RSP Permian (RSPP) 10-K 17 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2014	Mar. 16, 2015	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	RSP Permian, Inc.
Entity Central Index Key	1588216
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Amendment Flag	FALSE
Entity Public Float			$1,097,011,350
Entity Common Stock, Shares Outstanding		78,267,452

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
CURRENT ASSETS
Cash and cash equivalents	$56,292	$13,234
Accounts receivable	40,436	26,346
Accounts receivable, related party	0	3,672
Other assets	24	3,212
Derivative instruments	76,990	671
Total current assets	173,742	47,135
PROPERTY, PLANT AND EQUIPMENT
Oil and natural gas properties, successful efforts method	2,240,803	595,486
Accumulated depletion and impairment	-171,046	-88,514
Total oil and natural gas properties, net	2,069,757	506,972
Other property and equipment, net	24,861	9,316
Total property, plant and equipment	2,094,618	516,288
OTHER LONG-TERM ASSETS
Derivative instruments	0	1,078
Restricted cash	152	150
Other long-term assets	21,435	23,004
Total long-term assets	21,587	24,232
TOTAL ASSETS	2,289,947	587,655
CURRENT LIABILITIES
Accounts payable	35,728	18,548
Accrued expenses	57,977	10,460
Interest payable	9,227	296
Deferred taxes	25,789	0
Derivative instruments	1,320	1,562
Total current liabilities	130,041	30,866
LONG-TERM LIABILITIES
Asset retirement obligations	4,873	2,584
Derivative instruments	0	43
Long-term debt	500,000	128,155
NPI payable	0	36,931
Deferred taxes	329,262	2,195
Total long-term liabilities	834,135	169,908
Total liabilities	964,176	200,774
STOCKHOLDERS’/MEMBERS’ EQUITY
Members’ equity	0	386,881
Common stock, $.01 par value; 300,000,000 shares authorized, 77,903,834 shares issued and outstanding at December 31, 2014; no shares authorized, issued or outstanding at December 31, 2013	779	0
Additional paid-in capital	1,322,494	0
Retained earnings	2,498	0
Total stockholders’/members’ equity	1,325,771	386,881
TOTAL LIABILITIES AND STOCKHOLDERS’/MEMBERS’ EQUITY	$2,289,947	$587,655

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$0.01
Common stock, shares authorized	300,000,000	0
Common stock, shares issued	77,903,834	0
Common stock, shares outstanding	77,903,834	0

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES
Oil sales	$253,371	$110,345	$91,441
Natural gas sales	10,572	5,383	4,284
NGL sales	17,982	7,314	8,702
Total revenues	281,925	123,042	104,427
OPERATING EXPENSES
Lease operating expenses	34,704	14,113	12,693
Production and ad valorem taxes	19,758	8,326	7,575
Depreciation, depletion and amortization	87,844	47,158	48,803
Asset retirement obligation accretion	142	121	115
Impairments	4,344	0	0
Exploration	3,854	551	161
General and administrative expenses	38,357	3,852	2,859
Total operating expenses	189,003	74,121	72,206
Loss (gain) on sale of assets	13	-22,700	-6,734
OPERATING INCOME	92,909	71,621	38,955
OTHER INCOME (EXPENSE)
Other income (expenses), net	-44	1,202	884
Gain (loss) on derivative instruments	81,470	-2,607	-796
Interest expense	-14,031	-5,216	-3,474
Total other income (expense)	67,395	-6,621	-3,386
INCOME BEFORE TAXES	160,304	65,000	35,569
INCOME TAX (EXPENSE) BENEFIT	-157,806	-2,262	339
NET INCOME	$2,498	$62,738	$35,908
Income per common share:
Basic (in dollars per share)	$0.03
Diluted (in dollars per share)	$0.03
Weighted average shares outstanding:
Basic (in shares)	71,898
Diluted (in shares)	71,898

Consolidated_Statement_of_Chan

Consolidated Statement of Changes In Stockholders'/Members' Equity (USD $)	Total	Members' Equity [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]
In Thousands, except Share data, unless otherwise specified
Total Stockholders' Equity/Members' Equity, beginning balance at Dec. 31, 2011	$317,935	$317,935	$0	$0	$0
Issued Shares of Common Stock, beginning balance at Dec. 31, 2011			0
Stockholders' Equity/Members' Equity [Roll Forward]
Net income	35,908	35,908
Total Stockholders' Equity/Members' Equity, ending balance at Dec. 31, 2012	353,843	353,843	0	0	0
Issued Shares of Common Stock, ending balance at Dec. 31, 2012			0
Stockholders' Equity/Members' Equity [Roll Forward]
Contributions	300	300
Distributions	-30,000	-30,000
Net income	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 at Dec. 31, 2013	0		0
Stockholders' Equity/Members' 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, Shares			63,275,000
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
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, Shares			14,017,000
Shares of common stock issued in public offerings, net of offering costs	280,703		140	280,563
Equity-based compensation, Shares			612,000
Equity-based compensation	20,232		6	20,226
Net income	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 at Dec. 31, 2014	77,903,834		77,904,000

Consolidated_Statement_of_Chan1

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

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$2,498	$62,738	$35,908
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	87,844	47,158	48,347
Impairment	4,344	0	0
Abandoned equipment	0	2	135
Asset retirement obligation accretion	142	121	115
Equity-based compensation	20,232	0	0
Amortization of loan fees	1,202	1,746	456
Deferred income taxes	153,468	2,195	0
Equity in earnings of investment	98	-14	-11
Gain on certificate of deposit	0	0	-3
Loss (gain) on sale of assets	13	-22,700	-6,734
(Gain) loss on derivative instruments	-81,470	2,607	796
Net cash payments on settled derivatives	-102	-886	-474
Changes in operating assets and liabilities:
Accounts receivable and accounts receivable from related parties	-4,383	-3,758	-3,907
Other assets	14,952	-17,739	-2,148
Interest payable	8,932	44	63
Accounts payable	17,180	-5,380	-1,722
Accrued expenses	-1,793	7,211	1,982
Net cash provided by operating activities	223,157	73,345	72,803
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of assets	2	115,339	63,196
Acquisition of equity investment	-625	0	-1,146
Additions to other property and equipment	-5,475	-3,265	-1,287
Additions to oil and natural gas properties	-810,827	-231,665	-173,983
Net cash used in investing activities	-816,925	-119,591	-113,220
CASH FLOWS FROM FINANCING ACTIVITIES
Contributions	0	300	0
Proceeds from issuance of common stock, net	280,703	0	0
Distributions	-1,663	-30,000	0
Payment of deferred loan costs	-14,059	0	0
Borrowings under long-term debt	440,512	101,569	90,000
Restricted short-term investment	0	1,031	-25,000
Payments on long-term debt	-568,667	-85,000	0
Issuance of senior unsecured notes	500,000	0	0
NPI payable	0	20,348	16,583
Net cash provided by financing activities	636,826	8,248	81,583
NET CHANGE IN CASH	43,058	-37,998	41,166
CASH AT BEGINNING OF PERIOD	13,234	51,232	10,066
CASH AT END OF PERIOD	56,292	13,234	51,232
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest	3,897	3,373	3,420
Cash paid for taxes	3,800	0	0
NON-CASH ACTIVITIES
Asset retirement obligation acquired	2,147	644	0
Common stock issued for oil and gas properties	677,402	0	0
Deferred tax liabilities recorded for oil and gas property acquisitions	199,389	0	0
Elimination of NPI payable	36,931	0	0
Change in accrued capital expenditures	$41,573	$4,921	$154

Nature_of_Operations_and_Basis

Nature of Operations and Basis of Presentation	12 Months Ended
	Dec. 31, 2014
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 ultimately 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, development and operation of oil and natural gas properties. Until our 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. 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.
	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.
	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.
	Subsequent Events
	The Company has evaluated subsequent events of its consolidated financial statements. There were no material subsequent events requiring additional disclosure in these financial statements.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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 and the fair value of incentive unit compensation 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,
			2014				2013
			(In thousands)
	Sale of oil and natural gas and related products		$	24,059			$	15,618
	Joint interest owners		10,400				10,728
	Derivatives - settled, but uncollected		5,977				—
	Total accounts receivable		$	40,436			$	26,346
	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 Company has not provided an allowance for doubtful accounts based on management’s expectations that all material receivables at year-end will be collected. The need for an allowance is determined based upon reviews of individual accounts, historical losses, existing economic conditions and other pertinent factors. No bad debt expense was recorded for the years ended December 31, 2014, 2013 or 2012.
	Transactions with Related Parties
	The Company's accounts receivable from related parties as of December 31, 2013 was $3.7 million and was owed by Wallace LP. 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. As of December 31, 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.
	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 capitalizes interest on expenditures while activities are in progress to bring the assets to their intended use for significant exploration and development projects that last more than six months. The Company did not capitalize any interest in the years ended December 31, 2014, 2013 or 2012, as no projects lasted more 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. Unproved properties are assessed at least annually for possible impairment.
	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. Capitalized exploration well costs and development costs, including AROs, are depleted on a field basis, based on proved developed reserves. Depletion expense for oil and natural gas producing property was $87.2 million, $46.9 million, and $48.0 million, for the years ended December 31, 2014, 2013 and 2012, 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, 2014 and December 31, 2013 consisted of the following:
			As of December 31,
			2014				2013
			(In thousands)
	Proved oil and natural gas properties		$	1,585,125			$	562,019
	Unproved oil and natural gas properties		655,678				33,467
	Total oil and natural gas properties		2,240,803				595,486
	Less: accumulated depletion and impairment		(171,046		)		(88,514		)
	Total oil and natural gas properties, net		$	2,069,757			$	506,972
	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, 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. Unproved properties are assessed at least annually to determine whether they have been impaired. An impairment allowance is provided on an unproved property when the Company determines that the property will not be developed. 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, 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 years ended December 31, 2013 or 2012.
	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, 2014, 2013 and 2012 was $0.9 million, $0.3 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
	In October 2014, the Company invested $0.6 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 minority interest and will account for this investment using the equity method of accounting.
	Restricted Cash
	Restricted cash as of December 31, 2014 and 2013 consisted of certificates of deposit that mature in periods through 2017.
	Deferred Loan Costs
	Deferred loan costs 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 $15.1 million and $2.2 million as of December 31, 2014 and 2013, respectively, net of accumulated amortization, are included in other long-term assets in the accompanying consolidated balance sheets. Amortization of deferred loan costs of $1.2 million, $1.7 million and $0.5 million was recorded for the years ended December 31, 2014, 2013 and 2012, 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,
		2014				2013
		(In thousands)
	Asset retirement obligation at beginning of period	$	2,584			$	2,716
	Liabilities incurred or assumed	2,147				644
	Liabilities settled	—				(897		)
	Accretion expense	142				121
	Asset retirement obligation at end of period	$	4,873			$	2,584
	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. from January 23, 2014 through December 31, 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 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 following is an analysis of the Company’s consolidated income tax expense:
			Year Ended December 31,
			2014				2013		2012
			(In thousands)
Current			$	4,338			$	68	$	(339	)
Deferred			153,468				2,194		—
Income Tax Expense (Benefit)			$	157,806			$	2,262	$	(339	)
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, 2014, 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 and 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 January 2015, the Financial Accounting Standards Board (“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 does not expect the impact of its pending adoption of this guidance will have a material effect 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 evaluating the impact that this new guidance will have on its consolidated financial statements.

