Approach Resources (AREXQ) 10-K 26 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 23, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	AREX
Entity Registrant Name	Approach Resources Inc
Entity Central Index Key	1405073
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		40,581,110
Entity Public Float			$812

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
CURRENT ASSETS:
Cash and cash equivalents	$432	$58,761
Restricted cash		7,350
Accounts receivable:
Joint interest owners	132	158
Oil, NGL and gas sales	19,635	22,871
Unrealized gain on commodity derivatives	39,951
Prepaid expenses and other current assets	929	592
Deferred income taxes - current		681
Total current assets	61,079	90,413
PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting	1,708,278	1,320,195
Furniture, fixtures and equipment	5,561	2,537
Total oil and gas properties and equipment	1,713,839	1,322,732
Less accumulated depletion, depreciation and amortization	-382,180	-275,702
Net oil and gas properties and equipment	1,331,659	1,047,030
Other assets	8,689	8,041
Total assets	1,401,427	1,145,484
CURRENT LIABILITIES:
Accounts payable	33,336	38,575
Oil, NGL and gas sales payable	8,536	6,101
Deferred income taxes - current	14,242
Accrued liabilities	50,738	37,918
Unrealized loss on commodity derivatives		1,847
Total current liabilities	106,852	84,441
NON-CURRENT LIABILITIES:
Senior secured credit facility	150,000	0
Senior notes	250,000	250,000
Deferred income taxes	110,677	91,883
Unrealized loss on commodity derivatives		315
Asset retirement obligations	9,571	8,350
Total liabilities	627,100	434,989
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS' EQUITY :
Preferred stock, $0.01 par value, 10,000,000 shares authorized none outstanding
Common stock, $0.01 par value, 90,000,000 shares authorized, 39,814,199 and 39,047,699 issued and outstanding, respectively	399	390
Additional paid-in capital	572,888	565,237
Retained earnings	201,040	144,868
Total stockholders' equity	774,327	710,495
Total liabilities and stockholders' equity	$1,401,427	$1,145,484

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	90,000,000	90,000,000
Common stock, issued	39,814,199	39,047,699
Common stock, outstanding	39,814,199	39,047,699

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES:
Oil, NGL and gas sales	$258,529	$181,302	$128,892
EXPENSES:
Lease operating	32,701	19,152	19,002
Production and ad valorem taxes	15,934	12,840	9,255
Exploration	3,831	2,238	4,550
General and administrative	32,104	26,524	24,903
Depletion, depreciation and amortization	106,802	76,956	60,381
Total expenses	191,372	137,710	118,091
OPERATING INCOME	67,157	43,592	10,801
OTHER:
Interest expense, net	-21,651	-14,084	-4,737
Equity in (losses) earnings of investee	-181	156	-108
Gain on sale of equity method investment		90,743
Realized gain (loss) on commodity derivatives	2,359	-1,048	-108
Unrealized gain (loss) on commodity derivatives	42,113	-4,596	3,874
Other income	67
INCOME BEFORE INCOME TAX PROVISION	89,864	114,763	9,722
INCOME TAX PROVISION:
Current	-25	429
Deferred	33,717	42,078	3,338
NET INCOME	$56,172	$72,256	$6,384
EARNINGS PER SHARE:
Basic	$1.43	$1.85	$0.18
Diluted	$1.42	$1.85	$0.18
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic	39,407,733	38,997,815	34,965,182
Diluted	39,419,865	39,019,149	35,030,323

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Stockholders' Equity (USD $)	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]
In Thousands, except Share data
Beginning balance, value at Dec. 31, 2011	$467,449	$331	$400,890	$66,228
Beginning balance, shares at Dec. 31, 2011		33,093,594
Issuance of common stock upon exercise of options, value	798	2	796
Issuance of common stock upon exercise of options, shares	216,822	216,822
Issuance of common stock, net of issuance costs, value	154,417	53	154,364
Issuance of common stock, net of issuance costs, shares		5,325,000
Issuance of common shares to directors for compensation, value	535		535
Issuance of common shares to directors for compensation, shares		16,935
Restricted stock issuance, net of cancellations, value		2	-2
Restricted stock issuance, net of cancellations, shares		293,382
Share-based compensation expense	6,930		6,930
Surrender of restricted shares for payment of income taxes, value	-3,045		-3,045
Surrender of restricted shares for payment of income taxes, shares		-116,365
Net income	6,384			6,384
Ending balance, value at Dec. 31, 2012	633,468	388	560,468	72,612
Ending balance, shares at Dec. 31, 2012		38,829,368
Issuance of common stock upon exercise of options, value	58		58
Issuance of common stock upon exercise of options, shares	3,750	3,750
Issuance of common shares to directors for compensation, value	630		630
Issuance of common shares to directors for compensation, shares		24,317
Restricted stock issuance, net of cancellations, value		2	-2
Restricted stock issuance, net of cancellations, shares		245,262
Share-based compensation expense	5,271		5,271
Surrender of restricted shares for payment of income taxes, value	-1,188		-1,188
Surrender of restricted shares for payment of income taxes, shares		-54,998
Net income	72,256			72,256
Ending balance, value at Dec. 31, 2013	710,495	390	565,237	144,868
Ending balance, shares at Dec. 31, 2013		39,047,699
Issuance of common stock upon exercise of options, shares	0
Issuance of common shares to directors for compensation, value	749	1	748
Issuance of common shares to directors for compensation, shares		40,898
Restricted stock issuance, net of cancellations, value		8	-8
Restricted stock issuance, net of cancellations, shares		782,708
Share-based compensation expense	7,498		7,498
Surrender of restricted shares for payment of income taxes, value	-587		-587
Surrender of restricted shares for payment of income taxes, shares		-57,106
Net income	56,172			56,172
Ending balance, value at Dec. 31, 2014	$774,327	$399	$572,888	$201,040
Ending balance, shares at Dec. 31, 2014		39,814,199

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
OPERATING ACTIVITIES:
Net income	$56,172	$72,256	$6,384
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization	106,802	76,956	60,381
Amortization of loan origination fees	1,546	1,048
Unrealized (gain) loss on commodity derivatives	-42,113	4,596	-3,874
Gain on sale of equity method investment		-90,743
Exploration expense	3,831	2,238	4,550
Share-based compensation expense	8,247	5,901	7,465
Deferred income taxes	33,717	42,078	3,338
Equity in losses (earnings) of investee	181	-156	108
Other non-cash items	-179
Changes in operating assets and liabilities:
Accounts receivable	3,262	-10,239	-2,550
Prepaid expenses and other current assets	-179	-45	296
Accounts payable	-5,826	12,471	9,271
Oil, NGL and gas sales payable	2,435	1,141	212
Accrued liabilities	12,310	8,078	5,004
Cash provided by operating activities	180,206	125,580	90,585
INVESTING ACTIVITIES:
Additions to oil and gas properties	-390,506	-296,409	-296,927
Proceeds from sale of equity method investment, net of contributions	-181	100,791	-10,000
Change in restricted cash	7,350	-7,350
Additions to furniture, fixtures and equipment, net	-3,024	-429	-487
Cash used in investing activities	-386,361	-203,397	-307,414
FINANCING ACTIVITIES:
Borrowings under credit facility	353,921	129,950	304,600
Repayment of amounts outstanding under credit facility	-203,921	-235,950	-242,400
Proceeds from issuance of senior notes		242,824
Proceeds from issuance of common stock, net offering costs			154,417
Proceeds from issuance of common stock upon exercise of stock options		58	798
Loan origination fees	-2,174	-1,071	-120
Cash provided by financing activities	147,826	135,811	217,295
CHANGE IN CASH AND CASH EQUIVALENTS	-58,329	57,994	466
CASH AND CASH EQUIVALENTS, beginning of year	58,761	767	301
CASH AND CASH EQUIVALENTS, end of year	432	58,761	767
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for income taxes	404
Cash paid for interest	20,232	12,392	4,192
SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION:
Acquisition of oil and gas properties	510	132
Asset retirement obligations capitalized	$898	$584	$409

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	1	Summary of Significant Accounting Policies
	Organization and Nature of Operations
	Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight gas sands. Our properties are primarily located in the Permian Basin in West Texas. We also own interests in the East Texas Basin.
	Consolidation, Basis of Presentation and Significant Estimates
	The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect our estimate of depletion expense as well as our impairment analyses. Significant assumptions also are required in our estimation of accrued liabilities, commodity derivatives, income tax provision, share-based compensation and asset retirement obligations. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior-year amounts have been reclassified to conform to current-year presentation. These classifications have no impact on the net income reported.
	Cash and Cash Equivalents
	We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible.
	Restricted Cash
	The restricted cash on our balance sheet for the year ended December 31, 2013 consisted of $7.4 million in proceeds from the sale of our equity method investment that were restricted pursuant to an escrow agreement. The escrow agreement terminated on June 1, 2014, and the cash held in escrow was subsequently released.
	Oil and Gas Properties
	Capitalized Costs.    Our oil and gas properties comprised the following (in thousands):
			December 31,
			2014			2013
	Mineral interests in properties:
	Unproved leasehold costs		$	46,240		$	47,096
	Proved leasehold costs			42,409			40,620
	Wells and related equipment and facilities			1,600,703			1,195,556
	Support equipment			8,518			10,773
	Uncompleted wells, equipment and facilities			10,408			26,150
	Total costs			1,708,278			1,320,195
	Less accumulated depreciation, depletion and amortization			(379,892	)		(273,915	)
	Net capitalized costs		$	1,328,386		$	1,046,280
	We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to exploration expense. There were no exploratory wells capitalized, pending determination of whether the wells have proved reserves, at December 31, 2014 or 2013. Geological and geophysical costs, including seismic studies are charged to exploration expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use and while these expenditures are excluded from our depletable base. Through December 31, 2014, we have capitalized no interest costs because our individual wells and infrastructure projects are generally developed in less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.
	On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization with no gain or loss recognized in income.
	Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment was $106.2 million, $76.5 million and $60 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are periodically evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets, as events or changes in circumstances indicate that the carrying values of those assets may not be recoverable. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. Estimating future net cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. We noted no impairment of our proved properties based on our analysis for the years ended December 31, 2014, 2013 and 2012.
	Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance.
	On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
	Other Property
	Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to 15 years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $588,000, $502,000 and $333,000 for the years ended December 31, 2014, 2013 and 2012, respectively.
	Equity Method Investment
	For investments in which we have the ability to exercise significant influence but do not have control, we follow the equity method of accounting. In September 2012, we entered into a joint venture to build an oil pipeline in Crockett and Reagan Counties, Texas, which is used to transport our oil to market. In October 2013, we completed the sale of the joint venture. As of December 31, 2014, we have no investments that are accounted for under the equity method. See Note 2 for equity method investment disclosures.
	Other Assets
	Other assets consist of deferred costs associated with the issuance of the $250 million principal amount of 7% Senior Notes due 2021 (the “Senior Notes”) and the amended and restated senior secured revolving credit facility (the “Credit Facility”). These costs are amortized over the life of the Senior Notes and the life of the Credit Facility on a straight-line basis, which approximates the amortization that would be calculated using an effective interest rate method.
	Financial Instruments
	The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, as of December 31, 2014 and 2013. See Note 7 for commodity derivative and Senior Notes fair value disclosures.
	Income Taxes
	We are subject to U.S. federal income taxes along with state income taxes in Texas. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in the consolidated statement of income.
	Based on our analysis, we did not have any uncertain tax positions as of December 31, 2014 or 2013. The Company’s income tax returns are subject to examination by the relevant taxing authorities as follows: U.S. Federal income tax returns for tax years 2011 and forward, Texas income and margin tax returns for tax years 2011 and forward, New Mexico income tax returns for years 2011 and forward, and Kentucky income tax returns for the years 2011 and forward. There are currently no income tax examinations underway for these jurisdictions.
	Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change.
	Derivative Activity
	We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized gain (loss) on commodity derivatives.”
	Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our natural gas and oil production. Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.
	Accrued Liabilities
	The following is a summary of our accrued liabilities at December 31, 2014 and 2013 (in thousands):
			2014			2013
	Capital expenditures accrual		$	43,870		$	30,606
	Operating expenses and other			6,868			7,312
	Total		$	50,738		$	37,918
	Asset Retirement Obligations
	Our asset retirement obligations relate to future plugging and abandonment expenses on oil and gas properties. Based on the expected timing of payments, the full asset retirement obligation is classified as non-current. There were no significant changes to the asset retirement obligations for the years ended December 31, 2014, 2013 and 2012.
	Share-Based Compensation
	We measure and record compensation expense for all share-based payment awards to employees and outside directors based on estimated grant date fair values. We recognize compensation costs for awards granted over the requisite service period based on the grant date fair value in general and administrative expense on our consolidated statements of operations.
	Earnings Per Common Share
	We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts):
			For the Years Ended December 31,
			2014			2013			2012
	Income (numerator):
	Net income — basic		$	56,172		$	72,256		$	6,384
	Weighted average shares (denominator):
	Weighted average shares — basic			39,407,733			38,997,815			34,965,182
	Dilution effect of share-based compensation, treasury method			12,132			21,334			65,141
	Weighted average shares — diluted			39,419,865			39,019,149			35,030,323
	Earnings per share:
Basic		$	1.43		$	1.85		$	0.18
Diluted		$	1.42		$	1.85		$	0.18
Oil and Gas Operations
Revenue and Accounts Receivable.    We recognize revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices.
Accounts receivable, joint interest owners, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil, NGL and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2014 or 2013. As of December 31, 2014, accounts receivable related to oil, NGL and gas sales includes $4.8 million from realized gains on commodity derivatives.
Oil, NGL and Gas Sales Payable.    Oil, NGL and gas sales payable represents amounts collected from purchasers for oil, NGL and gas sales which are either revenues due to other revenue interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 60 days of the end of the month in which the related production occurred.
Production Costs.    Production costs, including compressor rental and repair, pumpers’ and supervisors’ salaries, saltwater disposal, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on our consolidated statements of operations.
Exploration expenses.    Exploration expenses include delay rentals, geological and geophysical costs and dry hole costs.
Dependence on Major Customers.    For the year ended December 31, 2014, sales to DCP Midstream, LP (“DCP”) and JP Energy Development, LP (“JP Energy”) accounted for approximately 30% and 69%, respectively, of our total sales. In addition, substantially all of our accounts receivable related to oil and gas sales were due from JP Energy and DCP at December 31, 2014. As of December 31, 2014, we had dedicated all of our oil production from northern Project Pangea and Pangea West through 2022 to JP Energy. In addition, as of December 31, 2014, we had contracted to sell all of our NGLs and natural gas production from Project Pangea to DCP through January 2023. For the year ended December 31, 2013, sales to Wildcat Permian Services, LLC, DCP and JP Energy Permian, LLC accounted for approximately 30%, 27% and 23%, respectively, of our total sales. For the year ended December 31, 2012, we sold substantially all of our oil and gas produced to seven purchasers. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased purchasers. Although we are exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy.
Segment Reporting
The Company presently operates in one business segment, the exploration and production of oil, NGLs and natural gas.
Recent Accounting Pronouncements
In April 2014, the Financial Accounting Standards Board (“FASB”) issued guidance that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. Under the updated standard, a discontinued operation is (i) a component of an entity or group of components that has been disposed of by sale, disposed of other than by sale or is classified as held for sale that represents a strategic shift that has or will have a major effect on an entity’s operations and financial results, or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of the acquisition. This update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results. This accounting standards update is effective for annual reporting periods beginning on or after December 15, 2014, and will be applied prospectively. Adoption of this standard is not expected to have a significant impact on the consolidated financial statements.
In May 2014, the FASB issued an accounting standards update for “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Topic 605, Revenue Recognition.” This accounting standard update provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. This new guidance permits adoption through the use of either full or retrospective approach or a modified retrospective approach for annual reporting periods beginning on or after December 15, 2016, with early application not permitted. The Company has not determined which transition method it will use and is continuing to evaluate our existing revenue recognition policies to determine whether any contracts will be affected by the new requirements.

