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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2012	Mar. 14, 2013	Jun. 30, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	Matador Resources Co
Entity Central Index Key	0001520006
Document Type	10-K
Document Period End Date	Dec. 31, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 454,393,967
Entity Common Stock, Shares Outstanding		55,894,438

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Current assets
Cash	$ 2,095	$ 10,284
Certificates of deposit	230	1,335
Accounts receivable
Oil and natural gas revenues	24,422	9,237
Joint interest billings	4,118	2,488
Other	974	1,447
Derivative instruments	4,378	8,989
Lease and well equipment inventory	877	1,343
Prepaid expenses	1,103	1,153
Total current assets	38,197	36,276
Oil and natural gas properties, full-cost method
Evaluated	763,527	423,945
Unproved and unevaluated	149,675	162,598
Other property and equipment	27,258	18,764
Less accumulated depletion, depreciation and amortization	(349,370)	(205,442)
Net property and equipment	591,090	399,865
Other assets
Derivative instruments	771	847
Deferred income taxes	411	1,594
Other assets	1,560	887
Total other assets	2,742	3,328
Total assets	632,029	439,469
Current liabilities
Accounts payable	28,120	18,841
Accrued liabilities	59,179	25,439
Royalties payable	6,541	1,855
Borrowings under Credit Agreement		25,000
Derivative instruments	670	171
Advances from joint interest owners	1,515
Deferred income taxes	411	3,024
Dividends payable - Class B		69
Other current liabilities	56	177
Total current liabilities	96,492	74,576
Long-term liabilities
Borrowings under Credit Agreement	150,000	88,000
Asset retirement obligations	5,109	3,935
Derivative instruments		383
Deferred income taxes	40,845	29,100
Other long-term liabilities	1,324	1,060
Total long-term liabilities	156,433	93,378
Commitments and contingencies (Note 13)
Shareholders' equity
Additional paid-in capital	404,311	263,562
Retained (deficit) earnings	(15,010)	18,279
Treasury stock, at cost, 1,201,051 and 1,179,175 shares, respectively	(10,765)	(10,765)
Total shareholders' equity	379,104	271,515
Total liabilities and shareholders' equity	632,029	439,469
Class A
Shareholders' equity
Common stock	$ 568	429
Class B
Shareholders' equity
Common stock		$ 10

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2012	Dec. 31, 2011
Treasury stock, shares	1,201,051	1,179,175
Class A
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	80,000,000	80,000,000
Common stock, shares issued	56,778,718	42,916,668
Common stock, shares outstanding	55,577,667	41,737,493
Class B
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	0	2,000,000
Common stock, shares issued	0	1,030,700
Common stock, shares outstanding	0	1,030,700

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues
Oil and natural gas revenues	$ 155,998	$ 67,000	$ 34,042
Realized gain on derivatives	13,960	7,106	5,299
Unrealized (loss) gain on derivatives	(4,802)	5,138	3,139
Total revenues	165,156	79,244	42,480
Expenses
Production taxes and marketing	11,672	6,278	1,982
Lease operating	28,184	7,244	5,284
Depletion, depreciation and amortization	80,454	31,754	15,596
Accretion of asset retirement obligations	256	209	155
Full-cost ceiling impairment	63,475	35,673	0
General and administrative	14,543	13,394	9,702
Total expenses	198,584	94,552	32,719
Operating (loss) income	(33,428)	(15,308)	9,761
Other income (expense)
Net loss on asset sales and inventory impairment	(485)	(154)	(224)
Interest expense	(1,002)	(683)	(3)
Interest and other income	224	315	364
Total other (expense) income	(1,263)	(522)	137
(Loss) income before income taxes	(34,691)	(15,830)	9,898
Income tax (benefit) provision
Current		(46)	(1,411)
Deferred	(1,430)	(5,475)	4,932
Total income tax (benefit) provision	(1,430)	(5,521)	3,521
Net (loss) income	$ (33,261)	$ (10,309)	$ 6,377
Basic
Basic	53,957	42,718	41,038
Diluted
Diluted	53,957	42,718	41,134
Class A
Basic
Basic	$ (0.62)	$ (0.25)	$ 0.15
Diluted
Diluted	$ (0.62)	$ (0.25)	$ 0.15
Basic
Basic	53,852	41,687	40,007
Diluted
Diluted	53,852	41,687	40,103
Class B
Basic
Basic	$ (0.35)	$ 0.02	$ 0.42
Diluted
Diluted	$ (0.35)	$ 0.02	$ 0.42
Basic
Basic	105	1,031	1,031
Diluted
Diluted	105	1,031	1,031

Consolidated Statements of Changes in Shareholders' Equity - USD ($) $ in Thousands	Total	Additional paid-in capital	Retained earnings (deficit)	Treasury stock	Class A	Class A Common stock	Class B	Class B Common stock
Beginning Balance at Dec. 31, 2009	$ 264,322	$ 241,664	$ 22,761	$ (517)		$ 404		$ 10
Beginning Balance, shares at Dec. 31, 2009				68,000		40,443,000		1,031,000
Issuance of Class A common stock	20,652	20,633				$ 19
Issuance of Class A common stock, shares						1,879,000
Cost to issue equity	(531)	(531)
Issuance of Class A common stock to Board member and advisors	198	198
Issuance of Class A common stock to Board member and advisors, shares						20,000
Stock options granted	414	414
Stock options exercised	1,978	1,974				$ 4
Stock options exercised, shares						393,000
Stock options modified	1,086	1,086
Restricted stock issued, shares						15,000
Restricted stock vested	74	74
Class B dividends declared	(275)		(275)
Current period net loss	6,377		6,377
Issuance of treasury stock	47	2		$ 45
Issuance of treasury stock, shares				(6,000)	(6,000)
Purchases of treasury stock	(10,293)			$ (10,293)
Purchases of treasury stock, shares				1,117,000
Ending Balance at Dec. 31, 2010	281,877	263,342	28,863	$ (10,765)		$ 427		$ 10
Ending Balance, shares at Dec. 31, 2010				1,179,000		42,750,000		1,031,000
Issuance of Class A common stock	592	591				$ 1
Issuance of Class A common stock, shares						54,000
Cost to issue equity	(1,667)	(1,667)
Issuance of Class A common stock to Board member and advisors	230	230
Issuance of Class A common stock to Board member and advisors, shares						20,000
Stock options exercised	1,023	1,022				$ 1
Stock options exercised, shares						93,000
Restricted stock vested	44	44
Class B dividends declared	(275)		(275)
Current period net loss	(10,309)		(10,309)
Ending Balance at Dec. 31, 2011	271,515	263,562	18,279	$ (10,765)		$ 429		$ 10
Ending Balance, shares at Dec. 31, 2011				1,179,000	41,737,493	42,917,000	1,030,700	1,031,000
Issuance of Class A common stock	146,510	146,388				$ 122
Issuance of Class A common stock, shares						12,209,000
Cost to issue equity	(11,268)	(11,268)
Conversion of Class B common stock to Class A common stock						$ 10		$ (10)
Conversion of Class B common stock to Class A common stock, shares						1,031,000		(1,031,000)
Issuance of Class A common stock to Board member and advisors	71	71
Issuance of Class A common stock to Board member and advisors, shares						7,000
Stock options expense related to equity based awards	432	432
Stock options exercised	$ 3,544	3,541				$ 3
Stock options exercised, shares	296,000					296,000
Liability based stock option awards forfeited or expired	$ (216)	(216)
Changes in fair value for liability based awards for which grant date fair value is in excess of fair value	620	620
Restricted stock issued		(4)				$ 4
Restricted stock issued, shares						319,000
Restricted stock forfeited	(29)	(29)
Restricted stock forfeited, Shares				22,000
Restricted stock and restricted stock units expense	(758)	(758)
Swing sale profit contribution	24	24
Class B dividends declared	(28)		(28)
Current period net loss	$ (33,261)		(33,261)
Issuance of treasury stock, shares	(12,209,167)
Ending Balance at Dec. 31, 2012	$ 379,104	$ 404,311	$ (15,010)	$ (10,765)		$ 568
Ending Balance, shares at Dec. 31, 2012				1,201,000	55,577,667	56,779,000	0

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Operating activities
Net (loss) income	$ (33,261)	$ (10,309)	$ 6,377
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Unrealized loss (gain) on derivatives	4,802	(5,138)	(3,139)
Depletion, depreciation and amortization	80,454	31,754	15,596
Accretion of asset retirement obligations	256	209	155
Full-cost ceiling impairment	63,475	35,673	0
Stock option and grant expense	(589)	2,362	824
Restricted stock grants	729	44	74
Deferred income tax (benefit) provision	(1,430)	(5,475)	4,932
Loss on asset sales and inventory impairment	485	154	224
Changes in operating assets and liabilities
Accounts receivable	(16,342)	(1,523)	(386)
Lease and well equipment inventory	50	22	(8)
Prepaid expenses	50	650	(580)
Other assets	(673)	(814)	33
Accounts payable, accrued liabilities and other current liabilities	19,740	13,497	2,488
Royalties payable	4,685	873	309
Advances from joint interest owners	1,515	(723)	273
Other long-term liabilities	282	613	101
Net cash provided by operating activities	124,228	61,868	27,273
Investing activities
Oil and natural gas properties capital expenditures	(300,689)	(156,431)	(159,050)
Expenditures for other property and equipment	(7,332)	(4,671)	(1,610)
Purchases of certificates of deposit	(496)	(4,298)	(3,739)
Sales of certificates of deposit.	1,601	5,312	17,065
Net cash used in investing activities	(306,916)	(160,088)	(147,334)
Financing activities
Repayments of borrowings under Credit Agreement	(123,000)	(103,000)
Borrowings under Credit Agreement	160,000	191,000	25,000
Proceeds from issuance of common stock	146,510	592	20,652
Swing sale profit contribution	24
Cost to issue equity	(11,599)	(1,710)	(172)
Proceeds from stock options exercised	2,660	837	1,978
Payment of dividends - Class B	(96)	(275)	(275)
Purchases of treasury stock			(10,292)
Net cash provided by financing activities	174,499	87,444	36,891
Decrease in cash and cash equivalents	(8,189)	(10,776)	(83,170)
Cash and cash equivalents at beginning of year	10,284	21,060	104,230
Cash and cash equivalents at end of year	$ 2,095	$ 10,284	$ 21,060

Nature of Operations

12 Months Ended

Dec. 31, 2012

Nature of Operations [Abstract]

NATURE OF OPERATIONS

NOTE 1 — NATURE OF OPERATIONS

Matador Resources Company (“Matador” or the “Company”) is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Matador’s current operations are focused primarily in the oil and liquids rich Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. In addition to these primary operating areas, Matador has a growing acreage position in Southeast New Mexico and West Texas where the Company plans to begin exploring the Wolfcamp and Bone Spring plays during 2013. Matador also has a large exploratory position in Southwest Wyoming and adjacent areas in Utah and Idaho where the Company is testing the Meade Peak shale.

On November 22, 2010, the company formerly known as Matador Resources Company, a Texas corporation founded on July 3, 2003, formed a wholly-owned subsidiary, Matador Holdco, Inc. Pursuant to the terms of a corporate reorganization that was completed on August 9, 2011, the former Matador Resources Company became a wholly-owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company.

MRC Energy Company holds the primary assets of the Company and has four wholly-owned subsidiaries: Matador Production Company, MRC Permian Company, MRC Rockies Company and Longwood Gathering and Disposal Systems GP, Inc. Matador Production Company serves as the oil and natural gas operating entity. MRC Permian Company conducts oil and natural gas exploration and development activities in Southeast New Mexico. MRC Rockies Company conducts oil and natural gas exploration and development activities in the Rocky Mountains and specifically in the states of Wyoming, Utah and Idaho. Longwood Gathering and Disposal Systems GP, Inc. serves as the general partner of Longwood Gathering and Disposal Systems, LP which owns a majority of the pipeline systems and salt water disposal wells used in the Company’s operations and also transports limited quantities of third-party natural gas.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned subsidiary, MRC Energy Company, as well as the accounts of MRC Energy Company’s four wholly-owned subsidiaries, Matador Production Company, Longwood Gathering and Disposal Systems GP, Inc., MRC Permian Company and MRC Rockies Company, and the accounts of Longwood Gathering and Disposal Systems, LP. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). The Company’s operations are conducted in the one segment generally referred to as the oil and natural gas exploration and production industry. All significant intercompany balances and transactions have been eliminated in consolidation.