Acquisitions_and_Sales_of_Oil_

Acquisitions and Sales of Oil and Natural Gas Property Interests	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions and Sales of Oil and Natural Gas Property Interests	ACQUISITIONS AND SALES OF OIL AND NATURAL GAS PROPERTY INTERESTS
	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 below), 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
	Recent 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.
	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.

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2014
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. 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.
	The following table summarizes all open positions as of December 31, 2014:
		Contracts Maturing During 2015
	Crude Oil Swaps:
	Notional volume (Bbl)	120,000
	Weighted average price ($/Bbl)(1)	$	92.6
	Crude Oil Collars:
	Notional volume (Bbl)	2,337,000
	Weighted average ceiling price ($/Bbl)(1)	$	94.64
	Weighted average floor price ($/Bbl)(1)	$	86.42
	_______________________________________
	(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
		31-Dec-14			December 31, 2013			31-Dec-14			December 31, 2013
		(In thousands)
	Derivative Instruments:
	Current amounts
	Commodity contracts	$	76,990		$	671		$	(1,320	)	$	(1,562	)
	Noncurrent amounts
	Commodity contracts	—			1,078			—			(43		)
	Total derivative instruments	$	76,990		$	1,749		$	(1,320	)	$	(1,605	)
	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:
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Gain (loss) on derivative instruments:
	Commodity derivative instruments	$	81,470		$	(2,583	)	$	(408	)
	Interest rate derivative instruments	—			(24		)	(388		)
	Total	$	81,470		$	(2,607	)	$	(796	)
	Offsetting of Derivative Assets and Liabilities
	The following table presents the Company’s gross and net derivative assets and liabilities.
		Gross Amount			Netting			Net
		Presented on			Adjustments(a)			Amount
		Balance Sheet
		(In thousands)
	31-Dec-14
	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		$	—
	December 31, 2013
	Derivative instrument assets with right of offset or master netting agreements	$	1,749		$	(1,332	)	$	417
	Derivative instrument liabilities with right of offset or master netting agreements	$	(1,605	)	$	1,332		$	(273	)
	_______________________________________
	(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, 2014 and December 31, 2013.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
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, 2014:
	Commodity derivative instruments	$	—	$	75,670	$	—	$	75,670
	Total	$	—	$	75,670	$	—	$	75,670
		Level 1		Level 2		Level 3		Total fair value
		(In thousands)
	As of December 31, 2013:
	Commodity derivative instruments	$	—	$	144	$	—	$	144
	Total	$	—	$	144	$	—	$	144
	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, 2014, 2013, and 2012.
	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.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt
	Long-term debt consists of the following:
		As of December 31,
		2014		2013
		(In millions)
	Term loan	$	—	$	70
	Revolving credit facility	—		58.2
	6.625% Senior notes	500		—
	Total long-term debt	$	500	$	128.2
	Credit Agreement
	On September 10, 2013, in conjunction with the Spanish Trail Acquisition, the Company amended and restated its credit agreement, dated December 15, 2010, with Comerica Bank, as administrative agent providing for a revolving credit facility of up to $500 million, and expanded its syndicated bank group to 11 lenders.  In addition, the Company entered into a new term loan in the amount of $70 million to partially finance the Spanish Trail Acquisition. On January 23, 2014, the Company repaid the term loan in full, and has no contractual obligations with respect to the term loan.
	On June 9, 2014, the borrowing base under the revolving credit facility was increased from $300 million to $375 million as a result of the semiannual borrowing base redetermination under the revolving credit facility.
	In conjunction with the closing of our acquisitions in Glasscock County, on August 29, 2014, the Company amended the revolving credit facility to increase the borrowing base to $500 million, to increase the lenders’ maximum facility commitments to $1.0 billion, to extend the maturity date to August 29, 2019 and to allow the Company to issue the senior unsecured notes described below. In connection with the Company's issuance of its senior unsecured notes, on September 24, 2014, the Company amended the revolving credit facility to permit the Company to make payment to the Company to enable it to pay principal, premium (if any) and interest on the unsecured notes provided no default has occurred and to allow RSP LLC to guaranty the unsecured notes.
	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, 2014.
	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 reference 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, 2014, the prime borrowing rate of interest under the Company’s revolving credit facility was 3.25%. 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, 2014, 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 $500 million as of December 31, 2014, 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. 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 borrowing 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 commences 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 notes, 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. The Company was in compliance with the provisions of the indenture governing the senior unsecured notes as of December 31, 2014.

Net_Profits_Interest

Net Profits Interest	12 Months Ended
	Dec. 31, 2014
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.
	As described in Note 3, 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, 2014
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,
		2014		2013		2012
	Shell Trading (US) Company	31	%	40	%	3	%
	Enterprise Crude Oil LLC	24	%	14	%	—	%
	Diamondback E&P, LLC	14	%	11	%	2	%
	Coronado Midstream, LLC	6	%	8	%	11	%
	Plains Marketing, L.P.	—	%	13	%	76	%
	Permian Transport & Trading	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, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity Based Compensation
	Equity-based compensation expense, which is recorded in General and administrative expenses, was $20.2 million for the twelve months ended December 31, 2014. Equity-based compensation expense includes certain costs which are non-recurring; expense for restricted shares which were issued as a bonus related to our IPO ($2.8 million) along with expense related to incentive units ($14.7 million) as discussed below.
	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 these awards was $4.7 million for the year ended December 31, 2014. Included in the before mentioned amount is $2.8 million of expense related to restricted shares issued as a bonus related to our IPO. 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, 2014, the Company had unrecognized compensation expense of $6.9 million related to restricted stock awards which is expected to be recognized over a weighted average period of 1.6 years.
	The following table represents restricted stock award activity for the twelve months ended December 31, 2014:
		Shares		Weighted Average Fair Value
	Restricted shares outstanding, beginning of period	—		$	—
	Restricted shares granted	489,544		$23.69
	Restricted shares canceled	(11,777	)	$23.03
	Restricted shares outstanding, end of period	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. We 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.
	Equity-based compensation for these awards was $0.8 million for the twelve months ended December 31, 2014. The compensation expense for the market condition is based on a grant date valuation of $28.14 per share using a Monte-Carlo simulation. The unrecognized compensation expense related to these shares is approximately $3.0 million as of December 31, 2014 and is expected to be recognized over the next 2.17 years. The payout level is calculated based on actual performance achieved during the performance period compared to a defined peer group.
	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, consisting of Tier I, Tier I A, Tier II, Tier III and Tier IV units. The incentive units were intended to be compensation for services rendered to the Company. All incentive units, whether vested or not, are forfeited if payouts are not achieved by a specified date. Tier I and Tier I A incentive units vest ratably over three years but are subject to forfeiture if payout is not achieved. Tier I and Tier I A payout is realized upon the return of members’ invested capital and a specified rate of return. Tiers II, III and IV incentive units vest only upon the achievement of certain distribution thresholds for each such Tier and each Tier of the incentive units is subject to forfeiture if the applicable required payouts are not achieved. In addition, vested and unvested units will be forfeited if an incentive unit holder’s employment is terminated for cause or if the unitholder voluntarily terminates his or her employment.
	In connection with the IPO, the incentive units of RSP LLC became incentive units in RSP Permian Holdco, L.L.C. and therefore based upon distributions to members of RSP Permian Holdco, L.L.C. rather than members of RSP LLC. The terms and conditions of the profits interest awards remained substantially similar to the terms applicable to the incentive unit awards prior to the IPO, including the retention of existing vesting schedules.
	The achievement of payout conditions is a performance condition that requires the Company to assess, at each reporting period, the probability that an event of payout will occur. Compensation cost is required to be recognized at such time that the payout terms are probable of being met. At the grant dates and subsequent reporting periods prior to the IPO, the Company did not deem as probable that such payouts would be achieved for any Tier of incentive units. At such time that the occurrence of the performance conditions associated with these incentive units are deemed probable, the Company will record a non-cash compensation expense based upon the grant date fair value of the incentive units that are probable of reaching payout as a result of reaching established distribution thresholds.
	After successful completion of the IPO, the performance conditions associated with the Tier I, Tier I A and Tier II incentive units were deemed probable of reaching payout, while the performance conditions of the Tier III incentive units were deemed probable of reaching payout in the fourth quarter of 2014. In 2014, the Company recognized non-cash compensation expense of $14.7 million related to these incentive units. In December 2014, the incentive unit plan was terminated and all awards remaining under Tier I, Tier I A, Tier II, and Tier III incentive units were satisfied. These incentive units determined the stock allocation between management and NGP and had no dilutive impact, or cash impact, to RSP Permian, Inc.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013, the Company had no environmental matters requiring specific disclosure or requiring the recognition of a liability.
	Leases
	In October 2014, RSP LLC entered into a 60-month lease agreement for office space in Midland, Texas. In February 2014, RSP LLC entered into a 64-month lease agreement through May 2019 for office space in Dallas, Texas.  In July 2014, RSP LLC entered into a 58-month lease agreement through May 2019 for additional office space in Dallas, Texas. Rent expense for the year ended December 31, 2014, 2013, and 2012 was $0.5 million, $0.2 million, and $0.2 million respectively.
	Contractual Obligations
	A summary of the Company's contractual obligations as of December 31, 2014 is provided in the following table (in thousands).
		Payments Due by Period For the Year Ended December 31,
		2015		2016		2017		2018		2019		Thereafter		Total
		(In thousands)
	Revolving credit facility (1)	$	—	$	—	$	—	$	—	$	—	$	—	$	—
	6.625% Senior Notes (2)	—		—		—		—		—		500,000		500,000
	Interest cost (3)	33,125		33,125		33,125		33,125		33,125		91,094		256,719
	Drilling rig commitments (4)	34,296		19,440		1,645		—		—		—		55,381
	Office and equipment leases	1,114		1,078		890		778		503		—		4,363
	Asset retirement obligations (5)	—		—		—		—		—		4,873		4,873
	Total	$	68,535	$	53,643	$	35,660	$	33,903	$	33,628	$	595,967	$	821,336
	(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.
	(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, 2014
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 net income for the year ended December 31, 2014, unvested restricted share awards were recognized in earnings per share calculations as they are dilutive.  A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
			Year Ended December 31, 2014
	Numerator:
	Net income available to stockholders		$	2,498
	Basic net income allocable to participating securities (1)		15
	Income available to stockholders		$	2,483
	Denominator:
	Weighted average number of common shares outstanding - basic		71,898
	Effect of dilutive securities:
	Restricted stock		—
	Weighted average number of common shares outstanding - diluted		71,898
	Net income per share:
	Basic		$	0.03
	Diluted		$	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, 2014
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, 2014 is as follows:
		For the year ended December 31,
		2014
		(In thousands)
	Current Income Tax Provision:
	Federal	$	4,111
	State	227
	Total income tax provision	4,338
	Deferred Income Tax Provision:
	Federal	$	157,806
	State	(227		)
	Federal alternative minimum tax	(4,111		)
	Total deferred income tax provision	153,468
	Total Provision for Income Taxes	$	157,806
	Included in the deferred federal income tax provision 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,
		2014
		(In thousands)
	Income tax expense at the federal statutory rate (35%)	$	56,106
	Income tax expense relating to change in tax status	95,162
	State income tax expense, net of federal tax benefit	1,081
	Non-deductible expenses	5,457
	Provision for income taxes	$	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 as of December 31, 2014 are as follows:
		For the year ended December 31, 2014
		(In thousands)
	Current:
	Deferred tax assets
	Derivative instruments	$	—
	Other	1,519
	Total current deferred tax assets	1,519
	Deferred tax liabilities
	Derivative instruments	(26,949		)
	Other	(359		)
	Total current deferred tax liabilities	(27,308		)
	Net current deferred tax assets	(25,789		)
	Noncurrent:
	Deferred tax assets
	Net operating loss carryforwards (subject to 20 year expiration)	13,604
	Stock based compensation	1,943
	Alternative minimum tax credit carryforward	4,111
	Other	8
	Total noncurrent deferred tax assets	19,666
	Deferred tax liabilities
	Oil and natural gas properties and equipment	(348,928		)
	Other	—
	Total noncurrent deferred tax liabilities	(348,928		)
	Net noncurrent deferred tax liabilities	(329,262		)
	Net deferred tax liabilities	$	(355,051	)
	Federal net operating loss carryforwards totaled $38.9 million at December 31, 2014.