Equity_Method_Investment

Equity Method Investment	12 Months Ended
	Dec. 31, 2014
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investment	2	Equity Method Investment
	In September 2012, we entered into a joint venture to build an oil pipeline in Crockett and Reagan Counties, Texas, which is used to transport our oil to market. In October 2012, we made an initial contribution of $10 million to the joint venture for pipeline and facilities construction. In 2013, we contributed $8.3 million to the equity joint venture for pipeline and facilities construction prior to its sale in October 2013. Our contributions were recorded at cost and were included in noncurrent assets, “Equity method investment,” on our consolidated balance sheets and in investing activities, “Contribution to equity method investment,” on our consolidated statements of cash flows. Our share of the investee earnings was recorded on our consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012. In October 2013, we completed the sale of the joint venture, and net proceeds to Approach at closing totaled approximately $109.1 million, after deducting our share of transactional costs paid at closing. We recognized a pre-tax gain of $90.7 million related to this transaction, subject to normal post-closing adjustments, in 2013. Of the $109.1 million in proceeds, $7.4 million was restricted pursuant to an escrow agreement and recorded as restricted cash at December 31, 2013. The escrow agreement terminated on June 1, 2014, and the cash held in escrow was subsequently released. We incurred $0.2 million in post-closing working capital adjustments during the year ended December 31, 2014.

Public_Equity_Offerings

Public Equity Offerings	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Public Equity Offerings	3	Public Equity Offerings
	On September 19, 2012, we completed a public offering of 5 million shares of our common stock. The underwriters exercised their option and purchased an additional 325,000 shares on October 3, 2012. After deducting underwriting discounts and transaction costs of approximately $8 million, we received net proceeds of approximately $154.4 million. We used the proceeds of the 2012 equity offering to repay outstanding borrowings under our revolving credit facility, fund our capital expenditures for the Wolfcamp oil shale resource play and for general working capital needs.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	4	Long-Term Debt
	The following table provides a summary of our long-term debt at December 31, 2014, and December 31, 2013 (in thousands).
			December 31,		December 31,
			2014		2013
	Senior secured credit facility		$	150,000	$	—
	Senior Notes			250,000		250,000
	Total long-term debt		$	400,000	$	250,000
	Revolving Credit Facility
	The Credit Facility has a maturity date of May 7, 2019. At December 31, 2014, our borrowing base was $600 million, with aggregate lender commitments of $450 million and maximum commitments from the lenders of $1 billion. The borrowing base is redetermined semi-annually in April and October based on our oil, NGL and gas reserves. We, or the lenders, can each request one additional borrowing base redetermination each calendar year.
	Borrowings under the Credit Facility bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 0.50% to 1.50%, or the sum of the LIBOR rate plus an applicable margin ranging from 1.50% to 2.50%. In addition, we pay an annual commitment fee ranging from 0.375% to 0.50% of unused borrowings available under the Credit Facility. Margins vary based on the borrowings outstanding compared to the borrowing base of the lenders.
	On December 30, 2014, we entered into a second amendment to the Credit Facility. The second amendment, among other things, modifies the negative covenant allowing optional redemption of Permitted Unsecured Notes.
	We had $150 million of outstanding borrowings under the Credit Facility at December 31, 2014, compared to no outstanding borrowings at December 31, 2013. The weighted average interest rate applicable to borrowings under the Credit Facility at December 31, 2014, was 1.8%. We also had outstanding unused letters of credit under our Credit Facility totaling $0.3 million at December 31, 2014 and 2013, which reduce amounts available for borrowing under the Credit Facility.
	Obligations under the Credit Facility are secured by mortgages on substantially all of the oil and gas properties of the Company and its subsidiaries. The Company is required to maintain liens covering the oil and gas properties of the Company and its subsidiaries representing at least 80% of the total value of all oil and gas properties of the Company and its subsidiaries.
	Covenants
	The Credit Facility contains two principal financial covenants:
		•		a consolidated modified current ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of not less than 1.0 to 1.0 as of the last day of any fiscal quarter, and
		•		a consolidated interest coverage ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of consolidated EBITDAX to interest of not less than 2.5 to 1.0 as of the last day of any fiscal quarter.
	The Credit Facility also contains covenants restricting cash distributions and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, asset sales, investment in other entities and liens on properties.
	In addition, the obligations of the Company may be accelerated upon the occurrence of an Event of Default (as defined in the Credit Facility). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as defined in the Credit Facility), which includes instances where a third party becomes the beneficial owner of more than 50% of the Company’s outstanding equity interests entitled to vote.
	Senior Notes
	In June 2013, we completed our public offering of $250 million principal amount of 7% Senior Notes due 2021. Annual interest on the Senior Notes of $17.5 million is payable semi-annually on June 15 and December 15. We received net proceeds from the issuance of the Senior Notes of approximately $243 million, after deducting fees and expenses. We used a portion of the net proceeds from the offering to repay all outstanding borrowings under the Credit Facility, fund our capital expenditures for the development of our Wolfcamp shale oil resource play and for general working capital needs.
	We issued the Senior Notes under a senior indenture dated June 11, 2013, among the Company, our subsidiary guarantors and Wells Fargo Bank, National Association, as trustee. The senior indenture, as supplemented by a supplemental indenture dated June 11, 2013, is referred to as the “Indenture.”
	On and after June 15, 2016, we may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. Before June 15, 2016, we may redeem up to 35% of the Senior Notes at a redemption price of 107% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. In addition, before June 15, 2016, we may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the Senior Notes from holders. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our subsidiaries, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee:
		•		in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if the sale or other disposition otherwise complies with the indenture;
		•		in connection with any sale or other disposition of the capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if that guarantor no longer qualifies as a subsidiary of the Company as a result of such disposition and the sale or other disposition otherwise complies with the indenture;
		•		if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the indenture;
		•		upon defeasance or covenant defeasance of the notes or satisfaction and discharge of the indenture, in each case, in accordance with the indenture;
		•		upon the liquidation or dissolution of that guarantor, provided that no default or event of default occurs under the indenture as a result thereof or shall have occurred and is continuing; or
		•		in the case of any restricted subsidiary that, after the issue date of the notes is required under the indenture to guarantee the notes because it becomes a guarantor of indebtedness issued or an obligor under a credit facility with respect to the Company and/or its subsidiaries, upon the release or discharge in full from its (x) guarantee of such indebtedness or (y) obligation under such credit facility, in each case, which resulted in such restricted subsidiary’s obligation to guarantee the notes.
	The Indenture restricts our ability, among other things, to (i) sell certain assets, (ii) pay distributions on, redeem or repurchase, equity interests, (iii) incur additional debt, (iv) make certain investments, (v) enter into transactions with affiliates, (vi) incur liens and (vii) merge or consolidate with another company. These restrictions are subject to a number of important exceptions and qualifications. If at any time the Senior Notes are rated investment grade by both Moody’s Investors Service and Standard & Poor’s Ratings Services and no default (as defined in the Indenture) has occurred and is continuing, many of these restrictions will terminate. The Indenture contains customary events of default.
	On December 15, 2014, we made a semi-annual interest payment of $8.8 million.
	Subsidiary Guarantors
	The Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. Approach Resources Inc. is a holding company with no independent assets or operations. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no significant restrictions on the Company’s ability, or the ability of any subsidiary guarantor, to obtain funds from its subsidiaries through dividends, loans, advances or otherwise.
	At December 31, 2014, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.

