498	62,738
Pro Forma [Member]
Business Acquisition, Pro Forma Information [Line Items]
Revenues										286,910	197,309
Net income (loss)										$ 2,743	$ 73,228

Derivative Instruments - (Outst

Derivative Instruments - (Outstanding Positions) (Details) - Commodity Contract [Member] - Crude Oil [Member] - Collars Maturing in Next Fiscal Year [Member] bbl in Thousands	12 Months Ended
	Dec. 31, 2015$ / bblbbl
Derivative [Line Items]
Notional volume (Bbl) | bbl	555
Weighted average ceiling price (in dollars per Bbl/Mmbtu)	74.08
Weighted average floor price (in dollars per Bbl/Mmbtu)	55
Weighted average short put price (in dollars per Bbl/Mmbtu)	45

Derivative Instruments - (Gross

Derivative Instruments - (Gross Assets and Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative assets	$ 8,452	$ 76,990
Derivative liabilities	(3,994)	(1,320)
Commodity Contract [Member] | Current amounts, Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	8,452	76,990
Commodity Contract [Member] | Current amounts, Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ (3,994)	$ (1,320)

Derivative Instruments - (Gain

Derivative Instruments - (Gain Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ 20,906	$ 81,470	$ (2,607)
Commodity derivative instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	20,906	81,470	(2,583)
Interest rate derivative instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$ 0	$ 0	$ (24)

Derivative Instruments - (Offse

Derivative Instruments - (Offsetting Assets and Liabilities) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Offsetting of Derivative Assets and Liabilities [Abstract]
Derivative asset, Gross Amount Presented on Balance Sheet	$ 8,452,000	$ 76,990,000
Derivative asset, Netting Adjustments	(3,994,000)	(1,320,000)
Derivative asset, Net Amount	4,458,000	75,670,000
Derivative liability, Gross Amount Presented on Balance Sheet	(3,994,000)	(1,320,000)
Derivative liability, Netting Adjustments	3,994,000	1,320,000
Derivative liability, Net Amount	0	0
Credit-Risk Related Contingent Features in Derivatives [Abstract]
Collateral posted for derivative instruments with credit-risk related contingent features	$ 0	$ 0

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$ 4,458	$ 75,670
Recurring basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	4,458	75,670
Recurring basis [Member] | Commodity derivative instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	4,458	75,670
Recurring basis [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Recurring basis [Member] | Level 1 [Member] | Commodity derivative instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Recurring basis [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	4,458	75,670
Recurring basis [Member] | Level 2 [Member] | Commodity derivative instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	4,458	75,670
Recurring basis [Member] | Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Recurring basis [Member] | Level 3 [Member] | Commodity derivative instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$ 0	$ 0

Long-Term Debt (Details)

Long-Term Debt (Details)	Sep. 26, 2014USD ($)	Feb. 24, 2016USD ($)	Jun. 30, 2015USD ($)	Sep. 30, 2015	Dec. 31, 2015USD ($)financial_ratio	Dec. 31, 2014USD ($)	Aug. 24, 2015USD ($)	Aug. 10, 2015USD ($)
Debt Instrument [Line Items]
Revolving credit facility					$ 0	$ 0
6.625% Senior notes					698,700,000	500,000,000
Total long-term debt					$ 698,700,000	$ 500,000,000
Stated interest rate (percent)					6.625%	6.625%
Subsidiary [Member]
Debt Instrument [Line Items]
Subsidiary, cumulative ownership (percent)					100.00%
Unsecured Debt [Member] | Debt Instrument, Redemption, Period Two [Member]
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	104.969%
Unsecured Debt [Member] | January 1, 2020 [Member]
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	100.00%
Unsecured Debt [Member] | Before October 1, 2017 [Member]
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	106.625%
Percentage of principal amount of debt that may be redeemed, maximum	35.00%
Unsecured Debt [Member] | Event of change in control [Member]
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed					101.00%
Six Point Six Two Five Percent Notes Due 2022 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Stated interest rate (percent)	6.625%				6.625%
Term loan, face amount	$ 500,000,000							$ 200,000,000
Debt Instrument, Percentage of Principal Amount Issued								99.25%
Debt issuance costs					$ 2,400,000	$ 11,300,000
Extinguishment of debt			$ 500,000
Six Point Six Two Five Percent Notes Due 2022 [Member] | Unsecured Debt [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Extinguishment of debt		$ 200,000
Registered Senior Notes Due 2022 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Term loan, face amount			$ 500,000,000
Registered Senior Notes Due 2022 [Member] | Unsecured Debt [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Term loan, face amount		$ 200,000,000
Revolving credit facility [Member]
Debt Instrument [Line Items]
Credit agreement, maximum borrowing capacity					$ 600,000,000		$ 600,000,000
Number of financial ratios | financial_ratio					3
Working capital ratio, required (not less than)					1
Leverage ratio, required (not greater than)					4.5
Senior secured leverage ratio (not greater than)					3.5
Variable interest rate at period end					3.50%
Credit agreement, maximum borrowing capacity, lender commitments					$ 1,000,000,000
Revolving credit facility [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Variable rate basis, base percentage prior to adjustments				100.00%
Revolving credit facility [Member] | LIBOR [Member]
Debt Instrument [Line Items]
Basis spread on variable rate				1.00%
Facility fee (percent)				0.50%
Revolving credit facility [Member] | LIBOR [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate				1.00%
Revolving credit facility [Member] | LIBOR [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate				2.00%
Revolving credit facility [Member] | Federal Funds Rate [Member]
Debt Instrument [Line Items]
Basis spread on variable rate				1.00%
Revolving credit facility [Member] | Base Rate [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate				0.00%
Revolving credit facility [Member] | Base Rate [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate				1.00%