Supplemental_Disclosure_of_Oil

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited)	12 Months Ended
	Dec. 31, 2014
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:
		2014				2013				2012
		(In thousands)
	Property acquisition costs:
	Proved (1)	$	581,307			$	86,958			$	—
	Unproved (1)	622,210				7,875				—
	Exploration costs	16,762				—				—
	Development costs	462,063				136,832				173,983
	Total costs incurred	$	1,682,342			$	231,665			$	173,983
	(1) Includes non-cash additions in connection with the Company's IPO 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:
		2014				2013
		(In thousands)
	Capitalized costs:
	Proved	$	1,585,125			$	562,019
	Unproved	655,678				33,467
		$	2,240,803			$	595,486
	Less accumulated depreciation, depletion, amortization and impairment	(171,046		)		(88,514		)
	Net capitalized costs	$	2,069,757			$	506,972
	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:
		2014				2013				2012
		(In thousands)
	Revenues:
	Oil and natural gas sales	$	281,925			$	123,042			$	104,427
	Costs:
	Lease operating expenses	34,704				14,113				12,693
	Production and ad valorem taxes	19,758				8,326				7,575
	Depreciation, depletion, and amortization	87,844				47,158				48,803
	Asset retirement obligation accretion	142				121				115
	Impairments	4,344				—				—
	Exploration	3,854				551				161
	Income tax expense (benefit)	157,806				2,262				(339		)
	Results of operations	$	(26,527	)		$	50,511			$	35,419
	Net Proved Oil and Natural Gas Reserves
	The Company’s proved oil and natural gas reserves as of December 31, 2014 were prepared by independent third party reserve engineers. The Predecessor’s proved oil and natural gas reserves as of December 31, 2013 were prepared by independent third party reserve engineers, while the proved oil and gas reserves as of December 31, 2012 were prepared internally by management. In accordance with SEC regulations, reserves at December 31, 2014, 2013, and 2012 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, 2014, 2013, and 2012 is as follows:
		Natural			Oil			NGLs			MBoe
		Gas			(MBbls)			(MBbls)
		(MMcf)
	Proved developed and undeveloped reserves:
	As of January 1, 2012	92,416			33,371			—			48,774
	Revisions of previous estimates	(57,872	)		(15,353	)		391			(24,608	)
	Extensions, discoveries and other additions	7,724			3,885			4,829			10,001
	Production	(1,576	)		(1,040	)		(264	)		(1,567	)
	As of December 31, 2012	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
	Proved developed reserves:
	31-Dec-12	17,847			7,730			1,723			12,427
	31-Dec-13	14,396			9,533			2,703			14,636
	31-Dec-14	35,921			27,716			8,221			41,924
Proved undeveloped reserves:
31-Dec-12	22,845			13,133			3,233			20,173
31-Dec-13	21,407			14,199			4,210			21,977
31-Dec-14	56,501			41,557			13,518			64,492
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, 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.
For the year ended December 31, 2012, the Predecessor’s negative revision of 24,608 MBoe of previous estimated quantities is primarily due to a change in development strategy to replace 20-acre proved vertical well locations with non-proved horizontal well locations. In addition, in 2012, the Predecessor switched to the recognition of three stream instead of two stream sales volumes, which resulted in a negative revision of natural gas reserves and a positive revision of NGL reserves. Extensions, discoveries and other additions of 10,001 MBoe during the year ended December 31, 2012, resulted primarily from the drilling of new wells during the year and from new proved undeveloped locations added during the year.
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, 2014, 2013, and 2012 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:
	2014				2013				2012
	(In thousands)
Future cash inflows	$	7,015,504			$	2,547,566			$	2,210,325
Future production costs	(2,025,302		)		(727,939		)		(655,720		)
Future development costs	(1,182,981		)		(378,695		)		(362,876		)
Future income tax expenses(1)	(1,154,808		)		—				—
Future net cash flows	2,652,413				1,440,932				1,191,729
10% discount for estimated timing of cash flows	(1,776,282		)		(890,217		)		(737,556		)
Standardized measure of discounted future net cash flows	$	876,131			$	550,715			$	454,173
(1)         Future net cash flows for 2013 and 2012 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 and 2012 would have been $247.4 million and $155.7 million, respectively. The unaudited standardized measure at December 31, 2013 and 2012 would have been $303.3 million and $298.5 million, respectively.
In the foregoing determination of future cash inflows, sales prices used for gas and oil for December 31, 2014, 2013 and 2012 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:
	2014				2013				2012
	(In thousands)
Standardized measure of discounted future net cash flows, beginning of year	$	550,715			$	454,173			$	854,424
Changes in the year resulting from:
Sales, less production costs	(223,608		)		(100,052		)		(83,998		)
Revisions of previous quantity estimates	20,892				(53,557		)		(439,043		)
Extensions, discoveries and other additions	646,855				157,086				84,149
Net change in prices and production costs	(74,081		)		45,388				(133,485		)
Changes in estimated future development costs	(7,858		)		2,318				38,096
Previously estimated development costs incurred during the period	44,925				46,938				108,367
Divestiture of reserves	—				(151,440		)		—
Purchases of minerals in place	366,106				94,751				—
Accretion of discount	55,072				45,417				85,442
Net change in income taxes	(441,506		)		—				—
Timing differences and other	(61,380		)		9,693				(59,779		)
Standardized measure of discounted future net cash flows, end of year	$	876,132			$	550,715			$	454,173
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, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	QUARTERLY FINANCIAL DATA (Unaudited)
	The Company’s unaudited quarterly financial data for 2014 and 2013 is summarized below.
		2014
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	Revenues	$	57,758		$	74,062		$	70,645		$	79,458
	Income from operations	12,657			30,576			33,160			16,512
	Income tax (expense) benefit	(135,213		)	(4,948		)	(20,704		)	3,060
	Net income	$	(127,530	)	$	8,226		$	32,297		$	89,503
	Earnings 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.
		2013
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	Revenues	$	24,655		$	25,147		$	36,860		$	36,380
	Income from operations	14,948			7,114			27,039			22,520
	Income tax (expense) benefit	—			(68		)	—			(2,194		)
	Net income	$	12,866		$	7,859		$	24,037		$	17,976
	Pro forma information:
	Net income	$	12,866		$	7,859		$	24,037		$	17,976
	Pro forma provision for income taxes (1)	4,632			2,829			8,653			6,472
	Pro forma net income	8,234			5,030			15,384			11,504
	Earnings per share:
	Basic and diluted	$	0.26		$	0.16		$	0.48		$	0.36
	(1) Our predecessor, RSP Permian, L.L.C., was formed as a holding company in October 2010, and did not conduct any material business operations until December 2010. RSP Permian, Inc. is a C-Corp. under the Code, and is subject to income taxes. The Company computed a pro forma income tax provision for 2013 as if RSP Permian, L.L.C. and Rising Star were subject to income taxes since January 1, 2013. For 2013 comparative purposes, we have included pro forma financial data to give effect to income taxes assuming the earnings of the RSP Permian, L.L.C. and Rising Star had been subject to federal income tax as a C-Corp. since inception. The unaudited pro forma data is presented for informational purposes only and does not purport to project our results of operations for any future period or our financial position as of any future date. 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.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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.
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 and the fair value of incentive unit compensation 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 Company has not provided an allowance for doubtful accounts based on management’s expectations that all material receivables at year-end will be collected. The need for an allowance is determined based upon reviews of individual accounts, historical losses, existing economic conditions and other pertinent factors.
Oil and Natural Gas Properties	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 capitalizes interest on expenditures while activities are in progress to bring the assets to their intended use for significant exploration and development projects that last more than six months. The Company did not capitalize any interest in the years ended December 31, 2014, 2013 or 2012, as no projects lasted more 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. Unproved properties are assessed at least annually for possible impairment.
	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. Capitalized exploration well costs and development costs, including AROs, are depleted on a field basis, based on proved developed reserves. Depletion expense for oil and natural gas producing property was $87.2 million, $46.9 million, and $48.0 million, for the years ended December 31, 2014, 2013 and 2012, respectively. Depletion expense is included in depreciation, depletion and amortization in the accompanying consolidated statements of operations.
	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, 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. Unproved properties are assessed at least annually to determine whether they have been impaired. An impairment allowance is provided on an unproved property when the Company determines that the property will not be developed. 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, 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 years ended December 31, 2013 or 2012.
	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 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. from January 23, 2014 through December 31, 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 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.
	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, 2014, 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 and 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 January 2015, the Financial Accounting Standards Board (“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 does not expect the impact of its pending adoption of this guidance will have a material effect 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 evaluating the impact that this new guidance will have on its consolidated financial statements.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Schedule of Oil and Natural Gas Properties	The Company’s oil and natural gas properties as of December 31, 2014 and December 31, 2013 consisted of the following:
			As of December 31,
			2014				2013
			(In thousands)
	Proved oil and natural gas properties		$	1,585,125			$	562,019
	Unproved oil and natural gas properties		655,678				33,467
	Total oil and natural gas properties		2,240,803				595,486
	Less: accumulated depletion and impairment		(171,046		)		(88,514		)
	Total oil and natural gas properties, net		$	2,069,757			$	506,972
	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:
			2014				2013
			(In thousands)
	Capitalized costs:
	Proved		$	1,585,125			$	562,019
	Unproved		655,678				33,467
			$	2,240,803			$	595,486
	Less accumulated depreciation, depletion, amortization and impairment		(171,046		)		(88,514		)
	Net capitalized costs		$	2,069,757			$	506,972
Schedule of Changes in Asset Retirement Obligation	The ARO consisted of the following for the period indicated:
		Year Ended December 31,
		2014				2013
		(In thousands)
	Asset retirement obligation at beginning of period	$	2,584			$	2,716
	Liabilities incurred or assumed	2,147				644
	Liabilities settled	—				(897		)
	Accretion expense	142				121
	Asset retirement obligation at end of period	$	4,873			$	2,584
Schedule of Income Tax Expense	The following is an analysis of the Company’s consolidated income tax expense:
				Year Ended December 31,
				2014				2013		2012
				(In thousands)
	Current			$	4,338			$	68	$	(339	)
	Deferred			153,468				2,194		—
	Income Tax Expense (Benefit)			$	157,806			$	2,262	$	(339	)
	The components of the provision for income taxes for the year ended December 31, 2014 is as follows:
			For the year ended December 31,
			2014
			(In thousands)
	Current Income Tax Provision:
	Federal		$	4,111
	State		227
	Total income tax provision		4,338
	Deferred Income Tax Provision:
	Federal		$	157,806
	State		(227		)
	Federal alternative minimum tax		(4,111		)
	Total deferred income tax provision		153,468
	Total Provision for Income Taxes		$	157,806