ShareBased_Compensation

Share-Based Compensation	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation	5	Share-Based Compensation
	In June 2007, the board of directors and stockholders approved the 2007 Stock Incentive Plan (“the 2007 Plan”). Under the 2007 Plan, we may grant restricted stock, stock options, stock appreciation rights, restricted stock units, performance awards, unrestricted stock awards and other incentive awards. Under a Second Amendment to the 2007 Plan effective May 31, 2012, the maximum number of shares of common stock available for the grant of awards under the 2007 Plan after May 31, 2012, is 2,100,000. Awards of any stock options are to be priced at not less than the fair market value at the date of the grant. The vesting period of any stock award is to be determined by the board or an authorized committee at the time of the grant. The term of each stock option is to be fixed at the time of grant and may not exceed 10 years. Shares issued upon stock options exercised are issued as new shares.
	Share-based compensation expense amounted to $8.2 million, $5.9 million and $7.5 million for the years ended December 31, 2014, 2013 and 2012, respectively. Such amounts represent the estimated fair value of stock awards for which the requisite service period elapsed during those periods. Included in share-based compensation expense in 2014 and 2013 is a benefit of $1.1 million and $1 million, respectively, for forfeited stock awards related to the retirement of two of our executive officers. Share-based compensation expense for the years ended December 31, 2014, 2013 and 2012, included $749,000, $630,000 and $535,000, respectively, related to grants to nonemployee directors.
	Stock Options
	There were no stock option grants during the years ended December 31, 2014, 2013 and 2012. As of December 31, 2014, all stock options are fully vested.
	The following table summarizes stock options outstanding and activity as of and for the years ended December 31, 2014, 2013 and 2012, (dollars in thousands):
			Shares			Weighted		Weighted		Aggregate
			Subject to			Average		Average		Intrinsic
			Stock			Exercise		Remaining		Value
			Options			Price		Contractual
								Term
								(in years)
	Outstanding at January 1, 2012			260,097		$	5.13		1.94	$	6,315
	Granted			—			—
	Exercised			(216,822	)		3.68
	Canceled			—			—
	Outstanding at December 31, 2012			43,275		$	12.38		4.88	$	547
	Granted			—			—
	Exercised			(3,750	)		15.42
	Canceled			—			—
	Outstanding at December 31, 2013			39,525		$	12.09		3.84	$	285
	Granted			—			—
	Exercised			—			—
	Canceled			—			—
	Outstanding at December 31, 2014			39,525		$	12.09		2.86	$	—
	Exercisable (fully vested) at December 31, 2014			39,525		$	12.09		2.86	$	—
	There were no options exercised during the year ended December 31, 2014. The intrinsic value of the options exercised during the years ended December 31, 2013 and 2012 was $35,000 and $7 million, respectively. There was no tax benefit recognized related to the stock option exercises in the years ended December 31, 2013 and 2012.
	Nonvested Shares
	Share grants totaling 992,919 shares, 377,379 shares and 316,279 shares with an approximate aggregate fair market value of $14.4 million, $8.6 million and $10.4 million at the time of grant were granted to employees during the years ended December 31, 2014, 2013 and 2012, respectively. Included in the share grants for 2014, 2013 and 2012, are 245,157 shares, 183,672 shares and 129,890 shares, respectively, awarded to our executive officers. The aggregate fair market value of these shares on the grant date was $4.5 million, $4.4 million and $4.8 million, respectively, to be expensed over a remaining service period of approximately three years, subject to certain performance restrictions.
	A summary of the status of nonvested shares for the years ended December 31, 2014, 2013 and 2012, is presented below:
			Shares			Weighted
						Average
						Grant-Date
						Fair Value
	Nonvested at January 1, 2012			790,122			15.06
	Granted			316,279			32.94
	Vested			(333,957	)		14.57
	Canceled			(19,365	)		23.74
	Nonvested at December 31, 2012			753,079			22.35
	Granted			377,379			22.77
	Vested			(299,110	)		18.79
	Canceled			(132,117	)		24.47
	Nonvested at December 31, 2013			699,231			23.7
	Granted			992,919			14.48
	Vested			(400,429	)		20.18
	Canceled			(169,311	)		25.57
	Nonvested at December 31, 2014			1,122,410		$	16.52
	As of December 31, 2014, unrecognized compensation expense related to the nonvested shares amounted to $11.6 million, which will be recognized over a remaining service period of two years.
	Subsequent Restricted Share Award
	Subsequent to December 31, 2014, 724,249 restricted shares were awarded to our executive officers, of which 482,833 shares are subject to certain performance conditions and 241,416 shares are subject to three-year total shareholder return (“TSR”) conditions, assuming maximum TSR. The aggregate fair market value of the shares subject to performance conditions on the grant date was $3.4 million, to be expensed over a remaining service period of approximately three years.
	Employee Benefit Plan
	The Company has a defined contribution employee benefit plan covering substantially all of its employees. We make a matching contribution equal to 100% of each pre-tax dollar contributed by the participant on the first 3% of eligible compensation and 50% on the next 2% of eligible compensation. The Company made contributions to the plan of approximately $310,000, $279,000 and $179,000 during the years ended December 31, 2014, 2013 and 2012, respectively.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	6	Income Taxes
	Our provision for income taxes comprised the following (in thousands):
			Years Ended December 31,
			2014			2013			2012
	Current:
	Federal		$	(25	)	$	429		$	—
	State			—			—			—
	Total current provision for income taxes		$	(25	)	$	429		$	—
	Deferred:
	Federal		$	32,754		$	41,175		$	3,359
	State			963			903			(21	)
	Total deferred provision for income taxes		$	33,717		$	42,078		$	3,338
	Total income tax expense differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income (in thousands):
			Years Ended December 31,
			2014			2013			2012
	Statutory tax at 35%		$	31,452		$	40,167		$	3,306
	State taxes, net of federal impact			989			709			(21	)
	Share-based compensation tax shortfall			1,670			—			—
	Permanent differences			37			34			53
	Other differences			(456	)		1,597			—
	Total		$	33,692		$	42,507		$	3,338
	In 2014, the Company recorded a tax shortfall related to share-based compensation of $1.7 million. This shortfall is for grants in which the realized tax deduction was less than the expense booked for these grants due to a decline in share price from the time of grant. Although we had excess tax benefits related to share-based compensation in prior years, this benefit was not recorded as the excess tax benefits were not realized due to our net operating loss carryforwards.
	Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax basis of assets and liabilities. Our net deferred tax assets and liabilities are recorded as a long-term liability of $110.7 million and $91.9 million at December 31, 2014 and 2013, respectively. At December 31, 2014, $14.2 million of deferred taxes expected to be realized within one year were included in current liabilities. At December 31, 2013, $0.7 million of deferred taxes expected to be realized within one year were included in current assets.
	Significant components of net deferred tax assets and liabilities are (in thousands):
			Years Ended December 31,
			2014			2013
	Deferred tax assets:
	Current portion of unrealized loss on commodity derivatives		$	—		$	681
	Net operating loss carryforwards			46,730			26,674
	Unrealized loss on commodity derivatives			—			113
	Other			1,305			295
	Total deferred tax assets			48,035			27,763
	Deferred tax liabilities:
	Difference in depreciation, depletion and capitalization methods — oil and gas properties			(158,647	)		(118,965	)
	Unrealized gain on commodity derivatives			(14,307	)		—
	Total deferred tax liabilities			(172,954	)		(118,965	)
	Net deferred tax liability		$	(124,919	)	$	(91,202	)
	Net operating loss carryforwards for tax purposes have the following expiration dates (in thousands):
	Expiration Dates		Amounts			Stock			Total
						Adjustments
	2030		$	4,083		$	750		$	4,833
	2031			18,642			1,012			19,654
	2032			51,931			2,724			54,655
	2033			524			741			1,265
	2034			54,939			—			54,939
	Total		$	130,119		$	5,227		$	135,346
	As of December 31, 2014, we had net operating loss carryforwards of approximately $135.3 million, of which approximately $5.2 million was generated from the benefit of stock options. When these benefits are realized, they will be credited to additional paid-in capital.

Derivatives

Derivatives

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

7

Derivatives

At December 31, 2014, we had the following commodity derivatives positions outstanding:

Commodity and Period

Contract

Volume Transacted

Contract Price

Type

Crude Oil

January 2015 — March 2015

Collar

1,500 Bbls/d

$85.00/Bbl – $95.30/Bbl

January 2015 — December 2015

Collar

1,600 Bbls/d

$84.00/Bbl – $91.00/Bbl

January 2015 — December 2015

Collar

1,000 Bbls/d

$90.00/Bbl – $102.50/Bbl

January 2015 — December 2015

Three-Way

500 Bbls/d

$75.00/Bbl – $84.00/Bbl –

Collar

$94.00/Bbl

January 2015 — December 2015

Three-Way

500 Bbls/d

$75.00/Bbl – $84.00/Bbl –

Collar

$95.00/Bbl

Natural Gas

January 2015 — June 2015

Collar

80,000 MMBtu/month

$4.00/MMBtu – $4.74/MMBtu

January 2015 — December 2015

Swap

200,000

$4.10/MMBtu

MMBtu/month

January 2015 — December 2015

Collar

130,000

$4.00/MMBtu – $4.25/MMBtu

MMBtu/month

The following summarizes the fair value of our open commodity derivatives as of December 31, 2014 and 2013 (in thousands):

Asset Derivatives

Liability Derivatives

Fair Value

Fair Value

Balance Sheet

December 31,

December 31,

Balance Sheet

December 31,

December 31,

Location

2014

2013

Location

2014

2013

Derivatives not designated as hedging instruments

Commodity derivatives

Unrealized gain on commodity derivatives

$

39,951

$

9,108

Unrealized loss on commodity derivatives

$

—

$

11,270

The following summarizes the change in the fair value of our commodity derivatives (in thousands):

Income Statement Location

Year Ended December 31,

2014

2013

2012

Derivatives not designated as hedging instruments

Commodity derivatives

Unrealized gain (loss) on commodity derivatives

$

42,113

$

(4,596

)

$

3,874

Realized gain (loss) on commodity derivatives

2,359

(1,048

)

(108

)

$

44,472

$

(5,644

)

$

3,766

Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair value of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.

To estimate the fair value of our commodity derivatives positions, we use market data or 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. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based upon the hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

•

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At December 31, 2014, we had no Level 1 measurements.

•

Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At December 31, 2014, all of our commodity derivatives were valued using Level 2 measurements.

•

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At December 31, 2014, we had no Level 3 measurements.

Financial Instruments Not Recorded at Fair Value

The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands).

December 31, 2014

Carrying

Fair Value

Amount

Senior Notes

$

250,000

$

175,300

The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	8	Commitments and Contingencies
	We periodically enter into contractual arrangements under which we are committed to expend funds to drill wells in the future, including agreements to secure drilling rig services, which require us to make future minimum payments to the rig operators. We record drilling commitments in the periods in which well capital expenditures are incurred or rig services are provided. Our commitment under daywork drilling contracts was $7.3 million at December 31, 2014.
	At December 31, 2014, we had outstanding employment agreements with all four of our executive officers that contained automatic renewal provisions providing that such agreements may be automatically renewed for successive terms of one year unless the employment is terminated at the end of the term by written notice given to the employee not less than 60 days prior to the end of such term. Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, was approximately $6.3 million at December 31, 2014. This estimate assumes the maximum potential bonus for 2015 is earned by each executive officer during 2015.
	We lease our office space in Fort Worth, Texas, under a non-cancelable agreement that expires on December 31, 2019. We also have non-cancelable operating lease commitments related to office equipment that expire by 2019. The following is a schedule by years of future minimum rental payments required under our operating lease arrangements as of December 31, 2014 (in thousands):
	2015		$	695
	2016			678
	2017			671
	2018			673
	2019			668
	Total		$	3,385
	Rent expense under our lease arrangements amounted to $717,000, $734,000 and $716,000 for the years ended December 31, 2014, 2013 and 2012, respectively.
	Litigation
	We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows.
	Environmental Issues
	We are engaged in oil and gas exploration and production and may become subject to certain liabilities or damages as they relate to environmental clean up of well sites or other environmental restoration or ground water contamination, in connection with drilling or operating oil and gas wells. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up, restoration or contamination, we would be responsible for curing such a violation or paying damages. No claim has been made, nor are we aware of any liability that exists, as it relates to any environmental clean up, restoration, contamination or the violation of any rules or regulations relating thereto.

Oil_and_Gas_Producing_Activiti

Oil and Gas Producing Activities	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Oil and Gas Producing Activities	9	Oil and Gas Producing Activities
	Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities (in thousands):
			For the Years Ended December 31,
			2014			2013			2012
	Property acquisition costs:
	Unproved properties		$	4,578		$	5,857		$	2,335
	Proved properties			—			1,000			5,407
	Exploration costs			3,831			2,238			4,550
	Development costs(1)			382,995			287,898			285,039
	Total costs incurred		$	391,404		$	296,993		$	297,331
	-1	For the years ended December 31, 2014, 2013 and 2012, development costs include $898,000, $584,000 and $409,000 in non-cash asset retirement obligations, respectively.
	Set forth below is certain information regarding the results of operations for oil and gas producing activities (in thousands):
			For the Years Ended December 31,
			2014			2013			2012
	Revenues		$	258,529		$	181,302		$	128,892
	Production costs			(48,635	)		(31,992	)		(28,257	)
	Exploration expense			(3,831	)		(2,238	)		(4,550	)
	Depletion			(106,802	)		(76,956	)		(60,381	)
	Income tax expense			(35,387	)		(24,996	)		(12,139	)
	Results of operations		$	63,874		$	45,120		$	23,565