Net Profits Interest (Details)

Net Profits Interest (Details) - USD ($)	1 Months Ended
	Jan. 31, 2014	Mar. 31, 2013	Dec. 31, 2012	Jul. 31, 2011	Mar. 31, 2014	Oct. 01, 2012
ACTOIL NPI Repurchase [Member] | ACTOIL, LLC [Member]
Business Acquisition [Line Items]
Financing agreement, face value				$ 175,000,000
Percentage of net profit interest transferred	25.00%			25.00%
Sale of Oil and Natural Gas Properties [Member]
Business Acquisition [Line Items]
Sale price		$ 144,200,000				$ 69,000,000
Option to acquire additional interests						$ 2,400,000
Sale of Oil and Natural Gas Properties [Member] | RSP LLC, ACTOIL and Other Minority Non-operating Working Interest Owners [Member]
Business Acquisition [Line Items]
Interest in oil and natural gas assets sold (percent)		67.65%	32.35%		67.65%	32.35%
Sale price		$ 230,000,000	$ 110,000,000		$ 230,000,000	$ 110,000,000
Option to acquire additional interests			5,000,000			$ 5,000,000
Sale of Oil and Natural Gas Properties [Member] | ACTOIL, LLC [Member]
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties		31,800,000	$ 15,800,000
Net profits interest, cumulative deficit					0
NPI payable					$ 21,100,000
Sale of Oil and Natural Gas Properties [Member] | ACTOIL, LLC [Member] | Proceeds Used To Reduce Cumulative Deficit [Member]
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties		21,100,000
Sale of Oil and Natural Gas Properties [Member] | ACTOIL, LLC [Member] | Proceeds Distributed To Counterparty [Member]
Business Acquisition [Line Items]
Proceeds from sale of oil and gas properties		$ 10,700,000

Major Customers and Suppliers53

Major Customers and Suppliers (Details) - Sales Revenue, Net [Member] - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Shell Trading (US) Company [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	37.00%	31.00%	40.00%
Phillips 66 Company [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	22.00%	0.00%	0.00%
Enterprise Crude Oil LLC [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	12.00%	24.00%	14.00%
Diamondback E&P, LLC [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	13.00%	14.00%	11.00%
Plains Marketing, L.P. [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	0.00%	0.00%	13.00%
Permian Transport & Trading [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	5.00%	21.00%	0.00%

Equity-Based Compensation Narra

Equity-Based Compensation Narrative (Details) - USD ($)	1 Months Ended		12 Months Ended
	Mar. 31, 2015	Jun. 30, 2014	Dec. 31, 2015	Dec. 31, 2014
Restricted stock awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense			$ 6,400,000	$ 4,700,000
Unrecognized share-based compensation expense			$ 7,900,000
Unrecognized compensation expense, weighted average recognition period			1 year 6 months
Performance-based restricted stock awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense			$ 3,000,000	800,000
Unrecognized share-based compensation expense			$ 6,300,000
Unrecognized compensation expense, weighted average recognition period			1 year 10 months 15 days
Award vesting period	2 years 9 months 29 days	2 years 9 months
Stock awards granted during the period (in shares)	159,932	134,400
Target payout percentage	100.00%	100.00%
Performance-based restricted stock awards [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout percentage	0.00%	0.00%
Performance-based restricted stock awards [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout percentage	200.00%	200.00%
Incentive Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense			$ 0	14,700,000
General and administrative expenses [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense			$ 9,400,000	$ 20,200,000