Acquisitions_and_Sales_of_Oil_1

Acquisitions and Sales of Oil and Natural Gas Property Interests (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014
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, 2014:
		Contracts Maturing During 2015
	Crude Oil Swaps:
	Notional volume (Bbl)	120,000
	Weighted average price ($/Bbl)(1)	$	92.6
	Crude Oil Collars:
	Notional volume (Bbl)	2,337,000
	Weighted average ceiling price ($/Bbl)(1)	$	94.64
	Weighted average floor price ($/Bbl)(1)	$	86.42
	_______________________________________
	(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
		31-Dec-14			December 31, 2013			31-Dec-14			December 31, 2013
		(In thousands)
	Derivative Instruments:
	Current amounts
	Commodity contracts	$	76,990		$	671		$	(1,320	)	$	(1,562	)
	Noncurrent amounts
	Commodity contracts	—			1,078			—			(43		)
	Total derivative instruments	$	76,990		$	1,749		$	(1,320	)	$	(1,605	)
Derivative Instruments, Gains (Losses)	The following represents the Company’s reported gains and losses on derivative instruments for the periods presented:
		Year Ended December 31,
		2014			2013			2012
		(In thousands)
	Gain (loss) on derivative instruments:
	Commodity derivative instruments	$	81,470		$	(2,583	)	$	(408	)
	Interest rate derivative instruments	—			(24		)	(388		)
	Total	$	81,470		$	(2,607	)	$	(796	)
Gross and Net Derivative Assets	The following table presents the Company’s gross and net derivative assets and liabilities.
		Gross Amount			Netting			Net
		Presented on			Adjustments(a)			Amount
		Balance Sheet
		(In thousands)
	31-Dec-14
	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		$	—
	December 31, 2013
	Derivative instrument assets with right of offset or master netting agreements	$	1,749		$	(1,332	)	$	417
	Derivative instrument liabilities with right of offset or master netting agreements	$	(1,605	)	$	1,332		$	(273	)
	_______________________________________
	(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			Netting			Net
		Presented on			Adjustments(a)			Amount
		Balance Sheet
		(In thousands)
	31-Dec-14
	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		$	—
	December 31, 2013
	Derivative instrument assets with right of offset or master netting agreements	$	1,749		$	(1,332	)	$	417
	Derivative instrument liabilities with right of offset or master netting agreements	$	(1,605	)	$	1,332		$	(273	)
	_______________________________________
	(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, 2014
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, 2014:
	Commodity derivative instruments	$	—	$	75,670	$	—	$	75,670
	Total	$	—	$	75,670	$	—	$	75,670
		Level 1		Level 2		Level 3		Total fair value
		(In thousands)
	As of December 31, 2013:
	Commodity derivative instruments	$	—	$	144	$	—	$	144
	Total	$	—	$	144	$	—	$	144

Major_Customers_and_Suppliers_

Major Customers and Suppliers (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014		2013		2012
	Shell Trading (US) Company	31	%	40	%	3	%
	Enterprise Crude Oil LLC	24	%	14	%	—	%
	Diamondback E&P, LLC	14	%	11	%	2	%
	Coronado Midstream, LLC	6	%	8	%	11	%
	Plains Marketing, L.P.	—	%	13	%	76	%
	Permian Transport & Trading	21	%	—	%	—	%

Equity_Based_Compensation_Tabl

Equity Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014:
		Shares		Weighted Average Fair Value
	Restricted shares outstanding, beginning of period	—		$	—
	Restricted shares granted	489,544		$23.69
	Restricted shares canceled	(11,777	)	$23.03
	Restricted shares outstanding, end of period	477,767		$23.71

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Contractual Obligations, Annual Maturity Schedule	A summary of the Company's contractual obligations as of December 31, 2014 is provided in the following table (in thousands).
		Payments Due by Period For the Year Ended December 31,
		2015		2016		2017		2018		2019		Thereafter		Total
		(In thousands)
	Revolving credit facility (1)	$	—	$	—	$	—	$	—	$	—	$	—	$	—
	6.625% Senior Notes (2)	—		—		—		—		—		500,000		500,000
	Interest cost (3)	33,125		33,125		33,125		33,125		33,125		91,094		256,719
	Drilling rig commitments (4)	34,296		19,440		1,645		—		—		—		55,381
	Office and equipment leases	1,114		1,078		890		778		503		—		4,363
	Asset retirement obligations (5)	—		—		—		—		—		4,873		4,873
	Total	$	68,535	$	53,643	$	35,660	$	33,903	$	33,628	$	595,967	$	821,336
	(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.
	(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, 2014
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:
			Year Ended December 31, 2014
	Numerator:
	Net income available to stockholders		$	2,498
	Basic net income allocable to participating securities (1)		15
	Income available to stockholders		$	2,483
	Denominator:
	Weighted average number of common shares outstanding - basic		71,898
	Effect of dilutive securities:
	Restricted stock		—
	Weighted average number of common shares outstanding - diluted		71,898
	Net income per share:
	Basic		$	0.03
	Diluted		$	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, 2014
Income Tax Disclosure [Abstract]
Schedule of Components, Provision for Income Taxes	The following is an analysis of the Company’s consolidated income tax expense:
			Year Ended December 31,
			2014		2013		2012
			(In thousands)
	Current		$	4,338	$	68	$	(339	)
	Deferred		153,468		2,194		—
	Income Tax Expense (Benefit)		$	157,806	$	2,262	$	(339	)
	The components of the provision for income taxes for the year ended December 31, 2014 is as follows:
		For the year ended December 31,
		2014
		(In thousands)
	Current Income Tax Provision:
	Federal	$	4,111
	State	227
	Total income tax provision	4,338
	Deferred Income Tax Provision:
	Federal	$	157,806
	State	(227		)
	Federal alternative minimum tax	(4,111		)
	Total deferred income tax provision	153,468
	Total Provision for Income Taxes	$	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,
		2014
		(In thousands)
	Income tax expense at the federal statutory rate (35%)	$	56,106
	Income tax expense relating to change in tax status	95,162
	State income tax expense, net of federal tax benefit	1,081
	Non-deductible expenses	5,457
	Provision for income taxes	$	157,806
Schedule of Deferred Tax Assets and Liabilities	The components of the Company’s deferred tax assets and liabilities as of December 31, 2014 are as follows:
		For the year ended December 31, 2014
		(In thousands)
	Current:
	Deferred tax assets
	Derivative instruments	$	—
	Other	1,519
	Total current deferred tax assets	1,519
	Deferred tax liabilities
	Derivative instruments	(26,949		)
	Other	(359		)
	Total current deferred tax liabilities	(27,308		)
	Net current deferred tax assets	(25,789		)
	Noncurrent:
	Deferred tax assets
	Net operating loss carryforwards (subject to 20 year expiration)	13,604
	Stock based compensation	1,943
	Alternative minimum tax credit carryforward	4,111
	Other	8
	Total noncurrent deferred tax assets	19,666
	Deferred tax liabilities
	Oil and natural gas properties and equipment	(348,928		)
	Other	—
	Total noncurrent deferred tax liabilities	(348,928		)
	Net noncurrent deferred tax liabilities	(329,262		)
	Net deferred tax liabilities	$	(355,051	)

