Rosetta Resources 10-K 24 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2013	Feb. 07, 2014	Jun. 28, 2013
Document And Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'ROSE	'	'
Entity Registrant Name	'ROSETTA RESOURCES INC.	'	'
Entity Central Index Key	'0001340282	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	61,344,077	'
Entity Public Float	'	'	$2.60

Consolidated_Balance_Sheet

Consolidated Balance Sheet (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$193,784	$36,786
Accounts receivable	122,677	103,828
Derivative instruments	4,307	14,437
Prepaid expenses	9,860	5,742
Deferred income taxes	27,976	311
Other current assets	1,284	1,456
Total current assets	359,888	162,560
Oil and natural gas properties using the full cost method of accounting:	'	'
Proved properties	3,951,397	2,829,431
Unproved/unevaluated properties, not subject to amortization	755,438	95,540
Gathering systems and compressor stations	168,730	104,978
Other fixed assets	26,362	16,346
Total property and equipment, gross	4,901,927	3,046,295
Accumulated depreciation, depletion and amortization, including impairment	-2,020,879	-1,808,190
Total property and equipment, net	2,881,048	1,238,105
Other assets:	'	'
Debt issuance costs	25,602	7,699
Derivative instruments	5,458	6,790
Other long-term assets	4,622	262
Total other assets	35,682	14,751
Total assets	3,276,618	1,415,416
Current liabilities:	'	'
Accounts payable and accrued liabilities	190,950	122,210
Royalties and other payables	78,264	61,637
Derivative instruments	4,913	'
Total current liabilities	274,127	183,847
Long-term liabilities:	'	'
Derivative instruments	433	563
Long-term debt	1,500,000	410,000
Deferred income taxes	136,407	10,086
Other long-term liabilities	17,317	6,921
Total liabilities	1,928,284	611,417
Commitments and contingencies (Note 11)	'	'
Stockholders' equity:	'	'
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2013 or 2012	'	'
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 62,032,162 shares and 53,145,853 shares at December 31, 2013 and 2012, respectively	61	53
Additional paid-in capital	1,182,672	830,539
Treasury stock, at cost; 724,755 shares and 581,717 shares at December 31, 2013 and 2012, respectively	-24,592	-17,479
Accumulated other comprehensive loss	-108	-63
Retained earnings (Accumulated deficit)	190,301	-9,051
Total stockholders' equity	1,348,334	803,999
Total liabilities and stockholders' equity	$3,276,618	$1,415,416

Consolidated_Balance_Sheet_Par

Consolidated Balance Sheet (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Statement Of Financial Position [Abstract]	'	'
Preferred stock, par value	$0.00	$0.00
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Common stock, par value	$0.00	$0.00
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	62,032,162	53,145,853
Treasury stock, shares	724,755	581,717

Consolidated_Statement_of_Oper

Consolidated Statement of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Oil sales	$475,119	$318,782	$156,284
NGL sales	198,966	160,461	125,301
Natural gas sales	147,028	93,711	163,382
Derivative instruments	-7,095	40,545	1,233
Total revenues	814,018	613,499	446,200
Operating costs and expenses:	'	'	'
Lease operating expense	53,336	35,138	28,822
Treating and transportation	71,338	51,826	22,316
Taxes, other than income	31,075	24,013	18,151
Depreciation, depletion and amortization	218,571	154,223	123,244
Reserve for commercial disputes	20,450	'	'
General and administrative costs	73,043	68,731	75,256
Total operating costs and expenses	467,813	333,931	267,789
Operating income	346,205	279,568	178,411
Other expense (income):	'	'	'
Interest expense, net of interest capitalized	35,957	24,316	21,291
Interest income	-2	-7	-42
Other expense, net	314	60	903
Total other expense	36,269	24,369	22,152
Income before provision for income taxes	309,936	255,199	156,259
Income tax expense	110,584	95,904	55,713
Net income	$199,352	$159,295	$100,546
Earnings per share:	'	'	'
Basic	$3.40	$3.03	$1.93
Diluted	$3.39	$3.01	$1.91
Weighted average shares outstanding:	'	'	'
Basic	58,571	52,496	51,996
Diluted	58,830	52,887	52,616

Consolidated_Statement_of_Comp

Consolidated Statement of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement Of Income And Comprehensive Income [Abstract]	'	'	'
Net income	$199,352	$159,295	$100,546
Other comprehensive (loss) income:	'	'	'
Change in fair value of hedging instruments	'	'	2,033
Reclassification of (gain) on settled hedging instruments, net of income tax benefit of $5,770 for the year ended December 31, 2011	'	'	-11,660
Amortization of accumulated other comprehensive gain (loss) related to de-designated hedges, net of income taxes of ($37) and $968 for the year ended December 31, 2013 and 2012, respectively	63	-1,695	'
Postretirement medical benefits prior service cost, net of income tax benefit of $61 for the year ended December 31, 2013	-108	'	'
Other comprehensive loss	-45	-1,695	-9,627
Comprehensive income	$199,307	$157,600	$90,919

Consolidated_Statement_of_Comp1

Consolidated Statement of Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement Of Income And Comprehensive Income [Abstract]	'	'	'
Reclassification of (gain) on settled hedging instruments, income tax benefit	'	'	$5,770
Amortization of accumulated other comprehensive gain (loss) related to de-designated hedges, income taxes	-37	968	'
Postretirement medical benefits prior service cost, income tax benefit	$61	'	'

Consolidated_Statement_of_Cash

Consolidated Statement of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:	'	'	'
Net income	$199,352	$159,295	$100,546
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Depreciation, depletion and amortization	218,571	154,223	123,244
Deferred income taxes	100,876	95,904	56,170
Amortization of deferred loan fees recorded as interest expense	8,421	2,856	2,248
Stock-based compensation expense	10,979	18,539	29,010
Loss (gain) due to change in fair value of derivative instruments	16,345	-19,662	-12,124
Change in operating assets and liabilities:	'	'	'
Accounts receivable	-18,849	-26,454	-41,215
Prepaid expenses	21	-2,780	-226
Other current assets	172	680	287
Long-term assets	-108	650	-450
Accounts payable and accrued liabilities	37,370	-19,997	765
Royalties and other payables	16,627	10,948	37,409
Other long-term liabilities	3,413	-3,572	-8,863
Income taxes	-2,181	'	'
Derivative instruments	'	'	12,736
Net cash provided by operating activities	591,009	370,630	299,537
Cash flows from investing activities:	'	'	'
Acquisitions of oil and gas assets	-956,892	'	'
Additions to oil and gas assets	-871,092	-622,168	-432,951
Disposals of oil and gas assets	-1,304	88,527	242,588
Net cash used in investing activities	-1,829,288	-533,641	-190,363
Cash flows from financing activities:	'	'	'
Borrowings on Credit Facility	670,000	290,000	'
Payments on Credit Facility	-880,000	-110,000	-100,000
Repayments on Restated Term Loan	'	-20,000	'
Issuance of Senior Notes	1,300,000	'	'
Proceeds from issuance of common stock	329,008	'	'
Deferred loan fees	-28,280	-1,980	-3,150
Proceeds from stock options exercised	4,981	910	3,792
Purchases of treasury stock	-7,113	-6,183	-4,400
Excess tax benefit from share-based awards	6,681	'	'
Net cash provided by (used in) financing activities	1,395,277	152,747	-103,758
Net increase (decrease) in cash	156,998	-10,264	5,416
Cash and cash equivalents, beginning of year	36,786	47,050	41,634
Cash and cash equivalents, end of year	193,784	36,786	47,050
Supplemental disclosures:	'	'	'
Cash paid for interest expense, net of capitalized interest	24,824	20,834	19,044
Cash paid (received) for income taxes	2,941	-105	-405
Supplemental non-cash disclosures:	'	'	'
Capital expenditures included in Accounts payable and accrued liabilities	$118,725	$88,844	$57,546

Consolidated_Statement_of_Stoc

Consolidated Statement of Stockholders' Equity (USD $)	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive (Loss)/Income [Member]	Retained Earnings / (Accumulated Deficit) [Member]
In Thousands, except Share data
Balance at Dec. 31, 2010	$528,816	$52	$793,293	($6,896)	$11,259	($268,892)
Balance, Treasury Stock, Shares at Dec. 31, 2010	'	'	'	343,093	'	'
Balance, Common Stock Shares at Dec. 31, 2010	'	52,031,004	'	'	'	'
Stock options exercised	3,792	'	3,792	'	'	'
Stock options exercised, shares	'	230,741	'	'	'	'
Treasury stock-employee tax payment	-4,400	'	'	-4,400	'	'
Treasury Stock, Shares, Acquired	'	'	'	107,080	'	'
Stock-based compensation	13,709	'	13,709	'	'	'
Vesting of restricted stock	'	'	'	'	'	'
Vesting of restricted stock, Shares	'	'	'	'	'	'
Net income	100,546	'	'	'	'	100,546
Other comprehensive loss	-9,627	'	'	'	-9,627	'
Balance at Dec. 31, 2011	632,836	52	810,794	-11,296	1,632	-168,346
Balance, Treasury Stock, Shares at Dec. 31, 2011	'	'	'	450,173	'	'
Balance, Common Stock, Shares at Dec. 31, 2011	'	52,630,483	'	'	'	'
Stock options exercised	911	1	910	'	'	'
Stock options exercised, shares	69,862	69,862	'	'	'	'
Treasury stock-employee tax payment	-6,183	'	'	-6,183	'	'
Treasury Stock, Shares, Acquired	'	'	'	131,544	'	'
Stock-based compensation	18,835	'	18,835	'	'	'
Vesting of restricted stock	'	'	'	'	'	'
Vesting of restricted stock, Shares	'	'	'	'	'	'
Net income	159,295	'	'	'	'	159,295
Other comprehensive loss	-1,695	'	'	'	-1,695	'
Balance at Dec. 31, 2012	803,999	53	830,539	-17,479	-63	-9,051
Balance, Treasury Stock, Shares at Dec. 31, 2012	581,717	'	'	581,717	'	'
Balance, Common Stock, Shares at Dec. 31, 2012	'	53,145,853	'	'	'	'
Stock options exercised	4,981	'	4,981	'	'	'
Stock options exercised, shares	379,145	379,145	'	'	'	'
Treasury stock-employee tax payment	-7,113	'	'	-7,113	'	'
Treasury Stock, Shares, Acquired	'	'	'	143,038	'	'
Stock-based compensation	11,471	'	11,471	'	'	'
Issuance of common stock	329,008	8	329,000	'	'	'
Issuance of common stock, Shares	'	8,050,000	'	'	'	'
Vesting of restricted stock	'	'	'	'	'	'
Vesting of restricted stock, Shares	'	457,164	'	'	'	'
Excess tax benefit from share-based awards	6,681	'	6,681	'	'	'
Net income	199,352	'	'	'	'	199,352
Other comprehensive loss	-45	'	'	'	-45	'
Balance at Dec. 31, 2013	$1,348,334	$61	$1,182,672	($24,592)	($108)	$190,301
Balance, Treasury Stock, Shares at Dec. 31, 2013	724,755	'	'	724,755	'	'
Balance, Common Stock, Shares at Dec. 31, 2013	'	62,032,162	'	'	'	'

Organization_and_Operations_of

Organization and Operations of the Company	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Organization and Operations of the Company	'
	(1) Organization and Operations of the Company
	Nature of Operations. Rosetta Resources Inc. (together with its consolidated subsidiaries, the “Company”) is an independent exploration and production company engaged in the acquisition and development of onshore energy resources in the United States of America. The Company’s operations are located in the Eagle Ford shale in South Texas and the Permian Basin in West Texas.
	In preparing these financial statements, events occurring after December 31, 2013 through the release of these financial statements were evaluated by the Company to ensure that subsequent events meeting the criteria for recognition and/or disclosure in this report have been included.
	Certain reclassifications of prior year balances have been made to conform with current year classifications. These reclassifications have no impact on net income.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	(2) Summary of Significant Accounting Policies
	Use of Estimates in Preparation of Financial Statements
	The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, the outcome of pending litigation and environmental costs, stock-based compensation, valuation of derivative instruments, future development and abandonment costs, estimates related to certain oil, NGL and natural gas revenues and operating expenses, determination of the fair value of assets acquired and liabilities assumed and recording of goodwill and deferred taxes, if any, in connection with business combinations, and the estimates of proved oil, NGL and natural gas reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties.
	Cash and Cash Equivalents
	The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
	With respect to the current market environment for liquidity and access to credit, the Company, through banks participating in its credit facility, has invested available cash in interest and non-interest bearing demand deposit accounts in those participating banks and in money market accounts and funds whose investments are limited to U.S. Government securities, securities backed by the U.S. Government, or securities of U.S. Government agencies. The Company has followed this policy and believes this is an appropriate approach for the investment of Company funds.
	Allowance for Doubtful Accounts
	The Company regularly reviews all aged accounts receivables for collectability and establishes an allowance as necessary for individual customer balances. As of December 31, 2013 and 2012, the Company had no allowance for doubtful accounts.
	Oil and Natural Gas Properties
	The Company follows the full cost method of accounting whereby all costs incurred in acquiring, exploring and developing properties, including salaries, benefits and other internal costs directly attributable to these activities, are capitalized when incurred into cost centers that are established on a country-by-country basis. Such costs are amortized on a unit-of-production basis over reserves in the cost center in which they are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. In some cases, however, certain significant costs, such as those associated with unevaluated properties and significant development projects, are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and natural gas producing activities are regarded as integral to the acquisition, discovery and development of reserves that ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $7.2 million, $6.0 million and $7.0 million of internal costs for the years ended December 31, 2013, 2012 and 2011, respectively. Unevaluated costs are excluded from the full cost pool and are periodically evaluated for impairment. Upon evaluation or impairment, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally reflected in the full cost pool, unless a significant portion of the pool or reserves is sold causing a significant change in the relationship between capitalized costs and proved reserves, in which case a gain or loss is calculated and recognized in the Consolidated Statement of Operations.
	The Company assesses the impairment for oil and natural gas properties quarterly using a ceiling test to determine if impairment is necessary. This ceiling limits capitalized costs to the present value of estimated future cash flows from proved oil and natural gas reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage values) to the extent not included in oil and natural gas properties pursuant to authoritative guidance, and estimated future income taxes thereon.
	A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date. If required, a write-down would reduce earnings and impact shareholders’ equity in the period of occurrence and result in lower DD&A expense in the future.
	Other Fixed Assets
	Other fixed assets primarily include computer hardware and software, office leasehold, and furniture and fixtures, which are recorded at cost and depreciated on a straight-line basis over useful lives of five to seven years. Repair and maintenance costs are charged to expense as incurred while renewals and betterments are capitalized as additions to the related assets in the period incurred. Gains or losses from the disposal of other fixed assets are recorded in the period incurred. The net book value of other fixed assets that are retired or sold is charged to accumulated depreciation and the difference is recognized as a gain or loss in the Consolidated Statement of Operations in the period the retirement or sale transpires.
	Future Development and Abandonment Costs
	Future development costs include costs incurred to obtain access to proved reserves, such as drilling costs and the installation of production equipment, and such costs are included in the calculation of DD&A expense. Future abandonment costs include costs to plug and abandon wells, dismantle and relocate or dispose of our production platforms, gathering systems and related structures and restoration costs of land and seabed. The Company develops estimates of these costs for each of its properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. The Company reviews its assumptions and estimates of future development and future abandonment costs on an annual basis.
	The Company provides for future abandonment costs in accordance with authoritative guidance regarding the accounting for asset retirement obligations. A liability is recorded for the fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.
	Capitalized Interest
	The Company capitalizes interest on capital invested in projects related to unevaluated properties and significant development projects. As proved reserves are established or impairment determined, the related capitalized interest is included in costs subject to amortization. The Company capitalized interest of $28.3 million, $3.8 million, and $5.5 million in 2013, 2012 and 2011, respectively.
	Fair Value of Financial Instruments
	Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company’s financial assets and liabilities are measured at fair value on a recurring basis and non-financial assets and liabilities, such as asset retirement obligations and other property and equipment, are recognized at fair value on a non-recurring basis but at least annually. For non-financial assets and liabilities, the Company is required to disclose information that enables users to assess the inputs used to develop these measurements. Changes in fair value associated with both financial and non-financial assets and liabilities are recorded in the Consolidated Statement of Operations. See Note 7 – Fair Value Measurements.
	Concentrations of Credit Risk
	Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of cash, accounts receivable and derivative instruments. The Company’s accounts receivable and derivative instruments are concentrated among entities engaged in the energy industry within the U.S. and financial institutions, respectively. The Company periodically assesses the financial condition of these entities and institutions and considers any possible credit risk to be minimal.
	Debt Issuance Costs
	Costs incurred in connection with the Company’s Credit Facility, Restated Term Loan and Senior Notes (each as hereinafter defined in Note 10 – Debt and Credit Agreements) are recorded on the Company’s Consolidated Balance Sheet as Debt issuance costs. Such costs are amortized to interest expense over the term of the related debt using the effective interest method.
	Derivative Instruments and Activities
	The Company utilizes various types of derivative instruments to manage commodity price risk, including fixed price swaps and costless collars. The Company does not enter into derivative agreements for trading or other speculative purposes and the fair value of derivative contracts is presented on a net basis where the right of offset is provided for in the counterparty agreements. Effective January 1, 2012, the Company elected to de-designate all of its commodity derivative contracts that had previously been designated as cash flow hedges as of December 31, 2011 and elected to discontinue hedge accounting prospectively. See Note 6 – Commodity Derivative Contracts for a more detailed discussion of derivative activities.
	Environmental
	Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the cost can be reasonably estimated. There were no significant environmental liabilities as of December 31, 2013 or 2012.
	Stock-Based Compensation
	Stock-based compensation cost for restricted stock is estimated at the grant date based on the award’s fair value, which is equal to the average high and low common stock price on the date of grant. Such fair value is recognized as expense over the requisite service period. Stock-based compensation cost for options is estimated at the grant date based on the award’s fair value as calculated using an option-pricing model. During the years ended December 31, 2013, 2012 and 2011, no options were granted to the Company’s employees, officers or directors and all options granted prior to 2011 have vested. Compensation expense was recognized ratably over the requisite service period.
	Stock-based compensation expense for performance share units (“PSUs”) is measured and adjusted quarterly until settlement occurs, based on Company performance, quarter-end closing common stock prices and the anticipated vesting percentage. Compensation expense for performance-based awards is recognized when it is probable that performance conditions will be achieved and such awards are expected to vest. The Compensation Committee of the Board of Directors retains discretion beyond the stated performance metrics to ensure it has the ability to reward a focus on behaviors that improve total shareholder return over the long-term and promote various corporate goals. The Compensation Committee has not adopted a policy that all compensation must be deductible for federal income tax purposes, and therefore the Company may make payments that are not fully deductible if it believes such payments are necessary to achieve corporate objectives and protect shareholder interests. See Note 12 – Stock-Based Compensation and Employee Benefits.
	Any excess tax benefit arising from the Company’s stock-based compensation plans is recognized as a credit to additional paid-in capital when realized and is calculated as the amount by which the tax effect of the tax deduction received exceeds the deferred tax asset associated with recorded stock-based compensation expense. Current authoritative guidance requires that cash flows resulting from tax deductions in excess of recorded compensation expense are recognized as financing activities.
	Preferred Stock
	The Company is authorized to issue 5,000,000 shares of preferred stock with preferences and rights as determined by the Company’s Board of Directors. As of December 31, 2013 and 2012, there were no shares of preferred stock outstanding.
	Treasury Stock
	The Company repurchases shares that are surrendered by employees and certain directors to pay tax withholding upon the vesting of restricted stock awards. These repurchases are not part of a publicly announced program to repurchase shares of the Company’s common stock, nor does the Company have a publicly announced program to repurchase shares of common stock. Treasury stock purchases are recorded at cost.
	Revenue Recognition
	Oil, NGL and natural gas revenue from our interests in producing wells is recognized upon delivery and passage of title, using the sales method for gas imbalances, net of any royalty interests or other profit interests in the produced product. Under the sales method, if our gas imbalance (amount of production sold in excess of amount entitled) exceeds our portion of the estimated remaining recoverable reserves of the well, a liability is recorded. No receivables are recorded for those wells on which we have taken less than our ownership share of production, unless the amount taken by other parties exceeds the estimate of their remaining reserves. There were no significant gas imbalances at December 31, 2013 or 2012.
	Income Taxes
	The Company uses the liability method of accounting for income taxes. Under this method, deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax basis of assets and liabilities. Income taxes are provided based on earnings reported for tax return purposes in addition to a provision for deferred income taxes and are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
	Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not support the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.
	Recent Accounting Developments
	The following recently issued accounting development has been applied for the current period.
	Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance to increase the prominence of items reported in other comprehensive income. This guidance requires an entity to present components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements of net income and comprehensive income. In February 2013, the FASB further clarified this guidance relating to the presentation of reclassification adjustments stating that an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income. The Company adopted the provisions of the initial guidance effective January 1, 2012 and the provisions of the February 2013 amendment effective January 1, 2013. See the Consolidated Statement of Comprehensive Income, Note 6 – Commodity Derivative Contracts and Note 12 – Stock-Based Compensation and Employee Benefits.

Accounts_Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2013
Receivables [Abstract]	'
Accounts Receivable	'
	(3) Accounts Receivable
	Accounts receivable consists of the following:
		December 31,
		2013		2012
		(In thousands)
	Oil, NGL and natural gas sales	$	96,576	$	84,533
	State severance tax refunds		19,157		16,269
	Joint interest billings		4,696		3,026
	Other		2,248		—
	Total	$	122,677	$	103,828
	There are no balances in accounts receivable that are considered to be uncollectible and an allowance was unnecessary as of December 31, 2013 and 2012.