Reclassifications

Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of operations, cash flows or retained earnings.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates.

The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of thirty (30) days or less as cash equivalents, and cash equivalents are recorded at market. Except for small cash balances held in the Company’s operating accounts to conduct its ongoing business, the remainder of the Company’s cash equivalents during the year ended December 31, 2010 was held in money market accounts composed of United States Treasury securities offering daily liquidity. The Company had no cash equivalents as of December 31, 2012 or 2011.

Certificates of Deposit

Certificates of deposit (“CD’s”) are highly liquid, short-term investments with an original maturity of more than 30 days but not more than one year. Each CD is recorded at market and is fully insured by the Federal Deposit Insurance Corporation.

Accounts Receivable

The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see Note 14). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date, respectively, and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts.

The Company reviews its need for an allowance for doubtful accounts on a periodic basis, and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented.

The Company wrote off receivables of $24,229 in 2011; there were no receivables written off in 2012 or 2010. When necessary, the Company accounts for a write off by recording the loss as a reduction of accounts receivable once the specific account has been determined to be uncollectible.

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of equipment scheduled for use in future well operations or equipment held for sale.

Property and Equipment

The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $2.6 million, $2.0 million and $1.6 million of its general and administrative costs in 2012, 2011 and 2010, respectively. The Company capitalized $1.6 million and $1.3 million of its interest expense for the years ended December 31, 2012 and 2011, respectively. The Company recorded only $3,235 in interest expense for the year ended December 31, 2010. As a result, the Company capitalized no interest expense for the year ended December 31, 2010.

The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost ceiling, with any excess above the cost center ceiling charged to operations as a full-cost ceiling impairment. Beginning January 1, 2011, the need for a full-cost ceiling impairment is assessed on a quarterly basis. The cost center ceiling is defined as the sum of (a) the present value discounted at 10 percent of future net revenues of proved oil and natural gas reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to the properties involved. Future net revenues from proved non-producing and proved undeveloped reserves are reduced by the estimated costs for developing these reserves. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes.

The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent on the commodity prices used in these estimates. These estimates are determined in accordance with guidelines established by the SEC for estimating and reporting oil and natural gas reserves. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period January through December 2012, these average oil and natural gas prices were $91.21 per barrel and $2.757 per MMBtu, respectively. For the period January through December 2011, these average oil and natural gas prices were $92.71 per barrel and $4.118 per MMBtu, respectively. For the period January through December 2010, these average oil and natural gas prices were $75.96 per barrel and $4.376 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation fees and regional price differentials.

During the second quarter ended June 30, 2012, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $21.3 million. The Company recorded an impairment charge of $33.2 million to its net capitalized costs and a deferred income tax credit of $11.9 million related to the full-cost ceiling limitation. During the third quarter ended September 30, 2012, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $2.3 million. The Company recorded an impairment charge of $3.6 million to its net capitalized costs and a deferred income tax credit of $1.3 million related to the full-cost ceiling limitation. During the fourth quarter ended December 31, 2012, the Company’s net capitalized costs exceeded the cost center ceiling by $17.3 million. The Company recorded an impairment charge of $26.7 million to its net capitalized costs and a deferred income tax credit of $9.4 million related to the full-cost ceiling limitation. These charges for the second, third and fourth quarters of 2012 are reflected in the Company’s consolidated statement of operations for the year ended December 31, 2012. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods.

During the first quarter ended March 31, 2011, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling by $23.0 million. The Company recorded an impairment charge of $35.7 million to its net capitalized costs and a deferred income tax credit of $12.7 million related to the full-cost ceiling limitation. These charges are reflected in the Company’s consolidated statement of operations for the year ended December 31, 2011. The Company recorded no impairment to its net capitalized costs and no corresponding charge to its consolidated statement of operations for the year ended December 31, 2010.

As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its balance sheet, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported.

Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive.

Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized.

Other property and equipment are stated at cost. Computer equipment, furniture, software and other equipment are depreciated over their useful life (5 to 10 years) using the straight-line method. Support equipment and facilities include the pipelines and salt water disposal systems owned by Longwood Gathering and Disposal Systems, LP and are depreciated over a 30-year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease.

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or support equipment and facilities on the balance sheet. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statement of operations. In general, the Company’s future asset retirement obligations relate to future costs associated with plugging and abandonment of its oil and natural gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in its estimate or if federal or state regulators enact new plugging and abandonment requirements. At the time of actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent that the actual costs are different from the estimated liability.

Derivative Financial Instruments

From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. These instruments consist of put and call options in the form of costless (or zero-cost) collars and swap contracts. Costless collars provide the Company with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, these arrangements are initially “costless” to the Company. In the case of a costless collar, the put option and the call option have different fixed price components. In a swap contract, a floating price is exchanged for a fixed price over a specified period, providing downside price protection. The Company’s derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statement of operations (see Note 11). The fair value of the Company’s derivative financial instruments is determined using purchase and sale information available for similarly traded securities. Realized gains and realized losses from the settlement of derivative financial instruments and unrealized gains and losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in our consolidated statement of operations.

Revenue Recognition

The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to its ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received.

Stock-Based Compensation

Effective January 1, 2012, the Board of Directors adopted the 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). The 2012 Incentive Plan was also approved by the Company’s shareholders at its Annual Meeting of Shareholders on June 7, 2012. During 2012, all stock option awards granted under the 2012 Incentive Plan were non-qualified options and the associated compensation expense is recognized over the vesting period, which is typically four years. All stock option awards granted in 2012 are classified as equity instruments due to the methods of exercise specified in the 2012 Incentive Plan. Compensation expense for restricted stock and restricted stock unit grants awarded in 2012 was recognized immediately or over the vesting period, which is typically three to four years.

The Company did not grant any stock option awards in 2011. Prior to 2011, all stock option awards were granted under the 2003 Stock and Incentive Plan (the “2003 Plan”), and since November 22, 2010, these awards have been accounted for as liability instruments. No additional stock-based compensation will be awarded under the 2003 Plan. Non-qualified stock option grants awarded under the 2003 Plan typically vested upon issuance, while incentive stock option grants awarded under the 2003 Plan typically vest over four years, and the associated compensation expense is recognized on a straight-line basis over the vesting period. Compensation expense for restricted stock grants awarded under the 2003 Plan was recognized immediately or over the vesting period, which was typically three years.

At December 31, 2012 and 2011, the Company used the fair value method to measure and recognize the liability and equity associated with its outstanding stock options. At December 31, 2010, the Company measured and recognized the liability associated with its outstanding stock options using the intrinsic value method.

Prior to November 22, 2010, all of the Company’s then-outstanding stock options were classified as equity instruments, with all stock-based compensation expense measured on the date of grant and recognized over the vesting period, if any. On November 22, 2010, the Company changed its method of accounting for its then-outstanding stock options, reclassifying all of its then-outstanding stock options from equity to liability instruments. This change was made as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s Class A common stock. At December 31, 2012, we continue to account for all stock options granted under the 2003 Plan as liability instruments.

The Company’s consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010 include a stock-based compensation (non-cash) expense of $0.1 million, $2.4 million and $0.9 million, respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $0.1 million, $0.2 million and $0.2 million in 2012, 2011 and 2010, respectively, paid to members of the Board of Directors and advisors as compensation for their services to the Company.

Income Taxes

The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and provides a valuation allowance for the portion of any deferred tax assets where the likelihood of realizing an income tax benefit in the future does not meet the more likely than not criteria for recognition.

The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. Management believes that the material positions taken by the Company would more likely than not be sustained by examination. At December 31, 2012 and 2011, the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions.

When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income tax for the years ended December 31, 2012, 2011 and 2010.

Earnings Per Common Share

The Company reports 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.

Prior to consummation of the Company’s initial public offering (the “Initial Public Offering,” see Note 10) in February 2012, the Company had issued two classes of common stock, Class A and Class B. The holders of the Class B shares were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends were accrued and paid quarterly. Dividends declared during 2012 totaled $27,643. Dividends declared during 2011 and 2010 totaled $274,853 in each year. Class B dividends declared during the fourth quarter of 2011 and the first quarter of 2012 were paid during the first quarter of 2012 totaling $96,356. As of December 31, 2012, the Company has not paid any dividends to holders of the Class A shares. Concurrent with the completion of the Initial Public Offering, all 1,030,700 shares of the Company’s Class B common stock were converted to Class A common stock on a one-for-one basis. The Class A common stock is now referred to as the “common stock.”

The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted distributed and undistributed earnings per common share as reported for the years ended December 31, 2012, 2011 and 2010 (in thousands, except per share data).


	Year ended December 31,
	2012			2011			2010
Net income (loss) — numerator
Net (loss) income	$	(33,261	)	$	(10,309	)	$	6,377
Less dividends to Class B shareholders — distributed earnings		(28	)		(275	)		(275	)

Undistributed (loss) earnings	$	(33,289	)	$	(10,584	)	$	6,102

Weighted average common shares outstanding — denominator
Basic
Class A		53,852			41,687			40,007
Class B		105			1,031			1,031

Total		53,957			42,718			41,038

Diluted
Class A
Weighted average common shares outstanding for basic earnings (loss) per share		53,852			41,687			40,007
Dilutive effect of options		–			–			96

Class A weighted average common shares outstanding — diluted		53,852			41,687			40,103
Class B
Weighted average common shares outstanding — no associated dilutive shares		105			1,031			1,031

Total diluted weighted average common shares outstanding		53,957			42,718			41,134


	Year ended December 31,
	2012			2011			2010
Earnings (loss) per common share
Basic
Class A
Distributed earnings	$	–		$	–		$	–
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.62	)	$	(0.25	)	$	0.15

Class B
Distributed earnings	$	0.27		$	0.27		$	0.27
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.35	)	$	0.02		$	0.42

Diluted
Class A
Distributed earnings	$	–		$	–		$	–
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.62	)	$	(0.25	)	$	0.15

Class B
Distributed earnings	$	0.27		$	0.27		$	0.27
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.35	)	$	0.02		$	0.42

A total of 1,067,069 and 1,024,500 options to purchase shares of the Company’s Class A common stock and 162,368 and zero restricted stock units were excluded from the calculations above for the years ended December 31, 2012 and 2011, respectively, because their effects were anti-dilutive. Additionally, 305,807 restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2012 as the security holders do not have the obligation to share in the losses of the Company. There were no participating securities at December 31, 2011.

Fair Value Measurements

The Company measures and reports certain assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company follows FASB guidance establishing a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value.

Credit Risk

The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company believes that any credit risk posed is insignificant and is offset by the creditworthiness of its customer base and industry partners.

Risks and Uncertainties

As an oil and natural gas exploration and production company focused on finding and developing its own prospects and reserves, the Company’s success is highly dependent on the results of its exploration and development program. Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reserves will be discovered. In addition, there are uncertainties as to the future costs or timing of drilling, completing and producing wells. Poor results from the Company’s exploration and development activities could limit the Company’s ability to replace and grow reserves and materially and adversely affect the Company’s financial position, results of operations and cash flows.