Supplemental_Disclosure_of_Oil1

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
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:
		2014				2013				2012
		(In thousands)
	Property acquisition costs:
	Proved (1)	$	581,307			$	86,958			$	—
	Unproved (1)	622,210				7,875				—
	Exploration costs	16,762				—				—
	Development costs	462,063				136,832				173,983
	Total costs incurred	$	1,682,342			$	231,665			$	173,983
	(1) Includes non-cash additions in connection with the Company's IPO 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, 2014 and December 31, 2013 consisted of the following:
		As of December 31,
		2014				2013
		(In thousands)
	Proved oil and natural gas properties	$	1,585,125			$	562,019
	Unproved oil and natural gas properties	655,678				33,467
	Total oil and natural gas properties	2,240,803				595,486
	Less: accumulated depletion and impairment	(171,046		)		(88,514		)
	Total oil and natural gas properties, net	$	2,069,757			$	506,972
	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:
		2014				2013
		(In thousands)
	Capitalized costs:
	Proved	$	1,585,125			$	562,019
	Unproved	655,678				33,467
		$	2,240,803			$	595,486
	Less accumulated depreciation, depletion, amortization and impairment	(171,046		)		(88,514		)
	Net capitalized costs	$	2,069,757			$	506,972
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:
		2014				2013				2012
		(In thousands)
	Revenues:
	Oil and natural gas sales	$	281,925			$	123,042			$	104,427
	Costs:
	Lease operating expenses	34,704				14,113				12,693
	Production and ad valorem taxes	19,758				8,326				7,575
	Depreciation, depletion, and amortization	87,844				47,158				48,803
	Asset retirement obligation accretion	142				121				115
	Impairments	4,344				—				—
	Exploration	3,854				551				161
	Income tax expense (benefit)	157,806				2,262				(339		)
	Results of operations	$	(26,527	)		$	50,511			$	35,419
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, 2014, 2013, and 2012 is as follows:
		Natural			Oil			NGLs			MBoe
		Gas			(MBbls)			(MBbls)
		(MMcf)
	Proved developed and undeveloped reserves:
	As of January 1, 2012	92,416			33,371			—			48,774
	Revisions of previous estimates	(57,872	)		(15,353	)		391			(24,608	)
	Extensions, discoveries and other additions	7,724			3,885			4,829			10,001
	Production	(1,576	)		(1,040	)		(264	)		(1,567	)
	As of December 31, 2012	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
	Proved developed reserves:
	31-Dec-12	17,847			7,730			1,723			12,427
	31-Dec-13	14,396			9,533			2,703			14,636
	31-Dec-14	35,921			27,716			8,221			41,924
	Proved undeveloped reserves:
	31-Dec-12	22,845			13,133			3,233			20,173
	31-Dec-13	21,407			14,199			4,210			21,977
	31-Dec-14	56,501			41,557			13,518			64,492
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:
		2014				2013				2012
		(In thousands)
	Future cash inflows	$	7,015,504			$	2,547,566			$	2,210,325
	Future production costs	(2,025,302		)		(727,939		)		(655,720		)
	Future development costs	(1,182,981		)		(378,695		)		(362,876		)
	Future income tax expenses(1)	(1,154,808		)		—				—
	Future net cash flows	2,652,413				1,440,932				1,191,729
	10% discount for estimated timing of cash flows	(1,776,282		)		(890,217		)		(737,556		)
	Standardized measure of discounted future net cash flows	$	876,131			$	550,715			$	454,173
	(1)         Future net cash flows for 2013 and 2012 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 and 2012 would have been $247.4 million and $155.7 million, respectively. The unaudited standardized measure at December 31, 2013 and 2012 would have been $303.3 million and $298.5 million, respectively.
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:
		2014				2013				2012
		(In thousands)
	Standardized measure of discounted future net cash flows, beginning of year	$	550,715			$	454,173			$	854,424
	Changes in the year resulting from:
	Sales, less production costs	(223,608		)		(100,052		)		(83,998		)
	Revisions of previous quantity estimates	20,892				(53,557		)		(439,043		)
	Extensions, discoveries and other additions	646,855				157,086				84,149
	Net change in prices and production costs	(74,081		)		45,388				(133,485		)
	Changes in estimated future development costs	(7,858		)		2,318				38,096
	Previously estimated development costs incurred during the period	44,925				46,938				108,367
	Divestiture of reserves	—				(151,440		)		—
	Purchases of minerals in place	366,106				94,751				—
	Accretion of discount	55,072				45,417				85,442
	Net change in income taxes	(441,506		)		—				—
	Timing differences and other	(61,380		)		9,693				(59,779		)
	Standardized measure of discounted future net cash flows, end of year	$	876,132			$	550,715			$	454,173

Quarterly_Financial_Data_Unaud1

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Data (Unaudited)	The Company’s unaudited quarterly financial data for 2014 and 2013 is summarized below.
		2014
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	Revenues	$	57,758		$	74,062		$	70,645		$	79,458
	Income from operations	12,657			30,576			33,160			16,512
	Income tax (expense) benefit	(135,213		)	(4,948		)	(20,704		)	3,060
	Net income	$	(127,530	)	$	8,226		$	32,297		$	89,503
	Earnings 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.
		2013
		First			Second			Third			Fourth
		Quarter			Quarter			Quarter			Quarter
	Revenues	$	24,655		$	25,147		$	36,860		$	36,380
	Income from operations	14,948			7,114			27,039			22,520
	Income tax (expense) benefit	—			(68		)	—			(2,194		)
	Net income	$	12,866		$	7,859		$	24,037		$	17,976
	Pro forma information:
	Net income	$	12,866		$	7,859		$	24,037		$	17,976
	Pro forma provision for income taxes (1)	4,632			2,829			8,653			6,472
	Pro forma net income	8,234			5,030			15,384			11,504
	Earnings per share:
	Basic and diluted	$	0.26		$	0.16		$	0.48		$	0.36
	(1) Our predecessor, RSP Permian, L.L.C., was formed as a holding company in October 2010, and did not conduct any material business operations until December 2010. RSP Permian, Inc. is a C-Corp. under the Code, and is subject to income taxes. The Company computed a pro forma income tax provision for 2013 as if RSP Permian, L.L.C. and Rising Star were subject to income taxes since January 1, 2013. For 2013 comparative purposes, we have included pro forma financial data to give effect to income taxes assuming the earnings of the RSP Permian, L.L.C. and Rising Star had been subject to federal income tax as a C-Corp. since inception. The unaudited pro forma data is presented for informational purposes only and does not purport to project our results of operations for any future period or our financial position as of any future date. 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.

Nature_of_Operations_and_Basis1

Nature of Operations and Basis of Presentation (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Aug. 12, 2014	Jan. 17, 2014	Jan. 16, 2014
Subsidiary, Sale of Stock [Line Items]
Proceeds from issuance of common stock	$280,703,000	$0	$0
IPO and Secondary Offering [Member]
Subsidiary, Sale of Stock [Line Items]
Total number of shares sold in the IPO				11,500,000	23,000,000
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				4,800,000
Proceeds from issuance of common stock				118,000,000
IPO [Member]
Subsidiary, Sale of Stock [Line Items]
Shares of common stock issued in public offerings net of offering costs, Shares					9,200,000
Proceeds from issuance of common stock					180,000,000
Proceeds from common stock issuance, net					163,000,000
IPO [Member] | ACTOIL, LLC [Member]
Subsidiary, Sale of Stock [Line Items]
Net profits interest (percent)					25.00%
IPO [Member] | Revolving credit facility [Member]
Subsidiary, Sale of Stock [Line Items]
Repayment of revolving credit facility					56,000,000
IPO [Member] | Term loan [Member]
Subsidiary, Sale of Stock [Line Items]
Repayment of term loan					$70,000,000
Secondary Offering [Member]
Subsidiary, Sale of Stock [Line Items]
Number of shares sold in IPO by existing stockholders					13,800,000
RSP Permian, Inc. [Member] | Natural Gas Partners and affiliates [Member]
Subsidiary, Sale of Stock [Line Items]
Ownership percentage in Company (percent)						90.00%
Rising Star GP [Member] | Natural Gas Partners and affiliates [Member]
Subsidiary, Sale of Stock [Line Items]
Ownership percentage in Company (percent)	90.00%
Rising Star LP [Member] | Natural Gas Partners and affiliates [Member]
Subsidiary, Sale of Stock [Line Items]
Ownership percentage in Company (percent)	80.00%

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - (Accounts Receivable, Related Parties) (Details) (USD $)	12 Months Ended			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Aug. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Sale of oil and natural gas and related products	$24,059,000	$15,618,000
Joint interest owners	10,400,000	10,728,000
Derivatives - settled, but uncollected	5,977,000	0
Total accounts receivable	40,436,000	26,346,000
Accounts receivable, related party	0	3,672,000
Purchase price to acquire oil and gas properties	810,827,000	231,665,000	173,983,000
Glasscock County [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Purchase price to acquire oil and gas properties				257,000,000
Wallace LP [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, related party		3,700,000
Pecos [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Acquisition of working interests in acreage and wells				$4,500,000

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - (Oil and Natural Gas) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Boe	Boe
Accounting Policies [Abstract]
Minimum project term to capitalize interest	6 months	6 months
Depletion expense	$87,200,000	$46,900,000	$48,000,000
Costs capitalized in connection with exploratory wells in progress	0	0
Impairment of proved properties	4,300,000	0	0
Conversion of natural gas volumes to barrel of oil equivalent	6	6
Oil and Natural Gas Properties [Abstract]
Proved oil and natural gas properties	1,585,125,000	562,019,000
Unproved oil and natural gas properties	655,678,000	33,467,000
Total oil and natural gas properties	2,240,803,000	595,486,000
Less: accumulated depletion and impairment	-171,046,000	-88,514,000
Total oil and natural gas properties, net	$2,069,757,000	$506,972,000