Property_and_Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Property and Equipment	'
	(4) Property and Equipment
	The Company’s total property and equipment consists of the following:
		December 31,
		2013			2012
		(In thousands)
	Proved properties	$	3,951,397		$	2,829,431
	Unproved/unevaluated properties		755,438			95,540
	Gathering systems and compressor stations		168,730			104,978
	Other fixed assets		26,362			16,346
	Total		4,901,927			3,046,295
	Less: Accumulated depreciation, depletion and amortization		(2,020,879	)		(1,808,190	)
	Total property and equipment, net	$	2,881,048		$	1,238,105
	Acquisitions
	Permian Basin Acquisition. On March 14, 2013, the Company entered into a purchase and sale agreement with Comstock Oil & Gas, LP (“Comstock”) to purchase producing and undeveloped oil and natural gas interests in the Permian Basin in Gaines and Reeves Counties, Texas for $768 million, subject to customary closing adjustments, including adjustments based upon title and environmental due diligence (the “Permian Acquisition”). The Company completed the Permian Acquisition on May 14, 2013 (the “Permian Acquisition Date”), with an effective date of January 1, 2013, for total cash consideration of $825.2 million. The Permian Acquisition was financed with the proceeds from the Company’s issuance of the 5.625% Senior Notes, as described in Note 10 – Debt and Credit Agreements, and the common stock offering described in Note 14 – Equity. In connection with the Permian Acquisition and related financings, the Company incurred total transaction costs of approximately $31.0 million, including (i) $5.6 million of commitment fees and related expenses associated with a bridge credit facility (“Bridge Credit Facility”), which were recorded as Interest expense since the Company did not borrow under the Bridge Credit Facility, (ii) $10.0 million of debt issuance costs paid in connection with the issuance of the 5.625% Senior Notes, which were deferred and are being amortized over the term of these senior notes, (iii) $13.1 million of equity issuance costs and related expenses associated with the common stock offering, which were reflected as a reduction of equity proceeds, and (iv) $2.3 million of consulting, investment, advisory, legal and other acquisition-related fees, which were expensed and are included in General and administrative costs.
	Gates Ranch Acquisition. In the second quarter of 2013, the Company acquired the remaining 10% working interest in certain producing wells in certain leases of its Gates Ranch leasehold located in the Eagle Ford shale (the “Gates Acquisition”) in Webb County for total cash consideration of approximately $128.1 million. The transaction closed on June 5, 2013 (the “Gates Acquisition Date”) and was financed with borrowings under the Company’s Credit Facility, as described in Note 10 – Debt and Credit Agreements. As of the Gates Acquisition Date, the Company now owns 100% working interest in the entire Gates Ranch leasehold.
	Both of the above transactions were accounted for under the acquisition method of accounting, whereby the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill (or shortfall of purchase price versus net fair value recorded as bargain purchase). Based on the purchase price allocation for these acquisitions, no goodwill or bargain purchase was recognized. The combined cash consideration paid for these transactions and the assets and liabilities recognized at the respective acquisition dates are shown in the table below.
		Total Purchase Price
		Allocation
		(in thousands)
	Cash consideration	$	953,242
	Fair value of assets acquired:
	Other fixed assets	$	600
	Oil and natural gas properties
	Proved properties		290,273
	Unproved/unevaluated properties		663,300
	Total assets acquired	$	954,173
	Fair value of liabilities assumed:
	Asset retirement obligations	$	931
	Net assets acquired	$	953,242
	The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
	The results of operations attributable to the Permian Basin assets and the acquired Gates Ranch working interests were included in the Company’s Consolidated Statement of Operations beginning on May 14, 2013 (Permian Acquisition) and June 5, 2013 (Gates Acquisition), respectively. Revenues of $68.4 million and net income of $47.4 million from these acquired assets were generated in the year ended December 31, 2013, and are included in the Consolidated Statement of Operations for the year ended December 31, 2013.
	The following unaudited pro forma information shows the pro forma effects of the acquisitions, the issuance of the 5.625% Senior Notes, the issuance of common stock in the equity offering and the use of proceeds from the debt and equity offerings. The unaudited pro forma information assumes the transactions and related financings occurred on January 1, 2012. The pro forma results of operations have been prepared by adjusting the Company’s historical results to include the historical results of the acquired assets based on information provided by the seller, the Company’s knowledge of the acquired properties and the impact of the Company’s preliminary purchase price allocation. The Company believes the assumptions used provide a reasonable basis for reflecting the pro forma significant effects directly attributable to the acquisitions and associated financings. The pro forma results of operations do not include any cost savings or other synergies that may result from the Permian Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the Permian assets. The pro forma information does not purport to represent what the Company’s results of operations would have been if such transactions had occurred on January 1, 2012.
		Year Ended December 31,
		2013			2012
		(In thousands, except per share and share data)
	Total revenues	$	846,560		$	671,780
	Net income		191,478			151,144
	Earnings per share:
	Basic	$	3.13		$	2.5
	Diluted	$	3.12		$	2.48
	Weighted average shares outstanding:
	Basic		61,081			60,546
	Diluted		61,339			60,937
	Divestitures
	On February 15, 2012, the Company entered into an agreement to sell its Lobo assets and a portion of its Olmos assets for $95.0 million, subject to customary post-closing adjustments and the receipt of appropriate consents for assignment. During the third quarter of 2012, the Company closed on the sale of the final portion of the properties. Proceeds from the closing of the divestiture were recorded as adjustments to the full cost pool, with no gain or loss recognized.
	In February 2011, the Company executed purchase and sale agreements for the divestitures of its Sacramento Basin assets in California and its DJ Basin assets in Colorado for $200.0 million and $55.0 million, respectively. These asset divestitures were effective as of January 1, 2011 and were subject to post-closing purchase price adjustments. Proceeds from the divestitures were recorded as adjustments to the full cost pool, with no gain or loss recognized.
	Additional Disclosures about Property and Equipment
	Included in the Company’s oil and natural gas properties are asset retirement costs of $22.2 million and $15.1 million as of December 31, 2013 and 2012, respectively, including additions of $2.7 million and $4.7 million for the years ended December 31, 2013 and 2012, respectively.
	Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and natural gas assets within each separate cost center. All of the Company’s costs are included in one cost center because all of the Company’s operations are located in the United States. The Company’s ceiling test was calculated using trailing twelve-month, unweighted-average first-day-of-the-month prices for oil and natural gas as of December 31, 2013, which were based on a West Texas Intermediate oil price of $93.42 per Bbl and a Henry Hub natural gas price of $3.67 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount exceeded the net capitalized cost of oil and natural gas properties at December 31, 2013 and as a result, no write-down was recorded.
	The Company did not record any write-downs or impairments for the years ended December 31, 2013, 2012 and 2011. Effective January 1, 2012, the Company elected to de-designate all of its commodity contracts that had previously been designated as cash flow hedges as of December 31, 2011 and elected to discontinue hedge accounting prospectively. As a result, there is no future impact to the calculated ceiling value due to cash flow hedges, and there was no potential impairment absent the effects of hedging in 2011.
	Capitalized costs excluded from DD&A as of December 31, 2013 and 2012, all of which are located onshore in the U.S., are as follows by the year in which such costs were incurred:
		December 31, 2013
		Total			2013			2012		2011		Prior
		(In thousands)
	Development costs	$	129,812		$	129,812		$	—	$	—	$	—
	Exploration costs		15,459			8,445			7,014		—		—
	Acquisition cost of undeveloped acreage		584,137			565,330			4,485		5,170		9,152
	Capitalized interest		26,030			22,718			1,471		480		1,361
	Total capitalized costs excluded from DD&A	$	755,438		$	726,305		$	12,970	$	5,650	$	10,513
		31-Dec-12
		Total			2012			2011		2010		Prior
		(In thousands)
	Development costs	$	29,857		$	29,857		$	—	$	—	$	—
Exploration costs		16,180			16,180			—		—		—
Acquisition cost of undeveloped acreage		42,186			15,297			6,672		16,920		3,297
Capitalized interest		7,317			3,309			2,064		1,481		463
Total capitalized costs excluded from DD&A	$	95,540		$	64,643		$	8,736	$	18,401	$	3,760
It is anticipated that development costs of $129.8 million will be included in oil and natural gas properties subject to amortization within one year. With respect to the remaining capitalized costs excluded from DD&A of $625.6 million, it is anticipated that these costs will be included in oil and natural gas properties subject to amortization within five years.
Gathering systems and compressor stations. The gross book value of the Company’s gathering systems and compressor stations was $168.7 million and $105.0 million at December 31, 2013 and 2012, respectively, and is being depreciated on a straight-line basis over 15 years. Accumulated depreciation related to these assets at December 31, 2013 and 2012 was $13.7 million and $5.7 million, respectively. Depreciation expense associated with the gathering systems and compressor stations for the years ended December 31, 2013, 2012, and 2011 was $7.9 million, $4.0 million, and $2.3 million, respectively. In connection with divestitures in 2011, the Company sold certain of these assets primarily located in the Sacramento Basin in California with no gain or loss recognized.
Other fixed assets. Other fixed assets at December 31, 2013 and 2012 of $26.4 million and $16.3 million, respectively, consisted primarily of office leasehold, furniture and fixtures and computer hardware and software. Accumulated depreciation associated with Other fixed assets at December 31, 2013 and 2012 was $2.9 million and $5.1 million, respectively. For the years ended December 31, 2013, 2012 and 2011, depreciation expense for Other fixed assets was $3.4 million, $1.4 million and $2.6 million, respectively.

Debt_Issuance_Costs

Debt Issuance Costs	12 Months Ended
	Dec. 31, 2013
Deferred Costs Capitalized Prepaid And Other Assets Disclosure [Abstract]	'
Debt Issuance Costs	'
	(5) Debt Issuance Costs
	As of December 31, 2013 and 2012, debt issuance costs, net were $25.6 million and $7.7 million, respectively. Total amortization expense for such costs was $8.4 million, $2.9 million and $2.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Commodity_Derivative_Contracts

Commodity Derivative Contracts	12 Months Ended
	Dec. 31, 2013
Derivative Instruments And Hedging Activities Disclosure [Abstract]	'
Commodity Derivative Contracts	'
	(6) Commodity Derivative Contracts
	The Company is exposed to various market risks, including volatility in oil, NGL and natural gas prices, which are managed through derivative instruments. The level of derivative activity utilized depends on market conditions, operating strategies and available derivative prices. The Company utilizes various types of derivative instruments to manage commodity price risk, including fixed price swaps and costless collars. Forward contracts on various commodities are entered into to manage the price risk associated with forecasted sales of the Company’s oil, NGL and natural gas production.
	At December 31, 2013, the following derivative contracts were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations:
	Product		Settlement	Derivative		Notional Daily				Total Notional				Average		Average
			Period	Instrument		Volume				Volume				Floor/Fixed Prices		Ceiling Prices
						(Bbls)				(Bbls)				per Bbl		per Bbl
	Crude oil		2014	Costless Collar			3,000				1,095,000			$	83.33	$	109.63
	Crude oil		2014	Swap			6,000				2,190,000				93.13
	Crude oil		2015	Swap			10,000				3,650,000				88.58
	Crude oil		2016	Swap			1,000				366,000				84.4
											7,301,000
	Product		Settlement	Derivative		Notional Daily				Total Notional				Average
			Period	Instrument		Volume				Volume				Fixed Prices
						(Bbls)				(Bbls)				per Bbl
	NGL-Ethane		2014	Swap			4,500				1,642,500			$	13.21
	NGL-Propane		2014	Swap			2,785				1,016,525				44.71
	NGL-Isobutane		2014	Swap			930				339,450				61.26
	NGL-Normal Butane		2014	Swap			875				319,375				60.29
	NGL-Pentanes Plus		2014	Swap			910				332,150				84.97
	NGL-Ethane		2015	Swap			2,500				912,500				11.59
	NGL-Propane		2015	Swap			1,250				456,250				43.26
	NGL-Isobutane		2015	Swap			450				164,250				53.76
	NGL-Normal Butane		2015	Swap			400				146,000				53.76
											5,329,000
	Product		Settlement	Derivative		Notional Daily				Total Notional				Average		Average
			Period	Instrument		Volume				Volume				Floor/Fixed Prices		Ceiling Prices
						(MMBtu)				(MMBtu)				per MMBtu		per MMBtu
	Natural gas		2014	Costless Collar			50,000				18,250,000			$	3.6	$	4.94
	Natural gas		2015	Costless Collar			50,000				18,250,000				3.6		5.04
	Natural gas		2014	Swap			30,000				10,950,000				4.07
	Natural gas		2015	Swap			40,000				14,600,000				4.18
	Natural gas		2016	Swap			10,000				3,660,000				4.03
											65,710,000
	The Company’s derivative instruments are with counterparties who are lenders under the Company’s Credit Facility. This practice allows the Company to satisfy any need for margin obligations resulting from an adverse change in the fair market value of its derivative contracts with the collateral securing its Credit Facility, thus eliminating the need for independent collateral postings. The Company’s ability to continue satisfying any applicable margin requirements in this manner may be subject to change as described in Items 1 and 2. Business and Properties – Government Regulation. As of December 31, 2013, the Company had no deposits for collateral regarding commodity derivative positions.
	Discontinuance of Hedge Accounting
	Effective January 1, 2012, the Company elected to de-designate all commodity contracts previously designated as cash flow hedges as of December 31, 2011, and elected to discontinue hedge accounting prospectively. Accumulated other comprehensive income included $2.6 million ($1.6 million after tax) of unrealized net gains, representing the mark-to-market value of the Company’s cash flow hedges as of December 31, 2011. As a result of discontinuing hedge accounting, the mark-to-market values included in Accumulated other comprehensive income as of the de-designation date were frozen and were reclassified into earnings as the underlying hedged transactions affected earnings. For the years ended December 31, 2013 and 2012, the Company reclassified unrealized net losses of $0.1 million and unrealized net gains of $2.7 million, respectively, into earnings from Accumulated other comprehensive income. As of December 31, 2013, all frozen mark-to-market values included in Accumulated other comprehensive have been reclassified into earnings.
	With the election to de-designate hedging instruments, all of the Company’s derivative instruments continue to be recorded at fair value with unrealized gains and losses recognized immediately in earnings rather than in Accumulated other comprehensive income. These mark-to-market adjustments produce a degree of earnings volatility that can be significant from period to period, but such adjustments had no cash flow impact in the current period. The cash flow impact occurs upon settlement of the underlying contract.
	Additional Disclosures about Derivative Instruments
	Authoritative derivative guidance requires companies to recognize all derivative instruments as either assets or liabilities at fair value in the Company’s financial statements. The following table sets forth information on the location and amounts of the Company’s derivative instrument fair values in the Consolidated Balance Sheet as of December 31, 2013 and 2012, respectively:
				Asset (Liability) Fair Value
	Commodity derivative contracts		Location on Consolidated Balance Sheet	December 31, 2013				December 31, 2012
				(in thousands)
	Oil		Derivative instruments—current assets	$	1,299			$	564
	Oil		Derivative instruments—non-current assets		2,117				3,329
	Oil		Derivative instruments—current liabilities		(5,629	)			—
	NGL		Derivative instruments—current assets		2,834				8,361
	NGL		Derivative instruments—non-current assets		(129	)			3,534
	NGL		Derivative instruments—current liabilities		461				—
	NGL		Derivative instruments—non-current liabilities		(433	)			(563	)
	Natural gas		Derivative instruments—current assets		174				5,512
	Natural gas		Derivative instruments—non-current assets		3,470				(73	)
	Natural gas		Derivative instruments—current liabilities		255				—
	Total derivative fair value, net, not designated as hedging instruments			$	4,419			$	20,664
	The following table sets forth information on the location and amounts of derivative gains and losses in the Consolidated Statement of Operations for the years ended December 31, 2013, 2012 and 2011, respectively:
	Location on Consolidated		Description of Gain (Loss)	December 31,
	Statement of Operations			2013				2012				2011
				(in thousands)
	Oil sales		Loss reclassified from Accumulated OCI	$	—			$	—			$	(2,149	)
	NGL sales		Loss reclassified from Accumulated OCI		—				—				(10,190	)
	Natural gas sales		Gain reclassified from Accumulated OCI		—				—				18,751
	Natural gas sales (1)		Gain recognized in income		—				—				11,018
	Derivative instruments		Gain recognized in income		9,250				20,883				—
			Realized gain recognized in income	$	9,250			$	20,883			$	17,430
Derivative instruments (2)		(Loss) gain recognized in income due to changes in fair value	$	(16,245	)		$	16,999			$	1,233
Derivative instruments		(Loss) gain reclassified from Accumulated OCI		(100	)			2,663				—
		Unrealized (loss) gain recognized in income	$	(16,345	)		$	19,662			$	1,233
		Total commodity derivative (loss) gain recognized in income	$	(7,095	)		$	40,545			$	18,663
-1	For 2011, the amount represents the realized gains associated with the 2011 termination of derivatives used to hedge production from the Company’s divested DJ Basin and Sacramento Basin properties.
-2	For 2011, the amount represents the unrealized gain associated with the change in fair value of the Company’s crude oil basis and NYMEX roll swaps.
As a result of the Company’s election to de-designate all commodity contracts that were previously designated as cash flow hedges as of December 31, 2011 and to discontinue hedge accounting prospectively, the Company recognized no gain or loss in Accumulated other comprehensive income for the years ended December 31, 2013 and 2012. The Company recognized unrealized losses of $2.0 million in Accumulated other comprehensive income for the year ended December 31, 2011.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	(7) Fair Value Measurements
	The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company measures its non-financial assets and liabilities, such as asset retirement obligations and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. As none of the Company’s non-financial assets and liabilities were impaired during the year ended December 31, 2013, and because the Company had no other material assets or liabilities reported at fair value on a non-recurring basis, no additional disclosures are provided as of December 31, 2013.
	As defined in the FASB’s guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.
	The FASB’s guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are as follows:
		•		“Level 1” inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.
		•		“Level 2” inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.
		•		“Level 3” inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.
	As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities along with their placement within the fair value hierarchy levels. The Company determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes any transfers at the end of the reporting period.
	The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012.
			Fair value as of December 31, 2013
			Level 1			Level 2			Level 3			Netting (1)			Total
			(In thousands)
	Assets:
	Money market funds		$	—		$	1,035		$	—		$	—		$	1,035
	Commodity derivative contracts			—			—			21,675			(11,910	)		9,765
	Liabilities:
	Commodity derivative contracts			—			—			(17,256	)		11,910			(5,346	)
	Total fair value		$	—		$	1,035		$	4,419		$	—		$	5,454
			Fair value as of December 31, 2012
			Level 1			Level 2			Level 3			Netting (1)			Total
			(In thousands)
	Assets:
	Money market funds		$	—		$	1,035		$	—		$	—		$	1,035
	Commodity derivative contracts			—			—			44,036			(22,809	)		21,227
	Liabilities:
	Commodity derivative contracts			—			—			(23,372	)		22,809			(563	)
	Total fair value		$	—		$	1,035		$	20,664		$	—		$	21,699
	-1	Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle. No margin or collateral balances are deposited with counterparties and as such, gross amounts are offset to determine the net amounts presented in the Consolidated Balance Sheet.
	The Company’s Level 3 instruments include commodity derivative contracts for which fair value is determined by a third-party provider. Although the Company compares the fair values derived from the third-party provider with its counterparties, the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments and does not have access to the specific valuation models or certain inputs used by its third-party provider or counterparties. Therefore, these commodity derivative contracts are classified as Level 3 instruments.
	The following table presents a range of the unobservable inputs provided by our third-party provider utilized in the fair value measurements of the Company’s assets and liabilities classified as Level 3 instruments as of December 31, 2013 (in thousands):
									Range						Weighted
	Level 3 Instrument		Asset (Liability)			Valuation Technique		Unobservable Input	Minimum			Maximum			Average
	Oil swaps			(5,297	)	Discounted cash flow		Forward price curve-swaps	$	91.67		$	98.52		$	95.58
	Oil swaps			2,117		Discounted cash flow		Forward price curve-swaps		81.93			90.9			87.61
	Oil costless collars			967		Option model		Forward price curve- costless collar option value		(1.39	)		3.62			0.88
	NGL swaps			5,764		Discounted cash flow		Forward price curve-swaps		0.27			1.4			0.58
	NGL swaps			(3,031	)	Discounted cash flow		Forward price curve-swaps		0.28			2.13			0.97
	Natural gas swaps			1,984		Discounted cash flow		Forward price curve-swaps		3.86			4.4			4.04
	Natural gas swaps			(100	)	Discounted cash flow		Forward price curve-swaps		3.95			4.34			4.08
	Natural gas costless collars			2,015		Option model		Forward price curve-costless collar option value		(0.26	)		0.31			0.06
	Total		$	4,419
	The determination of derivative fair values by the third-party provider incorporates a credit adjustment for nonperformance risk, including the credit standing of the counterparties involved, and the impact of the Company’s nonperformance risk on its liabilities. The Company recorded a downward adjustment to the fair value of its derivative instruments in the amount of $0.3 million as of December 31, 2013.
	The significant unobservable inputs for Level 3 derivative contracts include forward price curves and option values. Significant increases (decreases) in the quoted forward prices for commodities and option values generally lead to corresponding decreases (increases) in the fair value measurement of the Company’s oil, NGL and natural gas derivative contracts.
	The tables below present reconciliations of financial assets and liabilities classified as Level 3 in the fair value hierarchy during the indicated periods.
			Derivative Asset			Money Market Funds			Total
			(Liability)			Asset (Liability)
			(In thousands)
	Balance at December 31, 2011		$	3,665		$	1,035		$	4,700
	Total Gains or (Losses) (Realized or Unrealized):
	Included in Earnings			37,882			—			37,882
	Included in Other Comprehensive Income			—			—			—
	Purchases, Issuances and Settlements
	Settlements			(20,883	)		—			(20,883	)
	Purchases			—			—			—
	Transfers in and out of Level 3 (1)			—			(1,035	)		(1,035	)
	Balance at December 31, 2012		$	20,664		$	—		$	20,664
	Total Gains or (Losses) (Realized or Unrealized):
	Included in Earnings			(6,995	)		—			(6,995	)
	Included in Other Comprehensive Income			—			—			—
	Purchases, Issuances and Settlements
	Settlements			(9,250	)		—			(9,250	)
	Purchases			—			—			—
	Transfers in and out of Level 3			—			—			—
Balance at December 31, 2013		$	4,419		$	—		$	4,419
-1	The value related to the money market funds was transferred from Level 3 to Level 2 in 2012 as a result of the Company’s ability to obtain independent market-corroborated data.
Fair Value of Other Financial Instruments
All of the Company’s other financial instruments (excluding derivatives) are presented on the balance sheet at carrying value. As of December 31, 2013, the carrying value of cash and cash equivalents (excluding money market funds), other current assets and current liabilities reported in the Consolidated Balance Sheet approximate fair value because of their short-term nature, and all such financial instruments are considered Level 1 instruments.
The Company’s debt consists of publicly traded Senior Notes (defined below) and borrowings under the Credit Facility (defined below). The fair values of the Company’s Senior Notes are based upon unadjusted quoted market prices and are considered Level 1 instruments. The Company’s borrowings under the Credit Facility approximate fair value as the interest rates are variable and reflective of current market rates, and are therefore considered a Level 1 instrument. As of December 31, 2013 and 2012, the estimated fair value of total debt was $1.5 billion and $432.5 million, respectively.