As a result of the Company’s sale of certain assets to Chesapeake Louisiana, L.P. (“Chesapeake”) in 2008, the Company does not operate its most significant natural gas asset, that being the deep rights to explore for and develop the Haynesville shale formation (underlying its existing Cotton Valley production) on the Company’s Elm Grove/Caspiana leasehold in Northwest Louisiana. Although the Company has reserved the right to participate for a proportionately reduced 25% working interest in all wells that Chesapeake drills or participates in to develop the Haynesville on this acreage, and although the Company has the right to propose the drilling of Haynesville wells on these properties, the Company may have limited influence on when, how and at what pace these properties are developed. This could impact the Company’s ability to replace and grow reserves and materially and adversely affect the Company’s financial position, results of operations and cash flows. In addition, in 2012, 2011 and 2010, the Company acquired other non-operated acreage positions in Northwest Louisiana that it believes to be prospective for the Haynesville shale. The Company has, or will have, small, non-operated working interests in the Haynesville units including these properties, and as a result, the Company will have limited influence on when, how and at what pace these properties are developed.

Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates. Any significant variance could materially and adversely affect the Company’s future reserves estimates, financial position, results of operations and cash flows.

Historically, the market for oil, natural gas and natural gas liquids has experienced significant price fluctuations, and this has been particularly evident in recent years. Oil, natural gas and natural gas liquids prices are impacted by supply and demand, both domestic and international, seasonal variations caused by changing weather conditions, political conditions, governmental regulations, the availability, proximity and capacity of gathering, processing and transportation systems for natural gas and natural gas liquids and numerous other factors. Increases or decreases in prices received could have a significant and material impact on the Company’s future reserves estimates, financial position, results of operations and cash flows.

To mitigate its exposure to fluctuations in oil, natural gas and natural gas liquids prices, the Company, from time to time, enters into hedging arrangements with respect to a portion of its oil, natural gas and natural gas liquids production. Decisions as to whether and at what production volumes to hedge are difficult and depend on market conditions and the Company’s forecast of future production and commodity prices, and the Company may not always employ the optimal hedging strategy.

The federal, state and local governments in the areas in which the Company operates or has assets impose taxes on the oil and natural gas products sold, and sales and use taxes are charged on significant portions of the Company’s drilling, completion and operating costs. Many states have raised state taxes on energy sources or state taxes associated with the extraction of hydrocarbons, and additional increases may occur. In addition, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration and production companies like Matador. Among other issues, President Obama has proposed to eliminate allowing small oil and natural gas companies to deduct intangible drilling costs as incurred and percentage depletion. Changes to tax laws could materially and adversely affect the Company’s future financial position, results of operations and cash flows.

Recent Accounting Pronouncements

Balance Sheet. In January 2013, the FASB issued Accounting Standards Update, or ASU, 2013-01, Balance Sheet. The ASU clarifies the scope of ASU 2011-11 to limit the application of ASU 2011-11 to derivatives accounted for in accordance with Accounting Standards Codification, or ASC, 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. The adoption of ASU 2013-01 is not expected to have a material effect on our consolidated financial statements, but may require certain additional disclosures.

Balance Sheet. In December 2011, the FASB issued ASU 2011-11, Balance Sheet. The requirements amend the disclosure requirements related to offsetting in ASC 210-20-50. The amendments require enhanced disclosures by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The adoption of ASU 2011-11 is not expected to have a material effect on the Company’s consolidated financial statements, but may require certain additional disclosures. The amendments in ASU 2011-11 are to be applied for annual reporting periods beginning on or after January 1, 2013 and are to be applied retrospectively for all periods presented.

Fair Value. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. ASU 2011-04 amends ASC 820, Fair Value Measurements, providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value measurements. The Company adopted ASU 2011-04 on January 1, 2012; adoption did not have a material effect on the Company’s consolidated financial statements, but did require additional disclosures (see Note 12).

Property and Equipment

12 Months Ended

Dec. 31, 2012

Property and Equipment [Abstract]

PROPERTY AND EQUIPMENT

NOTE 3 — PROPERTY AND EQUIPMENT

The following table presents a summary of the Company’s property and equipment balances as of December 31, 2012 and 2011 (in thousands).


	December 31,
	2012			2011
Oil and natural gas properties
Evaluated (subject to amortization)	$	763,527		$	423,945
Unproved and unevaluated (not subject to amortization)
Incurred in 2012		36,488			–
Incurred in 2011		24,138			60,934
Incurred in 2010		70,417			80,593
Incurred in 2009 and prior		18,632			21,071

Total unproved and unevaluated		149,675			162,598

Total oil and natural gas properties		913,202			586,543
Accumulated depletion		(344,609	)		(201,543	)

Net oil and natural gas properties		568,593			385,000
Other property and equipment
Computer equipment		834			787
Furniture		793			458
Software		1,355			1,111
Other equipment		196			194
Leasehold improvements		644			627
Support equipment and facilities		23,436			15,587

Total other property and equipment		27,258			18,764
Accumulated depreciation		(4,761	)		(3,899	)

Net other property and equipment		22,497			14,865

Net property and equipment	$	591,090		$	399,865

The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2012 and the year in which these costs were incurred (in thousands).


Description	2012		2011		2010		2009 and prior		Total
Costs incurred for
Property acquisition	$	29,165	$	21,748	$	70,417	$	18,632	$	139,962
Exploration wells		4,680		1,932		–		–		6,612
Development wells		2,573		–		–		–		2,573
Capitalized interest		70		458		–		–		528

Total	$	36,488	$	24,138	$	70,417	$	18,632	$	149,675

Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions.

Property acquisition costs incurred in 2012 were related primarily to the Company’s leasing and acquisition activities in the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Delaware Basin in West Texas.

Property acquisition costs incurred in 2011 were related primarily to the Company’s leasing and acquisition activities in the Eagle Ford shale play in South Texas. The 2010 property acquisition costs were related primarily to the Company’s leasing activities in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. These costs are associated with acreage for which proved reserves have yet to be assigned. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. The Company estimates that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within three to five years.

Property acquisition costs incurred in 2009 and prior years were related primarily to the Company’s leasing activities in the Haynesville shale play in Northwest Louisiana and in Southwest Wyoming, Northeast Utah and Southeast Idaho. During 2011, the Company drilled its first exploration well on its acreage in Southwest Wyoming. We re-entered this vertical well in late 2012 and drilled a horizontal lateral that will be completed in 2013. The Company estimates that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within two to four years.

Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis, as these wells are completed and proved reserves are established or confirmed. These costs totaled $7.3 million at December 31, 2012. Of this total, $4.7 million was associated with exploration wells and $2.6 million was associated with development wells. The Company anticipates that the entire $7.3 million associated with these wells in progress at December 31, 2012 will be transferred to the amortization base during 2013. At December 31, 2012, there were $1.9 million in exploratory well costs excluded from amortization that were incurred in years prior to 2012, all associated with the exploration well in Southwest Wyoming. The Company plans to complete and test this well in 2013 and anticipates that the entire $1.9 million incurred in 2011 will also be transferred to the amortization base during 2013.

- Definition

The entire disclosure for long-lived, physical assets that are used in the normal conduct of business to produce goods and services and not intended for resale. Examples include land, buildings, machinery and equipment, and other types of furniture and equipment including, but not limited to, office equipment, furniture and fixtures, and computer equipment and software. This disclosure may include property plant and equipment accounting policies and methodology, a schedule of property, plant and equipment gross, additions, deletions, transfers and other changes, depreciation, depletion and amortization expense, net, accumulated depreciation, depletion and amortization expense and useful lives, income statement disclosures, assets held for sale and public utility disclosures.

+ References + Details

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligations [Abstract]

ASSET RETIREMENT OBLIGATIONS

NOTE 4 — ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2012 and 2011 (in thousands).


	Year ended December 31,
	2012		2011
Beginning asset retirement obligations	$	4,270	$	3,695
Liabilities incurred during period		1,243		187
Revisions in estimated cash flows		–		312
Liabilities settled during period		–		(133	)
Accretion expense		256		209

Ending asset retirement obligations	$	5,769	$	4,270

At December 31, 2012 and 2011, $660,303 and $334,500, respectively, of the Company’s asset retirement obligations were classified as current liabilities and included in “accrued liabilities” in the Company’s consolidated balance sheets, based on the expected timing of payments.

Asset Sales and Impairment

12 Months Ended

Dec. 31, 2012

Asset Sales and Impairment [Abstract]

ASSET SALES AND IMPAIRMENT

NOTE 5 — ASSET SALES AND IMPAIRMENT

In December 2012, the Company recorded an impairment to reduce the remaining balance of its drilling rig parts held in inventory to zero following a determination that there was no current market for these parts. The carrying value of the inventory was reduced to zero and a charge of $425,000 was recorded to the consolidated statement of operations. In addition, the Company recorded a loss of approximately $60,000 on certain other equipment that was sold during 2012.

In December 2011, the Company recorded an impairment to some of its equipment held in inventory following a determination that the current market value of the equipment, consisting primarily of drilling rig parts, was less than the cost. The carrying value of the inventory was reduced by $17,500 on the balance sheet, and a corresponding charge was recorded to the consolidated statement of operations. In December 2011, the Company also recorded an impairment to some of its equipment held in inventory following a determination that the current market value of the equipment, consisting primarily of pipe and other equipment, was less than the cost. The carrying value of the inventory was reduced by $22,276 on the balance sheet, and a corresponding charge was recorded to the consolidated statement of operations. In addition, the Company recorded a loss of $113,757 on certain other equipment that was sold during 2011.

In December 2010, the Company wrote off the Boise South Pipeline asset in Orange County, Texas from its Longwood Gathering and Disposal Systems, LP subsidiary and recorded a net loss of $173,690. The decision to write off this asset resulted from the fact that natural gas was no longer being put through this pipeline, nor was natural gas expected to be put through this pipeline in the future. In December 2010, the Company also recorded an impairment to some of its equipment held in inventory following a determination that the current market value of the equipment, consisting primarily of drilling rig parts, was less than the cost. The carrying value of the inventory was reduced by $50,000 on the balance sheet, and a corresponding charge was recorded to the consolidated statement of operations.

Revolving Credit Agreement

12 Months Ended

Dec. 31, 2012

Revolving Credit Agreement [Abstract]

REVOLVING CREDIT AGREEMENT

NOTE 6 — REVOLVING CREDIT AGREEMENT

In December 2011, the Company entered into its second amended and restated senior secured revolving Credit Agreement for which Comerica Bank served as administrative agent. Among other things, this amendment increased the size of the facility and extended the term until December 2016. MRC Energy Company, a wholly-owned subsidiary of Matador Resources Company, was the borrower under the amended Credit Agreement. Borrowings were secured by mortgages on substantially all of the Company’s oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly-owned subsidiaries, which were also guarantors. In addition, all obligations under the Credit Agreement were guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with one of the lenders under the Credit Agreement (or an affiliate thereof) were also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company.

The amount of the borrowings under the second amended and restated Credit Agreement were limited to the lesser of $400.0 million or the borrowing base, which was determined by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves, but also on external factors, such as the lenders’ lending policies and the lenders’ estimates of future oil and natural gas prices, over which the Company has no control. At December 31, 2011, the borrowing base was $125.0 million and the Company had $113.0 million in outstanding borrowings under the Credit Agreement. In January 2012, the Company borrowed an additional $10.0 million to finance a portion of its working capital requirements, bringing the then-outstanding indebtedness under the Credit Agreement to $123.0 million. Following the completion of the Initial Public Offering, the Company used a portion of the net proceeds to repay the then-outstanding $123.0 million under its Credit Agreement in February 2012, at which time the borrowing base was reduced to $100.0 million. On February 28, 2012, the borrowing base was increased to $125.0 million pursuant to a special borrowing base redetermination made at the Company’s request. This borrowing base increase was determined by the lenders based upon, among other items, the increase in the Company’s proved oil and natural gas reserves at December 31, 2011.

On September 28, 2012, the Company entered into its third amended and restated senior secured revolving Credit Agreement. Among other things, this amendment increased the maximum facility amount from $400.0 million to $500.0 million, increased the borrowing base from $125.0 million to $200.0 million and named Royal Bank of Canada (“RBC”) as the administrative agent. In addition, the amendment provided for a conforming borrowing base of $165.0 million. The borrowing base will automatically be reduced to the conforming borrowing base on the earlier of (i) December 31, 2013 or (ii) the closing of a secondary public offering of equity interests that results in net cash proceeds to the Company in an amount greater than or equal to $25.0 million. The Credit Agreement matures December 29, 2016. MRC Energy Company is the borrower under the Credit Agreement. Borrowings are secured by mortgages on substantially all of the Company’s oil and natural gas properties and by the equity interests of all of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador Resources Company, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by the eligible subsidiaries of MRC Energy Company.