Equity-Based Compensation Sched

Equity-Based Compensation Schedule of Share-based Compensation, Restricted Stock Award Activity (Details) - Restricted stock awards [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Restricted shares outstanding, beginning of period	477,767	0
Restricted shares granted	279,181	489,544
Restricted shares canceled	(6,640)	(11,777)
Restricted shares vested	(250,779)	0
Restricted shares outstanding, end of period	499,529	477,767
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Restricted shares outstanding, beginning of period, Weighted Average Fair Value (in dollars per share)	$ 23.71	$ 0
Restricted shares granted, Weighted Average Fair Value (in dollars per share)	27.18	23.69
Restricted shares canceled, Weighted Average Fair Value (in dollars per share)	26.43	23.03
Restricted shares vested, Weighted Average Fair Value (in dollars per share)	22.97	0
Restricted shares outstanding, end of period, Weighted Average Fair Value (in dollars per share)	$ 25.99	$ 23.71

Equity-Based Compensation Share

Equity-Based Compensation Share-based Compensation, Performance Shares Award Outstanding Activity (Details) - Performance-based restricted stock awards [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Restricted shares outstanding, beginning of period	134,400	0
Restricted shares granted	159,932	134,400
Restricted shares outstanding, end of period	294,332	134,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Restricted shares outstanding, beginning of period, Weighted Average Fair Value (in dollars per share)	$ 28.14	$ 0
Restricted shares granted, Weighted Average Fair Value (in dollars per share)	31.74	28.14
Restricted shares outstanding, end of period, Weighted Average Fair Value (in dollars per share)	$ 31.41	$ 28.14

Commitments and Contingencies -

Commitments and Contingencies - (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Rent expense	$ 0.9	$ 0.5	$ 0.2

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies - (Contractual Obligations) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Sep. 26, 2014
Contractual Obligation, Fiscal Year Maturity [Abstract]
2,016	$ 67,624
2,017	50,611
2,018	47,393
2,019	47,219
2,020	46,513
Thereafter	799,883
Total	$ 1,059,243
Stated interest rate (percent)	6.625%	6.625%
Interest cost [Member]
Contractual Obligation, Fiscal Year Maturity [Abstract]
2,016	$ 46,375
2,017	46,375
2,018	46,375
2,019	46,375
2,020	46,375
Thereafter	92,750
Total	324,625
Drilling rig commitments [Member]
Contractual Obligation, Fiscal Year Maturity [Abstract]
2,016	19,933
2,017	3,035
2,018	0
2,019	0
2,020	0
Thereafter	0
Total	22,968
Office and equipment leases [Member]
Contractual Obligation, Fiscal Year Maturity [Abstract]
2,016	1,316
2,017	1,201
2,018	1,018
2,019	844
2,020	138
Thereafter	70
Total	4,587
Asset retirement obligations [Member]
Contractual Obligation, Fiscal Year Maturity [Abstract]
2,016	0
2,017	0
2,018	0
2,019	0
2,020	0
Thereafter	7,063
Total	7,063
6.625% Senior Notes [Member]
Contractual Obligation, Fiscal Year Maturity [Abstract]
2,016	0
2,017	0
2,018	0
2,019	0
2,020	0
Thereafter	700,000
Total	700,000
Stated interest rate (percent)			6.625%
Revolving credit facility [Member]
Contractual Obligation, Fiscal Year Maturity [Abstract]
2,016	0
2,017	0
2,018	0
2,019	0
2,020	0
Thereafter	0
Total	$ 0

Earnings per Share - Basic and

Earnings per Share - Basic and Diluted (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Numerator:
Net income (loss) available to stockholders	$ (18,254)	$ 2,498
Basic net income allocable to participating securities	0	15
Income (loss) available to stockholders	$ (18,254)	$ 2,483
Denominator:
Weighted average number of common shares outstanding - basic (in shares)	86,770	71,898
Restricted stock (in shares)	0	0
Weighted average number of common shares outstanding - diluted (in shares)	86,770	71,898
Net income (loss) per share:
Basic (in dollars per share)	$ (0.21)	$ 0.03
Diluted (in dollars per share)	$ (0.21)	$ 0.03