Accounts_Payable_Accrued_Liabi

Accounts Payable, Accrued Liabilities, Royalties and Other Payables	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Accounts Payable, Accrued Liabilities, Royalties and Other Payables	'
	(8) Accounts Payable, Accrued Liabilities, Royalties and Other Payables
	The Company’s accrued liabilities consist of the following:
		December 31,
		2013		2012
		(In thousands)
	Accrued capital costs	$	93,725	$	88,844
	Accounts payable		29,682		1,874
	Accrued reserve for commercial disputes		20,000		—
	Accrued payroll and employee incentive expense		10,516		10,436
	Accrued lease operating expense		12,064		9,605
	Accrued interest		15,025		4,582
	Asset retirement obligation		3,930		2,440
	Other		6,008		4,429
	Total Accounts payable and accrued liabilities	$	190,950	$	122,210
	At December 31, 2013, Royalties and other payables of $78.3 million includes $47.0 million of royalty revenues payable to landowners, $14.1 million of accrued transportation costs and $17.2 million of other operating liabilities.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	(9) Asset Retirement Obligations
	The following table provides a rollforward of the Company’s asset retirement obligations (“ARO”). Liabilities incurred during the period include additions to obligations and obligations incurred from acquisitions. Liabilities settled during the period include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Activity related to the Company’s ARO is as follows:
		For the Year Ended December 31,
		2013			2012			2011
		(In thousands)
	ARO at the beginning of the period	$	8,400		$	14,313		$	27,934
	Liabilities incurred during period		1,795			866			2,096
	Liabilities settled during period		(1,566	)		(8,538	)		(20,395	)
	Revision of previous estimate		3,850			935			3,454
	Accretion expense		578			824			1,224
	ARO at the end of the period	$	13,057		$	8,400		$	14,313
	As of December 31, 2013 and 2012, the current portion of ARO of $3.9 million and $2.4 million, respectively, was included in Accrued liabilities on the Consolidated Balance Sheet. The long-term portion of ARO of $9.2 million and $6.0 million as of December 31, 2013 and 2012, respectively, was included in Other long-term liabilities on the Consolidated Balance Sheet. The increase in ARO in 2013 was primarily due to the assumption of obligations to plug and abandon wells acquired in Reeves County, as well as the acceleration of the abandonment of certain non-core assets. In 2012 and 2011, ARO obligations related to divested properties were assumed by the purchasers and resulted in a reduction of the obligation during those periods.

Debt_and_Credit_Agreements

Debt and Credit Agreements	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Debt and Credit Agreements	'
	(10) Debt and Credit Agreements
	The Company’s long-term debt consists of the following:
		December 31,
		2013		2012
		(In thousands)
	Credit Facility	$	—	$	210,000
	9.500% Senior Notes due 2018		200,000		—
	5.625% Senior Notes due 2021		700,000		—
	5.875% Senior Notes due 2022		600,000		200,000
	Total debt	$	1,500,000	$	410,000
	Senior Secured Revolving Credit Facility. As of December 31, 2013, the Company had no borrowings outstanding with $800.0 million of available borrowing capacity under its Credit Facility. Amounts outstanding under the Credit Facility bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 1.50% to 2.50% and mature in April 2018. Additionally, the Company can borrow under the Credit Facility at the Alternative Base Rate (ABR) which is typically based upon the Prime Rate in effect on such day plus a margin of 0.5% to 1.5% depending on the Company’s utilization percentage. The weighted average borrowing rate for the year ended December 31, 2013 under the Credit Facility was 3.22%, inclusive of interest and commitment fees. Borrowings under the Credit Facility are collateralized by liens and security interests on substantially all of the Company’s assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 proved reserve value, a guaranty by all of the Company’s domestic subsidiaries and a pledge of 100% of the membership and limited partnership interests of the Company’s domestic subsidiaries. Collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. The Company is also subject to certain financial covenants, including the requirement to maintain a minimum current ratio of consolidated current assets, including the unused amount of available borrowing capacity, to consolidated current liabilities, excluding certain non-cash obligations, of not less than 1.0 to 1.0 as of the end of each fiscal quarter. The terms of the credit agreement also require the maintenance of a maximum leverage ratio of total debt to earnings before interest expense, income taxes and noncash items, such as depreciation, depletion, amortization and impairment, of not greater than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly after giving pro forma effect to acquisitions and divestitures. At December 31, 2013, the Company’s current ratio was 4.4 and leverage ratio was 2.5. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties.
	9.500% Senior Notes. On April 15, 2010, the Company issued and sold $200.0 million in aggregate principal amount of 9.500% Senior Notes due 2018 in a private offering. Interest is payable on the 9.500% Senior Notes semi-annually on April 15 and October 15. The 9.500% Senior Notes were issued under an indenture (the “9.500% Senior Notes Indenture”) with Wells Fargo Bank, National Association, as trustee. Under the indenture, the Company has the option to redeem the notes on or after April 15, 2014 at a price of $104.75. Provisions of the 9.500% Senior Notes Indenture limit the Company’s ability to, among other things, incur additional indebtedness; pay dividends on capital stock or purchase, repurchase, redeem, defease or retire capital stock or subordinated indebtedness; make investments; incur liens; create any consensual restriction on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The 9.500% Senior Notes Indenture also contains customary events of default. On September 21, 2010, the Company exchanged all of the privately placed 9.500% Senior Notes for registered 9.500% Senior Notes which contain terms substantially identical to the terms of the privately placed notes.
	5.625% Senior Notes. On May 2, 2013, the Company completed its public offering of $700.0 million in aggregate principal amount of 5.625% Senior Notes due 2021. Interest is payable on the 5.625% Senior Notes semi-annually on May 1 and November 1. The 5.625% Senior Notes were issued under an indenture (the “Base Indenture”), as supplemented by a first supplemental indenture with Wells Fargo Bank, National Association, as trustee, which contains covenants and events of default substantially similar to those in the 9.500% Senior Notes Indenture.
	5.875% Senior Notes. On November 15, 2013, the Company completed its public offering of $600 million aggregate principal amount of 5.875% Senior Notes due 2022. Interest is payable on the 5.875% Senior Notes semi-annually on June 1 and December 1. The 5.875% Senior Notes were issued under the Base Indenture, as supplemented by a second supplemental indenture with Wells Fargo Bank, National Association, as trustee, which contains covenants and events of default substantially similar to those in the 9.500% Senior Notes Indenture.
	Second Lien Term Loan. The Company’s amended and restated term loan (the “Restated Term Loan”) of $20.0 million was prepaid in full on August 31, 2012. Outstanding fixed-rate borrowings under the Restated Term Loan bore interest at 13.75% and would have matured on October 2, 2012. The loan was collateralized by second priority liens on substantially all of the Company’s assets and upon prepayment, the second priority liens were released. In connection with the prepayment of the Restated Term Loan, $0.2 million of prepayment fees were incurred and have been reflected as a component of interest expense.
	Total Indebtedness. As of December 31, 2013, the Company had total outstanding borrowings of $1.5 billion, and for the year ended December 31, 2013 the Company’s weighted average borrowing rate was 5.99%. The Company does not have any debt that matures within the five years ending December 31, 2018 other than the 9.500% Senior Notes that become due in 2018.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	(11) Commitments and Contingencies
	Firm Oil and Natural Gas Transportation and Processing Commitments. The Company has commitments for the transportation and processing of its production in the Eagle Ford area and has an aggregate minimum commitment to deliver 6.1 MMBbls of oil by the end of 2017 and 367 million MMBtus of natural gas by the end of 2023. The Company is required to make periodic deficiency payments for any shortfalls in delivering the minimum volumes under these commitments. Currently, the Company has insufficient production to meet all of these contractual commitments. As the Company develops additional reserves in the Eagle Ford area, it anticipates exceeding its current minimum volume commitments and therefore intends to enter into additional transportation and processing commitments in the future. These future transportation and processing commitments could expose the Company to volume deficiency payments as it further develops its Eagle Ford assets. As of December 31, 2013, the Company has accrued deficiency fees of $7.8 million and expects to continue to accrue deficiency fees under its commitments. Future obligations under firm oil and natural gas transportation and processing agreements as of December 31, 2013 are as follows:
		December 31, 2013
		(In thousands)
	2014		34,486
	2015		34,313
	2016		33,844
	2017		33,388
	2018		29,839
	Thereafter		104,088
	Total future obligations	$	269,958
	Drilling Rig and Completion Services Commitments. Drilling rig and completion services commitments represent obligations with certain contractors to execute the Company’s Eagle Ford and Permian Basin drilling programs, and payments under these commitments are accounted for as capital additions to oil and natural gas properties. As of December 31, 2013, the Company had two outstanding drilling rig commitments with a term greater than one year that will expire in 2015, and minimum contractual commitments due in the next twelve months are $19.8 million. As of December 31, 2013, the Company’s minimum contractual commitments due in the next twelve months for completion services agreements for the stimulation, cementing and delivery of drilling fluids were $14.8 million.
	Lease Obligations and Other Commitments. The Company has operating leases for office space and other property and equipment. The Company incurred rental expense of $7.3 million, $5.7 million and $3.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.
	Future minimum annual rental commitments under non-cancelable leases at December 31, 2013 were as follows:
		December 31, 2013
		(In thousands)
	2014	$	19,148
	2015		5,132
	2016		3,736
	2017		3,804
	2018		3,872
	Thereafter		19,823
		$	55,515
	Contingencies. The Company is party to various legal and regulatory proceedings and commercial disputes arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and in the event of a negative outcome as to any proceeding, the liability the Company may ultimately incur with respect to any such proceeding may be in excess of amounts currently accrued, if any. After considering the Company’s available insurance and, to the extent applicable, that of third parties, and the performance of contractual defense and indemnity rights and obligations, where applicable, the Company does not believe any such matter will have a material adverse effect on its financial position, results of operations or cash flows.
	Commercial Disputes. In the fourth quarter of 2013, the Company recorded a reserve of $20.5 million related to two commercial disputes, which is included in Reserve for commercial disputes in the Consolidated Statement of Operations for the year ended December 31, 2013. One commercial dispute was settled in the fourth quarter of 2013, and the other is expected to be settled in the first quarter of 2014.

StockBased_Compensation_and_Em

Stock-Based Compensation and Employee Benefits	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Stock-Based Compensation and Employee Benefits	'
	(12) Stock-Based Compensation and Employee Benefits
	Stock-based compensation expense includes the expense associated with restricted stock granted to employees and directors and the expense associated with the Performance Share Units (“PSUs”) granted to management. As of the indicated dates, stock-based compensation expense consisted of the following:
			Year Ended December 31,
			2013			2012			2011
			(in thousands)
	Total stock-based compensation expense		$	11,471		$	18,835		$	29,676
	Capitalized in oil and gas properties			(492	)		(296	)		(666	)
	Net stock-based compensation expense		$	10,979		$	18,539		$	29,010
	For the years ended December 31, 2013, 2012 and 2011, the Company had an associated tax benefit of $3.0 million, $2.8 million and $10.6 million, respectively, related to stock-based compensation.
	Long-Term Incentive Plans
	In July 2005, the Board of Directors adopted the Rosetta 2005 Long-Term Incentive Plan (the “2005 Plan”) under which stock was granted to employees, officers and directors of the Company. The 2005 Plan allowed for the granting of stock awards, stock options, restricted stock, restricted stock units, stock appreciation rights, performance awards and other incentive awards. As approved by the shareholders in 2008, the 2005 Plan allowed for a maximum of 4,950,000 shares to be granted, plus any shares that became available under the 2005 Plan for any reason other than exercise, such as shares traded for related tax withholding liabilities. The 2005 Plan was replaced by the 2013 Long-Term Incentive Plan (the “2013 Plan”) by vote of the Company’s shareholders in May 2013. No new grants are to be made from the 2005 Plan, although the Company will settle awards, options and PSUs made under the 2005 Plan as they vest.
	The 2013 Plan allows for the granting of stock options, stock awards, restricted stock, restricted stock units, stock appreciation rights, performance awards, and other incentive awards to employees, non-employee directors and other service providers who are in a position to make a significant contribution to the success of the Company. The maximum number of shares available for grant under the 2013 Plan is 3,600,000 shares, with any shares from the 2005 Plan that are forfeited, cancelled or expire added to the shares authorized for issuance under the 2013 Plan. Shares may not be returned to the 2013 Plan for reissuance that are tendered in payment of an option exercise price, or that are withheld to satisfy tax obligations. The maximum number of shares of common stock available for the grant of awards under the 2013 Plan to any one participant is (i) 500,000 shares during the fiscal year in which the participant begins work for Rosetta and (ii) 300,000 shares during each fiscal year thereafter.
	Stock Options
	Prior to 2010, the Company granted stock options under the Plan, which generally expire ten years from the date of grant. The exercise price of the option could not be less than the fair market value per share of the Company’s common stock on the grant date and the majority of options vested over a three-year period. During the years ended December 31, 2013, 2012 and 2011, no options were granted to employees, officers or directors of the Company and all options granted prior to 2011 under the Plan have vested. Compensation expense was recognized ratably over the requisite service period.
	The following table summarizes information related to outstanding and exercisable options held by the Company’s employees and directors at December 31, 2013:
			Shares			Weighted Average			Weighted Average			Aggregate Intrinsic
						Exercise Price			Remaining			Value
						Per Share			Contractual Term			(In thousands) (1)
									(In years)
	Outstanding at December 31, 2011			580,513		$	13.48
	Granted			—			—
	Exercised			(69,862	)		13.21
	Forfeited			—			—
	Outstanding at December 31, 2012			510,651		$	13.52
	Granted			—			—
	Exercised			(379,145	)		13.08
	Forfeited			—			—
	Outstanding at December 31, 2013			131,506		$	14.79
	Options vested and exercisable at December 31, 2013			131,506		$	14.79			3.91		$	4,302
	-1	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock, at the indicated date, exceeds the exercise price of the option.
	Stock-based compensation expense recorded for stock option awards for the years ended December 31, 2012 and 2011 was less than $0.1 million and $0.4 million, respectively. As of December 31, 2013, the Company has no unrecognized expense because all outstanding stock options have vested.
	The total intrinsic value of options exercised during the years ended December 31, 2013, 2012 and 2011 was $13.4 million, $2.3 million and $7.1 million, respectively.
	Restricted Stock
	The Company has granted restricted stock to employees and directors under the Plan. The majority of the Company’s restricted stock grants vest over a three-year period. The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite service period. The Company has assumed an annual forfeiture rate of 10% for these awards based on the Company’s history for this type of award to various employee groups.
	The following table summarizes information related to restricted stock held by the Company’s employees and directors at December 31, 2013:
			Shares			Weighted
						Average Grant
						Date Fair Value
	Non-vested shares outstanding at December 31, 2011			542,222		$	23.43
	Granted			267,377			47.33
	Lapse of restrictions			(445,508	)		25.82
	Forfeited			(34,977	)		41.07
	Non-vested shares outstanding at December 31, 2012			329,114		$	37.76
	Granted			584,184			49.18
	Lapse of restrictions			(457,164	)		43.6
	Forfeited			(81,285	)		44.59
	Non-vested shares outstanding at December 31, 2013			374,849		$	46.94
	The fair value of awards vested for the year ended December 31, 2013 was $22.7 million. Stock-based compensation expense recorded for restricted stock awards for the years ended December 31, 2013, 2012 and 2011 was $6.7 million, $7.4 million and $4.9 million, respectively. Unrecognized expense as of December 31, 2013 for all outstanding restricted stock awards was $9.7 million and will be recognized over a weighted average period of 1.74 years.
	Performance Share Units
	The Company’s Compensation Committee of the Board of Directors agreed to allocate a portion of the long-term incentive grants to executives as PSUs. The PSUs are payable, at the Company’s option, either in shares of common stock or as a cash payment equivalent to the fair market value of a share of common stock at settlement based on the achievement of performance metrics or market conditions at the end of a three-year performance period. The number of shares vested or equivalent cash payment can range from 0% to 200% of the targeted amount as determined by the Compensation Committee. None of these PSUs have voting rights and they may be vested solely at the discretion of the Board of Directors. Any PSUs not vested by the Board at the end of a performance period will expire.
	As discussed in Note 2, stock-based compensation expense for PSUs is measured and adjusted quarterly until settlement occurs, based on Company performance, quarter-end closing common stock prices and the Board’s anticipated vesting percentage. For the years ended December 31, 2013, 2012 and 2011, the Company recognized $4.7 million, $11.4 million and $23.7 million, respectively, of stock-based compensation expense associated with PSUs.
	The following table is a summary of PSU awards for the year ended December 31, 2013 assuming a 100% payout of the targeted amount:
			PSUs
	Unvested PSUs at December 31, 2012			284,307
	Granted			82,192
	Vested			(152,319	)
	Forfeited			(46,595	)
	Unvested PSUs at December 31, 2013			167,585
	On December 31, 2013, the three-year performance period ended for the 2011 PSUs, and in the first quarter of 2014, the Company vested the 2011 PSUs at 150% of the targeted amount, or a total of 75,275 units, in common stock. Stock-based compensation expense associated with the 2011 PSUs was recognized over the three-year performance period, and as of December 31, 2013, the Company had accrued $3.7 million as a component of Additional paid-in capital.
	On December 31, 2012, the three-year performance period ended for the 2010 PSUs and in the first quarter of 2013, the Company vested the 2010 PSUs at 175% of the targeted amount, or a total of 268,469 units, in common stock. Stock-based compensation expense associated with the 2010 PSUs was recognized over the three-year performance period, and as of December 31, 2012, the Company had accrued $12.2 million as a component of Additional paid-in capital.
	As of December 31, 2013, there were 118,379 unvested PSUs associated with the 2012 and 2013 grants. These awards are accounted for as equity-classified awards and are included as a component of Additional paid-in capital. Based on the Company’s closing common stock price of $48.04 at December 31, 2013, and assuming that the Board elects the maximum available payout of 200% for unvested 2012 and 2013 PSUs, unrecognized stock-based compensation expense related to these awards is approximately $9.1 million and would be recognized over the remaining respective performance periods. The Company’s total stock-based compensation expense will be measured and adjusted quarterly until settlement occurs, based on the Company’s performance, quarter-end closing common stock prices and the Board’s anticipated vesting percentage.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	(13) Income Taxes
	The Company’s income tax expense (benefit) consists of the following:
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Current:
	Federal	$	5,332		$	—		$	—
	State		4,376			—			(457	)
			9,708			—			(457	)
	Deferred:
	Federal		99,768			92,001			52,327
	State		1,108			3,903			3,843
			100,876			95,904			56,170
	Total income tax expense	$	110,584		$	95,904		$	55,713
	The differences between income taxes computed using the statutory federal income tax rate and that shown in the Consolidated Statement of Operations are summarized as follows:
		Year Ended December 31,
		2013						2012						2011
		(In thousands)			(%)			(In thousands)			(%)			(In thousands)			(%)
	US statutory rate	$	108,477			35	%	$	89,320			35	%	$	54,691			35	%
	State income tax, net of federal benefit		3,538			1.1	%		1,846			0.7	%		3,348			2.2	%
	Non-deductible permanent items		1,137			0.4	%		4,197			1.6	%		677			0.4	%
	Valuation allowance		(15	)		(0.0	%)		954			0.4	%		(2,262	)		(1.4	%)
	Other, net		(2,553	)		(0.8	%)		(413	)		(0.1	%)		(741	)		(0.5	%)
	Total tax expense	$	110,584			35.7	%	$	95,904			37.6	%	$	55,713			35.7	%
	The effective tax rate in all periods is the result of earnings in various domestic tax jurisdictions that apply to a broad range of income tax rates. The provision for income taxes differs from the tax computed at the federal statutory income tax rate primarily due to the impact of state income taxes and the deductibility of certain incentive compensation. Future effective tax rates could be adversely affected if unfavorable changes in tax laws and regulations occur, or if the Company experiences future adverse determinations by taxing authorities.
	The components of deferred tax assets and liabilities are as follows:
		December 31,
		2013			2012
		(In thousands)
	Deferred income tax assets:
	Net operating loss carryforwards	$	119,794		$	194,259
	Stock-based compensation		2,001			3,223
	Other		13,737			4,083
	Gross deferred income tax assets	$	135,532		$	201,565
	Valuation allowance		(5,235	)		(5,250	)
	Net deferred income tax assets	$	130,297		$	196,315
	Deferred income tax liabilities:
	Oil and gas properties basis differences		(237,220	)		(198,734	)
	Derivative financial instruments		(1,508	)		(7,356	)
	Deferred income tax liability	$	(238,728	)	$	(206,090	)
	Net deferred income tax liability	$	(108,431	)	$	(9,775	)
	As of December 31, 2013, the total net operating loss (NOL) carryforward consists of $347.0 million of federal NOL carryforwards, which expire between 2029 and 2032, and $105.1 million of state NOL carryforwards, which expire primarily between 2014 and 2032. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be “more likely than not.” When the future utilization of some portion of the carryforward is determined not to be “more likely than not,” a valuation allowance is provided to reduce the recorded tax benefits from such assets. Management believes that the Company’s taxable temporary differences and future taxable income will more likely than not be sufficient to utilize all of its federal tax carryforwards prior to their expiration.
	However, in connection with the asset divestitures in 2010, 2011 and 2012, the Company concluded that it is more likely than not that the NOLs and other deferred tax assets for the states impacted by these divestitures will not be realized. Therefore, valuation allowances were established for these items as well as state NOLs in jurisdictions in which the Company previously operated but has since divested of its operating assets. Annually, changes in the Company’s valuation allowance are made to reflect revised estimates of the utilization of state deferred tax assets. The Company will continue to assess the need for a valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.
	The rollforward of our deferred tax asset valuation allowance is as follows:
		Year Ended December 31,
		2013			2012			2011
		(in thousands)
	Balance at the beginning of the year	$	5,250		$	4,296		$	6,558
	Change to provision for income taxes		(15	)		954			(2,262	)
	Balance at the end of the year	$	5,235		$	5,250		$	4,296
	Pursuant to authoritative guidance, the Company’s $119.8 million deferred tax asset related to NOL carryforwards is net of $7.0 million of unrealized excess tax benefits related to $20.0 million of stock-based compensation which will be recognized in Additional paid-in capital upon utilization of the Company’s NOL carryforward.
	Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2013, the Company had no unrecognized tax benefits. The Company files income tax returns in the U.S. and in various state jurisdictions. With few exceptions, the Company is subject to U.S. federal, state and local income tax examinations by tax authorities for tax periods 2005 and forward.
	Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the Consolidated Statement of Operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits.