Disclosures_About_Oil_and_Gas_

Disclosures About Oil and Gas Producing Activities (unaudited)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Disclosures About Oil and Gas Producing Activities (unaudited)	10	Disclosures About Oil and Gas Producing Activities (unaudited)
	Proved Reserves
	All of our estimated oil and natural gas reserves are attributable to properties within the United States, primarily in the Permian Basin in West Texas. The estimates of proved reserves and related valuations for the years ended December 31, 2014, 2013 and 2012, were prepared by DeGolyer and MacNaughton, independent petroleum engineers. Each year’s estimate of proved reserves and related valuations were also prepared in accordance with then-current rules and guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board.
	The following table summarizes the prices used in the reserve estimates for 2014, 2013 and 2012. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows:
			2014			2013			2012
	Oil (per Bbl)		$	94.56		$	97.28		$	90.21
	Natural gas liquids (per Bbl)		$	31.5		$	30.16		$	37.88
	Gas (per Mcf)		$	4.55		$	3.66		$	2.62
	Oil, NGL and natural gas reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
	The following table provides a summary of the changes of the total proved reserves for the years ended December 31, 2014, 2013 and 2012, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year.
	Total Proved Reserves		Oil			NGLs			Natural Gas			Total
			(MBbls)			(MBbls)			(MMcf)			(MBoe)
	Balance — December 31, 2011			18,051			29,123			178,807			76,975
	Extensions and discoveries			21,993			8,639			49,372			38,861
	Production			(969	)		(904	)		(6,089	)		(2,888	)
	Revisions to previous estimates			(1,823	)		(7,758	)		(47,330	)		(17,469	)
	Balance — December 31, 2012			37,252			29,100			174,760			95,479
	Extensions and discoveries			14,252			6,531			38,993			27,282
	Purchases of minerals in place			62			14			197			109
	Production(1)			(1,444	)		(951	)		(6,737	)		(3,517	)
	Revisions to previous estimates			(4,055	)		(2,102	)		8,789			(4,692	)
	Balance — December 31, 2013			46,067			32,593			216,002			114,661
	Extensions and discoveries			19,347			10,658			79,454			43,247
	Production(1)			(2,024	)		(1,461	)		(10,773	)		(5,281	)
	Revisions to previous estimates			(8,052	)		(883	)		15,337			(6,379	)
	Balance — December 31, 2014			55,338			40,907			300,020			146,248
	-1	Production includes 560 MMcf and 1,390 MMcf related to field fuel in 2013 and 2014, respectively.
	Total Proved Reserves		Oil			NGLs			Natural Gas			Total
			(MBbls)			(MBbls)			(MMcf)			(MBoe)
	Proved Developed Reserves:
	January 1, 2012			5,542			13,945			84,743			33,611
	December 31, 2012			8,816			11,761			73,178			32,774
	January 1, 2013			8,816			11,761			73,178			32,774
	December 31, 2013			13,646			14,919			99,742			45,189
	January 1, 2013			13,646			14,919			99,742			45,189
	December 31, 2014			17,978			19,082			138,961			60,220
	Proved Undeveloped Reserves:
	January 1, 2012			12,509			15,178			94,064			43,365
	December 31, 2012			28,436			17,339			101,582			62,705
	January 1, 2013			28,436			17,339			101,582			62,705
	December 31, 2013			32,421			17,674			116,260			69,472
	January 1, 2014			32,421			17,674			116,260			69,472
	December 31, 2014			37,360			21,825			161,059			86,028
	The following is a discussion of the material changes in our proved reserve quantities for the years ended December 31, 2014, 2013 and 2012:
	Year Ended December 31, 2014
	Extensions and discoveries for 2014 were 43.2 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2014, we recorded downward revisions totaling 6.4 MMBoe, including the reclassification of 9.3 MMBoe of proved undeveloped reserves to probable undeveloped. The reserves reclassified from proved undeveloped to probable undeveloped included 5.8 MMBoe attributable to vertical Canyon locations in Project Pangea that we do not plan to drill within five years from their initial booking, and 3.5 MMBoe attributable to horizontal Wolfcamp locations that are no longer included in our proved development plan. Revisions also included 6.3 MMBoe of positive net revisions attributable to updated well performance and 0.7 MMBoe of positive revisions due to pricing, offset by 4.1 MMBoe of negative revisions resulting from updated technical parameters and costs. We produced 5.3 MMBoe during 2014. This production included 1,390 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.
	Year Ended December 31, 2013
	Extensions and discoveries for 2013 were 27.3 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. We produced 3.5 MMBoe during 2013. This production included 560 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lifts) before the gas was delivered to a sales point. During 2013, we recorded downward revisions totaling 4.7 MMBoe. Revisions included the reclassification of 7.8 MMBoe of proved undeveloped reserves to probable undeveloped, partially offset by 3.1 MMBoe of positive revisions attributable to gas that will be produced and utilized as field fuel. The reserves reclassified from proved undeveloped to probable undeveloped were attributable to vertical Canyon locations in Project Pangea. Due to our horizontal Wolfcamp development project, including pad drilling, postponement of these deeper locations beyond five years from initial booking was necessary to integrate their development with the shallower Clearfork and Wolfcamp target zones.
	Year Ended December 31, 2012
	Extensions and discoveries of 38.9 MMBoe for 2012 were primarily attributable to ongoing development of Project Pangea in the Wolfcamp oil shale resource play in the Permian Basin. We produced 2.9 MMBoe during 2012, 99.4% of which is attributable to our assets in the Permian Basin. We recorded downward revisions of 17.5 MMBoe to the December 31, 2011, estimates of our proved reserves at year-end 2012. Downward revisions of 17.5 MMBoe include 8.9 MMBoe of deeper, Canyon reserves in southeast Project Pangea that we reclassified to probable undeveloped. Due to our horizontal Wolfcamp development project, including pad drilling, postponement of these deeper Canyon locations beyond five years from initial booking was necessary in order to integrate their development with shallower Clearfork and Wolfcamp target zones. Revisions in 2012 also included 3.3 MMBoe of performance revisions related to vertical Canyon wells in Project Pangea, 2.9 MMBoe of revisions resulting from technical evaluations and 2.4 MMBoe of revisions resulting from lower natural gas and NGL prices in 2012.
	Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
	The Standardized Measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference.
	Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
	The following table provides the Standardized Measure of discounted future net cash flows at December 31, 2014, 2013 and 2012:
			Years Ended December 31,
			2014			2013			2012
	Future cash flows		$	7,430,368		$	5,953,060		$	4,920,231
	Future production costs			(1,704,333	)		(1,372,005	)		(1,220,403	)
	Future development costs			(1,247,446	)		(1,154,685	)		(1,025,193	)
	Future income tax expense			(1,267,025	)		(919,454	)		(692,528	)
	Future net cash flows			3,211,564			2,506,916			1,982,107
	10% annual discount for estimated timing of cash flows			(2,155,749	)		(1,830,639	)		(1,487,887	)
	Standardized measure of discounted future net cash flows		$	1,055,815		$	676,277		$	494,220
	Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions outstanding at each period end.
Changes in Standardized Measure of Discounted Future Net Cash Flows
The changes in the Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):
		Years Ended December 31,
		2014			2013			2012
Balance, beginning of period		$	676,277		$	494,220		$	414,381
Net change in sales and transfer prices and in production (lifting) costs related to future production			(59,920	)		74,088			147,421
Changes in estimated future development costs			(388,772	)		(301,132	)		(486,435	)
Sales and transfers of oil and gas produced during the period			(209,893	)		(149,310	)		(100,634	)
Net change due to extensions, discoveries and improved recovery			534,231			360,080			467,822
Net change due to purchase of minerals in place			—			1,435			—
Net change due to revisions in quantity estimates			(78,801	)		(61,931	)		(210,296	)
Previously estimated development costs incurred during the period			382,995			287,898			285,039
Accretion of discount			113,188			87,937			60,162
Other			(11,897	)		1,896			(11,281	)
Net change in income taxes			98,407			(118,904	)		(71,959	)
Standardized Measure of discounted future net cash flows		$	1,055,815		$	676,277		$	494,220

Supplementary_Data

Supplementary Data	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Supplementary Data	11	Supplementary Data
	Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts):
			2014 Quarters Ended
			December 31			September 30			June 30			March 31
	Net revenue		$	55,070		$	68,124		$	73,408		$	61,927
	Net operating expenses			(50,136	)		(45,525	)		(50,812	)		(44,899	)
	Interest expense, net			(5,715	)		(5,442	)		(5,357	)		(5,137	)
	Equity in earnings (losses) of investee			5			—			(186	)		—
	Realized gain (loss) on commodity derivatives			7,782			(764	)		(3,320	)		(1,339	)
	Unrealized gain (loss) on commodity derivatives			36,907			18,810			(7,678	)		(5,926	)
	Other			176			—			(109	)		—
	Income before income tax			44,089			35,203			5,946			4,626
	Income tax provision			17,102			12,756			2,153			1,681
	Net income		$	26,987		$	22,447		$	3,793		$	2,945
	Basic net income applicable to common stockholders per common share		$	0.68		$	0.57		$	0.1		$	0.08
	Diluted net income applicable to common stockholders per common share		$	0.68		$	0.57		$	0.1		$	0.08
			2013 Quarters Ended
			December 31			September 30			30-Jun			31-Mar
	Net revenue		$	58,565		$	44,196		$	42,272		$	36,269
	Net operating expenses			(40,402	)		(34,314	)		(31,329	)		(31,665	)
	Interest expense, net			(5,225	)		(5,179	)		(2,451	)		(1,229	)
	Equity in (losses) earnings of investee			(4	)		340			(64	)		(116	)
	Gain on sale of Wildcat pipeline			90,743			—			—			—
	Realized gain (loss) on commodity derivatives			199			(840	)		(714	)		307
	Unrealized (loss) gain on commodity derivatives			(1,348	)		(3,438	)		4,290			(4,100	)
	Income (loss) before income tax (benefit)			102,528			765			12,004			(534	)
	Income tax provision (benefit)			38,207			270			4,217			(187	)
	Net income (loss)		$	64,321		$	495		$	7,787		$	(347	)
	Basic net income (loss) applicable to common stockholders per common share		$	1.65		$	0.01		$	0.2		$	(0.01	)
	Diluted net income (loss) applicable to common stockholders per common share		$	1.65		$	0.01		$	0.2		$	(0.01	)
			2012 Quarters Ended
			December 31			September 30			June 30			March 31
	Net revenue		$	35,309		$	33,038		$	29,927		$	30,618
	Net operating expenses			(36,777	)		(31,340	)		(26,095	)		(23,879	)
	Interest expense, net			(926	)		(1,544	)		(1,380	)		(887	)
	Equity in losses of investee			(108	)		—			—			—
	Realized (loss) gain on commodity derivatives			(408	)		423			361			(484	)
	Unrealized gain (loss) on commodity derivatives			1,292			(4,185	)		9,439			(2,672	)
	(Loss) income before income tax (benefit)			(1,618	)		(3,608	)		12,252			2,696
	Income tax (benefit) provision			(781	)		(1,253	)		4,390			982
	Net (loss) income		$	(837	)	$	(2,355	)	$	7,862		$	1,714
	Basic net (loss) income applicable to common stockholders per common share		$	(0.02	)	$	(0.07	)	$	0.23		$	0.05
	Diluted net (loss) income applicable to common stockholders per common share		$	(0.02	)	$	(0.07	)	$	0.23		$	0.05