Earnings per Share - Pro Forma

Earnings per Share - Pro Forma (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Numerator:
Income before taxes, as reported	$ (29,937)	$ 160,304	$ 65,000
Pro forma provision for income taxes		57,709
Pro forma net income available to stockholders		102,595
Basic net income allocable to participating securities		599
Pro forma net income available to stockholders		$ 101,996
Denominator:
Weighted average number of common shares outstanding - basic (in shares)		74,297
Restricted stock (in shares)		0
Weighted average number of common shares outstanding - diluted (in shares)		74,297
Net income per share:
Basic (in dollars per share)		$ 1.37
Diluted (in dollars per share)		$ 1.37

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Provision for deferred income tax expense (benefit)	$ 95,000	$ 132,000
Income tax expense relating to change in tax status			$ 0	$ 95,162
Federal net operating loss carryforwards	$ 38,900		$ 168,300	$ 38,900

Income Taxes - Provision (Detai

Income Taxes - Provision (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current Income Tax Provision (Benefit):
Federal									$ 5,504	$ 4,111
State									(320)	227
Total income tax provision (benefit)									5,184	4,338	$ 68
Deferred Income Tax Provision (Benefit):
Federal									(9,649)	157,806
State									(1,714)	(227)
Federal alternative minimum tax									(5,504)	(4,111)
Total deferred income tax provision (benefit)									(16,867)	153,468	2,194
Total Provision for (benefit from) Income Taxes	$ (10,307)	$ 4,953	$ (6,001)	$ (330)	$ (3,060)	$ 20,704	$ 4,948	$ 135,213	$ (11,683)	$ 157,806	$ 2,262

Income Taxes - Reconciliation (

Income Taxes - Reconciliation (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Federal statutory income tax rate (percent)									35.00%	35.00%
Income tax expense (benefit) at the federal statutory rate (35%)									$ (10,478)	$ 56,106
Income tax expense relating to change in tax status									0	95,162
State income tax expense (benefit), net of federal tax benefit									(1,322)	1,081
Non-deductible expenses									69	5,457
Other									48	0
Total Provision for (benefit from) Income Taxes	$ (10,307)	$ 4,953	$ (6,001)	$ (330)	$ (3,060)	$ 20,704	$ 4,948	$ 135,213	$ (11,683)	$ 157,806	$ 2,262

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets
Net operating loss carryforwards expiration period (in years)	20 years	20 years
Net operating loss carryforwards (subject to 20 year expiration)	$ 58,590	$ 13,604
Alternative minimum tax credit carryforward	9,615	4,111
Other	4,858	3,111
Total noncurrent deferred tax assets	73,063	20,826
Deferred tax liabilities
Oil and natural gas properties and equipment	(409,380)	(348,928)
Other	(1,555)	(26,949)
Total noncurrent deferred tax liabilities	(410,935)	(375,877)
Net noncurrent deferred tax liabilities	$ (337,872)	$ (355,051)

Supplemental Disclosure of Oi65

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Proved	$ 104,532	$ 581,307	$ 86,958
Unproved	351,806	622,210	7,875
Exploration costs	0	16,762	0
Development costs	378,910	462,063	136,832
Total costs incurred	$ 835,248	1,682,342	$ 231,665
Acquisition of oil and gas reserves, noncash additions		$ 842,000

Supplemental Disclosure of Oi66

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Capitalized Oil and Natural Gas Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Proved	$ 2,197,056	$ 1,585,125
Unproved	878,995	655,678
Capitalized costs, gross	3,076,051	2,240,803
Less accumulated depreciation, depletion, amortization and impairment	(357,524)	(171,046)
Net capitalized costs	$ 2,718,527	$ 2,069,757