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - (Other Property and Equipment) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Depreciation expense	$0.90	$0.30	$0.30
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

Summary_of_Significant_Account6

Summary of Significant Accounting Policies - (Investment in Unconsolidated Subsidiary) (Details) (USD $)	Oct. 31, 2014
In Millions, unless otherwise specified
Accounting Policies [Abstract]
Investment in unconsolidated subsidiary	$0.60
Commitment to invest in unconsolidated subsidiary	$5

Summary_of_Significant_Account7

Summary of Significant Accounting Policies - (Deferred Loan Costs) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Deferred loan costs	$15,100,000	$2,200,000
Amortization of deferred loan costs	$1,202,000	$1,746,000	$456,000

Summary_of_Significant_Account8

Summary of Significant Accounting Policies - (Asset Retirement Obligation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at beginning of period	$2,584	$2,716
Liabilities incurred or assumed	2,147	644
Liabilities settled	0	-897
Accretion expense	142	121	115
Asset retirement obligation at end of period	$4,873	$2,584	$2,716

Summary_of_Significant_Account9

Summary of Significant Accounting Policies - (Income Taxes) (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 23, 2014
									segment
Accounting Policies [Abstract]
Number of operating segments									1
Provision for deferred income taxes	$355,051,000								$355,051,000			$132,000,000
Deferred income tax adjustments				95,000,000
Income Tax Expense (Benefit) [Abstract]
Current									4,338,000	68,000	-339,000
Deferred									153,468,000	2,194,000	0
Total Provision for Income Taxes	($3,060,000)	$20,704,000	$4,948,000	$135,213,000	$2,194,000	$0	$68,000	$0	$157,806,000	$2,262,000	($339,000)

Acquisitions_and_Sales_of_Oil_2

Acquisitions and Sales of Oil and Natural Gas Property Interests - (Pro Forma Results) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition, Pro Forma Information [Line Items]
Revenues	$79,458	$70,645	$74,062	$57,758	$36,380	$36,860	$25,147	$24,655	$281,925	$123,042	$104,427
Net income	89,503	32,297	8,226	-127,530	17,976	24,037	7,859	12,866	2,498	62,738	35,908
Pro Forma [Member]
Business Acquisition, Pro Forma Information [Line Items]
Revenues									286,910	197,309
Net income									$2,743	$73,228

Acquisitions_and_Sales_of_Oil_3

Acquisitions and Sales of Oil and Natural Gas Property Interests - (Collins and Wallace) (Details) (USD $)	12 Months Ended			0 Months Ended	3 Months Ended	1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 23, 2014	Mar. 31, 2014	Aug. 31, 2014
					transaction
Business Acquisition [Line Items]
Purchase price to acquire oil and gas properties	$810,827,000	$231,665,000	$173,983,000
Costs to acquire proved oil and natural gas properties	581,307,000	86,958,000	0
Consideration Transferred [Abstract]
Common stock issued for oil and gas properties	677,402,000	0	0
Collins and Wallace Contributions [Member]
Consideration Transferred [Abstract]
Number of common shares issued in acquisition				22,023,654
Common stock issued for oil and gas properties				429,461,000
Cash paid in the Collins and Wallace Contributions				2,219,000
Total consideration for the assets contributed in the Collins and Wallace Contributions				431,680,000
Fair Value of Assets Acquired and Liabilities Assumed [Abstract]
Fair value of oil and natural gas properties				653,431,000
Asset retirement obligation				-1,063,000
Deferred tax liability				-215,609,000
Total net assets acquired				436,759,000
Tax percentage used to estimate book to tax differences for oil and gas properties acquired				36.00%
Acreage acquired, unproved (percent)				56.00%
Collins and Wallace Contributions [Member] | Collins [Member]
Consideration Transferred [Abstract]
Cash paid in the Collins and Wallace Contributions				1,600,000
Collins and Wallace Contributions [Member] | Wallace LP [Member]
Consideration Transferred [Abstract]
Cash paid in the Collins and Wallace Contributions				600,000
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					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

Acquisitions_and_Sales_of_Oil_4

Acquisitions and Sales of Oil and Natural Gas Property Interests - (ACTOIL NPI Repurchase) (Details) (USD $)	0 Months Ended		1 Months Ended
	Jan. 23, 2014	Sep. 10, 2013	Jul. 31, 2011
ACTOIL NPI Repurchase [Member]
Significant Acquisitions and Disposals [Line Items]
Number of shares issued for ACTOIL NPI Repurchase	10,816,626
Value of the 10,816,626 shares of the Company’s common stock issued in the ACTOIL NPI Repurchase	$210,924,000
Elimination of NPI payable	-36,931,000
Oil and natural gas properties cost	157,382,000
Asset retirement obligation	-639,000
Deferred tax asset	17,250,000
Total consideration for the assets contributed in the ACTOIL NPI Repurchase	$173,993,000
Tax percentage used to estimate book to tax differences for oil and gas properties acquired	36.00%
Acreage acquired, unproved (percent)	56.00%
ACTOIL, LLC [Member] | Spanish Trail Acquisition [Member]
Significant Acquisitions and Disposals [Line Items]
Percentage of net profit interest transferred		25.00%	25.00%
ACTOIL, LLC [Member] | IPO [Member]
Significant Acquisitions and Disposals [Line Items]
Percentage of net profit interest transferred	25.00%
ACTOIL, LLC [Member] | ACTOIL NPI Repurchase [Member]
Significant Acquisitions and Disposals [Line Items]
Percentage of net profit interest transferred			25.00%

Acquisitions_and_Sales_of_Oil_5

Acquisitions and Sales of Oil and Natural Gas Property Interests - (Spanish Trail) (Details) (USD $)	0 Months Ended		1 Months Ended
	Jan. 23, 2014	Sep. 10, 2013	Jul. 31, 2011
IPO [Member] | ACTOIL, LLC [Member]
Business Acquisition [Line Items]
Percentage of net profit interest transferred	25.00%
Spanish Trail Acquisition [Member]
Business Acquisition [Line Items]
Net purchase price		$155,000,000
25% NPI Sale to ACTOIL		-30,131,000
Oil and natural gas properties acquired		90,390,000
Asset retirement obligation assumed		296,000
Total net assets acquired		90,686,000
Spanish Trail Acquisition [Member] | Term loan [Member]
Business Acquisition [Line Items]
Term loan, face amount		70,000,000
Spanish Trail Acquisition [Member] | ACTOIL, LLC [Member]
Business Acquisition [Line Items]
Net purchase price		121,000,000
Percentage of net profit interest transferred		25.00%	25.00%
Total net assets acquired		91,000,000
Spanish Trail Acquisition [Member] | IPO [Member]
Business Acquisition [Line Items]
Net purchase price		$120,521,000

Acquisitions_and_Sales_of_Oil_6

Acquisitions and Sales of Oil and Natural Gas Property Interests - (Resolute Sale) (Details) (USD $)	1 Months Ended
	Oct. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012	Oct. 01, 2012
	escrow_payment
Significant Acquisitions and Disposals [Line Items]
Escrow held back from initial purchase price		$24,000	$3,212,000
Sale of Oil and Natural Gas Properties [Member]
Significant Acquisitions and Disposals [Line Items]
Sales price for interest in oil and natural gas properties				144,200,000		69,000,000
Option to acquire additional interests						2,400,000
Gain on sale of interest in oil and natural gas properties				6,000,000	6,700,000
Number of escrow payments received	2
Proceeds from collection of funds held in escrow	12,000,000
Sale of Oil and Natural Gas Properties [Member] | Title and environmental escrow [Member]
Significant Acquisitions and Disposals [Line Items]
Escrow held back from initial purchase price						5,000,000
Sale of Oil and Natural Gas Properties [Member] | Indemnity escrow [Member]
Significant Acquisitions and Disposals [Line Items]
Escrow held back from initial purchase price						11,000,000
Sale of Oil and Natural Gas Properties [Member] | RSP LLC, ACTOIL and Other Minority Non-operating Working Interest Owners [Member]
Significant Acquisitions and Disposals [Line Items]
Interest in oil and natural gas assets sold (percent)				67.65%	32.35%	32.35%
Sales price for interest in oil and natural gas properties				230,000,000	110,000,000	110,000,000
Option to acquire additional interests					5,000,000	5,000,000
Resolute sale [Member]
Significant Acquisitions and Disposals [Line Items]
Gain on sale of interest in oil and natural gas properties			$22,700,000

Derivative_Instruments_Outstan

Derivative Instruments - (Outstanding Positions) (Details) (Crude Oil [Member])	12 Months Ended
	Dec. 31, 2014
	bbl
Swaps Maturing in Next Fiscal Year [Member]
Derivative [Line Items]
Notional volume (Bbl)	120,000
Weighted average price (in dollars per Bbl)	92.6
Collars Maturing In Next Fiscal Year [Member]
Derivative [Line Items]
Notional volume (Bbl)	2,337,000
Weighted average ceiling price (in dollars per Bbl/Mmbtu)	94.64
Weighted average floor price (in dollars per Bbl/Mmbtu)	86.42

Derivative_Instruments_Gross_A

Derivative Instruments - (Gross Assets and Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]
Derivative assets	$76,990	$1,749
Derivative liabilities	-1,320	-1,605
Commodity contracts [Member] | Current amounts, Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	76,990	671
Commodity contracts [Member] | Current amounts, Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	-1,320	-1,562
Commodity contracts [Member] | Noncurrent amounts, Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	0	1,078
Commodity contracts [Member] | Noncurrent amounts, Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$0	($43)

Derivative_Instruments_Gain_Lo

Derivative Instruments - (Gain Loss) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$81,470	($2,607)	($796)
Commodity derivative instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	81,470	-2,583	-408
Interest rate derivative instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments	$0	($24)	($388)

Derivative_Instruments_Offsett

Derivative Instruments - (Offsetting Assets and Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Offsetting of Derivative Assets and Liabilities [Abstract]
Derivative asset, Gross Amount Presented on Balance Sheet	$76,990,000	$1,749,000
Derivative asset, Netting Adjustments	-1,320,000	-1,332,000
Derivative asset, Net Amount	75,670,000	417,000
Derivative liability, Gross Amount Presented on Balance Sheet	-1,320,000	-1,605,000
Derivative liability, Netting Adjustments	1,320,000	1,332,000
Derivative liability, Net Amount	0	-273,000
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 $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$76,990	$1,749
Recurring basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	75,670	144
Recurring basis [Member] | Commodity derivative instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	75,670	144
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	75,670	144
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	75,670	144
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