Equity

Equity	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Equity	'
	(14) Equity
	Earnings per Share. Basic earnings per share (“EPS”) is calculated by dividing income (the numerator) by the weighted-average number of shares of common stock (excluding unvested restricted stock awards) outstanding during the period (the denominator). Diluted EPS incorporates the dilutive impact of outstanding stock options and unvested restricted stock awards using the treasury stock method.
	The following is a calculation of basic and diluted weighted average shares outstanding:
		Year Ended December 31,
		2013		2012		2011
		(In thousands)
	Basic weighted average number of shares outstanding		58,571		52,496		51,996
	Dilution effect of stock option and restricted shares at the end of the period		259		391		620
	Diluted weighted average number of shares outstanding		58,830		52,887		52,616
	Anti-dilutive stock awards and shares		2		1		4
	Common Stock Offering. On April 23, 2013, the Company completed its public offering of 7,000,000 shares of common stock at a price to the public of $42.50 per share for net proceeds of approximately $286.3 million ($40.80 per share, net of underwriting discounts and commissions), including offering expenses and reimbursements by the underwriters of certain expenses incurred in connection with the offering. The Company also received net proceeds of approximately $43.0 million in connection with the underwriters’ full exercise of their over-allotment option to purchase 1,050,000 additional shares of common stock, which closed on April 29, 2013.

Operating_Segments

Operating Segments	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Operating Segments	'
	(15) Operating Segments
	The Company has one reportable segment, oil and natural gas exploration and production, as determined in accordance with authoritative guidance regarding disclosure about segments of an enterprise and related information. All of the Company’s costs are included in one cost pool because all of the Company’s operations are located in the United States.
	Geographic Area Information
	Geographic revenue information below is based on the physical location of the assets at the end of each period. Certain amounts in prior periods have been reclassified to conform to the current presentation.
			Year Ended December 31,
			2013 (1)		2012 (1)		2011 (1)
			(In thousands)
	Oil, NGL, and Natural Gas Revenue
	Eagle Ford		$	764,251	$	561,143	$	354,741
	Permian			52,603		—		—
	Other (2)			4,259		11,811		72,796
	Total		$	821,113	$	572,954	$	427,537
	-1	Excludes the effects of derivative losses of $7.1 million and gains of $40.5 million and $18.7 million, respectively, for the years ended December 31, 2013, 2012 and 2011.
	-2	The decline in revenues from 2011 to 2013 was due to the Company’s asset divestitures and suspension of capital programs in areas that produced primarily from dry gas reservoirs. See Note 4 – Property and Equipment.
	Major Customers
	In 2013, two customers, Shell Trading (US) Company and Enterprise Products Operating LLC, accounted for approximately 23% and 21%, respectively, of the Company’s consolidated revenue, excluding the effects of derivative instruments.
	In 2012, four customers, Enterprise Products Operating LLC, Shell Trading (US) Company, Exxon Mobil Corporation and Calpine Energy Services, accounted for approximately 21%, 21%, 13% and 12%, respectively, of the Company’s consolidated revenue, excluding the effects of derivative instruments.
	In 2011, four customers, Shell Trading (US) Company, Calpine Energy Services, Regency Gas Services, LLC, and Exxon Mobil Corporation, accounted for approximately 25%, 24%, 17% and 10%, respectively, of the Company’s consolidated revenue, excluding the effects of derivative instruments.
	No other customers accounted for more than 10% of the Company’s consolidated revenue, excluding the effects of derivative instruments, for the years ended December 31, 2013, 2012 and 2011. The loss of any one of these customers would not have a material adverse effect on the Company’s operations as management believes other purchasers are available in the Company’s areas of operations.

Guarantor_Subsidiaries

Guarantor Subsidiaries	12 Months Ended
	Dec. 31, 2013
Guarantees [Abstract]	'
Guarantor Subsidiaries	'
	(16) Guarantor Subsidiaries
	The Company’s Senior Notes are guaranteed by its wholly owned subsidiaries. Rosetta Resources Inc., as the parent company, has no independent assets or operations. The guarantees are full and unconditional and joint and several. In addition, there are no restrictions on the ability of the Company to obtain funds from its subsidiaries by dividend or loan. Finally, none of the Company’s subsidiaries has restricted assets that exceed 25% of net assets as of December 31, 2013, which may not be transferred to the Company in the form of loans, advances or cash dividends by the subsidiaries without the consent of a third party.

Supplemental_Oil_and_Gas_Discl

Supplemental Oil and Gas Disclosures	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Supplemental Oil and Gas Disclosures	'
	Supplemental Oil and Gas Disclosures
	(Unaudited)
	The following disclosures for the Company are made in accordance with authoritative guidance regarding disclosures about oil and natural gas producing activities. Users of this information should be aware that the process of estimating quantities of proved, proved developed and proved undeveloped crude oil, NGL and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reported reserve estimates represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
	Proved reserves are those quantities of oil, NGL and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate.
	Proved developed reserves are proved reserves that can be expected to be recovered (a) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (b) through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well.
	Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
	Estimates of proved developed and proved undeveloped reserves as of December 31, 2013 are based on estimates made by the Company’s engineers and audited by the Company’s independent engineers, Netherland, Sewell & Associates, Inc. (“NSAI”). The Company’s primary reserves estimator is the Company’s Vice President of Corporate Reserves and Technical Services, who has over 36 years of experience in the petroleum industry spent almost entirely in the evaluation of reserves and income attributable to oil and natural gas properties. He holds a Bachelor of Science in Mechanical Engineering from Texas A&M University. He is a licensed Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers. The Company makes representations to the independent engineers that it has provided all relevant operating data and documents, and in turn the Company reviews these reserve reports provided by the independent engineers to ensure completeness and accuracy. NSAI performs petroleum engineering consulting services under the Texas Board of Professional Engineers. NSAI’s President and Chief Operating Officer is a licensed professional engineer with more than 35 years of experience, and the engineer and geologist charged with the Company’s audit are both licensed professionals with more than 50 years of experience combined.
	The preparation of the Company’s reserve estimates are completed in accordance with the Company’s prescribed internal control procedures, which include verification of input data into a reserve forecasting and economic evaluation software, as well as management review. The technical persons responsible for preparing the reserve estimates meet the required standards regarding qualifications and objectivity. Additionally, the Company engages qualified, independent reservoir engineers to audit the internally generated reserve report in accordance with all SEC reserve estimation guidelines.
	A twelve-month first-day-of-the-month historical average price as of December 31, 2013, 2012 and 2011 was used for future sales of oil and natural gas. Future operating costs, production and ad valorem taxes and capital costs were based on current costs as of each year end, with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the standardized measure should not be construed as the current market value of proved oil, NGL and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in oil, NGL and natural gas prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risk.
	Capitalized Costs Relating to Oil, NGL and Gas Producing Activities
	The following table sets forth the capitalized costs relating to the Company’s oil, NGL and natural gas producing activities at December 31, 2013, 2012 and 2011:
			2013			2012			2011
			(In thousands)
	Proved properties		$	3,951,397		$	2,829,431		$	2,297,312
	Unproved properties			755,438			95,540			141,016
	Total			4,706,835			2,924,971			2,438,328
	Less: Accumulated depletion			(2,003,893	)		(1,797,203	)		(1,649,403	)
	Net capitalized costs		$	2,702,942		$	1,127,768		$	788,925
	Net capitalized costs include asset retirement costs of $22.2 million, $15.1 million and $18.0 million as of December 31, 2013, 2012 and 2011, respectively.
	Costs Incurred in Oil, NGL and Natural Gas Property Acquisition, Exploration and Development Activities
	The following table sets forth costs incurred related to the Company’s oil, NGL and natural gas producing activities for the years ended December 31, 2013, 2012 and 2011:
			Year Ended December 31,
			2013			2012			2011
			(In thousands)
	Acquisition costs
	Proved		$	290,273		$	—		$	—
	Unproved			672,634			18,753			10,605
	Subtotal			962,907			18,753			10,605
	Exploration costs			534,881			93,542			98,781
	Development costs			338,882			531,957			369,865
	Total		$	1,836,670		$	644,252		$	479,251
	Results of Operations for Oil, NGL and Natural Gas Producing Activities
			Year Ended December 31,
			2013 (1)			2012 (1)			2011 (1)
			(In thousands)
	Oil, NGL and natural gas producing revenues		$	821,113		$	572,954		$	427,537
	Production costs			155,749			110,977			69,289
	Depreciation, depletion and amortization			218,571			154,223			123,244
	Income before income taxes			446,793			307,754			235,004
	Income tax provision			159,505			115,716			83,896
	Results of operations		$	287,288		$	192,038		$	151,108
	-1	Excludes the effects of derivative losses of $7.1 million, and gains of $40.5 million and $18.7 million, respectively, for the years ended December 31, 2013, 2012 and 2011.
	The results of operations for oil, NGL and natural gas producing activities exclude other income and expenses, interest charges and general and administrative expenses. Sales are based on market prices.
	Net Proved and Proved Developed Reserve Summary
	The following table provides a rollforward of the total proved reserves (all within the United States) for the years ended December 31, 2013, 2012 and 2011, respectively, as well as proved developed and proved undeveloped reserves at the end of each respective year.
			Oil			Natural gas			Natural gas			Equivalents
			(MBbls) (1)			liquids			(MMcf)			(MBoe)
						(MBbls)
	Net proved reserves at December 31, 2010			12,401			19,326			288,927			79,819
	Revisions of previous estimates (2)			4,839			7,192			60,712			22,212
	Purchases in place			—			—			—			—
	Extensions, discoveries and other additions (3)			21,027			26,344			210,292			82,420
	Sales in place			(34	)		—			(80,582	)		(13,464	)
	Production			(1,863	)		(2,643	)		(33,393	)		(10,072	)
	Net proved reserves at December 31, 2011			36,370			50,219			445,956			160,915
	Revisions of previous estimates (4)			(4,947	)		4,923			(10,107	)		(1,709	)
	Purchases in place			70			104			744			298
	Extensions, discoveries and other additions (5)			16,737			22,440			158,788			65,641
	Sales in place			(309	)		(1,641	)		(52,075	)		(10,629	)
	Production			(3,497	)		(4,472	)		(33,853	)		(13,611	)
	Net proved reserves at December 31, 2012			44,424			71,573			509,453			200,905
	Revisions of previous estimates (6)			(8,945	)		(65	)		(9,580	)		(10,606	)
	Purchases in place (7)			10,972			5,857			36,523			22,916
Extensions, discoveries and other additions (8)			25,010			28,342			180,570			83,447
Sales in place			—			—			—			—
Production			(4,999	)		(6,398	)		(40,343	)		(18,121	)
Net proved reserves at December 31, 2013			66,462			99,309			676,623			278,541
Proved Developed Reserves
December 31, 2010			3,687			6,471			183,954			40,817
December 31, 2011			11,766			16,635			177,278			57,947
December 31, 2012			19,321			25,068			178,214			74,092
December 31, 2013			22,560			31,542			217,328			90,324
Proved Undeveloped Reserves
December 31, 2010			8,714			12,855			104,973			39,002
December 31, 2011			24,604			33,584			268,678			102,968
December 31, 2012			25,103			46,505			331,239			126,813
December 31, 2013			43,902			67,767			459,295			188,217
-1	Includes crude oil and condensate. As of December 31, 2013, 2012, 2011 and 2010, approximately 65%, 92%, 97%, and 95%, respectively, of our proved oil reserves consisted of condensate, which the Company defines as oil with an API gravity higher than 55 degrees.
-2	Upward revision of 22,212 MBoe resulting from positive performance revisions primarily due to an increase in the estimated ultimate recovery of hydrocarbons on 35 Gates Ranch wells. Twenty-two of these Gates Ranch wells have greater than 12 months of production history and some of these wells have been producing for over two years. The decline profiles on wells with significant production history indicate that the estimated ultimate recovery is much more likely to increase or remain constant than to decline.
-3	The Company added 82,420 MBoe in the Eagle Ford area by drilling and completing 13 wells and adding 91 proved undeveloped locations.
-4	The downward revision of 1,709 MBoe was primarily due to two factors in the Eagle Ford area. The first factor was a downward oil revision of 4,947 MBbls, partially offset by an upward NGL revision of 4,923 MBbls, which was due to condensate stabilization that is required before transportation of condensate to the market. The stabilization process separates NGLs from the Company’s oil production which resulted in a reclassification of some of the Company’s reserves from oil to NGLs. The second factor was a downward natural gas revision of 10,107 MMcf, which was due largely to a decrease in the twelve-month first-day-of-the-month historical average commodity price for natural gas from $4.12 per MMBtu in 2011 to $2.76 per MMBtu in 2012 and an increase in treating and transportation costs.
-5	The Company added 65,641 MBoe primarily in the Eagle Ford area by drilling and completing 37 wells and adding 54 proved undeveloped locations.
-6	The downward revision of 10,606 MBoe is primarily due to lower than expected condensate yields from the Company’s 2013 completions in the north central portion of Gates Ranch.
-7	The Company added 22,916 MBoe primarily due to the Permian Acquisition.
-8	The Company added 83,447 MBoe, of which 70,626 MBoe and 12,821 MBoe was from the Eagle Ford and Permian Basin areas, respectively. In the Eagle Ford area, the Company added reserves through the drilling and completion of 79 wells and the addition of 106 proved undeveloped locations. In the Permian Basin area, the Company added reserves through the drilling and completion of 30 wells and the addition of 84 proved undeveloped locations.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, NGL and Natural Gas Reserves
The following information has been developed utilizing procedures prescribed by authoritative guidance and based on oil, NGL and natural gas reserves and production volumes estimated by internal reserves engineers and audited by independent petroleum engineers. This information may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. In accordance with SEC requirements, the estimated discounted future net revenues from proved reserves are generally based on average first-day-of-the-month oil and natural gas prices in effect for the prior twelve months in 2013, 2012 and 2011 and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the average prices and costs as of the date of the estimate. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company’s oil and natural gas assets.
The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and natural gas producing activities.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s reserves for the years ended December 31, 2013, 2012 and 2011:
		Year Ended December 31, 2013
		Proved			Proved			Total
		Developed			Undeveloped
		(In millions)
Future cash inflows		$	3,826		$	7,770		$	11,596
Future production costs			(1,224	)		(2,188	)		(3,412	)
Future development costs			(20	)		(1,990	)		(2,010	)
Future income taxes			(641	)		(892	)		(1,533	)
Future net cash flows			1,941			2,700			4,641
Discount to present value at 10% annual rate			(982	)		(1,365	)		(2,347	)
Standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves		$	959		$	1,335		$	2,294
		Year Ended December 31, 2012
		Proved			Proved			Total
		Developed			Undeveloped
		(In millions)
Future cash inflows		$	3,239		$	5,013		$	8,252
Future production costs			(854	)		(1,227	)		(2,081	)
Future development costs			(8	)		(1,110	)		(1,118	)
Future income taxes			(652	)		(733	)		(1,385	)
Future net cash flows			1,725			1,943			3,668
Discount to present value at 10% annual rate			(859	)		(968	)		(1,827	)
Standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves		$	866		$	975		$	1,841
		Year Ended December 31, 2011
		Proved			Proved			Total
		Developed			Undeveloped
		(In millions)
Future cash inflows		$	2,527		$	4,765		$	7,292
Future production costs			(542	)		(816	)		(1,358	)
Future development costs			(18	)		(990	)		(1,008	)
Future income taxes			(584	)		(878	)		(1,462	)
Future net cash flows			1,383			2,081			3,464
Discount to present value at 10% annual rate			(702	)		(1,056	)		(1,758	)
Standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves		$	681		$	1,025		$	1,706
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2013, 2012 and 2011:
		Year ended December 31
		2013			2012			2011
		(in millions)
Standardized measure–beginning of year		$	1,841		$	1,706		$	697
Sales and transfers of crude oil, NGLs and natural gas produced, net of production costs			(665	)		(462	)		(358	)
Revisions to estimates of proved reserves:
Net changes in prices and production costs			(268	)		(591	)		39
Extensions, discoveries, additions and improved recovery, net of related costs			849			814			1,117
Development costs incurred			275			220			370
Changes in estimated future development costs			86			54			(26	)
Revisions of previous quantity estimates			(127	)		(12	)		357
Accretion of discount			244			229			143
Net change in income taxes			(113	)		(17	)		(549	)
Purchases of reserve in place			216			6			—
Sales of reserves in place			—			(104	)		(79	)
Changes in timing and other			(44	)		(2	)		(5	)
Standardized measure–end of year		$	2,294		$	1,841		$	1,706

Quarterly_Selected_Financial_D

Quarterly Selected Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Selected Financial Data (Unaudited)	'
	Quarterly Selected Financial Data
	(Unaudited)
	Summaries of the Company’s results of operations by quarter for the years ended 2013 and 2012 are as follows:
		2013
		First		Second		Third		Fourth
		Quarter		Quarter		Quarter		Quarter
		(In thousands, except per share data)
	Revenues	$	178,120	$	236,520	$	194,568	$	204,810
	Operating income		86,305		131,703		72,306		55,891
	Net income		53,480		75,352		41,025		29,495
	Basic earnings per share		1.01		1.28		0.67		0.48
	Diluted earnings per share		1.01		1.27		0.67		0.48
		2012
		First		Second		Third		Fourth
		Quarter		Quarter		Quarter		Quarter
		(In thousands, except per share data)
	Revenues	$	114,458	$	197,981	$	122,752	$	178,308
	Operating income		40,541		127,111		33,442		78,474
	Net income		22,297		76,969		17,689		42,340
	Basic earnings per share		0.43		1.47		0.34		0.81
	Diluted earnings per share		0.42		1.46		0.33		0.8