Supplemental Disclosure of Oi67

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Results of Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Oil and natural gas sales	$ 73,508	$ 80,644	$ 78,465	$ 51,375	$ 79,458	$ 70,645	$ 74,062	$ 57,758	$ 283,992	$ 281,925	$ 123,042
Lease operating expenses									53,124	34,704	14,113
Production and ad valorem taxes									19,995	19,758	8,326
Depreciation, depletion, and amortization									154,039	87,844	47,158
Asset retirement obligation accretion									336	142	121
Impairments	30,000	4,200			4,300				34,269	4,344	0
Exploration									2,380	3,854	551
Income tax expense (benefit)	$ (10,307)	$ 4,953	$ (6,001)	$ (330)	$ (3,060)	$ 20,704	$ 4,948	$ 135,213	(11,683)	157,806	2,262
Results of operations									$ 31,532	$ (26,527)	$ 50,511

Supplemental Disclosure of Oi68

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Proved Reserves (Details) Mcf in Thousands, MBoe in Thousands, MBbls in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2015BoeMBoeMBblsMcf	Dec. 31, 2015MBoeMBblsMcf	Dec. 31, 2015MBoeMBblsMcf	Dec. 31, 2015MBoeMBblsMcf	Dec. 31, 2014BoeMBoeMBblsMcf	Dec. 31, 2014MBoeMBblsMcf	Dec. 31, 2014MBoeMBblsMcf	Dec. 31, 2014MBoeMBblsMcf	Dec. 31, 2013BoeMBoeMBblsMcf	Dec. 31, 2013MBoeMBblsMcf	Dec. 31, 2013MBoeMBblsMcf	Dec. 31, 2013MBoeMBblsMcf
Proved Developed and Undeveloped Reserves, Energy [Roll Forward]
Beginning of year | MBoe			106,416				36,613				32,600
Revisions of previous estimates	(20,505)		(20,505)		1,529		1,529		(3,844)		(3,844)
Extensions, discoveries and other additions	66,565		66,565		40,125		40,125		11,099		11,099
Divestitures									(7,603)		(7,603)
Purchases of minerals in place	14,379		14,379		32,412		32,412		6,044		6,044
Production | MBoe			(7,682)				(4,263)				(1,683)
End of year | MBoe			159,173				106,416				36,613
Proved Developed Reserves, Energy [Abstract]
Proved developed reserves | MBoe	64,588	64,588	64,588	64,588	41,924	41,924	41,924	41,924	14,636	14,636	14,636	14,636
Proved Undeveloped Reserves, Energy [Abstract]
Proved undeveloped reserves | MBoe	94,585	94,585	94,585	94,585	64,492	64,492	64,492	64,492	21,977	21,977	21,977	21,977
Natural Gas [Member]
Proved Developed and Undeveloped Reserves, Volume [Roll Forward]
Beginning of year | Mcf				92,422				35,803				40,692
Revisions of previous estimates | Mcf				(20,205)				(5,477)				(2,628)
Extensions, discoveries and other additions | Mcf				55,313				25,229				8,151
Divestitures | Mcf												(14,687)
Purchases of minerals in place | Mcf				10,968				39,841				5,872
Production | Mcf				(4,991)				(2,974)				(1,597)
End of year | Mcf				133,507				92,422				35,803
Proved Developed Reserves, Volume [Abstract]
Proved developed reserves | Mcf	56,640	56,640	56,640	56,640	35,921	35,921	35,921	35,921	14,396	14,396	14,396	14,396
Proved Undeveloped Reserves, Volume [Abstract]
Proved undeveloped reserves | Mcf	76,867	76,867	76,867	76,867	56,501	56,501	56,501	56,501	21,407	21,407	21,407	21,407
Oil [Member]
Proved Developed and Undeveloped Reserves, Volume [Roll Forward]
Beginning of year		69,273				23,732				20,863
Revisions of previous estimates		(12,886)				223				(941)
Extensions, discoveries and other additions		50,375				30,023				6,301
Divestitures										(5,156)
Purchases of minerals in place		10,178				18,344				3,832
Production		(5,805)				(3,049)				(1,167)
End of year		111,135				69,273				23,732
Proved Developed Reserves, Volume [Abstract]
Proved developed reserves	44,128	44,128	44,128	44,128	27,716	27,716	27,716	27,716	9,533	9,533	9,533	9,533
Proved Undeveloped Reserves, Volume [Abstract]
Proved undeveloped reserves	67,007	67,007	67,007	67,007	41,557	41,557	41,557	41,557	14,199	14,199	14,199	14,199
Natural Gas Liquids [Member]
Proved Developed and Undeveloped Reserves, Volume [Roll Forward]
Beginning of year		21,739				6,913				4,956
Revisions of previous estimates		(4,251)				2,219				(2,465)
Extensions, discoveries and other additions		6,971				5,897				3,440
Divestitures										0
Purchases of minerals in place		2,373				7,428				1,232
Production		(1,045)				(718)				(250)
End of year		25,787				21,739				6,913
Proved Developed Reserves, Volume [Abstract]
Proved developed reserves	11,020	11,020	11,020	11,020	8,221	8,221	8,221	8,221	2,703	2,703	2,703	2,703
Proved Undeveloped Reserves, Volume [Abstract]
Proved undeveloped reserves	14,767	14,767	14,767	14,767	13,518	13,518	13,518	13,518	4,210	4,210	4,210	4,210