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	0 Months Ended	12 Months Ended
	Sep. 26, 2014	Dec. 31, 2014	Dec. 31, 2013	Sep. 10, 2013	Sep. 30, 2014	Aug. 29, 2014	Jun. 09, 2014	Jun. 08, 2014
Debt Instrument [Line Items]
Term loan		$0	$70,000,000
Revolving credit facility		0	58,200,000
6.625% Senior notes		500,000,000	0
Total long-term debt		500,000,000	128,200,000
Stated interest rate		6.63%	6.63%
Subsidiary [Member]
Debt Instrument [Line Items]
Subsidiary, cumulative ownership (percent)	100.00%
Senior unsecured notes [Member]
Debt Instrument [Line Items]
Stated interest rate	6.63%
Term loan, face amount	500,000,000
Debt issuance costs	11,300,000
Senior unsecured notes [Member] | After October 1, 2017 [Member]
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	104.97%
Senior unsecured notes [Member] | January 1, 2020 [Member]
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	100.00%
Senior unsecured notes [Member] | Before October 1, 2017 [Member]
Debt Instrument [Line Items]
Percentage of original principal amount of debt at which debt can be redeemed	106.63%
Percentage of principal amount of debt that may be redeemed, maximum	35.00%
Senior unsecured notes [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%
Spanish Trail Acquisition [Member] | Term loan [Member]
Debt Instrument [Line Items]
Term loan, face amount				70,000,000
Revolving credit facility [Member]
Debt Instrument [Line Items]
Credit agreement, maximum borrowing capacity		500,000,000		500,000,000		500,000,000	375,000,000	300,000,000
Number of lenders in syndicated bank group				11
Credit agreement, maximum borrowing capacity, lender commitments					$1,000,000,000	$1,000,000,000
Number of financial ratios				3
Working capital ratio, required		1
Leverage ratio, required		4.5
Senior secured leverage ratio		3.5
Variable interest rate at period end		3.25%
Revolving credit facility [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Variable rate basis, base percentage prior to adjustments		100.00%
Revolving credit facility [Member] | Eurodollar [Member] | Minimum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate		1.00%
Revolving credit facility [Member] | Eurodollar [Member] | Maximum [Member]
Debt Instrument [Line Items]
Basis spread on variable rate		2.00%
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]
Interest rate terms, percentage of borrowing base utilized margin		0.00%
Revolving credit facility [Member] | LIBOR [Member] | Maximum [Member]
Debt Instrument [Line Items]
Interest rate terms, percentage of borrowing base utilized margin		1.00%
Revolving credit facility [Member] | Federal Funds Rate [Member]
Debt Instrument [Line Items]
Basis spread on variable rate		1.00%

Net_Profits_Interest_Details

Net Profits Interest (Details) (USD $)	1 Months Ended
	Jul. 31, 2011	Dec. 31, 2014	Dec. 31, 2013	Jan. 23, 2014	Mar. 31, 2013	Oct. 01, 2012	Dec. 31, 2012
Significant Acquisitions and Disposals [Line Items]
NPI payable		$0	$36,931,000
ACTOIL NPI Repurchase [Member]
Significant Acquisitions and Disposals [Line Items]
Consideration for the assets contributed in the ACTOIL NPI Repurchase				173,993,000
ACTOIL NPI Repurchase [Member] | ACTOIL, LLC [Member]
Significant Acquisitions and Disposals [Line Items]
Financing agreement, face value	175,000,000
Percentage of net profit interest transferred	25.00%
Net profits interest, cumulative deficit			8,300,000
Sale of Oil and Natural Gas Properties [Member]
Significant Acquisitions and Disposals [Line Items]
Consideration for the assets contributed in the ACTOIL NPI Repurchase					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]
Significant Acquisitions and Disposals [Line Items]
Interest in oil and natural gas assets sold (percent)					67.65%	32.35%	32.35%
Consideration for the assets contributed in the ACTOIL NPI Repurchase					230,000,000	110,000,000	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]
Significant Acquisitions and Disposals [Line Items]
Consideration for the assets contributed in the ACTOIL NPI Repurchase					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]
Significant Acquisitions and Disposals [Line Items]
Consideration for the assets contributed in the ACTOIL NPI Repurchase					21,100,000
Sale of Oil and Natural Gas Properties [Member] | ACTOIL, LLC [Member] | Proceeds Distributed To Counterparty [Member]
Significant Acquisitions and Disposals [Line Items]
Consideration for the assets contributed in the ACTOIL NPI Repurchase					$10,700,000

Major_Customers_and_Suppliers_1

Major Customers and Suppliers (Details) (Sales Revenue, Net [Member], Customer Concentration Risk [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Shell Trading (US) Company [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	31.00%	40.00%	3.00%
Enterprise Crude Oil LLC [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	24.00%	14.00%	0.00%
Diamondback E&P, LLC [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	14.00%	11.00%	2.00%
Coronado Midstream, LLC [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	6.00%	8.00%	11.00%
Plains Marketing, L.P. [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	0.00%	13.00%	76.00%
Permian Transport & Trading [Member]
Concentration Risk [Line Items]
Percentage of Total Revenues	21.00%	0.00%	0.00%

Equity_Based_Compensation_Deta

Equity Based Compensation (Details) (USD $)	1 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2014
Restricted stock awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense		$2.80
Restricted stock awards [Member] | 2014 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense		4.7
Unrecognized share-based compensation expense		6.9
Unrecognized compensation expense, weighted average recognition period		1 year 7 months 6 days
Restricted Shares, Outstanding [Roll Forward]
Restricted shares outstanding, beginning of period		0
Restricted shares granted		489,544
Restricted shares canceled		-11,777
Restricted shares outstanding, end of period		477,767
Restricted Shares, Weighted Average Grant Price [Abstract]
Restricted shares outstanding, beginning of period, Weighted Average Fair Value (in dollars per share)		$0
Restricted shares granted, Weighted Average Fair Value (in dollars per share)		$23.69
Restricted shares canceled, Weighted Average Fair Value (in dollars per share)		$23.03
Restricted shares outstanding, end of period, Weighted Average Fair Value (in dollars per share)		$23.71
Performance-based restricted stock awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense		0.8
Unrecognized share-based compensation expense		3
Unrecognized compensation expense, weighted average recognition period		2 years 2 months 1 day
Award vesting period	2 years 9 months
Stock awards granted during the period (in shares)	134,400
Target payout percentage	100.00%
Restricted Shares, Weighted Average Grant Price [Abstract]
Restricted shares granted, Weighted Average Fair Value (in dollars per share)		$28.14
Performance-based restricted stock awards [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout percentage	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%
Incentive Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense		14.7
Incentive Units, Tier I and Tier IA [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period		3 years
Inventive Units, Tier I, Tier IA, Tier II and Tier III [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense		14.7
General and administrative expenses [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense		$20.20

Commitments_and_Contingencies_1

Commitments and Contingencies - Narrative (Details) (USD $)	12 Months Ended			1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2014	Jul. 31, 2014	Feb. 28, 2014
Other Commitments [Line Items]
Rent expense (2013, less than)	$0.50	$0.20	$0.20
Midland, Texas [Member]
Other Commitments [Line Items]
Operating lease, term				60 months
Dallas, Texas [Member]
Other Commitments [Line Items]
Operating lease, term					58 months	64 months

Commitments_and_Contingencies_2

Commitments and Contingencies Commitments and Contingencies - Contractual Obligations (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Sep. 26, 2014
In Thousands, unless otherwise specified
Other Commitments [Line Items]
Stated interest rate	6.63%	6.63%
Contractual Obligation, Fiscal Year Maturity [Abstract]
2015	$68,535
2016	53,643
2017	35,660
2018	33,903
2019	33,628
Thereafter	595,967
Total	821,336
Interest cost [Member]
Contractual Obligation, Fiscal Year Maturity [Abstract]
2015	33,125
2016	33,125
2017	33,125
2018	33,125
2019	33,125
Thereafter	91,094
Total	256,719
Drilling rig commitments [Member]
Contractual Obligation, Fiscal Year Maturity [Abstract]
2015	34,296
2016	19,440
2017	1,645
2018	0
2019	0
Thereafter	0
Total	55,381
Office and equipment leases [Member]
Contractual Obligation, Fiscal Year Maturity [Abstract]
2015	1,114
2016	1,078
2017	890
2018	778
2019	503
Thereafter	0
Total	4,363
Asset retirement obligations [Member]
Contractual Obligation, Fiscal Year Maturity [Abstract]
2015	0
2016	0
2017	0
2018	0
2019	0
Thereafter	4,873
Total	4,873
6.625% Senior Notes [Member]
Other Commitments [Line Items]
Stated interest rate			6.63%
Contractual Obligation, Fiscal Year Maturity [Abstract]
2015	0
2016	0
2017	0
2018	0
2019	0
Thereafter	500,000
Total	500,000
Revolving credit facility [Member]
Contractual Obligation, Fiscal Year Maturity [Abstract]
2015	0
2016	0
2017	0
2018	0
2019	0
Thereafter	0
Total	$0

Earnings_per_Share_Basic_and_D

Earnings per Share - Basic and Diluted (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014
Numerator:
Net income available to stockholders	$2,498
Basic net income allocable to participating securities	15
Income available to stockholders	$2,483
Denominator:
Weighted average number of common shares outstanding - basic (in shares)	71,898
Weighted average number of common shares outstanding - diluted (in shares)	71,898
Net loss per share:
Basic (in dollars per share)	$0.03
Diluted (in dollars per share)	$0.03

Earnings_per_Share_Pro_Forma_D

Earnings per Share - Pro Forma (Details) (USD $)	3 Months Ended				12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Numerator:
Income before taxes, as reported					$160,304	$65,000	$35,569
Pro forma provision for income taxes	-6,472	-8,653	-2,829	-4,632	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
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_Provision_Details