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations
	Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight gas sands. Our properties are primarily located in the Permian Basin in West Texas. We also own interests in the East Texas Basin.
Consolidation, Basis of Presentation and Significant Estimates	Consolidation, Basis of Presentation and Significant Estimates
	The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect our estimate of depletion expense as well as our impairment analyses. Significant assumptions also are required in our estimation of accrued liabilities, commodity derivatives, income tax provision, share-based compensation and asset retirement obligations. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior-year amounts have been reclassified to conform to current-year presentation. These classifications have no impact on the net income reported.
Cash and Cash Equivalents	Cash and Cash Equivalents
	We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible.
Restricted Cash	Restricted Cash
	The restricted cash on our balance sheet for the year ended December 31, 2013 consisted of $7.4 million in proceeds from the sale of our equity method investment that were restricted pursuant to an escrow agreement. The escrow agreement terminated on June 1, 2014, and the cash held in escrow was subsequently released.
Capitalized Costs	Capitalized Costs.    Our oil and gas properties comprised the following (in thousands):
		December 31,
		2014			2013
	Mineral interests in properties:
	Unproved leasehold costs	$	46,240		$	47,096
	Proved leasehold costs		42,409			40,620
	Wells and related equipment and facilities		1,600,703			1,195,556
	Support equipment		8,518			10,773
	Uncompleted wells, equipment and facilities		10,408			26,150
	Total costs		1,708,278			1,320,195
	Less accumulated depreciation, depletion and amortization		(379,892	)		(273,915	)
	Net capitalized costs	$	1,328,386		$	1,046,280
	We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to exploration expense. There were no exploratory wells capitalized, pending determination of whether the wells have proved reserves, at December 31, 2014 or 2013. Geological and geophysical costs, including seismic studies are charged to exploration expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use and while these expenditures are excluded from our depletable base. Through December 31, 2014, we have capitalized no interest costs because our individual wells and infrastructure projects are generally developed in less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.
	On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization with no gain or loss recognized in income.
	Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment was $106.2 million, $76.5 million and $60 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are periodically evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets, as events or changes in circumstances indicate that the carrying values of those assets may not be recoverable. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. Estimating future net cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. We noted no impairment of our proved properties based on our analysis for the years ended December 31, 2014, 2013 and 2012.
	Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance.
	On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Other Property	Other Property
	Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to 15 years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $588,000, $502,000 and $333,000 for the years ended December 31, 2014, 2013 and 2012, respectively.
Equity Method Investment	Equity Method Investment
	For investments in which we have the ability to exercise significant influence but do not have control, we follow the equity method of accounting. In September 2012, we entered into a joint venture to build an oil pipeline in Crockett and Reagan Counties, Texas, which is used to transport our oil to market. In October 2013, we completed the sale of the joint venture. As of December 31, 2014, we have no investments that are accounted for under the equity method. See Note 2 for equity method investment disclosures.
Other Assets	Other Property
	Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to 15 years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $588,000, $502,000 and $333,000 for the years ended December 31, 2014, 2013 and 2012, respectively.
Financial Instruments	Financial Instruments
	The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, as of December 31, 2014 and 2013. See Note 7 for commodity derivative and Senior Notes fair value disclosures.
Income Taxes	Income Taxes
	We are subject to U.S. federal income taxes along with state income taxes in Texas. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in the consolidated statement of income.
	Based on our analysis, we did not have any uncertain tax positions as of December 31, 2014 or 2013. The Company’s income tax returns are subject to examination by the relevant taxing authorities as follows: U.S. Federal income tax returns for tax years 2011 and forward, Texas income and margin tax returns for tax years 2011 and forward, New Mexico income tax returns for years 2011 and forward, and Kentucky income tax returns for the years 2011 and forward. There are currently no income tax examinations underway for these jurisdictions.
	Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change.
Derivative Activity	Derivative Activity
	We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our consolidated statements of operations under the caption entitled “unrealized gain (loss) on commodity derivatives.”
	Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our natural gas and oil production. Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.
Accrued Liabilities	Accrued Liabilities
	The following is a summary of our accrued liabilities at December 31, 2014 and 2013 (in thousands):
		2014			2013
	Capital expenditures accrual	$	43,870		$	30,606
	Operating expenses and other		6,868			7,312
	Total	$	50,738		$	37,918
Asset Retirement Obligations	Asset Retirement Obligations
	Our asset retirement obligations relate to future plugging and abandonment expenses on oil and gas properties. Based on the expected timing of payments, the full asset retirement obligation is classified as non-current. There were no significant changes to the asset retirement obligations for the years ended December 31, 2014, 2013 and 2012.
Share-Based Compensation	Share-Based Compensation
	We measure and record compensation expense for all share-based payment awards to employees and outside directors based on estimated grant date fair values. We recognize compensation costs for awards granted over the requisite service period based on the grant date fair value in general and administrative expense on our consolidated statements of operations.
Earnings Per Common Share	Earnings Per Common Share
	We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts):
		For the Years Ended December 31,
		2014			2013			2012
	Income (numerator):
	Net income — basic	$	56,172		$	72,256		$	6,384
	Weighted average shares (denominator):
	Weighted average shares — basic		39,407,733			38,997,815			34,965,182
	Dilution effect of share-based compensation, treasury method		12,132			21,334			65,141
	Weighted average shares — diluted		39,419,865			39,019,149			35,030,323
	Earnings per share:
	Basic	$	1.43		$	1.85		$	0.18
	Diluted	$	1.42		$	1.85		$	0.18
Revenue and Accounts Receivable from Purchasers and Joint Interest Owners	Revenue and Accounts Receivable.    We recognize revenue for our production when the quantities are delivered to or collected by the respective purchaser. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices.
	Accounts receivable, joint interest owners, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil, NGL and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2014 or 2013. As of December 31, 2014, accounts receivable related to oil, NGL and gas sales includes $4.8 million from realized gains on commodity derivatives.
Oil and Gas Sales Payable	Oil, NGL and Gas Sales Payable.    Oil, NGL and gas sales payable represents amounts collected from purchasers for oil, NGL and gas sales which are either revenues due to other revenue interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 60 days of the end of the month in which the related production occurred.
Production Costs	Production Costs.    Production costs, including compressor rental and repair, pumpers’ and supervisors’ salaries, saltwater disposal, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expense on our consolidated statements of operations.
Exploration expenses	Exploration expenses.    Exploration expenses include delay rentals, geological and geophysical costs and dry hole costs.
Dependence on Major Customer	Dependence on Major Customers.    For the year ended December 31, 2014, sales to DCP Midstream, LP (“DCP”) and JP Energy Development, LP (“JP Energy”) accounted for approximately 30% and 69%, respectively, of our total sales. In addition, substantially all of our accounts receivable related to oil and gas sales were due from JP Energy and DCP at December 31, 2014. As of December 31, 2014, we had dedicated all of our oil production from northern Project Pangea and Pangea West through 2022 to JP Energy. In addition, as of December 31, 2014, we had contracted to sell all of our NGLs and natural gas production from Project Pangea to DCP through January 2023. For the year ended December 31, 2013, sales to Wildcat Permian Services, LLC, DCP and JP Energy Permian, LLC accounted for approximately 30%, 27% and 23%, respectively, of our total sales. For the year ended December 31, 2012, we sold substantially all of our oil and gas produced to seven purchasers. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased purchasers. Although we are exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy.
Segment Reporting	Segment Reporting
	The Company presently operates in one business segment, the exploration and production of oil, NGLs and natural gas.
Recent Accounting Pronouncements	Recent Accounting Pronouncements
	In April 2014, the Financial Accounting Standards Board (“FASB”) issued guidance that raised the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. Under the updated standard, a discontinued operation is (i) a component of an entity or group of components that has been disposed of by sale, disposed of other than by sale or is classified as held for sale that represents a strategic shift that has or will have a major effect on an entity’s operations and financial results, or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of the acquisition. This update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results. This accounting standards update is effective for annual reporting periods beginning on or after December 15, 2014, and will be applied prospectively. Adoption of this standard is not expected to have a significant impact on the consolidated financial statements.
	In May 2014, the FASB issued an accounting standards update for “Revenue from Contracts with Customers,” which supersedes the revenue recognition requirements in “Topic 605, Revenue Recognition.” This accounting standard update provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. This new guidance permits adoption through the use of either full or retrospective approach or a modified retrospective approach for annual reporting periods beginning on or after December 15, 2016, with early application not permitted. The Company has not determined which transition method it will use and is continuing to evaluate our existing revenue recognition policies to determine whether any contracts will be affected by the new requirements.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Oil and Gas Properties	Our oil and gas properties comprised the following (in thousands):
		December 31,
		2014			2013
	Mineral interests in properties:
	Unproved leasehold costs	$	46,240		$	47,096
	Proved leasehold costs		42,409			40,620
	Wells and related equipment and facilities		1,600,703			1,195,556
	Support equipment		8,518			10,773
	Uncompleted wells, equipment and facilities		10,408			26,150
	Total costs		1,708,278			1,320,195
	Less accumulated depreciation, depletion and amortization		(379,892	)		(273,915	)
	Net capitalized costs	$	1,328,386		$	1,046,280
Summary of Accrued Liabilities	The following is a summary of our accrued liabilities at December 31, 2014 and 2013 (in thousands):
		2014			2013
	Capital expenditures accrual	$	43,870		$	30,606
	Operating expenses and other		6,868			7,312
	Total	$	50,738		$	37,918
Reconciliations of Numerators and Denominators of Basic and Diluted Earnings Per Share	The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share, (dollars in thousands, except per-share amounts):
		For the Years Ended December 31,
		2014			2013			2012
	Income (numerator):
	Net income — basic	$	56,172		$	72,256		$	6,384
	Weighted average shares (denominator):
	Weighted average shares — basic		39,407,733			38,997,815			34,965,182
	Dilution effect of share-based compensation, treasury method		12,132			21,334			65,141
	Weighted average shares — diluted		39,419,865			39,019,149			35,030,323
	Earnings per share:
	Basic	$	1.43		$	1.85		$	0.18
	Diluted	$	1.42		$	1.85		$	0.18

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of Long Term Debt	The following table provides a summary of our long-term debt at December 31, 2014, and December 31, 2013 (in thousands).
		December 31,		December 31,
		2014		2013
	Senior secured credit facility	$	150,000	$	—
	Senior Notes		250,000		250,000
	Total long-term debt	$	400,000	$	250,000

ShareBased_Compensation_Tables

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of Stock Options Outstanding and Activity	he following table summarizes stock options outstanding and activity as of and for the years ended December 31, 2014, 2013 and 2012, (dollars in thousands):
		Shares			Weighted		Weighted		Aggregate
		Subject to			Average		Average		Intrinsic
		Stock			Exercise		Remaining		Value
		Options			Price		Contractual
							Term
							(in years)
	Outstanding at January 1, 2012		260,097		$	5.13		1.94	$	6,315
	Granted		—			—
	Exercised		(216,822	)		3.68
	Canceled		—			—
	Outstanding at December 31, 2012		43,275		$	12.38		4.88	$	547
	Granted		—			—
	Exercised		(3,750	)		15.42
	Canceled		—			—
	Outstanding at December 31, 2013		39,525		$	12.09		3.84	$	285
	Granted		—			—
	Exercised		—			—
	Canceled		—			—
	Outstanding at December 31, 2014		39,525		$	12.09		2.86	$	—
	Exercisable (fully vested) at December 31, 2014		39,525		$	12.09		2.86	$	—
Summary of Status of Nonvested Shares	A summary of the status of nonvested shares for the years ended December 31, 2014, 2013 and 2012, is presented below:
		Shares			Weighted
					Average
					Grant-Date
					Fair Value
	Nonvested at January 1, 2012		790,122			15.06
	Granted		316,279			32.94
	Vested		(333,957	)		14.57
	Canceled		(19,365	)		23.74
	Nonvested at December 31, 2012		753,079			22.35
	Granted		377,379			22.77
	Vested		(299,110	)		18.79
	Canceled		(132,117	)		24.47
	Nonvested at December 31, 2013		699,231			23.7
	Granted		992,919			14.48
	Vested		(400,429	)		20.18
	Canceled		(169,311	)		25.57
	Nonvested at December 31, 2014		1,122,410		$	16.52

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Provision for Income Taxes	Our provision for income taxes comprised the following (in thousands):
		Years Ended December 31,
		2014			2013			2012
	Current:
	Federal	$	(25	)	$	429		$	—
	State		—			—			—
	Total current provision for income taxes	$	(25	)	$	429		$	—
	Deferred:
	Federal	$	32,754		$	41,175		$	3,359
	State		963			903			(21	)
	Total deferred provision for income taxes	$	33,717		$	42,078		$	3,338
Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income	Total income tax expense differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income (in thousands):
		Years Ended December 31,
		2014			2013			2012
	Statutory tax at 35%	$	31,452		$	40,167		$	3,306
	State taxes, net of federal impact		989			709			(21	)
	Share-based compensation tax shortfall		1,670			—			—
	Permanent differences		37			34			53
	Other differences		(456	)		1,597			—
	Total	$	33,692		$	42,507		$	3,338
Components of Deferred Tax Assets and Liabilities Computing Deferred Taxes, Net	Significant components of net deferred tax assets and liabilities are (in thousands):
		Years Ended December 31,
		2014			2013
	Deferred tax assets:
	Current portion of unrealized loss on commodity derivatives	$	—		$	681
	Net operating loss carryforwards		46,730			26,674
	Unrealized loss on commodity derivatives		—			113
	Other		1,305			295
	Total deferred tax assets		48,035			27,763
	Deferred tax liabilities:
	Difference in depreciation, depletion and capitalization methods — oil and gas properties		(158,647	)		(118,965	)
	Unrealized gain on commodity derivatives		(14,307	)		—
	Total deferred tax liabilities		(172,954	)		(118,965	)
	Net deferred tax liability	$	(124,919	)	$	(91,202	)
Net Operating Loss Carryforwards for Tax Purposes	Net operating loss carryforwards for tax purposes have the following expiration dates (in thousands):
	Expiration Dates	Amounts			Stock			Total
					Adjustments
	2030	$	4,083		$	750		$	4,833
	2031		18,642			1,012			19,654
	2032		51,931			2,724			54,655
	2033		524			741			1,265
	2034		54,939			—			54,939
	Total	$	130,119		$	5,227		$	135,346

Derivatives_Tables

Derivatives (Tables)

12 Months Ended

Dec. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivatives Volumes and Prices

At December 31, 2014, we had the following commodity derivatives positions outstanding:

Commodity and Period

Contract

Volume Transacted

Contract Price

Type

Crude Oil

January 2015 — March 2015

Collar

1,500 Bbls/d

$85.00/Bbl – $95.30/Bbl

January 2015 — December 2015

Collar

1,600 Bbls/d

$84.00/Bbl – $91.00/Bbl

January 2015 — December 2015

Collar

1,000 Bbls/d

$90.00/Bbl – $102.50/Bbl

January 2015 — December 2015

Three-Way

500 Bbls/d

$75.00/Bbl – $84.00/Bbl –

Collar

$94.00/Bbl

January 2015 — December 2015

Three-Way

500 Bbls/d

$75.00/Bbl – $84.00/Bbl –

Collar

$95.00/Bbl

Natural Gas

January 2015 — June 2015

Collar

80,000 MMBtu/month

$4.00/MMBtu – $4.74/MMBtu

January 2015 — December 2015

Swap

200,000

$4.10/MMBtu

MMBtu/month

January 2015 — December 2015

Collar

130,000

$4.00/MMBtu – $4.25/MMBtu

MMBtu/month

Summary of Fair Value of Open Commodity Derivatives

The following summarizes the fair value of our open commodity derivatives as of December 31, 2014 and 2013 (in thousands):

Asset Derivatives

Liability Derivatives

Fair Value

Fair Value

Balance Sheet

December 31,

December 31,

Balance Sheet

December 31,

December 31,

Location

2014

2013

Location

2014

2013

Derivatives not designated as hedging instruments

Commodity derivatives

Unrealized gain on commodity derivatives

$

39,951

$

9,108

Unrealized loss on commodity derivatives

$

—

$

11,270

Summary of Change in Fair Value of Commodity Derivatives

The following summarizes the change in the fair value of our commodity derivatives (in thousands):

Income Statement Location

Year Ended December 31,

2014

2013

2012

Derivatives not designated as hedging instruments

Commodity derivatives

Unrealized gain (loss) on commodity derivatives

$

42,113

$

(4,596

)

$

3,874

Realized gain (loss) on commodity derivatives

2,359

(1,048

)

(108

)

$

44,472

$

(5,644

)

$

3,766

Summary of Financial Instruments Not Recorded at Fair Value

The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands).