Supplemental Disclosure of Oi69

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Discounted Future Net Cash Flows, Proved Reserves (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 5,964,332	$ 7,015,504	$ 2,547,566
Future production costs	(1,855,044)	(2,025,302)	(727,939)
Future development costs	(1,187,244)	(1,182,981)	(378,695)
Future income tax expenses	(699,070)	(1,154,808)	0
Future net cash flows	2,222,974	2,652,413	1,440,932
10% discount for estimated timing of cash flows	(1,426,958)	(1,776,282)	(890,217)
Standardized measure of discounted future net cash flows	$ 796,016	$ 876,131	550,715	$ 454,173
Pro Forma [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future income tax expenses			$ (247,400)

Supplemental Disclosure of Oi70

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, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ 876,131	$ 550,715	$ 454,173
Sales, less production costs	(210,874)	(223,608)	(100,052)
Revisions of previous quantity estimates	(192,081)	20,892	(53,557)
Extensions, discoveries and other additions	440,744	646,855	157,086
Net change in prices and production costs	(537,613)	(74,081)	45,388
Changes in estimated future development costs	14,480	(7,858)	2,318
Previously estimated development costs incurred during the period	107,829	44,925	46,938
Divestiture of reserves	0	0	(151,440)
Purchases of minerals in place	95,207	366,106	94,751
Accretion of discount	131,764	55,072	45,417
Net change in income taxes	164,377	(441,506)	0
Timing differences and other	(93,948)	(61,381)	9,693
Standardized measure of discounted future net cash flows, end of year	$ 796,016	$ 876,131	$ 550,715

Supplemental Disclosure of Oi71

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Narrative (Details) MBoe in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2015Boe	Dec. 31, 2015MBoe	Dec. 31, 2014Boe	Dec. 31, 2014MBoe	Dec. 31, 2013Boe	Dec. 31, 2013MBoe
Extractive Industries [Abstract]
Conversion of natural gas volumes to barrel of oil equivalent			6
Revisions of previous estimates			20,505,000	20,505	(1,529,000)	(1,529)	3,844,000	3,844
Negative revisions of previous estimates			19,641,000		4,053,000
Extensions, discoveries and other additions			66,565,000	66,565	40,125,000	40,125	11,099,000	11,099
Purchases of minerals in place			14,379,000	14,379	32,412,000	32,412	6,044,000	6,044
Divestitures							(7,603,000)	(7,603)
Discounted future net cash flows relating to oil and gas activities, term	12 months
Discounted future net cash flows relating to oil and gas activities, discount rate (percent)		10.00%

Quarterly Financial Data (Una72

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 73,508	$ 80,644	$ 78,465	$ 51,375	$ 79,458	$ 70,645	$ 74,062	$ 57,758	$ 283,992	$ 281,925	$ 123,042
Operating income (loss)	(21,564)	7,443	10,912	(4,568)	16,512	33,160	30,576	12,657	(7,774)	92,909	71,621
Income tax (expense) benefit	10,307	(4,953)	6,001	330	3,060	(20,704)	(4,948)	(135,213)	11,683	(157,806)	(2,262)
Net income (loss)	$ (20,751)	$ 8,974	$ (5,453)	$ (1,024)	$ 89,503	$ 32,297	$ 8,226	$ (127,530)	(18,254)	2,498	62,738
Basic and diluted (in dollars per share)	$ (0.21)	$ 0.10	$ (0.07)	$ (0.01)	$ 1.15	$ 0.43	$ 0.11	$ (2.03)
Provision for deferred income taxes, conversion to taxable C-corp								$ 132,000
Decrease in deferred income taxes	$ (37,000)				$ (37,000)
Impairment expense	$ 30,000	$ 4,200			$ 4,300				$ 34,269	$ 4,344	$ 0