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Use of Estimates in Preparation of Financial Statements	'
	Use of Estimates in Preparation of Financial Statements
	The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, the outcome of pending litigation and environmental costs, stock-based compensation, valuation of derivative instruments, future development and abandonment costs, estimates related to certain oil, NGL and natural gas revenues and operating expenses, determination of the fair value of assets acquired and liabilities assumed and recording of goodwill and deferred taxes, if any, in connection with business combinations, and the estimates of proved oil, NGL and natural gas reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents
	The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
	With respect to the current market environment for liquidity and access to credit, the Company, through banks participating in its credit facility, has invested available cash in interest and non-interest bearing demand deposit accounts in those participating banks and in money market accounts and funds whose investments are limited to U.S. Government securities, securities backed by the U.S. Government, or securities of U.S. Government agencies. The Company has followed this policy and believes this is an appropriate approach for the investment of Company funds.
Allowance for Doubtful Accounts	'
	Allowance for Doubtful Accounts
	The Company regularly reviews all aged accounts receivables for collectability and establishes an allowance as necessary for individual customer balances. As of December 31, 2013 and 2012, the Company had no allowance for doubtful accounts.
Oil and Natural Gas Properties	'
	Oil and Natural Gas Properties
	The Company follows the full cost method of accounting whereby all costs incurred in acquiring, exploring and developing properties, including salaries, benefits and other internal costs directly attributable to these activities, are capitalized when incurred into cost centers that are established on a country-by-country basis. Such costs are amortized on a unit-of-production basis over reserves in the cost center in which they are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. In some cases, however, certain significant costs, such as those associated with unevaluated properties and significant development projects, are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and natural gas producing activities are regarded as integral to the acquisition, discovery and development of reserves that ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $7.2 million, $6.0 million and $7.0 million of internal costs for the years ended December 31, 2013, 2012 and 2011, respectively. Unevaluated costs are excluded from the full cost pool and are periodically evaluated for impairment. Upon evaluation or impairment, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally reflected in the full cost pool, unless a significant portion of the pool or reserves is sold causing a significant change in the relationship between capitalized costs and proved reserves, in which case a gain or loss is calculated and recognized in the Consolidated Statement of Operations.
	The Company assesses the impairment for oil and natural gas properties quarterly using a ceiling test to determine if impairment is necessary. This ceiling limits capitalized costs to the present value of estimated future cash flows from proved oil and natural gas reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage values) to the extent not included in oil and natural gas properties pursuant to authoritative guidance, and estimated future income taxes thereon.
	A ceiling test write-down is a charge to earnings and cannot be reinstated even if the cost ceiling increases at a subsequent reporting date. If required, a write-down would reduce earnings and impact shareholders’ equity in the period of occurrence and result in lower DD&A expense in the future.
Other Fixed Assets	'
	Other Fixed Assets
	Other fixed assets primarily include computer hardware and software, office leasehold, and furniture and fixtures, which are recorded at cost and depreciated on a straight-line basis over useful lives of five to seven years. Repair and maintenance costs are charged to expense as incurred while renewals and betterments are capitalized as additions to the related assets in the period incurred. Gains or losses from the disposal of other fixed assets are recorded in the period incurred. The net book value of other fixed assets that are retired or sold is charged to accumulated depreciation and the difference is recognized as a gain or loss in the Consolidated Statement of Operations in the period the retirement or sale transpires.
Future Development and Abandonment Costs	'
	Future Development and Abandonment Costs
	Future development costs include costs incurred to obtain access to proved reserves, such as drilling costs and the installation of production equipment, and such costs are included in the calculation of DD&A expense. Future abandonment costs include costs to plug and abandon wells, dismantle and relocate or dispose of our production platforms, gathering systems and related structures and restoration costs of land and seabed. The Company develops estimates of these costs for each of its properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. The Company reviews its assumptions and estimates of future development and future abandonment costs on an annual basis.
	The Company provides for future abandonment costs in accordance with authoritative guidance regarding the accounting for asset retirement obligations. A liability is recorded for the fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset.
Capitalized Interest	'
	Capitalized Interest
	The Company capitalizes interest on capital invested in projects related to unevaluated properties and significant development projects. As proved reserves are established or impairment determined, the related capitalized interest is included in costs subject to amortization. The Company capitalized interest of $28.3 million, $3.8 million, and $5.5 million in 2013, 2012 and 2011, respectively.
Fair Value of Financial Instruments	'
	Fair Value of Financial Instruments
	Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company’s financial assets and liabilities are measured at fair value on a recurring basis and non-financial assets and liabilities, such as asset retirement obligations and other property and equipment, are recognized at fair value on a non-recurring basis but at least annually. For non-financial assets and liabilities, the Company is required to disclose information that enables users to assess the inputs used to develop these measurements. Changes in fair value associated with both financial and non-financial assets and liabilities are recorded in the Consolidated Statement of Operations. See Note 7 – Fair Value Measurements.
Concentrations of Credit Risk	'
	Concentrations of Credit Risk
	Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of cash, accounts receivable and derivative instruments. The Company’s accounts receivable and derivative instruments are concentrated among entities engaged in the energy industry within the U.S. and financial institutions, respectively. The Company periodically assesses the financial condition of these entities and institutions and considers any possible credit risk to be minimal.
Debt Issuance Costs	'
	Debt Issuance Costs
	Costs incurred in connection with the Company’s Credit Facility, Restated Term Loan and Senior Notes (each as hereinafter defined in Note 10 – Debt and Credit Agreements) are recorded on the Company’s Consolidated Balance Sheet as Debt issuance costs. Such costs are amortized to interest expense over the term of the related debt using the effective interest method.
Derivative Instruments and Activities	'
	Derivative Instruments and Activities
	The Company utilizes various types of derivative instruments to manage commodity price risk, including fixed price swaps and costless collars. The Company does not enter into derivative agreements for trading or other speculative purposes and the fair value of derivative contracts is presented on a net basis where the right of offset is provided for in the counterparty agreements. Effective January 1, 2012, the Company elected to de-designate all of its commodity derivative contracts that had previously been designated as cash flow hedges as of December 31, 2011 and elected to discontinue hedge accounting prospectively. See Note 6 – Commodity Derivative Contracts for a more detailed discussion of derivative activities.
Environmental	'
	Environmental
	Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the cost can be reasonably estimated. There were no significant environmental liabilities as of December 31, 2013 or 2012.
Stock-Based Compensation	'
	Stock-Based Compensation
	Stock-based compensation cost for restricted stock is estimated at the grant date based on the award’s fair value, which is equal to the average high and low common stock price on the date of grant. Such fair value is recognized as expense over the requisite service period. Stock-based compensation cost for options is estimated at the grant date based on the award’s fair value as calculated using an option-pricing model. During the years ended December 31, 2013, 2012 and 2011, no options were granted to the Company’s employees, officers or directors and all options granted prior to 2011 have vested. Compensation expense was recognized ratably over the requisite service period.
	Stock-based compensation expense for performance share units (“PSUs”) is measured and adjusted quarterly until settlement occurs, based on Company performance, quarter-end closing common stock prices and the anticipated vesting percentage. Compensation expense for performance-based awards is recognized when it is probable that performance conditions will be achieved and such awards are expected to vest. The Compensation Committee of the Board of Directors retains discretion beyond the stated performance metrics to ensure it has the ability to reward a focus on behaviors that improve total shareholder return over the long-term and promote various corporate goals. The Compensation Committee has not adopted a policy that all compensation must be deductible for federal income tax purposes, and therefore the Company may make payments that are not fully deductible if it believes such payments are necessary to achieve corporate objectives and protect shareholder interests. See Note 12 – Stock-Based Compensation and Employee Benefits.
	Any excess tax benefit arising from the Company’s stock-based compensation plans is recognized as a credit to additional paid-in capital when realized and is calculated as the amount by which the tax effect of the tax deduction received exceeds the deferred tax asset associated with recorded stock-based compensation expense. Current authoritative guidance requires that cash flows resulting from tax deductions in excess of recorded compensation expense are recognized as financing activities.
Preferred Stock	'
	Preferred Stock
	The Company is authorized to issue 5,000,000 shares of preferred stock with preferences and rights as determined by the Company’s Board of Directors. As of December 31, 2013 and 2012, there were no shares of preferred stock outstanding.
Treasury Stock	'
	Treasury Stock
	The Company repurchases shares that are surrendered by employees and certain directors to pay tax withholding upon the vesting of restricted stock awards. These repurchases are not part of a publicly announced program to repurchase shares of the Company’s common stock, nor does the Company have a publicly announced program to repurchase shares of common stock. Treasury stock purchases are recorded at cost.
Revenue Recognition	'
	Revenue Recognition
	Oil, NGL and natural gas revenue from our interests in producing wells is recognized upon delivery and passage of title, using the sales method for gas imbalances, net of any royalty interests or other profit interests in the produced product. Under the sales method, if our gas imbalance (amount of production sold in excess of amount entitled) exceeds our portion of the estimated remaining recoverable reserves of the well, a liability is recorded. No receivables are recorded for those wells on which we have taken less than our ownership share of production, unless the amount taken by other parties exceeds the estimate of their remaining reserves. There were no significant gas imbalances at December 31, 2013 or 2012.
Income Taxes	'
	Income Taxes
	The Company uses the liability method of accounting for income taxes. Under this method, deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax basis of assets and liabilities. Income taxes are provided based on earnings reported for tax return purposes in addition to a provision for deferred income taxes and are measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
	Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not support the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.
Recent Accounting Developments	'
	Recent Accounting Developments
	The following recently issued accounting development has been applied for the current period.
	Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance to increase the prominence of items reported in other comprehensive income. This guidance requires an entity to present components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements of net income and comprehensive income. In February 2013, the FASB further clarified this guidance relating to the presentation of reclassification adjustments stating that an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income. The Company adopted the provisions of the initial guidance effective January 1, 2012 and the provisions of the February 2013 amendment effective January 1, 2013. See the Consolidated Statement of Comprehensive Income, Note 6 – Commodity Derivative Contracts and Note 12 – Stock-Based Compensation and Employee Benefits.

Accounts_Receivable_Tables

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2013
Receivables [Abstract]	'
Schedule of Accounts Receivable	'
	Accounts receivable consists of the following:
		December 31,
		2013		2012
		(In thousands)
	Oil, NGL and natural gas sales	$	96,576	$	84,533
	State severance tax refunds		19,157		16,269
	Joint interest billings		4,696		3,026
	Other		2,248		—
	Total	$	122,677	$	103,828

Property_and_Equipment_Tables

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Schedule of Total Property, Plant and Equipment	'
	The Company’s total property and equipment consists of the following:
		December 31,
		2013			2012
		(In thousands)
	Proved properties	$	3,951,397		$	2,829,431
	Unproved/unevaluated properties		755,438			95,540
	Gathering systems and compressor stations		168,730			104,978
	Other fixed assets		26,362			16,346
	Total		4,901,927			3,046,295
	Less: Accumulated depreciation, depletion and amortization		(2,020,879	)		(1,808,190	)
	Total property and equipment, net	$	2,881,048		$	1,238,105
Schedule of Consideration Paid for the Transactions of Asset Acquired and Liabilities Assumed	'
	The combined cash consideration paid for these transactions and the assets and liabilities recognized at the respective acquisition dates are shown in the table below.
		Total Purchase Price
		Allocation
		(in thousands)
	Cash consideration	$	953,242
	Fair value of assets acquired:
	Other fixed assets	$	600
	Oil and natural gas properties
	Proved properties		290,273
	Unproved/unevaluated properties		663,300
	Total assets acquired	$	954,173
	Fair value of liabilities assumed:
	Asset retirement obligations	$	931
	Net assets acquired	$	953,242
Schedule of Results of Operations at the Time of Transactions	'
	The pro forma information does not purport to represent what the Company’s results of operations would have been if such transactions had occurred on January 1, 2012.
		Year Ended December 31,
		2013			2012
		(In thousands, except per share and share data)
	Total revenues	$	846,560		$	671,780
	Net income		191,478			151,144
	Earnings per share:
	Basic	$	3.13		$	2.5
	Diluted	$	3.12		$	2.48
	Weighted average shares outstanding:
	Basic		61,081			60,546
	Diluted		61,339			60,937
Schedule of Capitalized Costs Excluded From DD&A	'
	Capitalized costs excluded from DD&A as of December 31, 2013 and 2012, all of which are located onshore in the U.S., are as follows by the year in which such costs were incurred:
		December 31, 2013
		Total			2013			2012		2011		Prior
		(In thousands)
	Development costs	$	129,812		$	129,812		$	—	$	—	$	—
	Exploration costs		15,459			8,445			7,014		—		—
	Acquisition cost of undeveloped acreage		584,137			565,330			4,485		5,170		9,152
	Capitalized interest		26,030			22,718			1,471		480		1,361
	Total capitalized costs excluded from DD&A	$	755,438		$	726,305		$	12,970	$	5,650	$	10,513
		31-Dec-12
		Total			2012			2011		2010		Prior
		(In thousands)
	Development costs	$	29,857		$	29,857		$	—	$	—	$	—
	Exploration costs		16,180			16,180			—		—		—
	Acquisition cost of undeveloped acreage		42,186			15,297			6,672		16,920		3,297
	Capitalized interest		7,317			3,309			2,064		1,481		463
	Total capitalized costs excluded from DD&A	$	95,540		$	64,643		$	8,736	$	18,401	$	3,760

Commodity_Derivative_Contracts1

Commodity Derivative Contracts (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments And Hedging Activities Disclosure [Abstract]	'
Schedule of Derivative Instruments	'
	At December 31, 2013, the following derivative contracts were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations:
	Product		Settlement	Derivative		Notional Daily				Total Notional				Average		Average
			Period	Instrument		Volume				Volume				Floor/Fixed Prices		Ceiling Prices
						(Bbls)				(Bbls)				per Bbl		per Bbl
	Crude oil		2014	Costless Collar			3,000				1,095,000			$	83.33	$	109.63
	Crude oil		2014	Swap			6,000				2,190,000				93.13
	Crude oil		2015	Swap			10,000				3,650,000				88.58
	Crude oil		2016	Swap			1,000				366,000				84.4
											7,301,000
	Product		Settlement	Derivative		Notional Daily				Total Notional				Average
			Period	Instrument		Volume				Volume				Fixed Prices
						(Bbls)				(Bbls)				per Bbl
	NGL-Ethane		2014	Swap			4,500				1,642,500			$	13.21
	NGL-Propane		2014	Swap			2,785				1,016,525				44.71
	NGL-Isobutane		2014	Swap			930				339,450				61.26
	NGL-Normal Butane		2014	Swap			875				319,375				60.29
	NGL-Pentanes Plus		2014	Swap			910				332,150				84.97
	NGL-Ethane		2015	Swap			2,500				912,500				11.59
	NGL-Propane		2015	Swap			1,250				456,250				43.26
	NGL-Isobutane		2015	Swap			450				164,250				53.76
	NGL-Normal Butane		2015	Swap			400				146,000				53.76
											5,329,000
	Product		Settlement	Derivative		Notional Daily				Total Notional				Average		Average
			Period	Instrument		Volume				Volume				Floor/Fixed Prices		Ceiling Prices
						(MMBtu)				(MMBtu)				per MMBtu		per MMBtu
	Natural gas		2014	Costless Collar			50,000				18,250,000			$	3.6	$	4.94
	Natural gas		2015	Costless Collar			50,000				18,250,000				3.6		5.04
	Natural gas		2014	Swap			30,000				10,950,000				4.07
	Natural gas		2015	Swap			40,000				14,600,000				4.18
	Natural gas		2016	Swap			10,000				3,660,000				4.03
											65,710,000
Schedule of Derivative Instruments in Statement of Financial Position	'
	The following table sets forth information on the location and amounts of the Company’s derivative instrument fair values in the Consolidated Balance Sheet as of December 31, 2013 and 2012, respectively:
				Asset (Liability) Fair Value
	Commodity derivative contracts		Location on Consolidated Balance Sheet	December 31, 2013				December 31, 2012
				(in thousands)
	Oil		Derivative instruments—current assets	$	1,299			$	564
	Oil		Derivative instruments—non-current assets		2,117				3,329
	Oil		Derivative instruments—current liabilities		(5,629	)			—
	NGL		Derivative instruments—current assets		2,834				8,361
	NGL		Derivative instruments—non-current assets		(129	)			3,534
	NGL		Derivative instruments—current liabilities		461				—
	NGL		Derivative instruments—non-current liabilities		(433	)			(563	)
	Natural gas		Derivative instruments—current assets		174				5,512
	Natural gas		Derivative instruments—non-current assets		3,470				(73	)
	Natural gas		Derivative instruments—current liabilities		255				—
	Total derivative fair value, net, not designated as hedging instruments			$	4,419			$	20,664
Schedule of Derivative Gains and Losses in Consolidated Statement of Operation	'
	The following table sets forth information on the location and amounts of derivative gains and losses in the Consolidated Statement of Operations for the years ended December 31, 2013, 2012 and 2011, respectively:
	Location on Consolidated		Description of Gain (Loss)	December 31,
	Statement of Operations			2013				2012				2011
				(in thousands)
	Oil sales		Loss reclassified from Accumulated OCI	$	—			$	—			$	(2,149	)
	NGL sales		Loss reclassified from Accumulated OCI		—				—				(10,190	)
	Natural gas sales		Gain reclassified from Accumulated OCI		—				—				18,751
	Natural gas sales (1)		Gain recognized in income		—				—				11,018
	Derivative instruments		Gain recognized in income		9,250				20,883				—
			Realized gain recognized in income	$	9,250			$	20,883			$	17,430
	Derivative instruments (2)		(Loss) gain recognized in income due to changes in fair value	$	(16,245	)		$	16,999			$	1,233
	Derivative instruments		(Loss) gain reclassified from Accumulated OCI		(100	)			2,663				—
			Unrealized (loss) gain recognized in income	$	(16,345	)		$	19,662			$	1,233
			Total commodity derivative (loss) gain recognized in income	$	(7,095	)		$	40,545			$	18,663
	-1	For 2011, the amount represents the realized gains associated with the 2011 termination of derivatives used to hedge production from the Company’s divested DJ Basin and Sacramento Basin properties.
	-2	For 2011, the amount represents the unrealized gain associated with the change in fair value of the Company’s crude oil basis and NYMEX roll swaps.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Schedule of Fair Value Assets and Liabilities Measured on Recurring Basis	'
	The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012.
			Fair value as of December 31, 2013
			Level 1			Level 2			Level 3			Netting (1)			Total
			(In thousands)
	Assets:
	Money market funds		$	—		$	1,035		$	—		$	—		$	1,035
	Commodity derivative contracts			—			—			21,675			(11,910	)		9,765
	Liabilities:
	Commodity derivative contracts			—			—			(17,256	)		11,910			(5,346	)
	Total fair value		$	—		$	1,035		$	4,419		$	—		$	5,454
			Fair value as of December 31, 2012
			Level 1			Level 2			Level 3			Netting (1)			Total
			(In thousands)
	Assets:
	Money market funds		$	—		$	1,035		$	—		$	—		$	1,035
	Commodity derivative contracts			—			—			44,036			(22,809	)		21,227
	Liabilities:
	Commodity derivative contracts			—			—			(23,372	)		22,809			(563	)
	Total fair value		$	—		$	1,035		$	20,664		$	—		$	21,699
	-1	Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle. No margin or collateral balances are deposited with counterparties and as such, gross amounts are offset to determine the net amounts presented in the Consolidated Balance Sheet.
Schedule of Valuation Process and Unobservable Inputs	'
	The following table presents a range of the unobservable inputs provided by our third-party provider utilized in the fair value measurements of the Company’s assets and liabilities classified as Level 3 instruments as of December 31, 2013 (in thousands):
									Range						Weighted
	Level 3 Instrument		Asset (Liability)			Valuation Technique		Unobservable Input	Minimum			Maximum			Average
	Oil swaps			(5,297	)	Discounted cash flow		Forward price curve-swaps	$	91.67		$	98.52		$	95.58
	Oil swaps			2,117		Discounted cash flow		Forward price curve-swaps		81.93			90.9			87.61
	Oil costless collars			967		Option model		Forward price curve- costless collar option value		(1.39	)		3.62			0.88
	NGL swaps			5,764		Discounted cash flow		Forward price curve-swaps		0.27			1.4			0.58
	NGL swaps			(3,031	)	Discounted cash flow		Forward price curve-swaps		0.28			2.13			0.97
	Natural gas swaps			1,984		Discounted cash flow		Forward price curve-swaps		3.86			4.4			4.04
	Natural gas swaps			(100	)	Discounted cash flow		Forward price curve-swaps		3.95			4.34			4.08
	Natural gas costless collars			2,015		Option model		Forward price curve-costless collar option value		(0.26	)		0.31			0.06
	Total		$	4,419
Schedule of Fair Value Assets and Liabilities Classified	'
	The tables below present reconciliations of financial assets and liabilities classified as Level 3 in the fair value hierarchy during the indicated periods.
			Derivative Asset			Money Market Funds			Total
			(Liability)			Asset (Liability)
			(In thousands)
	Balance at December 31, 2011		$	3,665		$	1,035		$	4,700
	Total Gains or (Losses) (Realized or Unrealized):
	Included in Earnings			37,882			—			37,882
	Included in Other Comprehensive Income			—			—			—
	Purchases, Issuances and Settlements
	Settlements			(20,883	)		—			(20,883	)
	Purchases			—			—			—
	Transfers in and out of Level 3 (1)			—			(1,035	)		(1,035	)
	Balance at December 31, 2012		$	20,664		$	—		$	20,664
	Total Gains or (Losses) (Realized or Unrealized):
	Included in Earnings			(6,995	)		—			(6,995	)
	Included in Other Comprehensive Income			—			—			—
	Purchases, Issuances and Settlements
	Settlements			(9,250	)		—			(9,250	)
	Purchases			—			—			—
	Transfers in and out of Level 3			—			—			—
	Balance at December 31, 2013		$	4,419		$	—		$	4,419
	-1	The value related to the money market funds was transferred from Level 3 to Level 2 in 2012 as a result of the Company’s ability to obtain independent market-corroborated data.

Accounts_Payable_Accrued_Liabi1

Accounts Payable, Accrued Liabilities, Royalties and Other Payables (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Schedule of Accrued Liabilities, Royalties and Other Payables	'
	The Company’s accrued liabilities consist of the following:
		December 31,
		2013		2012
		(In thousands)
	Accrued capital costs	$	93,725	$	88,844
	Accounts payable		29,682		1,874
	Accrued reserve for commercial disputes		20,000		—
	Accrued payroll and employee incentive expense		10,516		10,436
	Accrued lease operating expense		12,064		9,605
	Accrued interest		15,025		4,582
	Asset retirement obligation		3,930		2,440
	Other		6,008		4,429
	Total Accounts payable and accrued liabilities	$	190,950	$	122,210

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of Asset Retirement Obligations	'
	Activity related to the Company’s ARO is as follows:
		For the Year Ended December 31,
		2013			2012			2011
		(In thousands)
	ARO at the beginning of the period	$	8,400		$	14,313		$	27,934
	Liabilities incurred during period		1,795			866			2,096
	Liabilities settled during period		(1,566	)		(8,538	)		(20,395	)
	Revision of previous estimate		3,850			935			3,454
	Accretion expense		578			824			1,224
	ARO at the end of the period	$	13,057		$	8,400		$	14,313

Debt_and_Credit_Agreements_Tab

Debt and Credit Agreements (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Schedule of Long-Term Debt	'
	The Company’s long-term debt consists of the following:
		December 31,
		2013		2012
		(In thousands)
	Credit Facility	$	—	$	210,000
	9.500% Senior Notes due 2018		200,000		—
	5.625% Senior Notes due 2021		700,000		—
	5.875% Senior Notes due 2022		600,000		200,000
	Total debt	$	1,500,000	$	410,000

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]	'
Future Obligations Under Firm Gas and Oil Transportation Agreements	'
	Future obligations under firm oil and natural gas transportation and processing agreements as of December 31, 2013 are as follows:
		December 31, 2013
		(In thousands)
	2014		34,486
	2015		34,313
	2016		33,844
	2017		33,388
	2018		29,839
	Thereafter		104,088
	Total future obligations	$	269,958
Future Minimum Annual Rental Commitments Under Non-Cancelable Leases	'
	Future minimum annual rental commitments under non-cancelable leases at December 31, 2013 were as follows:
		December 31, 2013
		(In thousands)
	2014	$	19,148
	2015		5,132
	2016		3,736
	2017		3,804
	2018		3,872
	Thereafter		19,823
		$	55,515