December 31, 2014

Carrying

Fair Value

Amount

Senior Notes

$

250,000

$

175,300

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of Years of Future Minimum Rental Payments Required Under Operating Lease Arrangements	commitments related to office equipment that expire by 2019. The following is a schedule by years of future minimum rental payments required under our operating lease arrangements as of December 31, 2014 (in thousands):
	2015	$	695
	2016		678
	2017		671
	2018		673
	2019		668
	Total	$	3,385

Oil_and_Gas_Producing_Activiti1

Oil and Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities	Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities (in thousands):
			For the Years Ended December 31,
			2014			2013			2012
	Property acquisition costs:
	Unproved properties		$	4,578		$	5,857		$	2,335
	Proved properties			—			1,000			5,407
	Exploration costs			3,831			2,238			4,550
	Development costs(1)			382,995			287,898			285,039
	Total costs incurred		$	391,404		$	296,993		$	297,331
	-1	For the years ended December 31, 2014, 2013 and 2012, development costs include $898,000, $584,000 and $409,000 in non-cash asset retirement obligations, respectively.
Schedule of Information Regarding Results of Operations for Oil and Gas Producing Activities	Set forth below is certain information regarding the results of operations for oil and gas producing activities (in thousands):
			For the Years Ended December 31,
			2014			2013			2012
	Revenues		$	258,529		$	181,302		$	128,892
	Production costs			(48,635	)		(31,992	)		(28,257	)
	Exploration expense			(3,831	)		(2,238	)		(4,550	)
	Depletion			(106,802	)		(76,956	)		(60,381	)
	Income tax expense			(35,387	)		(24,996	)		(12,139	)
	Results of operations		$	63,874		$	45,120		$	23,565

Disclosures_About_Oil_and_Gas_1

Disclosures About Oil and Gas Producing Activities (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Commodity Prices Inclusive of Adjustments for Quality and Location Used in Determining Future Net Revenues Related to Standardized Measure Calculation	The following table summarizes the prices used in the reserve estimates for 2014, 2013 and 2012. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows:
			2014			2013			2012
	Oil (per Bbl)		$	94.56		$	97.28		$	90.21
	Natural gas liquids (per Bbl)		$	31.5		$	30.16		$	37.88
	Gas (per Mcf)		$	4.55		$	3.66		$	2.62
Summary of Changes in Quantities of Proved Oil, NGL and Natural Gas Reserves	The following table provides a summary of the changes of the total proved reserves for the years ended December 31, 2014, 2013 and 2012, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year.
	Total Proved Reserves		Oil			NGLs			Natural Gas			Total
			(MBbls)			(MBbls)			(MMcf)			(MBoe)
	Balance — December 31, 2011			18,051			29,123			178,807			76,975
	Extensions and discoveries			21,993			8,639			49,372			38,861
	Production			(969	)		(904	)		(6,089	)		(2,888	)
	Revisions to previous estimates			(1,823	)		(7,758	)		(47,330	)		(17,469	)
	Balance — December 31, 2012			37,252			29,100			174,760			95,479
	Extensions and discoveries			14,252			6,531			38,993			27,282
	Purchases of minerals in place			62			14			197			109
	Production(1)			(1,444	)		(951	)		(6,737	)		(3,517	)
	Revisions to previous estimates			(4,055	)		(2,102	)		8,789			(4,692	)
	Balance — December 31, 2013			46,067			32,593			216,002			114,661
	Extensions and discoveries			19,347			10,658			79,454			43,247
	Production(1)			(2,024	)		(1,461	)		(10,773	)		(5,281	)
	Revisions to previous estimates			(8,052	)		(883	)		15,337			(6,379	)
	Balance — December 31, 2014			55,338			40,907			300,020			146,248
	-1	Production includes 560 MMcf and 1,390 MMcf related to field fuel in 2013 and 2014, respectively.
	Total Proved Reserves		Oil			NGLs			Natural Gas			Total
			(MBbls)			(MBbls)			(MMcf)			(MBoe)
	Proved Developed Reserves:
	January 1, 2012			5,542			13,945			84,743			33,611
	December 31, 2012			8,816			11,761			73,178			32,774
	January 1, 2013			8,816			11,761			73,178			32,774
	December 31, 2013			13,646			14,919			99,742			45,189
	January 1, 2013			13,646			14,919			99,742			45,189
	December 31, 2014			17,978			19,082			138,961			60,220
	Proved Undeveloped Reserves:
	January 1, 2012			12,509			15,178			94,064			43,365
	December 31, 2012			28,436			17,339			101,582			62,705
	January 1, 2013			28,436			17,339			101,582			62,705
	December 31, 2013			32,421			17,674			116,260			69,472
	January 1, 2014			32,421			17,674			116,260			69,472
	December 31, 2014			37,360			21,825			161,059			86,028
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves	The following table provides the Standardized Measure of discounted future net cash flows at December 31, 2014, 2013 and 2012:
			Years Ended December 31,
			2014			2013			2012
	Future cash flows		$	7,430,368		$	5,953,060		$	4,920,231
	Future production costs			(1,704,333	)		(1,372,005	)		(1,220,403	)
	Future development costs			(1,247,446	)		(1,154,685	)		(1,025,193	)
	Future income tax expense			(1,267,025	)		(919,454	)		(692,528	)
	Future net cash flows			3,211,564			2,506,916			1,982,107
	10% annual discount for estimated timing of cash flows			(2,155,749	)		(1,830,639	)		(1,487,887	)
	Standardized measure of discounted future net cash flows		$	1,055,815		$	676,277		$	494,220
Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves	The changes in the Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):
			Years Ended December 31,
			2014			2013			2012
	Balance, beginning of period		$	676,277		$	494,220		$	414,381
	Net change in sales and transfer prices and in production (lifting) costs related to future production			(59,920	)		74,088			147,421
	Changes in estimated future development costs			(388,772	)		(301,132	)		(486,435	)
	Sales and transfers of oil and gas produced during the period			(209,893	)		(149,310	)		(100,634	)
	Net change due to extensions, discoveries and improved recovery			534,231			360,080			467,822
	Net change due to purchase of minerals in place			—			1,435			—
	Net change due to revisions in quantity estimates			(78,801	)		(61,931	)		(210,296	)
	Previously estimated development costs incurred during the period			382,995			287,898			285,039
	Accretion of discount			113,188			87,937			60,162
	Other			(11,897	)		1,896			(11,281	)
	Net change in income taxes			98,407			(118,904	)		(71,959	)
	Standardized Measure of discounted future net cash flows		$	1,055,815		$	676,277		$	494,220

Supplementary_Data_Tables

Supplementary Data (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data	Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts):
		2014 Quarters Ended
		December 31			September 30			June 30			March 31
	Net revenue	$	55,070		$	68,124		$	73,408		$	61,927
	Net operating expenses		(50,136	)		(45,525	)		(50,812	)		(44,899	)
	Interest expense, net		(5,715	)		(5,442	)		(5,357	)		(5,137	)
	Equity in earnings (losses) of investee		5			—			(186	)		—
	Realized gain (loss) on commodity derivatives		7,782			(764	)		(3,320	)		(1,339	)
	Unrealized gain (loss) on commodity derivatives		36,907			18,810			(7,678	)		(5,926	)
	Other		176			—			(109	)		—
	Income before income tax		44,089			35,203			5,946			4,626
	Income tax provision		17,102			12,756			2,153			1,681
	Net income	$	26,987		$	22,447		$	3,793		$	2,945
	Basic net income applicable to common stockholders per common share	$	0.68		$	0.57		$	0.1		$	0.08
	Diluted net income applicable to common stockholders per common share	$	0.68		$	0.57		$	0.1		$	0.08
		2013 Quarters Ended
		December 31			September 30			30-Jun			31-Mar
	Net revenue	$	58,565		$	44,196		$	42,272		$	36,269
	Net operating expenses		(40,402	)		(34,314	)		(31,329	)		(31,665	)
	Interest expense, net		(5,225	)		(5,179	)		(2,451	)		(1,229	)
	Equity in (losses) earnings of investee		(4	)		340			(64	)		(116	)
	Gain on sale of Wildcat pipeline		90,743			—			—			—
	Realized gain (loss) on commodity derivatives		199			(840	)		(714	)		307
	Unrealized (loss) gain on commodity derivatives		(1,348	)		(3,438	)		4,290			(4,100	)
	Income (loss) before income tax (benefit)		102,528			765			12,004			(534	)
	Income tax provision (benefit)		38,207			270			4,217			(187	)
	Net income (loss)	$	64,321		$	495		$	7,787		$	(347	)
	Basic net income (loss) applicable to common stockholders per common share	$	1.65		$	0.01		$	0.2		$	(0.01	)
	Diluted net income (loss) applicable to common stockholders per common share	$	1.65		$	0.01		$	0.2		$	(0.01	)
		2012 Quarters Ended
		December 31			September 30			June 30			March 31
	Net revenue	$	35,309		$	33,038		$	29,927		$	30,618
	Net operating expenses		(36,777	)		(31,340	)		(26,095	)		(23,879	)
	Interest expense, net		(926	)		(1,544	)		(1,380	)		(887	)
	Equity in losses of investee		(108	)		—			—			—
	Realized (loss) gain on commodity derivatives		(408	)		423			361			(484	)
	Unrealized gain (loss) on commodity derivatives		1,292			(4,185	)		9,439			(2,672	)
	(Loss) income before income tax (benefit)		(1,618	)		(3,608	)		12,252			2,696
	Income tax (benefit) provision		(781	)		(1,253	)		4,390			982
	Net (loss) income	$	(837	)	$	(2,355	)	$	7,862		$	1,714
	Basic net (loss) income applicable to common stockholders per common share	$	(0.02	)	$	(0.07	)	$	0.23		$	0.05
	Diluted net (loss) income applicable to common stockholders per common share	$	(0.02	)	$	(0.07	)	$	0.23		$	0.05

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Segment	Wells		Customer
	Wells
Summary Of Significant Accounting Policies [Line Items]
Restricted cash		$7,350,000
Escrow termination date	1-Jun-14
Number of exploratory wells capitalized	0	0
Capitalized interest cost	0
Depreciation depletion and amortization for oil & gas	106,200,000	76,500,000	60,000,000
Impairment of proved properties	0	0	0
Depreciation expense for other property and equipment	588,000	502,000	333,000
Equity method investments	0
Tax benefit	50.00%
Uncertain tax positions	0	0
Number of days in which payment is to be made	30 days
Realized gains on commodity derivatives	4,800,000
Number of customers for oil and gas				7
Number of operating segment	1
Wildcat Permian Services, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Sales to customers		30.00%
DCP Midstream, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Sales to customers	30.00%	27.00%
JP Energy Permian, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Sales to customers	69.00%	23.00%
7% Senior Notes due on 2021 [Member]
Summary Of Significant Accounting Policies [Line Items]
Senior notes principle amounts	250,000,000
Escrow [Member]
Summary Of Significant Accounting Policies [Line Items]
Restricted cash		$7,400,000
Escrow termination date	1-Jun-14
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of furniture, fixtures and equipment	3 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives of furniture, fixtures and equipment	15 years
Oil and Gas [Member] | Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of days in which payment is to be made	30 days
Oil and Gas [Member] | Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Number of days in which payment is to be made	60 days

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Summary of Oil and Gas Properties (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Mineral interests in properties:
Unproved leasehold costs	$46,240	$47,096
Proved leasehold costs	42,409	40,620
Wells and related equipment and facilities	1,600,703	1,195,556
Support equipment	8,518	10,773
Uncompleted wells, equipment and facilities	10,408	26,150
Total costs	1,708,278	1,320,195
Less accumulated depreciation, depletion and amortization	-379,892	-273,915
Net capitalized costs	$1,328,386	$1,046,280

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Summary of Accrued Liabilities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Regulatory Assets [Abstract]
Capital expenditures accrual	$43,870	$30,606
Operating expenses and other	6,868	7,312
Total	$50,738	$37,918

Summary_of_Significant_Account6

Summary of Significant Accounting Policies - Reconciliations of Numerators and Denominators of Basic and Diluted Earnings Per Share (Detail) (USD $)	3 Months Ended												12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]
Net income - basic	$26,987	$22,447	$3,793	$2,945	$64,321	$495	$7,787	($347)	($837)	($2,355)	$7,862	$1,714	$56,172	$72,256	$6,384
Weighted average shares - basic													39,407,733	38,997,815	34,965,182
Dilution effect of share-based compensation, treasury method													12,132	21,334	65,141
Weighted average shares - diluted													39,419,865	39,019,149	35,030,323
Basic	$0.68	$0.57	$0.10	$0.08	$1.65	$0.01	$0.20	($0.01)	($0.02)	($0.07)	$0.23	$0.05	$1.43	$1.85	$0.18
Diluted	$0.68	$0.57	$0.10	$0.08	$1.65	$0.01	$0.20	($0.01)	($0.02)	($0.07)	$0.23	$0.05	$1.42	$1.85	$0.18

Equity_Method_Investment_Addit

Equity Method Investment - Additional Information (Detail) (USD $)	1 Months Ended		3 Months Ended	12 Months Ended
	Oct. 31, 2013	Oct. 31, 2012	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Results Related To Equity Accounted Investees [Line Items]
Contribution to joint venture		$10,000,000			$8,300,000
Proceeds from sale of joint venture	109,100,000
Restricted cash			7,350,000		7,350,000
Escrow termination date				1-Jun-14
Post-closing working capital adjustments				200,000
Pre-Tax Gain on sale of equity interest joint venture	90,700,000		90,743,000		90,743,000
Escrow [Member]
Schedule Of Results Related To Equity Accounted Investees [Line Items]
Restricted cash			$7,400,000		$7,400,000
Escrow termination date				1-Jun-14

Public_Equity_Offerings_Additi

Public Equity Offerings - Additional Information (Detail) (USD $)	0 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 19, 2012	Dec. 31, 2014	Dec. 31, 2013	Oct. 03, 2012	Sep. 19, 2012
Equity [Abstract]
Common stock, issued		39,814,199	39,047,699		5,000,000
Additional purchase of common stock				325,000
Transaction costs	$8
Received net proceeds	$154.40

LongTerm_Debt_Schedule_of_Long

Long-Term Debt - Schedule of Long Term Debt (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Disclosure [Abstract]
Senior secured credit facility	$150,000	$0
Senior notes	250,000	250,000
Total long-term debt	$400,000	$250,000