The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at June 30 and December 31 of each year. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. During the fourth quarter of 2012, the Company requested one such unscheduled redetermination, and on December 20, 2012, the borrowing base was increased from $200.0 million to $215.0 million as a result of the lenders’ review of the Company’s proved oil and natural gas reserves at September 30, 2012. In connection with this borrowing base redetermination, the conforming borrowing base was increased to $180.0 million at December 20, 2012. In addition, during the first quarter of 2013, the lenders completed their review of the Company’s proved oil and natural gas reserves at December 31, 2012, and as a result, on March 11, 2013, the borrowing base was increased to $255.0 million and the conforming borrowing base was increased to $220.0 million (see Note 18). This most recent redetermination constitutes the regularly scheduled May 1 redetermination. In the event of a borrowing base increase, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which will be determined based on market conditions at the time of the borrowing base increase. If the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months.

The Company incurred $0.8 million of additional deferred loan costs in connection with the amendment and restatement of the Credit Agreement in September 2012 and approximately $0.1 million of additional deferred loan costs in connection with the borrowing base increase in December 2012. These costs were included with the remaining unamortized portion of the deferred loan costs of $0.8 million incurred when the Company entered into the Credit Agreement in March 2008 as well as the second amended and restated Credit Agreement on December 30, 2011. As a result, total deferred loan costs are $1.6 million at December 31, 2012, and these costs are being amortized over the term of the agreement, which approximates the amortization of these costs using the effective interest method.

Between March 1, 2012 and December 31, 2012, the Company borrowed $150.0 million under the Credit Agreement to finance a portion of its working capital requirements and capital expenditures. At December 31, 2012, the Company had $150.0 million in borrowings outstanding under the Credit Agreement, approximately $1.1 million in outstanding letters of credit issued pursuant to the Credit Agreement and approximately $63.9 million available for additional borrowings. At December 31, 2012, the outstanding borrowings bore interest at an effective interest rate of approximately 3.3% per annum.

From January 1 through March 14, 2013, the Company borrowed an additional $30.0 million under the Credit Agreement to finance a portion of its working capital requirements and capital expenditures. At March 14, 2013, the Company had $180.0 million in borrowings outstanding under the Credit Agreement, approximately $1.3 million in outstanding letters of credit issued pursuant to the Credit Agreement and approximately $73.7 million available for additional borrowings (see Note 18).

If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate plus 1.0% plus, in each case, an amount from 0.75% to 2.25% of such outstanding loan depending on the level of borrowings under the agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which RBC is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.75% to 3.25% of such outstanding loan depending on the level of borrowings under the agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. A commitment fee of 0.375% to 0.50%, depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees as interest expense and in its interest rate calculations and related disclosures.

Key financial covenants under the third amended and restated Credit Agreement require the Company to maintain (1) a current ratio, which is defined as consolidated total current assets plus the unused availability under the Credit Agreement divided by consolidated total current liabilities, of 1.0 or greater measured at the end of each fiscal quarter beginning March 31, 2013 and (2) a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.0 or less. In connection with the March 11, 2013 borrowing base redetermination, the Credit Agreement was amended to delay first measurement of the current ratio until March 31, 2014 (see Note 18).

Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s, along with its subsidiaries’, ability to take certain actions, including, but not limited to, the following:

•

incur indebtedness or grant liens on any of its assets;

•

enter into commodity hedging agreements;

•

declare or pay dividends, distributions or redemptions;

•

merge or consolidate;

•

make any loans or investments;

•

engage in transactions with affiliates; and

•

engage in certain asset dispositions, including a sale of all or substantially all of its assets.

If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events:

•

failure to pay any principal or interest on the notes or any reimbursement obligation under any letter of credit when due or any fees or other amount within certain grace periods;

•

failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;

•

bankruptcy or insolvency events involving the Company or its subsidiaries; and

•

a change of control, as defined in the Credit Agreement.

At December 31, 2012, the Company believes that it was in compliance with the terms of its Credit Agreement.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References + Details

Income Taxes

12 Months Ended

Dec. 31, 2012

Income Taxes [Abstract]

INCOME TAXES

NOTE 7 — INCOME TAXES

Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2012 and 2011, respectively, is as follows (in thousands).


	December 31,
	2012			2011
Current deferred tax assets
Property and equipment	$	233		$	113
Other		869
Net operating loss carryforwards		–			13

Total current deferred tax assets		1,102			126

Valuation allowance on current deferred tax assets		(202	)		–

Total current deferred tax assets, net of valuation allowance		900			126
Current deferred tax liabilities
Unrealized gain on derivatives		(1,311	)		(2,998	)
Other		–			(152	)

Total current deferred tax liabilities		(1,311	)		(3,150	)

Net current deferred tax liability	$	(411	)	$	(3,024	)

Non-current deferred tax assets
Net operating loss carryforwards	$	44,654		$	24,034
Alternative minimum tax carryforward		6,660			6,660

Total non-current deferred tax assets		51,314			30,694

Valuation allowance on non-current deferred tax assets		(10,058	)		–

Total non-current deferred tax assets, net of valuation allowance		41,256			30,694
Non-current deferred tax liabilities
Unrealized gain on derivatives		(262	)		(324	)
Property and equipment		(36,363	)		(27,070	)
Other		(4,220	)		(1,706	)

Total non-current deferred tax liabilities		(40,845	)		(29,100	)

Net non-current deferred tax asset	$	411		$	1,594

At December 31, 2012, the Company had net operating loss carryforwards of $123.3 million for federal income tax purposes and $30.3 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning December 31, 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards began expiring at various dates beginning December 31, 2013 for the state of New Mexico; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027.

At June 30, 2012, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $21.3 million. As a result, the Company recorded an impairment charge of $33.2 million to the net capitalized costs of its oil and natural gas properties and a deferred income tax credit of $11.9 million. At September 30, 2012, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $2.3 million. As a result, the Company recorded an impairment charge of $3.6 million to the net capitalized costs of its oil and natural gas properties and a deferred income tax credit of $1.3 million. This deferred income tax credit exceeded the Company’s deferred tax liabilities at September 30, 2012. As a result, the Company established a valuation allowance of $2.4 million at September 30, 2012 due to uncertainties regarding the future realization of its deferred tax assets. At December 31, 2012, the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeded the full-cost ceiling by $17.3 million. As a result, the Company recorded an impairment charge of $26.7 million to the net capitalized costs of its oil and natural gas properties and a deferred income tax credit of $9.4 million. This deferred income tax credit exceeded the Company’s deferred tax liabilities at December 31, 2012. As a result, the Company increased the previously established valuation allowance by $7.9 million to maintain a full valuation allowance of $10.3 million against the Company’s net deferred tax assets.

The Company also recorded an impairment charge of $23.0 million to its net capitalized costs, net of a deferred income tax credit of $12.7 million related to the full-cost ceiling limitation during the first quarter ended March 31, 2011. This deferred income tax credit exceeded the Company’s deferred tax liabilities at March 31, 2011. As a result, the Company established a valuation allowance at March 31, 2011 and retained a valuation allowance until the fourth quarter of the year ended December 31, 2011 due to uncertainties regarding the future realization of its deferred tax assets. At December 31, 2011, the Company assessed the valuation allowance and determined that the allowance was no longer required.

The income tax expense reconciled to the tax computed at the statutory federal rate for the years ended December 31, 2012, 2011 and 2010, respectively, is as follows (in thousands).


	Year ended December 31,
	2012			2011			2010
Current income tax (benefit) provision
State income tax	$	–		$	(46	)	$	–
Federal alternative minimum tax		–			–			(1,411	)

Net current income tax benefit		–			(46	)		(1,411	)
Deferred income tax provision (benefit)
Federal tax expense at statutory rate (34%)		(11,767	)		(5,319	)		3,365
Statutory depletion carryforward		–			231			(157	)
State income tax		(819	)		(435	)		–
Change in state rate applied		–			–			275
Nondeductible expense		(122	)		48			38
Permanent differences⁽¹⁾		1,018			–			–
Federal alternative minimum tax		–			–			1,411
Change in valuation allowance		10,260			–			–

Net deferred income tax (benefit) provision		(1,430	)		(5,475	)		4,932

Total income tax (benefit) provision	$	(1,430	)	$	(5,521	)	$	3,521

⁽¹⁾

Amount is primarily attributable to stock-based compensation.

The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The tax years open for examination for the federal tax return are 2009, 2010, 2011 and 2012. The tax years open for examination by the state of Texas are 2008, 2009, 2010, 2011 and 2012. The tax years open for examination by the state of New Mexico are 2009, 2010, 2011 and 2012. The tax years open for examination by the state of Louisiana are 2009, 2010, 2011 and 2012.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

+ Details

Stock-Based Compensation

12 Months Ended

Dec. 31, 2012

Stock-Based Compensation [Abstract]

STOCK-BASED COMPENSATION

NOTE 8 — STOCK-BASED COMPENSATION

Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards

In 2003 the Company’s Board of Directors and shareholders approved the Matador Resources Company 2003 Stock and Incentive Plan (the “2003 Plan”). The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of Class A common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company.

Effective January 1, 2012, the Board of Directors adopted the 2012 Long-Term Incentive Plan (the “2012 Incentive Plan”). The 2012 Incentive Plan was also approved by the Company’s shareholders at its Annual Meeting of Shareholders on June 7, 2012. The 2012 Incentive Plan provides for a maximum of 4,000,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors and advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled.

The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of Directors, which determines the number of options or restricted shares to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. All stock-based compensation awards granted during 2012 were granted under the 2012 Incentive Plan, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan.

Stock Options

Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of four years and a typical maximum term of five or ten years.

On November 22, 2010, the Company changed its method of accounting for its then-outstanding stock options granted under the 2003 Plan, reclassifying all then-outstanding stock options from equity to liability instruments (see Note 2). At December 31, 2010, the Company measured and recognized the liability associated with its outstanding stock options using the intrinsic value method and an estimated fair value of $11.00 per share for the Company’s common stock. The fair value of equity stock option awards granted during the year ended December 31, 2010, prior to the reclassification, under the 2003 Plan was estimated using the following weighted average assumptions at December 31, 2010.


Stock option pricing model		Binomial Lattice
Expected option life		5.41 years
Risk-free interest rate		2.58%
Volatility		46.17%
Dividend yield		0.0%
Estimated forfeiture rate		11.15%
Weighted average fair value of stock option awards granted during the year		$3.02

Effective upon filing its initial Registration Statement with the SEC in August 2011, the Company adopted the fair value method and used an estimated fair value of $12.00 per share to measure and recognize the liability associated with its outstanding stock options. The Company recorded $1.1 million in additional general and administrative expenses during 2011 due to this change in the valuation method from the intrinsic value method to the fair value method.

The Company granted no stock option awards during the year ended December 31, 2011. The fair value of stock option awards outstanding under the 2003 Plan was estimated using the following weighted average assumptions at December 31, 2012 and 2011.


	2012	2011
Stock option pricing model	Black Scholes Merton	Black Scholes Merton
Expected option life	0.89 years	1.04 years
Risk-free interest rate	0.25%	0.37%
Volatility	54.28%	61.41%
Dividend yield	0.00%	0.00%
Estimated forfeiture rate	0.70%	1.04%

During 2012, the Company began granting stock-based compensation awards under the 2012 Incentive Plan. Stock option awards granted under this plan are accounted for as equity instruments. The weighted average grant date fair value was estimated using the following weighted average assumptions during the year ended December 31, 2012.