StockBased_Compensation_and_Em1

Stock-Based Compensation and Employee Benefits (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'
Schedule Of Stock-Based Compensation Expense	'
	As of the indicated dates, stock-based compensation expense consisted of the following:
			Year Ended December 31,
			2013			2012			2011
			(in thousands)
	Total stock-based compensation expense		$	11,471		$	18,835		$	29,676
	Capitalized in oil and gas properties			(492	)		(296	)		(666	)
	Net stock-based compensation expense		$	10,979		$	18,539		$	29,010
Information Related to Outstanding and Exercisable Options Held by Employees and Directors	'
	The following table summarizes information related to outstanding and exercisable options held by the Company’s employees and directors at December 31, 2013:
			Shares			Weighted Average			Weighted Average			Aggregate Intrinsic
						Exercise Price			Remaining			Value
						Per Share			Contractual Term			(In thousands) (1)
									(In years)
	Outstanding at December 31, 2011			580,513		$	13.48
	Granted			—			—
	Exercised			(69,862	)		13.21
	Forfeited			—			—
	Outstanding at December 31, 2012			510,651		$	13.52
	Granted			—			—
	Exercised			(379,145	)		13.08
	Forfeited			—			—
	Outstanding at December 31, 2013			131,506		$	14.79
	Options vested and exercisable at December 31, 2013			131,506		$	14.79			3.91		$	4,302
	-1	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock, at the indicated date, exceeds the exercise price of the option.
Information Related to Restricted Stock Held by Employees and Directors	'
	The following table summarizes information related to restricted stock held by the Company’s employees and directors at December 31, 2013:
			Shares			Weighted
						Average Grant
						Date Fair Value
	Non-vested shares outstanding at December 31, 2011			542,222		$	23.43
	Granted			267,377			47.33
	Lapse of restrictions			(445,508	)		25.82
	Forfeited			(34,977	)		41.07
	Non-vested shares outstanding at December 31, 2012			329,114		$	37.76
	Granted			584,184			49.18
	Lapse of restrictions			(457,164	)		43.6
	Forfeited			(81,285	)		44.59
	Non-vested shares outstanding at December 31, 2013			374,849		$	46.94
Summary of PSU Awards	'
	The following table is a summary of PSU awards for the year ended December 31, 2013 assuming a 100% payout of the targeted amount:
			PSUs
	Unvested PSUs at December 31, 2012			284,307
	Granted			82,192
	Vested			(152,319	)
	Forfeited			(46,595	)
	Unvested PSUs at December 31, 2013			167,585

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Tax Expense (Benefit)	'
	The Company’s income tax expense (benefit) consists of the following:
		Year Ended December 31,
		2013			2012			2011
		(In thousands)
	Current:
	Federal	$	5,332		$	—		$	—
	State		4,376			—			(457	)
			9,708			—			(457	)
	Deferred:
	Federal		99,768			92,001			52,327
	State		1,108			3,903			3,843
			100,876			95,904			56,170
	Total income tax expense	$	110,584		$	95,904		$	55,713
Differences between Income Taxes Computed Using Statutory Federal Income Tax Rate and that Shown in Statement of Operations	'
	The differences between income taxes computed using the statutory federal income tax rate and that shown in the Consolidated Statement of Operations are summarized as follows:
		Year Ended December 31,
		2013						2012						2011
		(In thousands)			(%)			(In thousands)			(%)			(In thousands)			(%)
	US statutory rate	$	108,477			35	%	$	89,320			35	%	$	54,691			35	%
	State income tax, net of federal benefit		3,538			1.1	%		1,846			0.7	%		3,348			2.2	%
	Non-deductible permanent items		1,137			0.4	%		4,197			1.6	%		677			0.4	%
	Valuation allowance		(15	)		(0.0	%)		954			0.4	%		(2,262	)		(1.4	%)
	Other, net		(2,553	)		(0.8	%)		(413	)		(0.1	%)		(741	)		(0.5	%)
	Total tax expense	$	110,584			35.7	%	$	95,904			37.6	%	$	55,713			35.7	%
Components of Deferred Tax Assets and Liabilities	'
	The components of deferred tax assets and liabilities are as follows:
		December 31,
		2013			2012
		(In thousands)
	Deferred income tax assets:
	Net operating loss carryforwards	$	119,794		$	194,259
	Stock-based compensation		2,001			3,223
	Other		13,737			4,083
	Gross deferred income tax assets	$	135,532		$	201,565
	Valuation allowance		(5,235	)		(5,250	)
	Net deferred income tax assets	$	130,297		$	196,315
	Deferred income tax liabilities:
	Oil and gas properties basis differences		(237,220	)		(198,734	)
	Derivative financial instruments		(1,508	)		(7,356	)
	Deferred income tax liability	$	(238,728	)	$	(206,090	)
	Net deferred income tax liability	$	(108,431	)	$	(9,775	)
Valuation Allowance	'
	The rollforward of our deferred tax asset valuation allowance is as follows:
		Year Ended December 31,
		2013			2012			2011
		(in thousands)
	Balance at the beginning of the year	$	5,250		$	4,296		$	6,558
	Change to provision for income taxes		(15	)		954			(2,262	)
	Balance at the end of the year	$	5,235		$	5,250		$	4,296

Equity_Tables

Equity (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Schedule of Basic and Diluted Weighted Average Shares Outstanding	'
	The following is a calculation of basic and diluted weighted average shares outstanding:
		Year Ended December 31,
		2013		2012		2011
		(In thousands)
	Basic weighted average number of shares outstanding		58,571		52,496		51,996
	Dilution effect of stock option and restricted shares at the end of the period		259		391		620
	Diluted weighted average number of shares outstanding		58,830		52,887		52,616
	Anti-dilutive stock awards and shares		2		1		4

Operating_Segments_Tables

Operating Segments (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Schedule of Geographic Revenue Information	'
	Geographic revenue information below is based on the physical location of the assets at the end of each period. Certain amounts in prior periods have been reclassified to conform to the current presentation.
			Year Ended December 31,
			2013 (1)		2012 (1)		2011 (1)
			(In thousands)
	Oil, NGL, and Natural Gas Revenue
	Eagle Ford		$	764,251	$	561,143	$	354,741
	Permian			52,603		—		—
	Other (2)			4,259		11,811		72,796
	Total		$	821,113	$	572,954	$	427,537
	-1	Excludes the effects of derivative losses of $7.1 million and gains of $40.5 million and $18.7 million, respectively, for the years ended December 31, 2013, 2012 and 2011.
	-2	The decline in revenues from 2011 to 2013 was due to the Company’s asset divestitures and suspension of capital programs in areas that produced primarily from dry gas reservoirs. See Note 4 – Property and Equipment.

Supplemental_Oil_and_Gas_Discl1

Supplemental Oil and Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Summary of Capitalized Costs Relating to Oil, NGL and Gas Producing Activities	'
	The following table sets forth the capitalized costs relating to the Company’s oil, NGL and natural gas producing activities at December 31, 2013, 2012 and 2011:
			2013			2012			2011
			(In thousands)
	Proved properties		$	3,951,397		$	2,829,431		$	2,297,312
	Unproved properties			755,438			95,540			141,016
	Total			4,706,835			2,924,971			2,438,328
	Less: Accumulated depletion			(2,003,893	)		(1,797,203	)		(1,649,403	)
	Net capitalized costs		$	2,702,942		$	1,127,768		$	788,925
Costs Incurred in Oil, NGL and Natural Gas Property Acquisition, Exploration and Development Activities	'
	The following table sets forth costs incurred related to the Company’s oil, NGL and natural gas producing activities for the years ended December 31, 2013, 2012 and 2011:
			Year Ended December 31,
			2013			2012			2011
			(In thousands)
	Acquisition costs
	Proved		$	290,273		$	—		$	—
	Unproved			672,634			18,753			10,605
	Subtotal			962,907			18,753			10,605
	Exploration costs			534,881			93,542			98,781
	Development costs			338,882			531,957			369,865
	Total		$	1,836,670		$	644,252		$	479,251
Results of Operations for Oil, NGL and Natural Gas Producing Activities	'
	Results of Operations for Oil, NGL and Natural Gas Producing Activities
			Year Ended December 31,
			2013 (1)			2012 (1)			2011 (1)
			(In thousands)
	Oil, NGL and natural gas producing revenues		$	821,113		$	572,954		$	427,537
	Production costs			155,749			110,977			69,289
	Depreciation, depletion and amortization			218,571			154,223			123,244
	Income before income taxes			446,793			307,754			235,004
	Income tax provision			159,505			115,716			83,896
	Results of operations		$	287,288		$	192,038		$	151,108
	-1	Excludes the effects of derivative losses of $7.1 million, and gains of $40.5 million and $18.7 million, respectively, for the years ended December 31, 2013, 2012 and 2011.
Summary of Net Proved and Proved Developed Reserve	'
	The following table provides a rollforward of the total proved reserves (all within the United States) for the years ended December 31, 2013, 2012 and 2011, respectively, as well as proved developed and proved undeveloped reserves at the end of each respective year.
			Oil			Natural gas			Natural gas			Equivalents
			(MBbls) (1)			liquids			(MMcf)			(MBoe)
						(MBbls)
	Net proved reserves at December 31, 2010			12,401			19,326			288,927			79,819
	Revisions of previous estimates (2)			4,839			7,192			60,712			22,212
	Purchases in place			—			—			—			—
	Extensions, discoveries and other additions (3)			21,027			26,344			210,292			82,420
	Sales in place			(34	)		—			(80,582	)		(13,464	)
	Production			(1,863	)		(2,643	)		(33,393	)		(10,072	)
	Net proved reserves at December 31, 2011			36,370			50,219			445,956			160,915
	Revisions of previous estimates (4)			(4,947	)		4,923			(10,107	)		(1,709	)
	Purchases in place			70			104			744			298
	Extensions, discoveries and other additions (5)			16,737			22,440			158,788			65,641
	Sales in place			(309	)		(1,641	)		(52,075	)		(10,629	)
	Production			(3,497	)		(4,472	)		(33,853	)		(13,611	)
	Net proved reserves at December 31, 2012			44,424			71,573			509,453			200,905
	Revisions of previous estimates (6)			(8,945	)		(65	)		(9,580	)		(10,606	)
	Purchases in place (7)			10,972			5,857			36,523			22,916
	Extensions, discoveries and other additions (8)			25,010			28,342			180,570			83,447
	Sales in place			—			—			—			—
	Production			(4,999	)		(6,398	)		(40,343	)		(18,121	)
	Net proved reserves at December 31, 2013			66,462			99,309			676,623			278,541
	Proved Developed Reserves
	December 31, 2010			3,687			6,471			183,954			40,817
	December 31, 2011			11,766			16,635			177,278			57,947
	December 31, 2012			19,321			25,068			178,214			74,092
	December 31, 2013			22,560			31,542			217,328			90,324
	Proved Undeveloped Reserves
	December 31, 2010			8,714			12,855			104,973			39,002
	December 31, 2011			24,604			33,584			268,678			102,968
	December 31, 2012			25,103			46,505			331,239			126,813
	December 31, 2013			43,902			67,767			459,295			188,217
	-1	Includes crude oil and condensate. As of December 31, 2013, 2012, 2011 and 2010, approximately 65%, 92%, 97%, and 95%, respectively, of our proved oil reserves consisted of condensate, which the Company defines as oil with an API gravity higher than 55 degrees.
	-2	Upward revision of 22,212 MBoe resulting from positive performance revisions primarily due to an increase in the estimated ultimate recovery of hydrocarbons on 35 Gates Ranch wells. Twenty-two of these Gates Ranch wells have greater than 12 months of production history and some of these wells have been producing for over two years. The decline profiles on wells with significant production history indicate that the estimated ultimate recovery is much more likely to increase or remain constant than to decline.
	-3	The Company added 82,420 MBoe in the Eagle Ford area by drilling and completing 13 wells and adding 91 proved undeveloped locations.
	-4	The downward revision of 1,709 MBoe was primarily due to two factors in the Eagle Ford area. The first factor was a downward oil revision of 4,947 MBbls, partially offset by an upward NGL revision of 4,923 MBbls, which was due to condensate stabilization that is required before transportation of condensate to the market. The stabilization process separates NGLs from the Company’s oil production which resulted in a reclassification of some of the Company’s reserves from oil to NGLs. The second factor was a downward natural gas revision of 10,107 MMcf, which was due largely to a decrease in the twelve-month first-day-of-the-month historical average commodity price for natural gas from $4.12 per MMBtu in 2011 to $2.76 per MMBtu in 2012 and an increase in treating and transportation costs.
	-5	The Company added 65,641 MBoe primarily in the Eagle Ford area by drilling and completing 37 wells and adding 54 proved undeveloped locations.
	-6	The downward revision of 10,606 MBoe is primarily due to lower than expected condensate yields from the Company’s 2013 completions in the north central portion of Gates Ranch.
	-7	The Company added 22,916 MBoe primarily due to the Permian Acquisition.
	-8	The Company added 83,447 MBoe, of which 70,626 MBoe and 12,821 MBoe was from the Eagle Ford and Permian Basin areas, respectively. In the Eagle Ford area, the Company added reserves through the drilling and completion of 79 wells and the addition of 106 proved undeveloped locations. In the Permian Basin area, the Company added reserves through the drilling and completion of 30 wells and the addition of 84 proved undeveloped locations.
Standardized Measure of Discounted Future Net Cash Flows	'
	The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s reserves for the years ended December 31, 2013, 2012 and 2011:
			Year Ended December 31, 2013
			Proved			Proved			Total
			Developed			Undeveloped
			(In millions)
	Future cash inflows		$	3,826		$	7,770		$	11,596
	Future production costs			(1,224	)		(2,188	)		(3,412	)
	Future development costs			(20	)		(1,990	)		(2,010	)
	Future income taxes			(641	)		(892	)		(1,533	)
	Future net cash flows			1,941			2,700			4,641
	Discount to present value at 10% annual rate			(982	)		(1,365	)		(2,347	)
	Standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves		$	959		$	1,335		$	2,294
			Year Ended December 31, 2012
			Proved			Proved			Total
			Developed			Undeveloped
			(In millions)
	Future cash inflows		$	3,239		$	5,013		$	8,252
	Future production costs			(854	)		(1,227	)		(2,081	)
	Future development costs			(8	)		(1,110	)		(1,118	)
	Future income taxes			(652	)		(733	)		(1,385	)
	Future net cash flows			1,725			1,943			3,668
	Discount to present value at 10% annual rate			(859	)		(968	)		(1,827	)
	Standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves		$	866		$	975		$	1,841
			Year Ended December 31, 2011
			Proved			Proved			Total
			Developed			Undeveloped
			(In millions)
	Future cash inflows		$	2,527		$	4,765		$	7,292
	Future production costs			(542	)		(816	)		(1,358	)
	Future development costs			(18	)		(990	)		(1,008	)
	Future income taxes			(584	)		(878	)		(1,462	)
	Future net cash flows			1,383			2,081			3,464
	Discount to present value at 10% annual rate			(702	)		(1,056	)		(1,758	)
	Standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves		$	681		$	1,025		$	1,706
Changes in Standardized Measure of Discounted Future Net Cash Flows	'
	The following table sets forth the changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2013, 2012 and 2011:
			Year ended December 31
			2013			2012			2011
			(in millions)
	Standardized measure–beginning of year		$	1,841		$	1,706		$	697
	Sales and transfers of crude oil, NGLs and natural gas produced, net of production costs			(665	)		(462	)		(358	)
	Revisions to estimates of proved reserves:
	Net changes in prices and production costs			(268	)		(591	)		39
	Extensions, discoveries, additions and improved recovery, net of related costs			849			814			1,117
	Development costs incurred			275			220			370
	Changes in estimated future development costs			86			54			(26	)
	Revisions of previous quantity estimates			(127	)		(12	)		357
	Accretion of discount			244			229			143
	Net change in income taxes			(113	)		(17	)		(549	)
	Purchases of reserve in place			216			6			—
	Sales of reserves in place			—			(104	)		(79	)
	Changes in timing and other			(44	)		(2	)		(5	)
	Standardized measure–end of year		$	2,294		$	1,841		$	1,706

Quarterly_Selected_Financial_D1

Quarterly Selected Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Schedule of Quarterly Financial Information	'
	Summaries of the Company’s results of operations by quarter for the years ended 2013 and 2012 are as follows:
		2013
		First		Second		Third		Fourth
		Quarter		Quarter		Quarter		Quarter
		(In thousands, except per share data)
	Revenues	$	178,120	$	236,520	$	194,568	$	204,810
	Operating income		86,305		131,703		72,306		55,891
	Net income		53,480		75,352		41,025		29,495
	Basic earnings per share		1.01		1.28		0.67		0.48
	Diluted earnings per share		1.01		1.27		0.67		0.48
		2012
		First		Second		Third		Fourth
		Quarter		Quarter		Quarter		Quarter
		(In thousands, except per share data)
	Revenues	$	114,458	$	197,981	$	122,752	$	178,308
	Operating income		40,541		127,111		33,442		78,474
	Net income		22,297		76,969		17,689		42,340
	Basic earnings per share		0.43		1.47		0.34		0.81
	Diluted earnings per share		0.42		1.46		0.33		0.8

Summary_of_Significant_Account2

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Line Items]	'	'	'
Cash and cash equivalents maturity period	'Three months or less	'	'
Allowance for doubtful accounts	$0	$0	'
Capitalized cost	7.2	6	7
Capitalized interest expense	28.3	3.8	5.5
Environmental liabilities	0	0	'
Options granted	'	'	'
Preferred stock, shares authorized	5,000,000	5,000,000	'
Preferred stock, shares outstanding	0	0	'
Gas imbalances	$0	$0	'
Minimum [Member]	'	'	'
Accounting Policies [Line Items]	'	'	'
Other fixed assets, estimated useful lives	'5 years	'	'
Maximum [Member]	'	'	'
Accounting Policies [Line Items]	'	'	'
Other fixed assets, estimated useful lives	'7 years	'	'

Accounts_Receivable_Schedule_o

Accounts Receivable - Schedule of Accounts Receivable (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Receivables [Abstract]	'	'
Oil, NGL and natural gas sales	$96,576	$84,533
State severance tax refunds	19,157	16,269
Joint interest billings	4,696	3,026
Other	2,248	'
Total	$122,677	$103,828

Accounts_Receivable_Additional

Accounts Receivable - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Receivables [Abstract]	'	'
Accounts receivable, uncollectible	$0	$0

Property_and_Equipment_Schedul

Property and Equipment - Schedule of Total Property, Plant and Equipment (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract]	'	'	'
Proved properties	$3,951,397	$2,829,431	$2,297,312
Unproved/unevaluated properties	755,438	95,540	141,016
Gathering systems and compressor stations	168,730	104,978	'
Other fixed assets	26,362	16,346	'
Total	4,901,927	3,046,295	'
Less: Accumulated depreciation, depletion and amortization	-2,020,879	-1,808,190	'
Total property and equipment, net	$2,881,048	$1,238,105	'

Property_and_Equipment_Additio

Property and Equipment - Additional Information (Detail) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Apr. 15, 2010

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 14, 2013

Dec. 31, 2013

Feb. 15, 2012

Feb. 28, 2011

Feb. 28, 2011

Dec. 31, 2013

Dec. 31, 2013

Bridge Loan [Member]

Senior Notes [Member]

South Texas Gates Ranch [Member]

Permian Acquisition [Member]

Gates Acquisition [Member]

Within Five Years [Member]

Gas Gathering Systems And Compressor Stations [Member]

Gas Gathering Systems And Compressor Stations [Member]

Gas Gathering Systems And Compressor Stations [Member]

Adjusted For Basis And Quality Differentials [Member]

Other Property And Equipment [Member]

Other Property And Equipment [Member]

Other Property And Equipment [Member]

Texas [Member]

Texas [Member]

Lobo And Olmos Assets [Member]

Sacramento Basin Properties [Member]

DJ Basin Properties [Member]

Eagle Ford Shale [Member]

Eagle Ford Shale [Member]

South Texas Gates Ranch [Member]

Property, Plant and Equipment [Line Items]

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Consideration of purchase and sale agreement for divestiture

$956,892,000

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$768,000,000

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Payments to acquire businesses

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825,200,000

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Transaction cost

31,000,000

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Commitment fees and related expenses

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5,600,000

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Debt issuance costs

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10,000,000

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'

'

Senior notes, percentage

'

'

'

9.50%

'

5.63%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity issuance costs and related expenses

13,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Acquisition related fees, included in general and administrative costs

2,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Acquisition date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14-May-13

'

'

'

'

'

Acquisition effective date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1-Jan-13

'

'

'

'

'

Working interest acquisition date

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5-Jun-13

'

Percentage of working interests acquired

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

100.00%

Working interest acquisition, total consideration

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

128,100,000

'

Revenue from acquired business included in Consolidated Statements of Operations

'

'

'

'

'

'

'

68,400,000

68,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net income (loss) from acquired business included in Consolidated Statements of Operations

'

'

'

'

'

'

'

47,400,000

47,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Consideration of purchase and sale agreement for divestiture

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

95,000,000

200,000,000

55,000,000

'

'

Asset retirement costs

22,200,000

15,100,000

18,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset retirement cost increase

2,700,000

4,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

West Texas Intermediate oil price (per Bbl)

'

'

'

'

'

'

'

'

'

'

'

'

'

93.42

'

'

'

'

'

'

'

'

'

'

Henry Hub natural gas price (per MMBtu)

'

'

'

'

'

'

'

'

'

'

'

'

'

3.67

'

'

'

'

'

'

'

'

'

'

Impairment charges

0

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost of oil and gas property

672,634,000

18,753,000

10,605,000

'

'

'

129,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Remaining capitalized costs excluded from DD&A

'

'

'

'

'

'

'

'

'

625,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Anticipated timing of inclusion of costs in amortization calculation

'Five years

'

'

'

'

'

'One years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gas gathering systems and compressor stations

168,730,000

104,978,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Useful life, years

'

'

'

'

'

'

'

'

'

'

'15

'

'

'

'

'

'

'

'

'

'

'

'

'

Accumulated depreciation for gas gathering system

2,020,879,000

1,808,190,000

'

'

'

'

'

'

'

'

13,700,000

5,700,000

'

'

'

'

'

'

'

'

'

'

'

'

Depreciation expense

'

'

'

'

'

'

'

'

'

'

7,900,000

4,000,000

2,300,000

'

3,400,000

1,400,000

2,600,000

'

'

'

'

'

'

'

Other property and equipment

26,362,000

16,346,000

'

'

'

'

'

'

'

'

'

'

'

'

26,400,000

16,300,000

'

'

'

'

'

'

'

'

Accumulated depreciation associated with other assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$2,900,000

$5,100,000

'

'

'

'

'

'

'

'

Property_and_Equipment_Schedul1

Property and Equipment - Schedule of Consideration Paid for the Transactions of Asset Acquired and Liabilities Assumed (Detail) (Level 3 [Member], USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Level 3 [Member]	'
Property Plant And Equipment Disclosure [Line Items]	'
Cash consideration	$953,242
Fair value of assets acquired :	'
Other fixed assets	600
Oil and natural gas properties	'
Proved properties	290,273
Unproved/unevaluated properties	663,300
Total assets acquired	954,173
Fair value of liabilities assumed:	'
Asset retirement obligations	931
Net assets acquired	$953,242