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Detail) (USD $)	0 Months Ended	12 Months Ended
	Dec. 15, 2014	Dec. 31, 2014	Dec. 31, 2013
Credit Facilities [Line Items]
Amount outstanding under revolving credit facility		$150,000,000	$0
Interest rate applicable of revolving credit facility		1.80%
Production from liens covering the oil and gas properties		80.00%
Consolidated current assets ratio		1
Consolidated current liabilities ratio		1
Interest coverage ratio		2.5
Interest coverage ratio		1
Outstanding equity interests ownership percentage		50.00%
Senior notes		250,000,000	250,000,000
Issuance of Senior Notes			242,824,000
Debt instrument redemption description		Before June 15, 2016, we may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date.
Semi-annual interest payment amount	8,800,000
Covenants Agreements One [Member]
Credit Facilities [Line Items]
Covenant description		A consolidated modified current ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of not less than 1.0 to 1.0 as of the last day of any fiscal quarter
Covenants Agreements Two [Member]
Credit Facilities [Line Items]
Covenant description		A consolidated interest coverage ratio covenant (as defined in the Credit Facility) that requires us to maintain a ratio of consolidated EBITDAX to interest of not less than 2.5 to 1.0 as of the last day of any fiscal quarter.
Credit Facility [Member]
Credit Facilities [Line Items]
Maturity period of revolving credit facility		7-May-19
Aggregate lender commitments		450,000,000
Revolving credit facility, borrowing base		600,000,000
Revolving credit facility, maximum borrowing capacity		1,000,000,000
Revolving credit facility, interest rate description		Borrowings under the Credit Facility bear interest based on the agent bank's prime rate plus an applicable margin ranging from 0.50% to 1.50%, or the sum of the LIBOR rate plus an applicable margin ranging from 1.50% to 2.50%. In addition, we pay an annual commitment fee ranging from 0.375% to 0.50%
Unused letters of credit outstanding		300,000	300,000
Debt instrument, redemption of principal amount percentage		100.00%
Credit Facility [Member] | Minimum [Member]
Credit Facilities [Line Items]
Annual commitment fee of unused borrowings		0.38%
Credit Facility [Member] | Maximum [Member]
Credit Facilities [Line Items]
Annual commitment fee of unused borrowings		0.50%
Credit Facility [Member] | Interest Rate Calculation One [Member] | Minimum [Member]
Credit Facilities [Line Items]
Revolving credit facility, marginal percentage		0.50%
Credit Facility [Member] | Interest Rate Calculation One [Member] | Maximum [Member]
Credit Facilities [Line Items]
Revolving credit facility, marginal percentage		1.50%
Credit Facility [Member] | Interest Rate Calculation Two [Member] | Minimum [Member]
Credit Facilities [Line Items]
Revolving credit facility, marginal percentage		1.50%
Credit Facility [Member] | Interest Rate Calculation Two [Member] | Maximum [Member]
Credit Facilities [Line Items]
Revolving credit facility, marginal percentage		2.50%
Debt Instrument Redemption Period [Member]
Credit Facilities [Line Items]
Debt instrument redemption description		Before June 15, 2016, we may redeem up to 35% of the Senior Notes at a redemption price of 107% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings.
Debt instrument, redemption percentage		35.00%
Debt instrument, redemption of principal amount percentage		107.00%
7% Senior Notes Originated June 11, 2013 [Member]
Credit Facilities [Line Items]
Senior Notes maturity date		15-Jun-21
Senior notes		250,000,000
Stated interest rate		7.00%
Issuance of Senior Notes		243,000,000
Debt instrument payment of interest		Semi-annually on June 15 and December 15.
Annual interest expense		$17,500,000

ShareBased_Compensation_Additi

Share-Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
The maximum number of common stock	2,100,000
Maximum term of stock option	10 years
Amendment effective date	31-May-12
Share-based compensation expense	$8,247,000	$5,901,000	$7,465,000
Number of stock options excercised	0	3,750	216,822
Intrinsic value of the options exercised		35,000	7,000,000
Tax benefit recognized related to the stock option exercises		0	0
Share subject to stock options, granted	0	0	0
Subsequent restricted share award	724,249
Fair market value of shares subject to performance conditions	3,400,000
Service period	3 years
Description of matching contribution	We make a matching contribution equal to 100% of each pre-tax dollar contributed by the participant on the first 3% of eligible compensation and 50% on the next 2% of eligible compensation.
Contributions to employee benefit plan	310,000	279,000	179,000
Primary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employer matching contribution on first three percentage	100.00%
Secondary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employer matching contribution on first three percentage	50.00%
Non Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense	749,000	630,000	535,000
Nonvested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares grant	992,919	377,379	316,279
Average grant date fair value	14,400,000	8,600,000	10,400,000
Unrecognized compensation expense related to nonvested shares	11,600,000
Nonvested outstanding weighted average remaining service period	2 years
Nonvested Shares [Member] | Executive Officers [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Additional shares grant	245,157	183,672	129,890
Additional share grant fair value	4,500,000	4,400,000	4,800,000
Performance Condition Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Subsequent restricted share award	482,833
Total Shareholder Return Performance Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Subsequent restricted share award	241,416
Forfeiture Benefit Adjustments Member [Member] | Executive Officers [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forfeited stock awards	$1,100,000	$1,000,000

ShareBased_Compensation_Summar

Share-Based Compensation - Summary of Stock Options Outstanding and Activity (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share Subject to Stock Options, Beginning Balance	39,525	43,275	260,097
Weighted Average Exercise Price, Outstanding, Beginning Balance	$12.09	$12.38	$5.13
Share subject to stock options, granted	0	0	0
Shares Subject to Stock Options, Exercised	0	-3,750	-216,822
Shares Subject to Stock Options, Canceled	0	0	0
Share Subject to Stock Options, Ending Balance	39,525	39,525	43,275	260,097
Shares Subject to Stock Options, Shares Exercisable, Ending Balance	39,525
Weighted Average Exercise Price, Outstanding, Granted	$0	$0	$0
Weighted Average Exercise Price, Outstanding, Exercised		$15.42	$3.68
Weighted Average Exercise Price, Outstanding, Canceled	$0	$0	$0
Weighted Average Exercise Price, Outstanding, Ending Balance	$12.09	$12.09	$12.38	$5.13
Weighted Average Exercise Price, Exercisable, Ending Balance	$12.09
Outstanding, Aggregate Intrinsic Value, Beginning Value	$285	$547	$6,315
Weighted Average Remaining Contractual Term, Outstanding	2 years 10 months 10 days	3 years 10 months 2 days	4 years 10 months 17 days	1 year 11 months 9 days
Outstanding, Aggregate Intrinsic Value, Ending Balance		285	547	6,315
Weighted Average Remaining Contractual Term, Exercisable, Ending Balance	2 years 10 months 10 days
Outstanding, Exercisable, Aggregate Intrinsic Value	$0

ShareBased_Compensation_Summar1

Share-Based Compensation - Summary of Status of Nonvested Shares (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Nonvested Shares, Beginning Balance	699,231	753,079	790,122
Nonvested Shares, Granted	992,919	377,379	316,279
Nonvested Shares, Vested	-400,429	-299,110	-333,957
Nonvested Shares, Canceled	-169,311	-132,117	-19,365
Nonvested Shares, Ending Balance	1,122,410	699,231	753,079
Weighted Average Grant-Date Fair Value, Nonvested, Beginning Balance	$23.70	$22.35	$15.06
Weighted Average Grant-Date Fair Value, Nonvested, Granted	$14.48	$22.77	$32.94
Weighted Average Grant-Date Fair Value, Nonvested, Vested	$20.18	$18.79	$14.57
Weighted Average Grant-Date Fair Value, Nonvested, Canceled	$25.57	$24.47	$23.74
Weighted Average Grant-Date Fair Value, Nonvested	$16.52	$23.70	$22.35

Income_Taxes_Schedule_of_Provi

Income Taxes - Schedule of Provision for Income Taxes (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal	($25)	$429
State	0	0	0
Total current provision for income taxes	-25	429
Deferred:
Federal	32,754	41,175	3,359
State	963	903	-21
Total deferred provision for income taxes	$33,717	$42,078	$3,338

Income_Taxes_Total_Income_Tax_

Income Taxes - Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income (Detail) (USD $)	3 Months Ended												12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Statutory tax at 35%													$31,452	$40,167	$3,306
State taxes, net of federal impact													989	709	-21
Share-based compensation tax shortfall													1,670
Permanent differences													37	34	53
Other differences													-456	1,597
Total	$17,102	$12,756	$2,153	$1,681	$38,207	$270	$4,217	($187)	($781)	($1,253)	$4,390	$982	$33,692	$42,507	$3,338

Income_Taxes_Total_Income_Tax_1

Income Taxes - Total Income Tax Expense Differed from Amounts Computed by Applying U.S. Federal Statutory Tax Rates to Pre-Tax Income (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Statutory tax rate	35.00%	35.00%	35.00%

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Share-based compensation tax shortfall	$1,670,000
Net deferred tax assets and liabilities recorded as long-term liability	110,700,000	91,900,000
Deferred taxes expected to be realized within one year	14,200,000	700,000
Net operating loss carryforwards	135,300,000
Benefit of stock options	$5,200,000

Income_Taxes_Significant_Compo

Income Taxes - Significant Components of Net Deferred Tax Assets and Liabilities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Income Tax Disclosure [Abstract]
Current portion of unrealized loss on commodity derivatives		$681
Net operating loss carryforwards	46,730	26,674
Unrealized loss on commodity derivatives		113
Other	1,305	295
Total deferred tax assets	48,035	27,763
Difference in depreciation, depletion and capitalization methods - oil and gas properties	-158,647	-118,965
Unrealized gain on commodity derivatives	-14,307
Total deferred tax liabilities	-172,954	-118,965
Net deferred tax liability	($124,919)	($91,202)

Income_Taxes_Net_Operating_Los

Income Taxes - Net Operating Loss Carryforwards for Tax Purposes (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Amounts	$130,119
Stock Adjustments	5,227
Total	135,346
Expiration Dates 2030 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	4,083
Stock Adjustments	750
Total	4,833
Expiration Dates	2030
Expiration Dates 2031 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	18,642
Stock Adjustments	1,012
Total	19,654
Expiration Dates	2031
Expiration Date 2032 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	51,931
Stock Adjustments	2,724
Total	54,655
Expiration Dates	2032
Expiration Date 2033 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	524
Stock Adjustments	741
Total	1,265
Expiration Dates	2033
Expiration Date 2034 [Member]
Operating Loss Carryforwards [Line Items]
Amounts	54,939
Total	$54,939
Expiration Dates	2034

Derivatives_Commodity_Derivati

Derivatives - Commodity Derivative Volumes and Prices (Detail)	12 Months Ended
	Dec. 31, 2014
	MMBTU
Natural Gas - January 2015 - June 2015 [Member] | Collar [Member]
Derivative [Line Items]
Volume Transacted	80,000
Natural Gas - January 2015 - December 2015 Contract One [Member] | Swap [Member]
Derivative [Line Items]
Contract Price	4.1
Volume Transacted	200,000
Natural Gas - January 2015 - December 2015 Contract Two [Member] | Collar [Member]
Derivative [Line Items]
Volume Transacted	130,000
Crude Oil - January 2015 - March 2015 Contract One [Member] | Collar [Member]
Derivative [Line Items]
Volume Transacted	1,500
Crude Oil - January 2015 - December 2015 [Member] | Collar [Member]
Derivative [Line Items]
Volume Transacted	1,600
Crude - Oil January 2015 - December 2015 Contract Two [Member] | Collar [Member]
Derivative [Line Items]
Volume Transacted	1,000
Crude - Oil January 2015 - December 2015 Contract Three [Member] | Three-Way Collar [Member]
Derivative [Line Items]
Volume Transacted	500
Contract Price	94
Crude Oil - January 2015 - December 2015 Contract Four [Member] | Three-Way Collar [Member]
Derivative [Line Items]
Volume Transacted	500
Contract Price	95
Minimum [Member] | Natural Gas - January 2015 - June 2015 [Member] | Collar [Member]
Derivative [Line Items]
Contract Price	4
Minimum [Member] | Natural Gas - January 2015 - December 2015 Contract Two [Member] | Collar [Member]
Derivative [Line Items]
Contract Price	4
Minimum [Member] | Crude Oil - January 2015 - March 2015 Contract One [Member] | Collar [Member]
Derivative [Line Items]
Contract Price	85
Minimum [Member] | Crude Oil - January 2015 - December 2015 [Member] | Collar [Member]
Derivative [Line Items]
Contract Price	84
Minimum [Member] | Crude - Oil January 2015 - December 2015 Contract Two [Member] | Collar [Member]
Derivative [Line Items]
Contract Price	90
Minimum [Member] | Crude - Oil January 2015 - December 2015 Contract Three [Member] | Three-Way Collar [Member]
Derivative [Line Items]
Contract Price	75
Minimum [Member] | Crude Oil - January 2015 - December 2015 Contract Four [Member] | Three-Way Collar [Member]
Derivative [Line Items]
Contract Price	75
Maximum [Member] | Natural Gas - January 2015 - June 2015 [Member] | Collar [Member]
Derivative [Line Items]
Contract Price	4.74
Maximum [Member] | Natural Gas - January 2015 - December 2015 Contract Two [Member] | Collar [Member]
Derivative [Line Items]
Contract Price	4.25
Maximum [Member] | Crude Oil - January 2015 - March 2015 Contract One [Member] | Collar [Member]
Derivative [Line Items]
Contract Price	95.3
Maximum [Member] | Crude Oil - January 2015 - December 2015 [Member] | Collar [Member]
Derivative [Line Items]
Contract Price	91
Maximum [Member] | Crude - Oil January 2015 - December 2015 Contract Two [Member] | Collar [Member]
Derivative [Line Items]
Contract Price	102.5
Maximum [Member] | Crude - Oil January 2015 - December 2015 Contract Three [Member] | Three-Way Collar [Member]
Derivative [Line Items]
Contract Price	84
Maximum [Member] | Crude Oil - January 2015 - December 2015 Contract Four [Member] | Three-Way Collar [Member]
Derivative [Line Items]
Contract Price	84