Stock option pricing model		Black Scholes Merton
Expected option life		4.44 years
Risk-free interest rate		0.71%
Volatility		71.16%
Dividend yield		0.00%
Estimated forfeiture rate		5.46%
Weighted average fair value of stock option awards granted during the year		$5.95

The Company estimated the future volatility of its common stock using the historical value of its peer group for a period of time commensurate with the expected term of the stock option due to the lack of historical trading data available for its common stock. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award.

Summarized information about stock options outstanding at December 31, 2012 under the Company’s 2003 Plan and the 2012 Incentive Plan is as follows (in thousands, except price data).


	Number of options			Weighted average exercise price
Options outstanding at December 31, 2011		1,025		$	9.75
Options granted		656			10.79
Options exercised		(296	)		9.00
Options forfeited		(248	)		11.43
Options expired		(70	)		9.95

Options outstanding at December 31, 2012		1,067		$	10.19


	Options outstanding at December 31, 2012						Options exercisable at December 31, 2012
Range of exercise prices	Shares outstanding		Weighted average remaining contractual life		Weighted average exercise price		Shares exercisable		Weighted average exercise price
$7.50-$9.00		139		6.34 years	$	8.77		66	$	8.75
$10.00-$13.33		928		2.37 years	$	10.41		459	$	10.32

At December 31, 2012, the aggregate intrinsic value was zero for both the outstanding options and the exercisable options, based on our quoted closing market price of $8.20 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2012 was 1.06 years.

The total intrinsic value of options exercised during the years ended December 31, 2012, 2011 and 2010 was $0.9 million, $0.2 million and $2.2 million, respectively. The tax related benefit realized from the exercise of stock options totaled zero, zero and $0.8 million for the years ended December 31, 2012, 2011 and 2010, respectively.

During the years ended December 31, 2012, 2011 and 2010, the Company recognized $(0.7) million, $2.1 million and $0.6 million, respectively, in stock compensation expense attributable to stock options. At December 31, 2012 and 2011, the Company had recorded $0.3 million and $0.3 million of long-term liabilities and $0.1 million and $2.9 million of current liabilities, respectively, related to its outstanding liability based stock options. The Company paid zero, $0.1 million and $0.4 million in settlement of liability based awards for the years ended December 31, 2012, 2011 and 2010, respectively.

At December 31, 2012, the total remaining unrecognized compensation expense related to unvested stock options was approximately $2.3 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was approximately 2.83 years.

The fair value of option shares vested during 2012, 2011 and 2010 was $0.3 million, $1.0 million and $2.4 million, respectively.

Restricted Stock, Restricted Stock Units and Common Stock

The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the restrictions being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a term no longer than two years after vesting. No such elections were made with respect to the 2012 restricted stock unit awards. The 2012 restricted stock awards included 116,841 performance based awards. These shares vest based on the outcome of the Company’s total shareholder return over a three-year period beginning March 19, 2012 and ending April 15, 2015 as compared to a designated peer group. This award may result in the vesting of an aggregate of up to 116,841 restricted stock units in addition to the restricted stock grants. If the performance conditions are not met, however, this award may result in no performance based restricted stock being vested and no restricted stock units being vested. The fair value of this award was estimated based on the most likely outcome of the award as determined by the Monte Carlo method. A total of 13,833 shares of restricted stock awards granted in 2012 vested immediately upon grant, and the remaining 2012 restricted stock and restricted stock units awards vest over the service period, which ranges from one year to a maximum of four years.

A summary of the non-vested restricted stock and restricted stock units as of December 31, 2012 is presented below (in thousands, except fair value).


	Restricted Stock										Restricted Stock Units
	Service Based					Performance Based					Service Based					Performance Based
Non-vested restricted stock and restricted stock units	Shares			Weighted average fair value		Shares			Weighted average fair Value⁽¹⁾		Shares			Weighted average fair value		Shares			Weighted average fair Value⁽¹⁾
Non-vested at January 1, 2012		8		$	11.00		–		$	–		–		$	–		–		$	–
Granted		207			9.66		117			13.24		54			10.04		117			–
Vested		(18	)		8.72		–			–		–			–		–			–
Forfeited		(15	)		10.76		(7	)		13.24		(2	)		11.02		(7	)		–

Non-vested at December 31, 2012		182		$	9.72		110		$	13.24		52		$	10.00		110		$	–

⁽¹⁾	The fair value of these restricted stock units is reflected in the fair value of the performance based restricted stock, which was estimated based on the most likely outcome of the award as determined by the Monte Carlo method.

At December 31, 2012, the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $3.7 million as calculated based on the maximum number of shares of restricted stock, performance based restricted stock and restricted stock units vesting, using the stock price on December 31, 2012.

During the years ended December 31, 2012, 2011 and 2010, the Company recognized $0.7 million, approximately $44,000 and $0.1 million, respectively, in stock compensation expense attributable to restricted stock and restricted stock units.

At December 31, 2012, the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $3.0 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was approximately 2.23 years.

The fair value of restricted stock and restricted stock units vested during 2012, 2011 and 2010 was $44,000, $44,000 and $46,330, respectively.

The total tax benefit recognized for stock-based compensation was $0.3 million, $0.9 million and $0.3 million for the years ended December 31, 2012, 2011 and 2010, respectively.

In February 2013, options to purchase 408,000 shares of the Company’s common stock at $10.00 per share expired unexercised or were forfeited (see Note 18).

During the years ended December 31, 2012, 2011 and 2010, the Company issued shares of common stock to certain members of its Board of Directors. The Company also issued shares of common stock to certain outside advisors who do not meet the definition of employees under ASC 718. The Company used the fair value of the stock issued on the grant date to recognize the expense related to these awards. The Company recognized $0.1 million, $0.2 million and $0.2 million in stock compensation expense attributable to these awards for the years ended December 31, 2012, 2011 and 2010, respectively.

In October 2008, the Company’s Board of Directors approved the adoption of the Employee Share Repurchase Program (“Repurchase Program”) authorizing the Company to repurchase shares of its Class A common stock from its employees, directors and officers, subject to certain conditions and restrictions. In 2010, the Company repurchased 117,505 shares of Class A common stock at $11.00 per share from thirteen employees (including the Executive Vice President, Chief Financial Officer and Chief Operating Officer, the Executive Vice President — Operations and the Vice President — Reservoir Engineering). No director nor the Company’s Chairman and Chief Executive Officer has ever participated in the Repurchase Program. The Company’s Board of Directors terminated the Repurchase Program in April 2011, and the Company is no longer authorized to repurchase shares of common stock from its employees, directors and officers. No shares were repurchased in 2011 prior to the termination of the Repurchase Program by the Board of Directors.

In October 2008, the Company’s Board of Directors approved the adoption of the Employee Option Exercise Loan Program (“Loan Program”), authorizing the Company to establish a loan program with a financial institution to assist its employees, directors and officers in the exercise of their outstanding options to purchase shares of Class A common stock, subject to certain conditions and restrictions outlined in the Loan Program. As part of the Loan Program, the Company provides the financial institution with a guaranty of repayment of the loan and makes deposits of funds in certificates of deposit to secure its guaranty. Notwithstanding the guaranty, these loans are fully recourse obligations of each loan recipient, and each loan recipient agrees to indemnify and reimburse the Company in full for all liabilities incurred by the Company in the event of the recipient’s default on the loan. Each loan recipient also pledges all shares purchased from the Company with the loan proceeds to further secure his or her obligations to the Company in return for its guaranty. No director nor the Company’s Chairman and Chief Executive Officer has ever participated in the Loan Program.

As of December 31, 2012, the Company had secured the loans of four employees pursuant to this Loan Program in the aggregate amount of $0.2 million. The Company considers the fair value of this aggregate guaranty to be minimal and has recorded no liability provision associated with this guaranty on its consolidated balance sheets in any reporting period presented. The Company’s Board of Directors terminated the Loan Program in April 2011, and the Company is no longer authorized to provide financial guaranties for additional loans. No new loans were guaranteed in 2011 prior to the termination of the Loan Program by the Board of Directors.

- Definition

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 50
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6406099&loc=d3e25284-112666

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 40
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6418621&loc=d3e17540-113929

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5070-113901

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5047-113901

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 718
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6415400&loc=d3e5444-113901

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 14

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 123R
-Paragraph 64, 65, A240
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 93-6
-Paragraph 53
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Employee Benefit Plans

12 Months Ended

Dec. 31, 2012

Employee Benefit Plans [Abstract]

EMPLOYEE BENEFIT PLANS

NOTE 9 — EMPLOYEE BENEFIT PLANS

401(k) Plan

Effective July 3, 2003, the Company established a defined contribution retirement plan. All full-time Company employees are eligible to join the plan the first day of the calendar month immediately following their date of employment. Each Participant may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution. The Company’s Safe Harbor match was approximately $0.2 million in each of 2012, 2011 and 2010. In addition, each year, the Company may determine and make a discretionary matching contribution as well as additional contributions. The Company’s discretionary matching contributions totaled $0.3 million, $0.2 million and $0.2 million in 2012, 2011 and 2010, respectively. The Company made no additional discretionary contributions in any reporting period presented.

Common Stock

12 Months Ended

Dec. 31, 2012

Common Stock [Abstract]

COMMON STOCK

NOTE 10 — COMMON STOCK

Dividends

At December 31, 2011 and 2010, the Company had issued two classes of common stock, Class A and Class B. In February 2012, upon the consummation of the Company’s Initial Public Offering, the Class B shares were converted to Class A shares, which are now referred to as common stock. The holders of the Class B shares were entitled to be paid cumulative dividends at a per share rate of $0.26-2/3 annually out of funds legally available for the payment of dividends. These dividends were accrued and paid quarterly. Dividends declared and paid during 2012 were $27,643. Dividends declared during 2011 and 2010 totaled $0.3 million in each year. Dividends for the fourth quarter of 2011 were accrued and paid in January 2012. Dividends for the fourth quarter of 2010 and 2009 were accrued and paid in January 2011 and 2010, respectively. As of December 31, 2012, the Company has not paid any dividends to holders of the Class A shares.

Stock Offerings, Retirement and Issuances

On August 12, 2011, the Company filed a Form S-1 Registration Statement under the Securities Act of 1933 to commence the Initial Public Offering. The Company’s Registration Statement (File 333-176263), as amended, was declared effective by the SEC on February 1, 2012. The underwriters for the Company’s Initial Public Offering were RBC Capital Markets, LLC; Citigroup Global Markets, Inc.; Jefferies & Company, Inc.; Howard Weil Incorporated; Stifel, Nicolaus & Company, Incorporated; Simmons & Company International; Stephens Inc.; and Comerica Securities, Inc. On February 2, 2012, shares of the Company’s common stock began trading on the New York Stock Exchange under the symbol “MTDR” at an initial offering price of $12.00 per share.

Pursuant to its Prospectus dated February 1, 2012, the Company and the selling shareholders offered 13,333,334 shares of the Company’s common stock for sale. The Company offered 11,666,667 shares of its common stock, and the selling shareholders offered 1,550,000 shares. On February 7, 2012, the Company closed the Initial Public Offering and issued 11,666,667 shares of its common stock pursuant to the Initial Public Offering.

The Company and the selling shareholders granted the underwriters the right to purchase up to an additional 2,000,000 shares of the Company’s common stock at the initial offering price of $12.00 per share, less the underwriters’ discounts and commissions, for a period of 30 days following the Initial Public Offering to cover over-allotments, with the Company offering 700,000 shares and the selling shareholders offering 1,300,000 shares. On March 2, 2012, the underwriters exercised their option to purchase an additional 1,550,000 shares, including the purchase of 542,500 shares from the Company and the purchase of 1,007,500 shares from the selling shareholders. On March 7, 2012, the Company closed this transaction and issued 542,500 shares of its common stock pursuant to the underwriters’ exercise of the over-allotment.