Property_and_Equipment_Schedul2

Property and Equipment - Schedule of Results of Operations at the Time of Transactions (Detail) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property Plant And Equipment Useful Life And Values [Abstract]	'	'
Total revenues	$846,560	$671,780
Net income	$191,478	$151,144
Earnings per share:	'	'
Basic	$3.13	$2.50
Diluted	$3.12	$2.48
Weighted average shares outstanding:	'	'
Basic	61,081	60,546
Diluted	61,339	60,937

Property_and_Equipment_Schedul3

Property and Equipment - Schedule of Capitalized Costs Excluded From DD&A (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012
In Thousands, unless otherwise specified				2013 [Member]	2012 [Member]	2012 [Member]	2011 [Member]	2011 [Member]	Prior [Member]	Prior [Member]	2010 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Development cost, Total	$129,812	$29,857	'	'	'	'	'	'	'	'	'
Exploration cost, Total	15,459	16,180	'	'	'	'	'	'	'	'	'
Acquisition cost of undeveloped acreage, Total	584,137	42,186	'	'	'	'	'	'	'	'	'
Capitalized interest, Total	26,030	7,317	'	'	'	'	'	'	'	'	'
Total capitalized costs excluded from DD&A, Total	755,438	95,540	141,016	'	'	'	'	'	'	'	'
Development costs	'	'	'	129,812	'	29,857	'	'	'	'	'
Exploration costs	'	'	'	8,445	7,014	16,180	'	'	'	'	'
Acquisition cost of undeveloped acreage	'	'	'	565,330	4,485	15,297	5,170	6,672	9,152	3,297	16,920
Capitalized interest	'	'	'	22,718	1,471	3,309	480	2,064	1,361	463	1,481
Total capitalized costs excluded from DD&A	'	'	'	$726,305	$12,970	$64,643	$5,650	$8,736	$10,513	$3,760	$18,401

Debt_Issuance_Costs_Additional

Debt Issuance Costs - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Debt Disclosure [Abstract]	'	'	'
Debt issuance costs	$25,602,000	$7,699,000	'
Total amortization expense	$8,400,000	$2,900,000	$2,200,000

Commodity_Derivative_Contracts2

Commodity Derivative Contracts - Schedule of Derivative Instruments (Detail)	Dec. 31, 2013
	MMBTU
Natural Gas [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Total Notional Volume MMBtu	65,710,000
NGL-Product [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Total of Notional Volume	5,329
Crude Oil [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Total of Notional Volume	7,301
Costless Collar [Member] | 2014 Settlement Period [Member] | Natural Gas [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume MMBtu	50,000
Total Notional Volume MMBtu	18,250,000
Average Fixed Prices per	3.6
Average Ceiling Prices per	4.94
Costless Collar [Member] | 2014 Settlement Period [Member] | Crude Oil [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	3
Total of Notional Volume	1,095
Average Fixed Prices per	83.33
Average Ceiling Prices per	109.63
Costless Collar [Member] | 2015 Settlement Period [Member] | Natural Gas [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume MMBtu	50,000
Total Notional Volume MMBtu	18,250,000
Average Fixed Prices per	3.6
Average Ceiling Prices per	5.04
Swap [Member] | 2014 Settlement Period [Member] | Natural Gas [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume MMBtu	30,000
Total Notional Volume MMBtu	10,950,000
Average Fixed Prices per	4.07
Swap [Member] | 2014 Settlement Period [Member] | NGL-Ethane [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	4.5
Total of Notional Volume	1,642.50
Average Fixed Prices per	13.21
Swap [Member] | 2014 Settlement Period [Member] | NGL-Propane [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	2.785
Total of Notional Volume	1,016.52
Average Fixed Prices per	44.71
Swap [Member] | 2014 Settlement Period [Member] | NGL-Isobutane [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	0.93
Total of Notional Volume	339.45
Average Fixed Prices per	61.26
Swap [Member] | 2014 Settlement Period [Member] | NGL-Normal Butane [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	0.875
Total of Notional Volume	319.375
Average Fixed Prices per	60.29
Swap [Member] | 2014 Settlement Period [Member] | NGL-Pentanes Plus [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	0.91
Total of Notional Volume	332.15
Average Fixed Prices per	84.97
Swap [Member] | 2014 Settlement Period [Member] | Crude Oil [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	6
Total of Notional Volume	2,190
Average Fixed Prices per	93.13
Swap [Member] | 2015 Settlement Period [Member] | Natural Gas [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume MMBtu	40,000
Total Notional Volume MMBtu	14,600,000
Average Fixed Prices per	4.18
Swap [Member] | 2015 Settlement Period [Member] | NGL-Ethane [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	2.5
Total of Notional Volume	912.5
Average Fixed Prices per	11.59
Swap [Member] | 2015 Settlement Period [Member] | NGL-Propane [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	1.25
Total of Notional Volume	456.25
Average Fixed Prices per	43.26
Swap [Member] | 2015 Settlement Period [Member] | NGL-Isobutane [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	0.45
Total of Notional Volume	164.25
Average Fixed Prices per	53.76
Swap [Member] | 2015 Settlement Period [Member] | NGL-Normal Butane [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	0.4
Total of Notional Volume	146
Average Fixed Prices per	53.76
Swap [Member] | 2015 Settlement Period [Member] | Crude Oil [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	10
Total of Notional Volume	3,650
Average Fixed Prices per	88.58
Swap [Member] | 2016 Settlement Period [Member] | Natural Gas [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume MMBtu	10,000
Total Notional Volume MMBtu	3,660,000
Average Fixed Prices per	4.03
Swap [Member] | 2016 Settlement Period [Member] | Crude Oil [Member]	'
Derivative Instruments, Gain (Loss) [Line Items]	'
Notional Daily Volume	1
Total of Notional Volume	366
Average Fixed Prices per	84.4

Commodity_Derivative_Contracts3

Commodity Derivative Contracts - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative [Line Items]	'	'	'
Accumulated other comprehensive income loss before tax	'	'	$2,600,000
Accumulated other comprehensive income	-108,000	-63,000	1,632,000
Unrealized net losses reclassified from AOCI into earnings	0	0	2,000,000
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]	'	'	'
Derivative [Line Items]	'	'	'
Unrealized net gains reclassified from AOCI	($100,000)	$2,700,000	'

Commodity_Derivative_Contracts4

Commodity Derivative Contracts - Schedule of Derivative Instruments in Statement of Financial Position (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	$4,419	'
Derivatives Not Designated As Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	4,419	20,664
Commodity Contracts [Member] | Current Assets [Member] | Crude Oil [Member] | Derivatives Not Designated As Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	1,299	564
Commodity Contracts [Member] | Current Assets [Member] | NGL [Member] | Derivatives Not Designated As Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	2,834	8,361
Commodity Contracts [Member] | Current Assets [Member] | Natural Gas [Member] | Derivatives Not Designated As Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	174	5,512
Commodity Contracts [Member] | Non-Current Assets [Member] | Crude Oil [Member] | Derivatives Not Designated As Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	2,117	3,329
Commodity Contracts [Member] | Non-Current Assets [Member] | NGL [Member] | Derivatives Not Designated As Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	-129	3,534
Commodity Contracts [Member] | Non-Current Assets [Member] | Natural Gas [Member] | Derivatives Not Designated As Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	3,470	-73
Commodity Contracts [Member] | Current Liabilities [Member] | Crude Oil [Member] | Derivatives Not Designated As Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	-5,629	'
Commodity Contracts [Member] | Current Liabilities [Member] | NGL [Member] | Derivatives Not Designated As Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	461	'
Commodity Contracts [Member] | Current Liabilities [Member] | Natural Gas [Member] | Derivatives Not Designated As Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	255	'
Commodity Contracts [Member] | Noncurrent Liabilities [Member] | NGL [Member] | Derivatives Not Designated As Hedging Instruments [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Fair value of derivative instruments	($433)	($563)

Commodity_Derivative_Contracts5

Commodity Derivative Contracts - Schedule of Derivative Gains and Losses in Consolidated Statement of Operations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Realized gain recognized in income	$9,250	$20,883	$17,430
Unrealized (loss) gain recognized in income	-16,345	19,662	12,124
Total commodity derivative (loss) gain recognized in income	-7,095	40,545	1,233
Derivative Instruments [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain recognized in income	9,250	20,883	'
(Loss) gain recognized in income due to changes in fair value	-16,245	16,999	1,233
(Loss) gain reclassified from Accumulated OCI	-100	2,663	'
Oil Sales [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
(Loss) gain reclassified from Accumulated OCI	'	'	-2,149
NGL sales [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
(Loss) gain reclassified from Accumulated OCI	'	'	-10,190
Natural Gas Sales [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain recognized in income	'	'	11,018
(Loss) gain reclassified from Accumulated OCI	'	'	$18,751

Fair_Value_Measurements_Schedu

Fair Value Measurements - Schedule of Fair Value Assets and Liabilities Measured on Recurring Basis (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	$5,454	$21,699
Money Market Funds Asset (Liability) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	1,035	1,035
Commodity Derivative Contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	9,765	21,227
Fair value of assets and liabilities measured on recurring basis	-5,346	-563
Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	'	'
Level 1 [Member] | Money Market Funds Asset (Liability) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	'	'
Level 1 [Member] | Commodity Derivative Contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	'	'
Fair value of assets and liabilities measured on recurring basis	'	'
Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	1,035	1,035
Level 2 [Member] | Money Market Funds Asset (Liability) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	1,035	1,035
Level 2 [Member] | Commodity Derivative Contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	'	'
Fair value of assets and liabilities measured on recurring basis	'	'
Level 3 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	4,419	20,664
Level 3 [Member] | Money Market Funds Asset (Liability) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	'	'
Level 3 [Member] | Commodity Derivative Contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	21,675	44,036
Fair value of assets and liabilities measured on recurring basis	-17,256	-23,372
Netting [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	'	'
Netting [Member] | Money Market Funds Asset (Liability) [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	'	'
Netting [Member] | Commodity Derivative Contracts [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair value of assets and liabilities measured on recurring basis	-11,910	-22,809
Fair value of assets and liabilities measured on recurring basis	$11,910	$22,809

Fair_Value_Measurements_Schedu1

Fair Value Measurements - Schedule of Valuation Process and Unobservable Inputs (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Fair Value, Derivative Asset (Liability)	$4,419
Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Fair Value, Derivative Asset (Liability)	-5,297
Derivative assets, Valuation Technique	'Discounted cash flow
Unobservable Input	'Forward price curve-swaps
Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Fair Value, Derivative Asset (Liability)	2,117
Derivative assets, Valuation Technique	'Discounted cash flow
Unobservable Input	'Forward price curve-swaps
Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Costless Collar [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Fair Value, Derivative Asset (Liability)	967
Derivative assets, Valuation Technique	'Option model
Unobservable Input	'Forward price curve- costless collar option value
MMBtu [Member] | Derivative Liabilities [Member] | NGL [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Fair Value, Derivative Asset (Liability)	-3,031
Derivative assets, Valuation Technique	'Discounted cash flow
Unobservable Input	'Forward price curve-swaps
MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Fair Value, Derivative Asset (Liability)	-100
Derivative assets, Valuation Technique	'Discounted cash flow
Unobservable Input	'Forward price curve-swaps
MMBtu [Member] | Derivative Assets [Member] | NGL [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Fair Value, Derivative Asset (Liability)	5,764
Derivative assets, Valuation Technique	'Discounted cash flow
Unobservable Input	'Forward price curve-swaps
MMBtu [Member] | Derivative Assets [Member] | Natural Gas [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Fair Value, Derivative Asset (Liability)	1,984
Derivative assets, Valuation Technique	'Discounted cash flow
Unobservable Input	'Forward price curve-swaps
MMBtu [Member] | Derivative Assets [Member] | Natural Gas [Member] | Costless Collar [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Fair Value, Derivative Asset (Liability)	$2,015
Derivative assets, Valuation Technique	'Option model
Unobservable Input	'Forward price curve-costless collar option value
Minimum [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	91.67
Minimum [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	81.93
Minimum [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Costless Collar [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	-1.39
Minimum [Member] | MMBtu [Member] | Derivative Liabilities [Member] | NGL [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	0.28
Minimum [Member] | MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	3.95
Minimum [Member] | MMBtu [Member] | Derivative Assets [Member] | NGL [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	0.27
Minimum [Member] | MMBtu [Member] | Derivative Assets [Member] | Natural Gas [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	3.86
Minimum [Member] | MMBtu [Member] | Derivative Assets [Member] | Natural Gas [Member] | Costless Collar [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	-0.26
Maximum [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	98.52
Maximum [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	90.9
Maximum [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Costless Collar [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	3.62
Maximum [Member] | MMBtu [Member] | Derivative Liabilities [Member] | NGL [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	2.13
Maximum [Member] | MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	4.34
Maximum [Member] | MMBtu [Member] | Derivative Assets [Member] | NGL [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	1.4
Maximum [Member] | MMBtu [Member] | Derivative Assets [Member] | Natural Gas [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	4.4
Maximum [Member] | MMBtu [Member] | Derivative Assets [Member] | Natural Gas [Member] | Costless Collar [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	0.31
Weighted Average [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	95.58
Weighted Average [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	87.61
Weighted Average [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Costless Collar [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	0.88
Weighted Average [Member] | MMBtu [Member] | Derivative Liabilities [Member] | NGL [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	0.97
Weighted Average [Member] | MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	4.08
Weighted Average [Member] | MMBtu [Member] | Derivative Assets [Member] | NGL [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	0.58
Weighted Average [Member] | MMBtu [Member] | Derivative Assets [Member] | Natural Gas [Member] | Swap [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	4.04
Weighted Average [Member] | MMBtu [Member] | Derivative Assets [Member] | Natural Gas [Member] | Costless Collar [Member]	'
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]	'
Forward Price Curve	0.06

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value Disclosures [Abstract]	'	'
Fair value of its derivative instruments	$0.30	'
Fair market value of total debt	$1,550	$432.50

Fair_Value_Measurements_Schedu2

Fair Value Measurements - Schedule of Fair Value Assets and Liabilities Classified (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'	'
Balance, Beginning	$20,664	$4,700	'
Included in Earnings	-6,995	37,882	'
Included in Other Comprehensive Income	'	'	'
Settlements	-9,250	-20,883	-17,430
Purchases	'	'	'
Transfers in and out of Level 3	'	-1,035	'
Balance, Ending	4,419	20,664	4,700
Derivatives Asset (Liability) [Member]	'	'	'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'	'
Balance, Beginning	20,664	3,665	'
Included in Earnings	-6,995	37,882	'
Included in Other Comprehensive Income	'	'	'
Settlements	-9,250	-20,883	'
Purchases	'	'	'
Transfers in and out of Level 3	'	'	'
Balance, Ending	4,419	20,664	'
Money Market Funds Asset (Liability) [Member]	'	'	'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'	'
Balance, Beginning	'	1,035	'
Included in Earnings	'	'	'
Included in Other Comprehensive Income	'	'	'
Settlements	'	'	'
Purchases	'	'	'
Transfers in and out of Level 3	'	-1,035	'
Balance, Ending	'	'	'

Accounts_Payable_Accrued_Liabi2

Accounts Payable, Accrued Liabilities, Royalties and Other Payables - Schedule of Accrued Liabilities, Royalties and Other Payables (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Payables And Accruals [Abstract]	'	'
Accrued capital costs	$93,725	$88,844
Accounts payable	29,682	1,874
Accrued reserve for commercial disputes	20,000	'
Accrued payroll and employee incentive expense	10,516	10,436
Accrued lease operating expense	12,064	9,605
Accrued interest	15,025	4,582
Asset retirement obligation	3,930	2,440
Other	6,008	4,429
Total Accounts payable and accrued liabilities	$190,950	$122,210

Accounts_Payable_Accrued_Liabi3

Accounts Payable, Accrued Liabilities, Royalties and Other Payables - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Payables And Accruals [Abstract]	'	'
Accrued Royalties Current	$78,264,000	$61,637,000
Royalty revenues payable to landowners	47,000,000	'
Accrued transportation costs	14,100,000	'
Other operating liabilities	$17,200,000	'

Asset_Retirement_Obligations_S

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation Disclosure [Abstract]	'	'	'
ARO at the beginning of the period	$8,400	$14,313	$27,934
Liabilities incurred during period	1,795	866	2,096
Liabilities settled during period	-1,566	-8,538	-20,395
Revision of previous estimate	3,850	935	3,454
Accretion expense	578	824	1,224
ARO at the end of the period	$13,057	$8,400	$14,313

Asset_Retirement_Obligations_A

Asset Retirement Obligations - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]	'	'
Current portion of ARO	$3,930,000	$2,440,000
Long-term portion of ARO	$9,200,000	$6,000,000

Debt_and_Credit_Agreements_Sch

Debt and Credit Agreements - Schedule of Long-Term Debt (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Apr. 15, 2010
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'	'	'
Total debt	$1,500,000	$410,000	'
Credit Facility [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Credit Facility	'	210,000	'
9.500% Senior Notes due 2018 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior Notes	200,000	'	200,000
5.625% Senior Notes due 2021 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior Notes	700,000	'	'
5.875% Senior Notes due 2022 [Member]	'	'	'
Debt Instrument [Line Items]	'	'	'
Senior Notes	$600,000	$200,000	'

Debt_and_Credit_Agreements_Sch1

Debt and Credit Agreements - Schedule of Long-Term Debt (Parenthetical) (Detail)	Apr. 15, 2010	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	2-May-13	Dec. 31, 2013	Dec. 31, 2012	Nov. 15, 2013
		9.500% Senior Notes due 2018 [Member]	9.500% Senior Notes due 2018 [Member]	5.625% Senior Notes due 2021 [Member]	5.625% Senior Notes due 2021 [Member]	5.625% Senior Notes due 2021 [Member]	5.875% Senior Notes due 2022 [Member]	5.875% Senior Notes due 2022 [Member]	5.875% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'
Debt maturity date	'	'Senior Notes due 2018	'Senior Notes due 2018	'Senior Notes due 2021	'Senior Notes due 2021	'	'Senior Notes due 2022	'Senior Notes due 2022	'
Debt instrument, interest rate, stated percentage	9.50%	9.50%	9.50%	5.63%	5.63%	5.63%	5.88%	5.88%	5.88%

Debt_and_Credit_Agreements_Add

Debt and Credit Agreements - Additional Information (Detail) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Apr. 15, 2010

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Apr. 15, 2010

Dec. 31, 2013

Dec. 31, 2012

2-May-13

Dec. 31, 2013

Dec. 31, 2012

Nov. 15, 2013

Minimum [Member]

Maximum [Member]

London Interbank Offered Rate (LIBOR) [Member]

London Interbank Offered Rate (LIBOR) [Member]

Alternative Base Rate [Member]

Alternative Base Rate [Member]

Second Lien Term Loan [Member]

Amended and Restated Senior Revolving Credit Agreement [Member]

9.500% Senior Notes due 2018 [Member]

9.500% Senior Notes due 2018 [Member]

9.500% Senior Notes due 2018 [Member]

5.625% Senior Notes due 2021 [Member]

5.625% Senior Notes due 2021 [Member]

5.625% Senior Notes due 2021 [Member]

5.875% Senior Notes due 2022 [Member]

5.875% Senior Notes due 2022 [Member]

5.875% Senior Notes due 2022 [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Line of Credit Facility [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount outstanding

'

'

'

'

'

'

'

'

'

'

$0

'

'

'

'

'

'

'

'

'

Available borrowing capacity

'

'

'

'

'

'

'

'

'

'

800,000,000

'

'

'

'

'

'

'

'

'

Debt instrument, interest rate, stated percentage

'

'

9.50%

'

'

1.50%

2.50%

0.50%

1.50%

'

'

9.50%

9.50%

'

5.63%

5.63%

5.63%

5.88%

5.88%

5.88%

Weighted average borrowing rate under Restated Revolver

3.22%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Pre-tax SEC PV-10 reserve value, percentage

80.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Pledge of membership and limited partnership interests percentage

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current ratio

'

'

'

0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Leverage ratio

'

'

'

'

0.04

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current ratio

4.40%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Leverage ratio

2.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior Notes

'

'

'

'

'

'

'

'

'

'

'

200,000,000

'

200,000,000

700,000,000

'

'

600,000,000

200,000,000

'

Debt maturity date

'

'

'

'

'

'

'

'

'

'October 2, 2012

'

'Senior Notes due 2018

'Senior Notes due 2018

'

'Senior Notes due 2021

'Senior Notes due 2021

'

'Senior Notes due 2022

'Senior Notes due 2022

'

Redemption of long-term debt

'

'

'

'

'

'

'

'

'

'

'

104.75

'

'

'

'

'

'

'

'

Issuance of aggregate principal amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

700,000,000

'

'

600,000,000

Repayment of term loan

'

20,000,000

'

'

'

'

'

'

'

20,000,000

'

'

'

'

'

'

'

'

'

'

Bearing interest rate

13.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayment charges

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total outstanding borrowings

$1,500,000,000

$410,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Weighted average borrowing rate

5.99%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt maturity date

31-Dec-18

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and Gas Delivery Commitments and Contracts [Line Items]	'	'	'
Accrued deficiency fees	$7,800,000	'	'
Outstanding commitments	19,800,000	'	'
Minimum remaining contractual commitment	14,800,000	'	'
Rental expense incurred	7,300,000	5,700,000	3,400,000
Reserve for commercial disputes	$20,450,000	'	'
Oil Commitments (MMBbls) [Member]	'	'	'
Oil and Gas Delivery Commitments and Contracts [Line Items]	'	'	'
Oil and gas delivery transportation commitments	6,100	'	'
Natural Gas Commitments (MMBtus) [Member]	'	'	'
Oil and Gas Delivery Commitments and Contracts [Line Items]	'	'	'
Oil and gas delivery transportation commitments	367,000,000	'	'

Commitments_and_Contingencies_2

Commitments and Contingencies - Future Obligations Under Firm Gas and Oil Transportation Agreements (Detail) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Oil And Gas Delivery Commitments And Contracts Additional Information [Abstract]	'
2014	$34,486
2015	34,313
2016	33,844
2017	33,388
2018	29,839
Thereafter	104,088
Total future obligations	$269,958

Commitments_and_Contingencies_3

Commitments and Contingencies - Future Minimum Annual Rental Commitments Under Non-Cancelable Leases (Detail) (Office Space And Other Property And Equipment [Member], USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Office Space And Other Property And Equipment [Member]	'
Operating Leased Assets [Line Items]	'
2014	$19,148
2015	5,132
2016	3,736
2017	3,804
2018	3,872
Thereafter	19,823
Transportation agreements, future minimum payments, total	$55,515

StockBased_Compensation_and_Em2

Stock-Based Compensation and Employee Benefits - Schedule of Stock-Based Compensation Expense (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'	'	'
Total stock-based compensation expense	$11,471	$18,835	$29,676
Capitalized in oil and gas properties	-492	-296	-666
Net stock-based compensation expense	$10,979	$18,539	$29,010

StockBased_Compensation_and_Em3

Stock-Based Compensation and Employee Benefits - Additional Information (Detail) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2008

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

31-May-13

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Minimum [Member]

Maximum [Member]

2010 and 2011 PSU Plans [Member]

Two Thousand Twelve Through Two Thousand Thirteen [Member]

2011 PSU Plans [Member]

2010 PSU Plans [Member]

Two Thousand and Thirteen Long Term Incentive Plan [Member]

Two Thousand and Thirteen Long Term Incentive Plan [Member]

Two Thousand and Thirteen Long Term Incentive Plan [Member]

Employee Stock Option [Member]

Employee Stock Option [Member]

Employee Stock Option [Member]

Restricted Stock [Member]

Restricted Stock [Member]

Restricted Stock [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Maximum [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Associated tax benefit

$3,000,000

$2,800,000

$10,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of shares available for grant

'

'

'

4,950,000

'

'

'

'

'

'

'

3,600,000

'

'

'

'

'

'

'

'

'

'

Maximum number of shares of common stock available for grant of awards, allocation to participants

'

'

'

'

'

'

'

'

'

'

'The maximum number of shares of common stock available for the grant of awards under the 2013 Plan to any one participant is (i) 500,000 shares during the fiscal year in which the participant begins work for Rosetta, and (ii) 300,000 shares during each fiscal year thereafter.