Income Taxes - Provision (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Provision for deferred income tax expense (benefit)	$95,000,000			$132,000,000
Current Income Tax Provision:
Federal									4,111,000
State									227,000
Total income tax provision									4,338,000	68,000	-339,000
Deferred Income Tax Provision:
Federal									157,806,000
State									-227,000
Federal alternative minimum tax									-4,111,000
Total deferred income tax provision									153,468,000	2,194,000	0
Total Provision for Income Taxes	($3,060,000)	$20,704,000	$4,948,000	$135,213,000	$2,194,000	$0	$68,000	$0	$157,806,000	$2,262,000	($339,000)

Income_Taxes_Reconciliation_De

Income Taxes - Reconciliation (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Federal statutory income tax rate (percent)									35.00%
Income tax expense at the federal statutory rate (35%)									$56,106
Income tax expense relating to change in tax status									95,162
State income tax expense, net of federal tax benefit									1,081
Non-deductible expenses									5,457
Total Provision for Income Taxes	($3,060)	$20,704	$4,948	$135,213	$2,194	$0	$68	$0	$157,806	$2,262	($339)

Income_Taxes_Deferred_Tax_Asse

Income Taxes - Deferred Tax Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Jan. 23, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Federal net operating loss carryforwards	$38,900,000
Deferred tax assets
Derivative instruments	0
Other	1,519,000
Total current deferred tax assets	1,519,000
Deferred tax liabilities
Derivative instruments	-26,949,000
Other	-359,000
Total current deferred tax liabilities	-27,308,000
Net current deferred tax assets	-25,789,000		0
Deferred tax assets
Net operating loss carryforwards (subject to 20 year expiration)	13,604,000
Stock based compensation	1,943,000
Alternative minimum tax credit carryforward	4,111,000
Other	8,000
Total noncurrent deferred tax assets	19,666,000
Deferred tax liabilities
Oil and natural gas properties and equipment	-348,928,000
Other	0
Total noncurrent deferred tax liabilities	-348,928,000
Net noncurrent deferred tax liabilities	-329,262,000		-2,195,000
Net deferred tax liabilities	($355,051,000)	($132,000,000)

Supplemental_Disclosure_of_Oil2

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Costs Incurred on Oil and Natural Gas Properties (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Proved (1)	$581,307,000	$86,958,000	$0
Unproved (1)	622,210,000	7,875,000	0
Exploration costs	16,762,000	0	0
Development costs	462,063,000	136,832,000	173,983,000
Total costs incurred	1,682,342,000	231,665,000	173,983,000
Acquisition of oil and gas reserves, noncash additions	$842,000,000

Supplemental_Disclosure_of_Oil3

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Capitalized Oil and Natural Gas Costs (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Extractive Industries [Abstract]
Proved	$1,585,125	$562,019
Unproved	655,678	33,467
Capitalized costs, gross	2,240,803	595,486
Less accumulated depreciation, depletion, amortization and impairment	-171,046	-88,514
Net capitalized costs	$2,069,757	$506,972

Supplemental_Disclosure_of_Oil4

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Results of Oil and Natural Gas Producing Activities (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Oil and natural gas sales	$79,458	$70,645	$74,062	$57,758	$36,380	$36,860	$25,147	$24,655	$281,925	$123,042	$104,427
Lease operating expenses									34,704	14,113	12,693
Production and ad valorem taxes									19,758	8,326	7,575
Depreciation, depletion, and amortization									87,844	47,158	48,803
Asset retirement obligation accretion									142	121	115
Impairments									4,344	0	0
Exploration									3,854	551	161
Income tax expense (benefit)	-3,060	20,704	4,948	135,213	2,194	0	68	0	157,806	2,262	-339
Results of operations									($26,527)	$50,511	$35,419

Supplemental_Disclosure_of_Oil5

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Proved Reserves (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Boe	Boe	stream	stream
	MBoe	MBoe	MBoe	MBoe
		acre	acre
Proved Developed and Undeveloped Reserves, Energy [Roll Forward]
Beginning of year	36,613,000	32,600,000	48,774,000
Revisions of previous estimates	1,529,000	-3,844,000	-24,608,000
Extensions, discoveries and other additions	40,125,000	11,099,000	10,001,000
Divestitures		-7,603,000
Purchases of minerals in place	32,412,000	6,044,000
Production	-4,263,000	-1,683,000	-1,567,000
End of year	106,416,000	36,613,000	32,600,000	48,774,000
Proved Developed Reserves, Energy [Abstract]
Proved developed reserves, beginning of year	14,636,000	12,427,000
Proved developed reserves, end of year	41,924,000	14,636,000	12,427,000
Proved Undeveloped Reserves, Energy [Abstract]
Proved undeveloped reserves, beginning of year	21,977,000	20,173,000
Proved undeveloped reserves, end of year	64,492,000	21,977,000	20,173,000
Conversion of natural gas volumes to barrel of oil equivalent	6	6
Negative revisions of previous estimates	4,053,000
Proved undeveloped reserves area, change in development strategy			20
Number of sales volume streams			3	2
Natural Gas [Member]
Proved Developed and Undeveloped Reserves, Volume [Roll Forward]
Beginning of year	35,803,000	40,692,000	92,416,000
Revisions of previous estimates	-5,477,000	-2,628,000	-57,872,000
Extensions, discoveries and other additions	25,229,000	8,151,000	7,724,000
Divestitures		-14,687,000
Purchases of minerals in place	39,841,000	5,872,000
Production	-2,974,000	-1,597,000	-1,576,000
End of year	92,422,000	35,803,000	40,692,000
Proved Developed Reserves, Volume [Abstract]
Proved developed reserves, beginning of year	14,396,000	17,847,000
Proved developed reserves, end of year	35,921,000	14,396,000	17,847,000
Proved Undeveloped Reserves, Volume [Abstract]
Proved undeveloped reserves, beginning of year	21,407,000	22,845,000
Proved undeveloped reserves, end of year	56,501,000	21,407,000	22,845,000
Oil [Member]
Proved Developed and Undeveloped Reserves, Volume [Roll Forward]
Beginning of year	23,732,000	20,863,000	33,371,000
Revisions of previous estimates	223,000	-941,000	-15,353,000
Extensions, discoveries and other additions	30,023,000	6,301,000	3,885,000
Divestitures		-5,156,000
Purchases of minerals in place	18,344,000	3,832,000
Production	-3,049,000	-1,167,000	-1,040,000
End of year	69,273,000	23,732,000	20,863,000
Proved Developed Reserves, Volume [Abstract]
Proved developed reserves, beginning of year	9,533,000	7,730,000
Proved developed reserves, end of year	27,716,000	9,533,000	7,730,000
Proved Undeveloped Reserves, Volume [Abstract]
Proved undeveloped reserves, beginning of year	14,199,000	13,133,000
Proved undeveloped reserves, end of year	41,557,000	14,199,000	13,133,000
Natural Gas Liquids [Member]
Proved Developed and Undeveloped Reserves, Volume [Roll Forward]
Beginning of year	6,913,000	4,956,000	0
Revisions of previous estimates	2,219,000	-2,465,000	391,000
Extensions, discoveries and other additions	5,897,000	3,440,000	4,829,000
Divestitures		0
Purchases of minerals in place	7,428,000	1,232,000
Production	-718,000	-250,000	-264,000
End of year	21,739,000	6,913,000	4,956,000
Proved Developed Reserves, Volume [Abstract]
Proved developed reserves, beginning of year	2,703,000	1,723,000
Proved developed reserves, end of year	8,221,000	2,703,000	1,723,000
Proved Undeveloped Reserves, Volume [Abstract]
Proved undeveloped reserves, beginning of year	4,210,000	3,233,000
Proved undeveloped reserves, end of year	13,518,000	4,210,000	3,233,000

Supplemental_Disclosure_of_Oil6

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Discounted Future Net Cash Flows, Proved Reserves (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	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	$7,015,504	$2,547,566	$2,210,325
Future production costs	-2,025,302	-727,939	-655,720
Future development costs	-1,182,981	-378,695	-362,876
Future income tax expenses	-1,154,808	0	0
Future net cash flows	2,652,413	1,440,932	1,191,729
10% discount for estimated timing of cash flows	-1,776,282	-890,217	-737,556
Standardized measure of discounted future net cash flows	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	155,700
Standardized measure of discounted future net cash flows	$303,300	$298,500

Supplemental_Disclosure_of_Oil7

Supplemental Disclosure of Oil and Natural Gas Operations (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
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%
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	$550,715	$454,173	$854,424
Sales, less production costs	-223,608	-100,052	-83,998
Revisions of previous quantity estimates	20,892	-53,557	-439,043
Extensions, discoveries and other additions	646,855	157,086	84,149
Net change in prices and production costs	-74,081	45,388	-133,485
Changes in estimated future development costs	-7,858	2,318	38,096
Previously estimated development costs incurred during the period	44,925	46,938	108,367
Divestiture of reserves	0	-151,440	0
Purchases of minerals in place	366,106	94,751	0
Accretion of discount	55,072	45,417	85,442
Net change in income taxes	-441,506	0	0
Timing differences and other	-61,380	9,693	-59,779
Standardized measure of discounted future net cash flows, end of year	$876,132	$550,715	$454,173

Quarterly_Financial_Data_Unaud2

Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Revenues	$79,458,000	$70,645,000	$74,062,000	$57,758,000	$36,380,000	$36,860,000	$25,147,000	$24,655,000	$281,925,000	$123,042,000	$104,427,000
Income from operations	16,512,000	33,160,000	30,576,000	12,657,000	22,520,000	27,039,000	7,114,000	14,948,000	92,909,000	71,621,000	38,955,000
Income tax expense (benefit)	3,060,000	-20,704,000	-4,948,000	-135,213,000	-2,194,000	0	-68,000	0	-157,806,000	-2,262,000	339,000
Net income	89,503,000	32,297,000	8,226,000	-127,530,000	17,976,000	24,037,000	7,859,000	12,866,000	2,498,000	62,738,000	35,908,000
Pro forma provision for income taxes (1)					6,472,000	8,653,000	2,829,000	4,632,000	-57,709,000
Pro forma net income					11,504,000	15,384,000	5,030,000	8,234,000
Basic and diluted (in dollars per share)	$1.15	$0.43	$0.11	($2.03)	$0.36	$0.48	$0.16	$0.26
Provision for deferred income taxes, conversion to taxable C-corp				132,000,000
Decrease in deferred income taxes	($37,000,000)								($153,468,000)	($2,195,000)	$0