Pursuant to the Initial Public Offering and the over-allotment, the Company issued a total of 12,209,167 shares of its common stock at $12.00 per share and received estimated net proceeds of approximately $133.6 million after deducting the underwriters’ discounts and commissions and the estimated legal, accounting and other fees associated with the offering. The Company did not receive any proceeds from the sale of shares of its common stock by the selling shareholders. On February 8, 2012, the Company used the net proceeds of the offering to repay the $123.0 million in borrowings then outstanding under its Credit Agreement in full. The Company used the remaining net proceeds of the offering to fund a portion of its 2012 capital expenditures.

Concurrent with the completion of the Initial Public Offering, all 1,030,700 outstanding shares of the Company’s Class B common stock were converted to Class A common stock on a one-for-one basis. In addition, in February 2012, the Company issued an additional 295,500 shares of its Class A common stock pursuant to the exercise of stock options and received net proceeds of $2.7 million. The Class A common stock is now referred to as the common stock.

In October 2010, the Board of Directors approved and authorized the private offering and sale of additional shares of the Company’s Class A common stock at $11.00 per share in the period from October 2010 through January 2011. As of December 31, 2010, the Company sold approximately 1.9 million shares and received net proceeds of $20.5 million. In January 2011, the Company sold an additional 53,772 shares as part of this offering and received net proceeds of approximately $0.6 million. The Company also sold 11,000 shares of Class A common stock at $9.00 per share to an accredited investor and received gross and net proceeds of $99,000 in May 2010.

Treasury Stock

The increase of 21,876 shares in treasury stock outstanding during 2012 represents forfeitures of non-vested restricted stock awards. During 2010, the Company issued 6,000 shares of Class A common stock valued at $7.50-$9.00 per share from treasury stock. The Company also purchased 1.1 million shares of Class A common stock for $9.00-$11.00 per share. These purchases included 1,000,000 shares of Class A common stock purchased from five shareholders, all advised by Wellington Management Company, in April 2010 at $9.00 per share, for a total of $9.0 million.

- Definition

The entire disclosure for shareholders' equity, comprised of portions attributable to the parent entity and noncontrolling interest, if any, including other comprehensive income (as applicable). Including, but not limited to: (1) balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings; (2) accumulated balance for each classification of other comprehensive income and total amount of comprehensive income; (3) amount and nature of changes in separate accounts, including the number of shares authorized and outstanding, number of shares issued upon exercise and conversion, and for other comprehensive income, the adjustments for reclassifications to net income; (4) rights and privileges of each class of stock authorized; (5) basis of treasury stock, if other than cost, and amounts paid and accounting treatment for treasury stock purchased significantly in excess of market; (6) dividends paid or payable per share and in the aggregate for each class of stock for each period presented; (7) dividend restrictions and accumulated preferred dividends in arrears (in aggregate and per share amount); (8) retained earnings appropriations or restrictions, such as dividend restrictions; (9) impact of change in accounting principle, initial adoption of new accounting principle and correction of an error in previously issued financial statements; (10) shares held in trust for Employee Stock Ownership Plan (ESOP); (11) deferred compensation related to issuance of capital stock; (12) note received for issuance of stock; (13) unamortized discount on shares; (14) description, terms, and number of warrants or rights outstanding; (15) shares under subscription and subscription receivables, effective date of new retained earnings after quasi-reorganization and deficit eliminated by quasi-reorganization and, for a period of at least ten years after the effective date, the point in time from which the new retained dates; and (16) retroactive effective of subsequent change in capital structure.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(d),(e))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Publisher FASB
-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=6959260&loc=d3e187085-122770

Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6405834&loc=d3e23285-112656

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Preferred Stock
-URI http://asc.fasb.org/extlink&oid=6521494

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21463-112644

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21564-112644

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 43
-Section B
-Paragraph 7, 11A
-Chapter 1
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 15: http://www.xbrl.org/2003/role/presentationRef
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 16: http://www.xbrl.org/2003/role/presentationRef
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 17: http://www.xbrl.org/2003/role/presentationRef
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-Number 210
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-Article 4

Reference 18: http://www.xbrl.org/2003/role/presentationRef
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Reference 20: http://www.xbrl.org/2003/role/presentationRef
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-Number 210
-Section 08
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Reference 21: http://www.xbrl.org/2003/role/presentationRef
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 23: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

+ Details

Derivative Financial Instruments

12 Months Ended

Dec. 31, 2012

Derivative Financial Instruments [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

NOTE 11 — DERIVATIVE FINANCIAL INSTRUMENTS

During 2012 and 2011, the Company entered into various costless collar contracts to mitigate its exposure to fluctuations in oil prices, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss pursuant to any of these transactions is the arithmetic average of the settlement prices for the NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month. When the settlement price is below the price floor established by these collars, the Company receives from its counterparties an amount equal to the difference between the settlement price and the price floor multiplied by the contract oil volume. When the settlement price is above the price ceiling established by these collars, the Company pays to its counterparties an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract oil volume.

During 2012, the Company entered into various swap contracts to mitigate its exposure to fluctuations in oil prices, each with an established fixed price. For each calculation period, the specified price for determining the realized gain or loss pursuant to any of these transactions is the arithmetic average of the settlement prices for NYMEX West Texas Intermediate oil futures contract for the first nearby month corresponding to the calculation period’s calendar month. When the settlement price is below the fixed price established by these swaps, the Company receives from its counterparties an amount equal to the difference between the settlement price and the fixed price multiplied by the contract oil volume. When the settlement price is above the fixed price established by these swaps the Company pays to its counterparties an amount equal to the difference between the settlement and the fixed price multiplied by the contract oil volume.

During 2012, 2011, and 2010, the Company entered into various costless collar transactions for natural gas, each with an established price floor and ceiling. For each calculation period, the specified price for determining the realized gain or loss to the Company pursuant to any of these transactions is the settlement price for the NYMEX Henry Hub natural gas futures contract for the delivery month corresponding to the calculation period’s calendar month for the last day of that contract period. When the settlement price is below the price floor established by these collars, the Company receives from its counterparties an amount equal to the difference between the settlement price and the price floor multiplied by the contract natural gas volume. When the settlement price is above the price ceiling established by these collars, the Company pays to its counterparties an amount equal to the difference between the settlement price and the price ceiling multiplied by the contract natural gas volume.

During 2012, the Company entered into various swap contracts to mitigate its exposure to fluctuations in natural gas liquids (“NGL”) prices on a portion of its future anticipated NGL production, each with an established fixed price. For each calculation period, the settlement price for determining the realized gain or loss to the Company pursuant to any of these transactions is the arithmetic average of any current month for delivery on the nearby month futures contracts of the underlying commodity as stated on the “Mont Belvieu Spot Gas Liquids Prices: NON-TET prop” on the pricing date. When the settlement price is below the fixed price established by these swaps, the Company receives from its counterparties an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume. When the settlement price is above the fixed price established by these swaps, the Company pays to its counterparties an amount equal to the difference between the settlement price and the fixed price multiplied by the contract NGL volume.

At December 31, 2012, the Company had various costless collar contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling. Each contract is set to expire at varying times during 2013 and 2014.

At December 31, 2012, the Company had various swap contracts open and in place to mitigate its exposure to oil and NGL price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and fixed price. Each contract is set to expire at varying times during 2013.

The following is a summary of the Company’s open costless collar contracts for oil and natural gas and open swap contracts for oil and natural gas liquids at December 31, 2012.


Commodity	Calculation Period		Notional Quantity (Bbl/month)		Price Floor ($/Bbl)		Price Ceiling ($/Bbl)		Fair Value of Asset (thousands)
Oil		01/01/2013 - 03/31/2013		20,000		90.00		110.00	$	122
Oil		01/01/2013 - 12/31/2013		20,000		85.00		102.25		96
Oil		01/01/2013 - 12/31/2013		20,000		90.00		115.00		980
Oil		01/01/2013 - 12/31/2013		20,000		85.00		110.40		471
Oil		01/01/2013 - 12/31/2013		20,000		85.00		108.80		418
Oil		01/01/2013 - 06/30/2014		8,000		90.00		114.00		666
Oil		01/01/2013 - 06/30/2014		12,000		90.00		115.50		1,036

Total open oil costless collar contracts										3,789

Commodity	Calculation Period		Notional Quantity (MMBtu/month)		Price Floor ($/MMBtu)		Price Ceiling ($/MMBtu)		Fair Value of Asset (Liability) (thousands)
Natural Gas		01/01/2013 - 07/31/2013		150,000		4.50		5.75		1,154
Natural Gas		01/01/2013 - 12/31/2013		100,000		3.00		3.83		(146	)
Natural Gas		01/01/2013 - 12/31/2013		100,000		3.00		4.95		40
Natural Gas		01/01/2013 - 12/31/2013		100,000		3.00		4.96		41
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.25		5.37		19
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.25		5.42		27

Total open natural gas costless collar contracts										1,135


Commodity	Calculation Period		Notional Quantity (Bbl/month)		Fixed Price ($/Bbl)		Fair Value of Liability (thousands)
Oil		01/01/2013 - 12/31/2013		10,000		90.20		(362	)
Oil		01/01/2013 - 12/31/2013		10,000		90.65		(308	)

Total open oil swap contracts								(670	)



Commodity	Calculation Period		Notional Quantity (Gal/month)		Fixed Price ($/Gal)		Fair Value of Asset (Liability) (thousands)
Purity Ethane		01/01/2013 - 12/31/2013		110,000		0.335		106
Purity Ethane		01/01/2013 - 12/31/2013		110,000		0.355		133
Propane		01/01/2013 - 12/31/2013		53,000		0.953		13
Propane		01/01/2013 - 12/31/2013		53,000		1.001		43
Normal Butane		01/01/2013 - 12/31/2013		14,700		1.455		(29	)
Normal Butane		01/01/2013 - 12/31/2013		14,700		1.560		(10	)
Isobutane		01/01/2013 - 12/31/2013		7,000		1.515		(18	)
Isobutane		01/01/2013 - 12/31/2013		7,000		1.625		(9	)
Natural Gasoline		01/01/2013 - 12/31/2013		12,000		2.025		(8	)
Natural Gasoline		01/01/2013 - 12/31/2013		12,000		2.085		1
Natural Gasoline		01/01/2013 - 12/31/2013		12,000		2.102		3

Total open NGL swap contracts							$	225

Total open derivative financial instruments							$	4,479

The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated balance sheets for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments.


Type of Instrument	Location in Balance Sheet	December 31, 2012			December 31, 2011
Derivative Instrument
Oil	Current assets: Derivative instruments	$	3,064		$	–
Oil	Other assets: Derivative instruments		725			–
Oil	Current liabilities: Derivative instruments		(670	)		(171	)
Oil	Long-term liabilities: Derivative instruments		–			(383	)
Natural Gas	Current assets: Derivative instruments		1,089			8,989
Natural Gas	Other assets: Derivative instruments		46			847
Natural Gas	Long-term liabilities: Derivative instruments		–			–
NGL’s	Current assets: Derivative instruments		225			–
NGL’s	Long-term liabilities: Derivative instruments		–			–

Total		$	4,479		$	9,282

The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments.


Type of Instrument	Location in Statement of Operations	Year Ended December 31,
Type of Instrument	Location in Statement of Operations	2012			2011			2010
Derivative Instrument
Oil	Revenues: Realized gain on derivatives	$	2,047		$	–		$	–
Natural Gas	Revenues: Realized gain on derivatives		11,892			7,106			5,299
NGL’s	Revenues: Realized gain on derivatives		21			–			–

Realized gain on derivatives			13,960			7,106			5,299
Oil	Revenues: Unrealized gain (loss) on derivatives		3,673			(554	)		–
Natural Gas	Revenues: Unrealized (loss) gain on derivatives		(8,700	)		5,692			3,139
NGL’s	Revenues: Unrealized gain on derivatives		225			–			–

Unrealized (loss) gain on derivatives			(4,802	)		5,138			3,139

Total		$	9,158		$	12,244		$	8,438

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

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+ Details

Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

NOTE 12 — FAIR VALUE MEASUREMENTS

The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements are classified and disclosed in one of the following categories.