'

'

'

'

'

'

'

'

'

'

'

Maximum Number of Shares Available Award Grant, In First Employed Fiscal Year

'

'

'

'

'

'

'

'

'

'

'

'

500,000

'

'

'

'

'

'

'

'

'

Maximum Number of Shares Available Award Grant, In First Employed Fiscal Year thereafter

'

'

'

'

'

'

'

'

'

'

'

'

300,000

'

'

'

'

'

'

'

'

'

Stock options expiration (in years)

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Majority of options vesting period

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'

'

'

'

'

Options granted

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock compensation expense recorded

10,979,000

18,539,000

29,010,000

'

'

'

'

'

'

'

'

'

'

'

100,000

400,000

6,700,000

7,400,000

4,900,000

'

'

'

Unrecognized compensation expense

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

9,700,000

'

'

'

'

'

Total intrinsic value of options exercised

'

'

'

'

'

'

'

'

'

'

'

'

'

13,400,000

2,300,000

7,100,000

'

'

'

'

'

'

Annual forfeiture rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

Fair value of awards vested

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

22,700,000

'

'

'

'

'

Unrecognized expense recognized, weighted average period, in years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year 8 months 27 days

'

'

'

'

'

Number of shares vested range, percentage of targeted amounts

'

'

'

'

0.00%

200.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

PSUs performance period, in years

'

'

'

'

'

'

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stock-based compensation expense associated with PSU

11,471,000

18,835,000

29,676,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4,700,000

11,400,000

23,700,000

Percentage of payout on target amount

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of target amount vested

'

'

'

'

'

'

'

'

150.00%

175.00%

'

'

'

'

'

'

'

'

'

'

'

'

Total amount vested

457,164

445,508

'

'

'

'

'

'

75,275

268,469

'

'

'

'

'

'

'

'

'

152,319

'

'

Additional paid-in capital

'

'

'

'

'

'

'

'

3,700,000

12,200,000

'

'

'

'

'

'

'

'

'

'

'

'

Unvested PSU unit

374,849

329,114

542,222

'

'

'

'

118,379

'

'

'

'

'

'

'

'

'

'

'

167,585

284,307

'

Closing common stock price

'

'

'

'

'

'

'

$48.04

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum available payout

'

'

'

'

'

'

'

200.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unrecognized stock-based compensation

'

'

'

'

'

'

'

$9,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

StockBased_Compensation_and_Em4

Stock-Based Compensation and Employee Benefits - Information Related to Outstanding and Exercisable Options Held by Employees and Directors (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'	'	'
Shares Outstanding, Beginning Balance	510,651	580,513	'
Granted, Shares	'	'	'
Exercised, Shares	-379,145	-69,862	'
Forfeited, Shares	'	'	'
Shares Outstanding, Ending Balance	131,506	510,651	580,513
Options Outstanding, Weighted Average Exercise Price Per Share, Beginning Balance	$13.52	$13.48	'
Options Vested and Exercisable, Shares	131,506	'	'
Granted, Weighted Average Exercise Price Per Share	'	'	'
Exercised, Weighted Average Exercise Price Per Share	$13.08	$13.21	'
Forfeited, Weighted Average Exercise Price Per Share	'	'	'
Options Outstanding, Weighted Average Exercise Price Per Share, Ending Balance	$14.79	$13.52	$13.48
Options Vested and Exercisable, Weighted Average Exercise Price Per Share	$14.79	'	'
Options Vested and Exercisable, Weighted Average Remaining Contractual Term (in years)	'3 years 10 months 28 days	'	'
Options Vested and Exercisable, Aggregate Intrinsic Value	$4,302	'	'

StockBased_Compensation_and_Em5

Stock-Based Compensation and Employee Benefits - Information Related to Restricted Stock Held by Employees and Directors (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]	'	'
Unvested PSUs at December 31, 2012	329,114	542,222
Granted, Shares	584,184	267,377
Lapse of restrictions, Shares	-457,164	-445,508
Forfeited, Shares	-81,285	-34,977
Unvested PSUs at December 31, 2013	374,849	329,114
Non-vested Shares Outstanding, Weighted Average Grant Date Fair Value, Beginning Balance	$37.76	$23.43
Granted, Weighted Average Grant Date Fair Value	$49.18	$47.33
Lapse of restrictions, Weighted Average Grant Date Fair Value	$43.60	$25.82
Forfeited, Weighted Average Grant Date Fair Value	$44.59	$41.07
Non-vested Shares Outstanding, Weighted Average Grant Date Fair Value, Ending Balance	$46.94	$37.76

StockBased_Compensation_and_Em6

Stock-Based Compensation and Employee Benefits - Summary of PSU Awards (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Unvested PSUs at December 31, 2012	329,114	542,222
Granted	584,184	267,377
Vested	-457,164	-445,508
Forfeited	-81,285	-34,977
Unvested PSUs at December 31, 2013	374,849	329,114
Performance Shares [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Unvested PSUs at December 31, 2012	284,307	'
Granted	82,192	'
Vested	-152,319	'
Forfeited	-46,595	'
Unvested PSUs at December 31, 2013	167,585	'

Income_Taxes_Income_Tax_Expens

Income Taxes - Income Tax Expense (Benefit) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Current, Federal	$5,332	'	'
Current, State	4,376	'	-457
Current, Total	9,708	'	-457
Deferred, Federal	99,768	92,001	52,327
Deferred, State	1,108	3,903	3,843
Deferred, Total	100,876	95,904	56,170
Total income tax expense	$110,584	$95,904	$55,713

Income_Taxes_Differences_betwe

Income Taxes - Differences between Income Taxes Computed Using Statutory Federal Income Tax Rate (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
US statutory rate, amount	$108,477	$89,320	$54,691
State income tax, net of federal benefit	3,538	1,846	3,348
Non-deductible permanent items, amount	1,137	4,197	677
Valuation allowance	-15	954	-2,262
Other, net, amount	-2,553	-413	-741
Total income tax expense	$110,584	$95,904	$55,713
US statutory rate, percentage	35.00%	35.00%	35.00%
State income tax, net of federal benefit, percentage	1.10%	0.70%	2.20%
Non-deductible permanent items, percentage	0.40%	1.60%	0.40%
Valuation allowance, percentage	0.00%	0.40%	-1.40%
Other, net, percentage	-0.80%	-0.10%	-0.50%
Total tax expense (benefit), percentage	35.70%	37.60%	35.70%

Income_Taxes_Components_of_Def

Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Components Of Deferred Tax Assets And Liabilities [Abstract]	'	'	'	'
Net operating loss carryforwards	$119,794	$194,259	'	'
Stock-based compensation	2,001	3,223	'	'
other	13,737	4,083	'	'
Gross deferred income tax assets	135,532	201,565	'	'
Valuation allowance	-5,235	-5,250	-4,296	-6,558
Net deferred income tax assets	130,297	196,315	'	'
Oil and gas properties basis differences	-237,220	-198,734	'	'
Derivative financial instruments	-1,508	-7,356	'	'
Deferred income tax liability	-238,728	-206,090	'	'
Net deferred income tax liability	($108,431)	($9,775)	'	'

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Income Tax Disclosure [Line Items]	'
State NOL carryforwards	$105.10
Current income taxes	0
Deferred tax asset related to NOL carryforwards	119.8
Unrealized excess tax benefits	7
Share based compensation expense	20
Unrecognized tax benefits	0
Interest or penalties associated with unrecognized tax benefits	0
Federal [Member]	'
Income Tax Disclosure [Line Items]	'
Federal NOL carryforwards	$347
NOL carryforward, expiration date	'2029 and 2032
State [Member]	'
Income Tax Disclosure [Line Items]	'
NOL carryforward, expiration date	'2014 and 2032

Income_Taxes_Valuation_Allowan

Income Taxes - Valuation Allowance (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Valuation Allowance [Abstract]	'	'	'
Balance at the beginning of the year	$5,250	$4,296	$6,558
Change to provision for income taxes	-15	954	-2,262
Balance at the end of the year	$5,235	$5,250	$4,296

Equity_Schedule_of_Basic_and_D

Equity - Schedule of Basic and Diluted Weighted Average Shares Outstanding (Detail)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity [Abstract]	'	'	'
Basic weighted average number of shares outstanding	58,571	52,496	51,996
Dilution effect of stock option and restricted shares at the end of the period	259	391	620
Diluted weighted average number of shares outstanding	58,830	52,887	52,616
Anti-dilutive stock awards and shares	2	1	4

Equity_Additional_Information_

Equity - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013
Equity [Line Items]	'
Common stock price per share	$42.50
Underwriting discount and structuring fee per share, net	$40.80
Net proceeds from equity issue	$329,008
Underwriters Overallotment Option [Member]	'
Equity [Line Items]	'
Public offering of common stock	1,050,000
Common Stock [Member]	'
Equity [Line Items]	'
Public offering of common stock	7,000,000
Net proceeds from equity issue	286,300
Common Stock [Member] | Underwriters Overallotment Option [Member]	'
Equity [Line Items]	'
Net proceeds from equity issue	$43,000

Operating_Segments_Additional_

Operating Segments - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue, Major Customer [Line Items]	'	'	'
Number of reportable segment	1	'	'
Consolidated revenues, excluding derivative instruments	10.00%	'	'
Number of customers accounted for more than 10% of the Company's consolidated revenue	0	'	'
Enterprise Products Operating LLC [Member]	'	'	'
Revenue, Major Customer [Line Items]	'	'	'
Consolidated revenues, excluding derivative instruments	21.00%	21.00%	'
Shell Trading (US) Company [Member]	'	'	'
Revenue, Major Customer [Line Items]	'	'	'
Consolidated revenues, excluding derivative instruments	23.00%	21.00%	25.00%
Exxon Mobil Corporation [Member]	'	'	'
Revenue, Major Customer [Line Items]	'	'	'
Consolidated revenues, excluding derivative instruments	'	13.00%	10.00%
Calpine Energy Services [Member]	'	'	'
Revenue, Major Customer [Line Items]	'	'	'
Consolidated revenues, excluding derivative instruments	'	12.00%	24.00%
Regency Gas Services [Member]	'	'	'
Revenue, Major Customer [Line Items]	'	'	'
Consolidated revenues, excluding derivative instruments	'	'	17.00%

Operating_Segments_Schedule_of

Operating Segments - Schedule of Geographical Revenue Information (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	$204,810	$194,568	$236,520	$178,120	$178,308	$122,752	$197,981	$114,458	$814,018	$613,499	$446,200
Eagle Ford [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	764,251	561,143	354,741
Permian [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	52,603	'	'
Other [Member]	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Total revenues	'	'	'	'	'	'	'	'	$4,259	$11,811	$72,796

Operating_Segments_Schedule_of1

Operating Segments - Schedule of Geographical Revenue Information (Parenthetical) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting [Abstract]	'	'	'
Hedging gains	($7,095)	$40,545	$1,233

Guarantor_Subsidiaries_Additio

Guarantor Subsidiaries - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013
Guarantees [Abstract]	'
Number of subsidiaries with restricted assets that exceed 25% of net assets	'None
Maximum percentage of non-transferrable net assets	25.00%

Supplemental_Oil_and_Gas_Discl2

Supplemental Oil and Gas Disclosures - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Period of time when a location is scheduled to be drilled that the undrilled location can be classified as having undeveloped reserves	'Five years	'	'
Primary reserves estimator years of experience, in years	'36 years	'	'
President and COO years of experience, in years	'35 years	'	'
Engineer and Geologist charged with the Company's audit years of experience, in years	'50 years	'	'
Asset retirement costs	$22.20	$15.10	$18

Supplemental_Oil_and_Gas_Discl3

Supplemental Oil and Gas Disclosures - Summary of Capitalized Costs Relating to Oil, NGL and Gas Producing Activities (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Extractive Industries [Abstract]	'	'	'
Proved properties	$3,951,397	$2,829,431	$2,297,312
Unproved properties	755,438	95,540	141,016
Total	4,706,835	2,924,971	2,438,328
Less: Accumulated depletion	-2,003,893	-1,797,203	-1,649,403
Net capitalized costs	$2,702,942	$1,127,768	$788,925

Supplemental_Oil_and_Gas_Discl4

Supplemental Oil and Gas Disclosures - Costs Incurred in Oil, NGL and Natural Gas Property Acquisition, Exploration and Development Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Acquisition costs, Proved	$290,273	'	'
Acquisition costs, Unproved	672,634	18,753	10,605
Acquisition costs, Subtotal	962,907	18,753	10,605
Exploration costs	534,881	93,542	98,781
Development costs	338,882	531,957	369,865
Total	$1,836,670	$644,252	$479,251

Supplemental_Oil_and_Gas_Discl5

Supplemental Oil and Gas Disclosures - Results of Operations for Oil, NGL and Natural Gas Producing Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Oil, NGL and natural gas producing revenues	$821,113	$572,954	$427,537
Production costs	155,749	110,977	69,289
Depreciation, depletion and amortization	218,571	154,223	123,244
Income before income taxes	446,793	307,754	235,004
Income tax provision	159,505	115,716	83,896
Results of operations	$287,288	$192,038	$151,108

Supplemental_Oil_and_Gas_Discl6

Supplemental Oil and Gas Disclosures - Results of Operations for Oil, NGL and Natural Gas Producing Activities (Parenthetical) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Effects of derivative gains	$7.10	$40.50	$18.70

Supplemental_Oil_and_Gas_Discl7

Supplemental Oil and Gas Disclosures - Summary of Net Proved and Proved Developed Reserve (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	MBoe	MBoe	MBoe	MBoe
Reserve Quantities [Line Items]	'	'	'	'
Revisions of previous estimates	'	1,709	'	'
Extensions, discoveries and other additions	83,447	'	'	'
Equivalents (MBoe) [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Net proved reserves, Beginning balance	200,905	160,915	79,819	'
Revisions of previous estimates	-10,606	-1,709	22,212	'
Purchases in place	22,916	298	'	'
Extensions, discoveries and other additions	83,447	65,641	82,420	'
Sales in place	'	-10,629	-13,464	'
Production	-18,121	-13,611	-10,072	'
Net proved reserves, Ending balance	278,541	200,905	160,915	'
Proved Developed Reserves	90,324	74,092	57,947	40,817
Proved Undeveloped Reserves	188,217	126,813	102,968	39,002
Natural Gas (MMcf) [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Net proved reserves, Beginning balance	509,453	445,956	288,927	'
Revisions of previous estimates	-9,580	-10,107	60,712	'
Purchases in place	36,523	744	'	'
Extensions, discoveries and other additions	180,570	158,788	210,292	'
Sales in place	'	-52,075	-80,582	'
Production	-40,343	-33,853	-33,393	'
Net proved reserves, Ending balance	676,623	509,453	445,956	'
Proved Developed Reserves	217,328	178,214	177,278	183,954
Proved Undeveloped Reserves	459,295	331,239	268,678	104,973
Natural Gas Liquids (MBbl) [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Net proved reserves, Beginning balance	71,573	50,219	19,326	'
Revisions of previous estimates	-65	4,923	7,192	'
Purchases in place	5,857	104	'	'
Extensions, discoveries and other additions	28,342	22,440	26,344	'
Sales in place	'	-1,641	'	'
Production	-6,398	-4,472	-2,643	'
Net proved reserves, Ending balance	99,309	71,573	50,219	'
Proved Developed Reserves	31,542	25,068	16,635	6,471
Proved Undeveloped Reserves	67,767	46,505	33,584	12,855
Oil (MBbl) [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Net proved reserves, Beginning balance	44,424	36,370	12,401	'
Revisions of previous estimates	-8,945	-4,947	4,839	'
Purchases in place	10,972	70	'	'
Extensions, discoveries and other additions	25,010	16,737	21,027	'
Sales in place	'	-309	-34	'
Production	-4,999	-3,497	-1,863	'
Net proved reserves, Ending balance	66,462	44,424	36,370	'
Proved Developed Reserves	22,560	19,321	11,766	3,687
Proved Undeveloped Reserves	43,902	25,103	24,604	8,714

Supplemental_Oil_and_Gas_Discl8

Supplemental Oil and Gas Disclosures - Summary of Net Proved and Proved Developed Reserve (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	Degrees	MBbls	Well
	MBoe	MBoe	MBoe
		MMcf
Reserve Quantities [Line Items]	'	'	'	'
Crude oil reserve	65.00%	92.00%	97.00%	95.00%
Crude oil API gravity	55	'	'	'
Upward revisions attributable to performance	'	'	22,212	'
Number of gates ranch wells	'	'	35	'
Number of wells have greater than twelve month of production history	'	'	22	'
Extensions, discoveries and other additions	83,447	'	'	'
Downward revision by the company	'	1,709	'	'
Downward oil revision	'	4,947	'	'
Upward natural gas liquid revision	'	4,923	'	'
Downward natural gas revision	'	10,107	'	'
Decrease in historical average commodity price for natural gas	'	2.76	4.12	'
Gates Acquisition [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Downward revision by the company	10,606	'	'	'
Eagle Ford [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Extensions, discoveries and other additions	70,626	65,641	82,420	'
Proved undeveloped location	'	'	91	'
Number of wells	106	54	13	'
Number of wells	79	37	'	'
Permian Basin areas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Extensions, discoveries and other additions	12,821	'	'	'
Number of wells	84	'	'	'
Number of wells	30	'	'	'
Permian [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Purchases in place	22,916	'	'	'

Supplemental_Oil_and_Gas_Discl9

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	$11,596	$8,252	$7,292
Future production costs	-3,412	-2,081	-1,358
Future development costs	-2,010	-1,118	-1,008
Future income taxes	-1,533	-1,385	-1,462
Future net cash flows	4,641	3,668	3,464
Discount to present value at 10% annual rate	-2,347	-1,827	-1,758
Standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves	2,294	1,841	1,706
Proved Developed [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	3,826	3,239	2,527
Future production costs	-1,224	-854	-542
Future development costs	-20	-8	-18
Future income taxes	-641	-652	-584
Future net cash flows	1,941	1,725	1,383
Discount to present value at 10% annual rate	-982	-859	-702
Standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves	959	866	681
Proved Undeveloped [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future cash inflows	7,770	5,013	4,765
Future production costs	-2,188	-1,227	-816
Future development costs	-1,990	-1,110	-990
Future income taxes	-892	-733	-878
Future net cash flows	2,700	1,943	2,081
Discount to present value at 10% annual rate	-1,365	-968	-1,056
Standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves	$1,335	$975	$1,025

Recovered_Sheet1

Supplemental Oil and Gas Disclosures - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Discount to present value	10.00%	10.00%	10.00%

Recovered_Sheet2

Supplemental Oil and Gas Disclosures - Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Standardized measure - beginning of year	$1,841	$1,706	$697
Sales and transfers of crude oil, NGLs and natural gas produced, net of production costs	-665	-462	-358
Revisions to estimates of proved reserves:	'	'	'
Net changes in prices and production costs	-268	-591	39
Extensions, discoveries, additions and improved recovery, net of related costs	849	814	1,117
Development costs incurred	275	220	370
Changes in estimated future development costs	86	54	-26
Revisions of previous quantity estimates	-127	-12	357
Accretion of discount	244	229	143
Net change in income taxes	-113	-17	-549
Purchases of reserve in place	216	6	'
Sales of reserves in place	'	-104	-79
Changes in timing and other	-44	-2	-5
Standardized measure - end of year	$2,294	$1,841	$1,706

Quarterly_Selected_Financial_D2

Quarterly Selected Financial Data (Unaudited) - Schedule of Quarterly Financial Information (Detail) (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, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Revenues	$204,810	$194,568	$236,520	$178,120	$178,308	$122,752	$197,981	$114,458	$814,018	$613,499	$446,200
Operating income	55,891	72,306	131,703	86,305	78,474	33,442	127,111	40,541	346,205	279,568	178,411
Net income	$29,495	$41,025	$75,352	$53,480	$42,340	$17,689	$76,969	$22,297	$199,352	$159,295	$100,546
Basic earnings per share	$0.48	$0.67	$1.28	$1.01	$0.81	$0.34	$1.47	$0.43	$3.40	$3.03	$1.93
Diluted earnings per share	$0.48	$0.67	$1.27	$1.01	$0.80	$0.33	$1.46	$0.42	$3.39	$3.01	$1.91