Derivatives_Summary_of_Fair_Va

Derivatives - Summary of Fair Value of Open Commodity Derivatives (Detail) (Commodity Derivatives [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Not Designated as Hedging Instruments, Fair Value of Assets Derivative [Member]
Derivatives, Fair Value [Line Items]
Unrealized gain on commodity derivatives	$39,951	$9,108
Derivative Not Designated as Hedging Instruments, Fair Value of Liability Derivative [Member]
Derivatives, Fair Value [Line Items]
Unrealized loss on commodity derivatives	$0	$11,270

Derivatives_Summary_of_Change_

Derivatives - Summary of Change in Fair Value of Commodity Derivatives (Detail) (USD $)	3 Months Ended												12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Unrealized gain (loss) on commodity derivatives													$42,113	($4,596)	$3,874
Realized gain (loss) on commodity derivatives	7,782	-764	-3,320	-1,339	199	-840	-714	307	-408	423	361	-484	2,359	-1,048	-108
Commodity Derivatives [Member]
Derivatives, Fair Value [Line Items]
Unrealized gain (loss) on commodity derivatives													42,113	-4,596	3,874
Realized gain (loss) on commodity derivatives													2,359	-1,048	-108
Derivatives not designated as hedging instruments, total (loss) gain													$44,472	($5,644)	$3,766

Derivatives_Summary_of_Financi

Derivatives - Summary of Financial Instruments Not Recorded at Fair Value (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Senior Notes, Carrying Amount	$250,000	$250,000
Senior Notes, Fair Value	$175,300

Commitments_and_Contingencies_1

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Commitments [Line Items]
Non-Cancelable operating lease expiration date	2019
Non-Cancelable lease agreement for office space, expiration date	31-Dec-19
Rent expense under lease arrangements	$717,000	$734,000	$716,000
Employment Agreements [Member]
Other Commitments [Line Items]
Commitment under contracts	6,300,000
Drilling Contracts [Member]
Other Commitments [Line Items]
Commitment under contracts	$7,300,000

Commitments_and_Contingencies_2

Commitments and Contingencies - Schedule of Years of Future Minimum Rental Payments Required Under Operating Lease Arrangements (Detail) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]
2015	$695
2016	678
2017	671
2018	673
2019	668
Total	$3,385

Oil_and_Gas_Producing_Activiti2

Oil and Gas Producing Activities - Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Unproved properties	$4,578	$5,857	$2,335
Proved properties		1,000	5,407
Exploration costs	3,831	2,238	4,550
Development costs	382,995	287,898	285,039
Total costs incurred	$391,404	$296,993	$297,331

Oil_and_Gas_Producing_Activiti3

Oil and Gas Producing Activities - Schedule of Information Regarding Costs Incurred for Oil and Gas Property Acquisition, Development and Exploration Activities (Parenthetical) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development costs	$382,995	$287,898	$285,039
Non-cash Asset Retirement Obligations [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Development costs	$898,000	$584,000	$409,000

Oil_and_Gas_Producing_Activiti4

Oil and Gas Producing Activities - Schedule of Information Regarding Results of Operations for Oil and Gas Producing Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Revenues	$258,529	$181,302	$128,892
Production costs	-48,635	-31,992	-28,257
Exploration expense	-3,831	-2,238	-4,550
Depletion	-106,802	-76,956	-60,381
Income tax expense	-35,387	-24,996	-12,139
Results of operations	$63,874	$45,120	$23,565

Disclosures_About_Oil_and_Gas_2

Disclosures About Oil and Gas Producing Activities - Commodity Prices Inclusive of Adjustments for Quality and Location Used in Determining Future Net Revenues Related to Standardized Measure Calculation (Detail) (Reserve Estimate [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil (MBbls) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices	94.56	97.28	90.21
NGLs (MBbls) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices	31.5	30.16	37.88
Natural Gas (MMcf) [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices	4.55	3.66	2.62

Disclosures_About_Oil_and_Gas_3

Disclosures About Oil and Gas Producing Activities - Summary of Changes in Quantities of Proved Oil, NGL and Natural Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MMcf	MMcf	MBoe
	MBoe	MBoe
Reserve Quantities [Line Items]
Production	1,390	560
Proved Developed and Proved Undeveloped Reserves, Mboe Beginning Balance	114,661	95,479	76,975
Extensions and discoveries, Mboe	43,247	27,282	38,861
Purchases of minerals in place, Mboe		109
Production, Mboe	-5,281	-3,517	-2,888
Revisions to previous estimates, Mboe	-6,379	-4,692	-17,469
Proved Developed and Proved Undeveloped Reserves, Mboe Ending Balance	146,248	114,661	95,479
Natural Gas (MMcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance	216,002	174,760	178,807
Extensions and discoveries	79,454	38,993	49,372
Purchases of minerals in place		197
Production	-10,773	-6,737	-6,089
Revisions to previous estimates	15,337	-8,789	-47,330
Proved Developed and Proved Undeveloped Reserves, Ending Balance	300,020	216,002	174,760
NGLs (MBbls) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance	32,593	29,100	29,123
Extensions and discoveries	10,658	6,531	8,639
Purchases of minerals in place		14
Production	-1,461	-951	-904
Revisions to previous estimates	-883	-2,102	-7,758
Proved Developed and Proved Undeveloped Reserves, Ending Balance	40,907	32,593	29,100
Oil (MBbls) [Member]
Reserve Quantities [Line Items]
Proved Developed and Proved Undeveloped Reserves, Beginning Balance	46,067	37,252	18,051
Extensions and discoveries	19,347	14,252	21,993
Purchases of minerals in place		62
Production	-2,024	-1,444	-969
Revisions to previous estimates	-8,052	-4,055	-1,823
Proved Developed and Proved Undeveloped Reserves, Ending Balance	55,338	46,067	37,252

Disclosures_About_Oil_and_Gas_4

Disclosures About Oil and Gas Producing Activities - Summary of Changes in Quantities of Proved Oil, NGL and Natural Gas Reserves (Parenthetical) (Detail)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MBoe	MBoe	MBoe	MBoe
Reserve Quantities [Line Items]
Beginning Balance, Proved Developed Reserves, Mboe	60,220	45,189	32,774	33,611
Ending Balance, Proved Developed Reserves, Mboe	60,220	45,189	32,774	33,611
Beginning Balance, Proved Undeveloped Reserves, Mboe	86,028	69,472	62,705	43,365
Ending Balance, Proved undeveloped Reserves, Mboe	86,028	69,472	62,705	43,365
Natural Gas (MMcf) [Member]
Reserve Quantities [Line Items]
Beginning Balance, Proved Developed Reserve, MMcf	138,961	99,742	73,178	84,743
Ending Balance, Proved Developed Reserve, MMcf	138,961	99,742	73,178	84,743
Beginning Balance, Proved Undeveloped Reserves, MMcf	161,059	116,260	101,582	94,064
Ending Balance, Proved Undeveloped Reserves, MMcf	161,059	116,260	101,582	94,064
NGLs (MBbls) [Member]
Reserve Quantities [Line Items]
Beginning Balance, Proved Developed Reserves, MBbls	19,082	14,919	11,761	13,945
Ending Balance, Proved Developed Reserves, MBbls	19,082	14,919	11,761	13,945
Beginning Balance, Proved Undeveloped Reserves, MBbls	21,825	17,674	17,339	15,178
Ending Balance, Proved Undeveloped Reserves, MBbls	21,825	17,674	17,339	15,178
Oil (MBbls) [Member]
Reserve Quantities [Line Items]
Beginning Balance, Proved Developed Oil Reserves, MBbls	17,978	13,646	8,816	5,542
Ending Balance, Proved Developed Oil Reserves, MBbls	17,978	13,646	8,816	5,542
Beginning Balance, Proved Undeveloped Oil Reserves, MBbls	37,360	32,421	28,436	12,509
Ending Balance, Proved Undeveloped Oil Reserves, MBbls	37,360	32,421	28,436	12,509

Disclosures_About_Oil_and_Gas_5

Disclosures About Oil and Gas Producing Activities - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MMBoe	MBoe	MBoe
	MBoe	MMBoe	MMBoe
	MMcf	MMcf
Reserve Quantities [Line Items]
Extensions and discoveries	43.2	27.3	38.9
Downward revisions	6.4	4.7	17.5
Economic revisions	9.3
Positive revisions	-6,379	-4,692	-17,469
Positive revision due to pricing	0.7
Production	5.3	3.5	2.9
Field fuel	1,390	560
Percentage of production attributable to assets			99.40%
Southeast Project Pangea [Member]
Reserve Quantities [Line Items]
Downward revisions	4.1
Economic revisions	5.8	7.8	8.9
Positive revisions		3.1
Wolfcamp Shale Oil Resources [Member]
Reserve Quantities [Line Items]
Economic revisions	3.5
Positive revisions	6.3
Project Pangea [Member]
Reserve Quantities [Line Items]
Downward revisions			3.3
Natural Gas and NGL [Member]
Reserve Quantities [Line Items]
Downward revisions			2.4
Technical Evaluations [Member]
Reserve Quantities [Line Items]
Downward revisions			2.9

Disclosures_About_Oil_and_Gas_6

Disclosures About Oil and Gas Producing Activities - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Extractive Industries [Abstract]
Future cash flows	$7,430,368	$5,953,060	$4,920,231
Future production costs	-1,704,333	-1,372,005	-1,220,403
Future development costs	-1,247,446	-1,154,685	-1,025,193
Future income tax expense	-1,267,025	-919,454	-692,528
Future net cash flows	3,211,564	2,506,916	1,982,107
10% annual discount for estimated timing of cash flows	-2,155,749	-1,830,639	-1,487,887
Standardized measure of discounted future net cash flows	$1,055,815	$676,277	$494,220	$414,381

Disclosures_About_Oil_and_Gas_7

Disclosures About Oil and Gas Producing Activities - Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Standardized measure of discounted future net cash flows, Beginning balance	$676,277	$494,220	$414,381
Net change in sales and transfer prices and in production (lifting) costs related to future production	-59,920	74,088	147,421
Changes in estimated future development costs	-388,772	-301,132	-486,435
Sales and transfers of oil and gas produced during the period	-209,893	-149,310	-100,634
Net change due to extensions, discoveries and improved recovery	534,231	360,080	467,822
Net change due to purchase of minerals in place		1,435
Net change due to revisions in quantity estimates	-78,801	-61,931	-210,296
Previously estimated development costs incurred during the period	382,995	287,898	285,039
Accretion of discount	113,188	87,937	60,162
Other	-11,897	1,896	-11,281
Net change in income taxes	98,407	-118,904	-71,959
Standardized Measure of discounted future net cash flows	$1,055,815	$676,277	$494,220

Supplementary_Data_Selected_Qu

Supplementary Data - Selected Quarterly Financial Data (Detail) (USD $)	1 Months Ended	3 Months Ended												12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Oct. 31, 2013	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Net revenue		$55,070	$68,124	$73,408	$61,927	$58,565	$44,196	$42,272	$36,269	$35,309	$33,038	$29,927	$30,618	$258,529	$181,302	$128,892
Net operating expenses		-50,136	-45,525	-50,812	-44,899	-40,402	-34,314	-31,329	-31,665	-36,777	-31,340	-26,095	-23,879	-191,372	-137,710	-118,091
Interest expense, net		-5,715	-5,442	-5,357	-5,137	-5,225	-5,179	-2,451	-1,229	-926	-1,544	-1,380	-887
Equity in (losses) earnings of investee		5		-186		-4	340	-64	-116	-108
Gain on sale of Wildcat pipeline	90,700					90,743									90,743
Realized gain (loss) on commodity derivatives		7,782	-764	-3,320	-1,339	199	-840	-714	307	-408	423	361	-484	2,359	-1,048	-108
Unrealized (loss) gain on commodity derivatives		36,907	18,810	-7,678	-5,926	-1,348	-3,438	4,290	-4,100	1,292	-4,185	9,439	-2,672
Other		176		-109
INCOME BEFORE INCOME TAX PROVISION		44,089	35,203	5,946	4,626	102,528	765	12,004	-534	-1,618	-3,608	12,252	2,696	89,864	114,763	9,722
Income tax (benefit) provision		17,102	12,756	2,153	1,681	38,207	270	4,217	-187	-781	-1,253	4,390	982	33,692	42,507	3,338
NET INCOME		$26,987	$22,447	$3,793	$2,945	$64,321	$495	$7,787	($347)	($837)	($2,355)	$7,862	$1,714	$56,172	$72,256	$6,384
Basic net (loss) income applicable to common stockholders per common share		$0.68	$0.57	$0.10	$0.08	$1.65	$0.01	$0.20	($0.01)	($0.02)	($0.07)	$0.23	$0.05	$1.43	$1.85	$0.18
Diluted net (loss) income applicable to common stockholders per common share		$0.68	$0.57	$0.10	$0.08	$1.65	$0.01	$0.20	($0.01)	($0.02)	($0.07)	$0.23	$0.05	$1.42	$1.85	$0.18