Level 1		Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2		Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
Level 3		Unobservable inputs that are not corroborated by market data. This category is comprised of financial and non-financial assets and liabilities whose fair value is estimated based on internally developed models or methodologies using significant inputs that are generally less readily observable from objective sources.

Financial and non-financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

At December 31, 2012 and 2011, the carrying values reported on the consolidated balance sheets for cash, accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, income taxes payable, advances from joint interest owners and other current liabilities approximate their fair values due to their short-term maturities and are classified at Level 1.

At December 31, 2012 and 2011, the carrying value of borrowings under the Credit Agreement approximates fair value as it is subject to short-term floating interest rates that reflect market rates available to the Company at the time and is classified at Level 2.

The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2012 and 2011 (in thousands).


Description	Fair Value Measurements at December 31, 2012 using
	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Certificates of deposit	$	–	$	230		$	–	$	230
Oil, natural gas and NGL derivatives		–		5,149			–		5,149
Oil, natural gas and NGL derivatives		–		(670	)		–		(670	)

Total	$	–	$	4,709		$	–	$	4,709


Description	Fair Value Measurements at December 31, 2011 using
	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Certificates of deposit	$	–	$	1,335		$	–	$	1,335
Oil and natural gas derivatives		–		9,836			–		9,836
Oil and natural gas derivatives		–		(554	)		–		(554	)

Total	$	–	$	10,617		$	–	$	10,617

The Company’s accounting policies for certificates of deposit and derivative financial instruments are discussed in Note 2; additional disclosures related to derivative financial instruments are provided in Note 11. For purposes of fair value measurement, the Company determined that certificates of deposit and derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified at Level 2.

The Company accounts for additions to asset retirement obligations and impairment of lease and well equipment inventory at fair value on a non-recurring basis. The following tables summarize the valuation of the Company’s assets and liabilities that were accounted for at fair value on a non-recurring basis as of December 31, 2012 and 2011 (in thousands).


Description	Fair Value Measurements at December 31, 2012 using
	Level 1		Level 2		Level 3			Total
Assets (Liabilities)
Asset retirement obligations	$	–	$	–	$	(1,243	)	$	(1,243	)
Lease and well equipment inventory		–		–		34			34

Total	$	–	$	–	$	(1,209	)	$	(1,209	)


Description	Fair Value Measurements at December 31, 2011 using
	Level 1		Level 2		Level 3			Total
Assets (Liabilities)
Asset retirement obligations	$	–	$	–	$	(187	)	$	(187	)
Lease and well equipment inventory		–		–		1,343			1,343

Total	$	–	$	–	$	1,156		$	1,156

The Company’s accounting policies for asset retirement obligations are discussed in Note 2; reconciliations of the Company’s asset retirement obligations are provided in Note 4 for the periods presented. For purposes of fair value measurement, the Company determined that the additions to asset retirement obligations should be classified at Level 3. The Company recorded additions to asset retirement obligations of approximately $1.2 million and $0.2 million in 2012 and 2011, respectively.

The Company’s accounting policies for lease and well equipment inventory are discussed in Note 2. For purposes of fair value measurement, the Company determined that lease and well equipment inventory should be classified at Level 3. The Company recorded an impairment to some of its equipment held in inventory, consisting primarily of drilling rig parts, of $425,000 and $17,500 in 2012 and 2011, respectively. The Company recorded an impairment to some of its equipment held in inventory, consisting primarily of pipe and other equipment, of $60,464 and $22,276 in 2012 and 2011, respectively. The Company periodically obtains estimates of the market value of its equipment held in inventory from an independent third-party contractor or seller of similar equipment and uses these estimates as a basis for its measurement of the fair value of this equipment.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7578670&loc=d3e19207-110258

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14172-108612

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
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-Paragraph 21
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13537-108611

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13504-108611

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=7491637&loc=d3e13433-108611

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15B
-Subparagraph a, b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 17-22, 27, 28
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-Subparagraph a-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15C, 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32, 33, 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 3, 10, 14, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 13 — COMMITMENTS AND CONTINGENCIES

Office Lease

The Company’s corporate headquarters are located in 28,743 square feet of office space at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas. The office lease commencement date was September 25, 2003 with an expiration date of June 30, 2011. In April 2011, the Company entered into a restated third amendment to its office lease agreement in which the office space was increased to 28,743 square feet and the term of the lease was extended to June 30, 2022. The effective base rent over the term of the new lease extension is $19.75 per square foot per year. The base rate escalates several times during the course of the lease, specifically in July 2015, July 2017, July 2019 and July 2020. This lease was amended subsequent to December 31, 2012 (see Note 18).

The following is a schedule of future minimum lease payments required under the office lease agreement as of December 31, 2012 (in thousands).


Year ending December 31,	Amount
2013	$	575
2014		575
2015		589
2016		604
2017		618
Thereafter		2,995

Total	$	5,956

Rent expense, including fees for operating expenses and consumption of electricity, was $0.6 million, $0.5 million and $0.4 million for 2012, 2011 and 2010, respectively.

Other Commitments

At December 31, 2012, the Company had entered into two drilling rig contracts to explore and develop its Eagle Ford acreage in South Texas. The two rigs began drilling on the Company’s acreage in March and December 2012, respectively. The first contract is for a term of 365 days and the second is for a term of 270 days. Should the Company elect to terminate one or both contracts and if the drilling contractor were unable to secure work for one or both rigs or if the drilling contractor were unable to secure work for one or both rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms, the Company would incur termination obligations. The Company’s maximum outstanding aggregate termination obligations under these contracts were approximately $5.1 million at December 31, 2012. The contract for the first rig was renegotiated in March 2013 (see Note 18).

Natural Gas and NGL Processing and Transportation Commitments

Effective September 1, 2012, the Company entered into a firm five-year natural gas processing and transportation agreement whereby the Company committed to transport the anticipated natural gas production from a significant portion of its Eagle Ford acreage in South Texas through the counterparty’s system for processing at the counterparty’s facilities. The agreement also includes firm transportation of the natural gas liquids extracted at the counterparty’s processing plant downstream for fractionation. After processing, the residue natural gas is purchased by the counterparty at the tailgate of its processing plant and further transported under its firm natural gas transportation agreements. The arrangement contains fixed processing and liquids transportation and fractionation fees, and the revenue the Company receives varies with the quality of natural gas transported to the processing facilities and the contract period.

Under this agreement, if the Company does not meet 80% of the maximum thermal quantity transportation and processing commitments in a contract year, it will be required to pay a deficiency fee per MMBtu of natural gas deficiency. Any quantity in excess of the maximum MMBtu delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. The Company believes that its current and anticipated production from the wells covered by this agreement is sufficient to meet 80% of the maximum thermal quantity transportation and processing commitments under this agreement. The Company paid approximately $0.3 million in processing and transportation fees under this agreement during the year ended December 31, 2012.

The aggregate undiscounted minimum commitments under this agreement at December 31, 2012 are as follows (in thousands).


Year ending December 31, 2012	Amount
2013	$	5,985
2014		4,731
2015		2,992
2016		1,800
2017		1,195

Total	$	16,703

Legal Proceedings

Cynthia Fry Peironnet, et al. v. Matador Resources Company. The Company is involved in a dispute over a mineral rights lease involving certain acreage in Louisiana. The dispute regards an extension of the term of a lease in Caddo Parish, Louisiana (the “Lease”) where the Company has drilled or participated in the drilling of both Cotton Valley and Haynesville shale wells. At issue are the deep rights below the Cotton Valley formation on approximately 1,805 gross acres where the Company has the right to participate for up to a 25% working interest, and also retains a small overriding royalty interest, in Haynesville shale wells drilled in units that include portions of the acreage. The Company’s total net revenue and overriding royalty interests in several non-operated Haynesville shale wells previously drilled on this acreage range from approximately 2% to 23%, and only portions of these interests are attributable to this acreage. The sum of the Company’s overriding royalty and net revenue interests attributable to this acreage from Haynesville wells previously drilled on this acreage comprises less than one net well.

The plaintiffs brought this claim against the Company on May 15, 2008 in the First Judicial District Court, Caddo Parish, Louisiana (the “Trial Court”). The plaintiffs sought (i) reformation or rescission of the lease extension, (ii) an accounting for additional royalty, (iii) monetary damages and (iv) attorney’s fees. During the pendency of the case in the Trial Court, the Company settled with one lessor who owned a 1/6^th undivided interest in the minerals. Since May 2008, the Trial Court has rendered multiple rulings in the favor of the Company, including a unanimous jury verdict in favor of the Company in the fall of 2010. Final judgment of the Trial Court was rendered in favor of Matador on June 6, 2011. On August 1, 2012, the Louisiana Second Circuit of Appeal (the “Court of Appeal”) affirmed in part and reversed in part the judgment of the Trial Court and remanded the case to the Trial Court for determination of damages. The Court of Appeal affirmed the Trial Court with respect to the 1/6^th royalty owner that settled and also affirmed that the Company’s lease extension was unambiguous. Nonetheless, the Court of Appeal reformed the lease extension to cover only approximately 169 gross acres, holding that the deep rights covering the remaining 1,636 gross acres had expired. The Court of Appeal denied the Company’s motion for rehearing, and the Company and certain other defendants filed an appeal with the Louisiana Supreme Court. The Louisiana Supreme Court has granted the requests to hear an appeal of the Court of Appeal’s decision.

The Company believes that the facts of the case and the applicable law do not support the Court of Appeal’s judgment and it intends to vigorously pursue its rights to have the Trial Court’s judgment reinstated. Although the Company does not consider a loss resulting from this dispute to be probable, it is reasonably possible that the Company could incur a loss as a result of the continuing litigation of this matter. The Company currently estimates that a reasonable range of potential loss is zero to $6 million.

The Company is a defendant in several other lawsuits encountered in the ordinary course of its business. In the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial position, results of operations or cash flows.

General Federal and State Regulations

Oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial monetary penalties or delay or suspension of operations. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable state and federal regulations. Because these rules and regulations are frequently amended or reinterpreted, however, the Company is unable to predict the future cost or impact of complying with these regulations.

Environmental Regulations

The exploration, development and production of oil and natural gas, including the operation of salt water injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. The Company’s activities are subject to a variety of environmental laws and regulations, including but not limited to the Oil Pollution Act of 1990, or OPA, the Clean Water Act, or CWA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the Resource Conservation and Recovery Act, or RCRA, the Clean Air Act, or CAA, the Safe Drinking Water Act, or SDWA, and the Occupational Safety and Health Act, or OSHA, as well as comparable state statutes and regulations. The Company is also subject to regulations governing the handling, transportation, storage and disposal of waste generated by its activities and of naturally occurring radioactive materials, or NORM, that may result from its oil and natural gas operations. Administrative, civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species, and require investigation and cleanup of pollution. The Company has no outstanding material environmental remediation liabilities and believes that it is in compliance with currently applicable environmental laws and regulations and that these laws and regulations will not have a material adverse impact on the financial position, results of operations or cash flows of the Company.

Changes in environmental laws and regulations occur frequently, however, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could, and in all likelihood would, materially adversely affect the Company’s financial position, results of operations and cash flows, as well as those of the oil and natural gas industry in general. Because these rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with these regulations. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal or state laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require the Company to incur increased operating costs adversely affecting its financial position, results of operations and cash flows.

The Company’s activities involve the use of hydraulic fracturing. Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection (unless diesel is a component of the fracturing fluid) at the federal level. At the federal level and in some states, there have been efforts to place additional regulatory burdens on hydraulic fracturing activities. At the state level, Texas and Wyoming, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. In addition, at least a few local governments or regional authorities have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additional burdens on hydraulic fracturing, such as reporting requirements or permitting requirements for the hydraulic fracturing activity, will result in additional expense and delay the Company’s operations adversely affecting its financial position, results of operations and cash flows.

Oil and natural gas exploration and production, operations and other activities have been conducted at some of the Company’s properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, may require remediation. In addition, the Company occasionally must agree to indemnify sellers of producing properties the Company acquires against some or all of the liability for environmental claims associated with these properties. While the Company does not believe that the costs it incurs for compliance with environmental regulations and remediating previously or currently owned or operated properties will be material, the Company cannot provide assurances that these costs will not result in material expenditures that adversely affect its financial position, results of operations and cash flows.

The Company maintains insurance against some, but not all, potential risks and losses associated with the oil and natural gas industry and operations. The Company does not carry business interruption insurance. For some risks, the Company may not obtain insurance if it believes the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could, and in all likelihood would, materially adversely affect the Company’s financial position, results of operations and cash flows.

- Definition

The entire disclosure for commitments and contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 20
-Section 50
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=6394976&loc=d3e25287-109308

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 14
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9, 10, 11, 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Major Customers

12 Months Ended

Dec. 31, 2012

Major Customers [Abstract]

MAJOR CUSTOMERS

NOTE 14 — MAJOR CUSTOMERS

For the years ended December 31, 2012, 2011 and 2010, the Company had three significant purchasers that accounted for approximately 74%, 60% and 70%, respectively, of its total oil, natural gas and natural gas liquids revenues. Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact on the Company’s financial position, results of operations or cash flows for any significant period of time. At December 31, 2012, 2011 and 2010, approximately 67%, 52% and 56%, respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers.

- Definition

The entire disclosure for any concentrations existing at the date of the financial statements that make an entity vulnerable to a reasonably possible, near-term, severe impact. This disclosure informs financial statement users about the general nature of the risk associated with the concentration, and may indicate the percentage of concentration risk as of the balance sheet date.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 275
-SubTopic 10
-Section 50
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=6927468&loc=d3e6327-108592

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Statement of Position (SOP)
-Number 94-6
-Paragraph 21, 22, 24
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Supplemental Disclosures

12 Months Ended

Dec. 31, 2012

Supplemental Disclosures [Abstract]

SUPPLEMENTAL DISCLOSURES

NOTE 15 — SUPPLEMENTAL DISCLOSURES

Accrued Liabilities

The following table summarizes the Company’s current accrued liabilities at December 31, 2012 and 2011 (in thousands).


	December 31,
	2012		2011
Accrued evaluated and unproved and unevaluated property costs	$	45,592	$	18,185
Accrued support equipment and facilities costs		1,382		216
Accrued cost to issue equity		–		332
Accrued stock-based compensation		65		2,860
Accrued lease operating expenses		5,218		575
Accrued interest on borrowings under Credit Agreement		255		34
Accrued asset retirement obligations		660		334
Accrued partners’ share of joint interest charges		3,597		51
Other		2,410		2,852

Total accrued liabilities	$	59,179	$	25,439

Supplemental Cash Flow Information

The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2012, 2011 and 2010 (in thousands).


	Year ended December 31,
	2012			2011			2010
Cash paid (refunded) for income taxes	$	–		$	–		$	(2,156	)
Cash paid for interest expense, net of amounts capitalized		780			634			–
Asset retirement obligations related to mineral properties		1,195			488			862
Asset retirement obligations related to support equipment and facilities		49			12			126
Increase in liabilities for oil and natural gas properties capital expenditures		24,847			1,864			15,531
Increase in liabilities for support equipment and facilities		1,112			175			40
Issuance of treasury stock for Board and advisor services		–			–			47
Issuance of restricted stock units for Board and advisor services		73			–			–
Issuance of common stock for Board and advisor services		71			230			198
(Decrease) increase in liabilities for accrued cost to issue equity		(332	)		(27	)		359
Stock based compensation expense recognized as liability		(1,092	)		2,102			164
Transfer of inventory to oil and natural gas properties		69			96			353

Transactions With Related Parties

12 Months Ended

Dec. 31, 2012

Transactions With Related Parties [Abstract]

TRANSACTIONS WITH RELATED PARTIES

NOTE 16 — TRANSACTIONS WITH RELATED PARTIES

In January 2007, the Company entered into a joint venture with Marlan Downey and Julie Downey Garvin of Roxanna Oil Company (“Roxanna”) to assemble acreage for and to market a new natural gas shale prospect in Southwest Wyoming, Northeast Utah and Southeast Idaho. Mr. Downey is a special advisor to the Company’s Board of Directors and a shareholder in the Company. Ms. Garvin is President of Roxanna, which is also a shareholder in Matador. Mr. Downey and Ms. Garvin developed the prospect concept independently and sought the Company’s expertise in assembling a large acreage position across the prospect. The Company actively marketed this prospect in conjunction with Mr. Downey and Ms. Garvin. In May 2010, the Company, Roxanna and its subsidiary, Roxanna Rocky Mountains, LLC, entered into participation and joint operating agreements with an industry partner for the joint exploration and development of this opportunity. Under these agreements, Roxanna Rocky Mountains, LLC reserves a 2.5% overriding royalty interest in the leases and has the opportunity to earn up to a 10% working interest in all wells drilled. The industry partner has a 50% working interest in the project, and the Company retains a working interest equal to the difference between 50% and the working interest participation elected by Roxanna Rocky Mountains, LLC. The Company, as operator, drilled the initial test well for this prospect located in Lincoln County, Wyoming during 2011 and suspended operations. The Company re-entered this vertical well in late 2012 and drilled a horizontal lateral wellbore in the Meade Peak shale. This well was awaiting completion of the horizontal lateral at December 31, 2012.

- Definition

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39603-107864

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39622-107864

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39549-107864

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39678-107864

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(k))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39691-107864

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph b
-Article 3A

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph k
-Article 4

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
-Paragraph 1-4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Supplemental Oil And Natural Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2012

Supplemental Oil and Natural Gas Disclosures (Unaudited) [Abstract]

SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED)

NOTE 17 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited)

Costs Incurred

The following table summarizes costs incurred and capitalized by the Company in the acquisition, exploration, and development of oil and natural gas properties for the years ended December 31, 2012, 2011 and 2010 (in thousands).


	Year ended December 31,
	2012		2011		2010
Property acquisition costs
Proved	$	–	$	–	$	–
Unproved and unevaluated		28,672		41,497		100,730
Exploration costs		115,084		108,662		60,719
Development costs		190,891		12,511		14,348

Total costs incurred	$	334,647	$	162,670	$	175,797

Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, including both unproved and unevaluated leasehold and purchases of reserves in place. For the years ended December 31, 2012, 2011 and 2010, respectively, essentially all of the Company’s property acquisition costs resulted from the acquisition of unproved and unevaluated leasehold positions.

Exploration costs are costs incurred in identifying areas of these oil and natural gas properties that may warrant further examination and in examining specific areas that are considered to have prospects of containing oil and natural gas, including costs of drilling exploratory wells, geological and geophysical costs, and costs of carrying and retaining unproved and unevaluated properties. Exploration costs may be incurred before or after acquiring the related oil and natural gas properties.

Development costs are costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Development costs include the costs of preparing well locations for drilling, drilling and equipping development wells and related service wells (e.g., salt water disposal wells) and acquiring, constructing and installing production facilities.

Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table above were approximately $1.2 million, $0.5 million and $1.0 million for the years ended December 31, 2012, 2011 and 2010, respectively. Capitalized general and administrative expenses that are directly related to acquisition, exploration and development activities are also included in the table above. The Company capitalized $2.6 million, $2.0 million and $1.6 million of these internal costs in 2012, 2011 and 2010, respectively. Capitalized interest expense for qualifying projects are also included in the table above. The Company capitalized $1.6 million and $1.3 million of its interest expense for the years ended December 31, 2012 and 2011, respectively. The Company recorded only $3,235 in interest expense for the year ended December 31, 2010. As a result, the Company capitalized no interest expense for the year ended December 31, 2010.

Oil and Natural Gas Operating Results

The following table provides the results of operations from oil and natural gas producing activities, excluding corporate overhead and interest costs, for the years ended December 31, 2012, 2011 and 2010 (in thousands, except per BOE amounts).


	Year ended December 31,
	2012			2011			2010
Oil and natural gas revenues	$	155,998		$	67,000		$	34,042
Production taxes and marketing expenses		11,672			6,278			1,982
Lease operating expenses		28,184			7,244			5,284
Depletion, depreciation and amortization		79,592			31,619			15,423
Accretion of asset retirement obligations		256			209			155
Full-cost ceiling impairment		63,475			35,673			–

Net operating (loss) income		(27,181	)		(14,023	)		11,198
Income tax (benefit) provision		(9,595	)		(5,019	)		3,983

Results of oil and natural gas operations	$	(17,586	)	$	(9,004	)	$	7,215

Depletion, depreciation and amortization per BOE	$	24.16		$	12.29		$	10.76

Oil and Natural Gas Reserves

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs using existing economic and operating conditions. Estimating oil and natural gas reserves is complex and is inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, petrophysical, engineering and production data. The extent, quality and reliability of both the data and the associated interpretations of that data can vary. The process also requires certain economic assumptions, including, but not limited to, oil and natural gas prices, drilling, completion and operating expenses, capital expenditures and taxes. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from the Company’s estimates.

Oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost escalations in future periods except by contractual arrangements. The commodity prices used to estimate oil and natural gas reserves are based on unweighted, arithmetic averages of first-day-of-the-month oil and natural gas prices for the previous 12-month period. For the period January through December 2012, these average oil and natural gas prices were $91.21 per barrel and $2.757 per MMBtu, respectively. For the period January through December 2011, these average oil and natural gas prices were $92.71 per barrel and $4.118 per MMBtu, respectively. For the period January through December 2010, these average oil and natural gas prices were $75.96 per barrel and $4.376 per MMBtu, respectively.

The Company’s oil and natural gas reserves estimates are prepared by the Company’s engineering staff in accordance with guidelines established by the SEC and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers, for the years ended December 31, 2012, 2011 and 2010.

The Company’s net ownership in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized as follows. All of the Company’s oil and natural gas reserves are attributable to properties located in the United States. The estimated reserves shown below are for proved reserves only and do not include any value for unproved reserves classified as probable or possible reserves that might exist for these properties, nor do they include any consideration that could be attributed to interests in unevaluated acreage beyond those tracts for which reserves have been estimated. The Company does not report its natural gas liquids production and reserves separately. In the tables presented throughout this section, natural gas is converted to oil equivalent using the ratio of one Bbl of oil, condensate or natural gas liquids to 6 Mcf of natural gas.


	Net Proved Reserves
	Oil			Gas			Oil Equivalent
	(MBbl)			(MMcf)			(MBOE)


Total at December 31, 2009		103			63,929			10,758
Revisions of prior estimates		66			874			211
Extensions and discoveries		16			71,009			11,851
Production		(33	)		(8,400	)		(1,433	)

Total at December 31, 2010		152			127,412			21,387
Revisions of prior estimates		51			(646	)		(57	)
Extensions and discoveries		3,745			58,164			13,439
Production		(154	)		(14,512	)		(2,573	)

Total at December 31, 2011		3,794			170,418			32,196
Revisions of prior estimates		(782	)		(103,375	)		(18,010	)
Extensions and discoveries		8,687			25,443			12,927
Production		(1,214	)		(12,479	)		(3,294	)

Total at December 31, 2012		10,485			80,007			23,819

Proved Developed Reserves

December 31, 2009		103			25,369			4,331
December 31, 2010		152			43,143			7,342
December 31, 2011		1,419			56,547			10,843
December 31, 2012		4,764			54,040			13,771

Proved Undeveloped Reserves

December 31, 2009		–			38,560			6,427
December 31, 2010		–			84,269			14,045
December 31, 2011		2,375			113,871			21,353
December 31, 2012		5,721			25,967			10,048

The following is a discussion of the changes in the Company’s proved oil and natural gas reserves estimates for the years ended December 31, 2012, 2011 and 2010.

The Company’s proved oil and natural gas reserves decreased to 23,819 MBOE at December 31, 2012 from 32,196 MBOE at December 31, 2011. The Company’s proved oil and natural gas reserves decreased by 5,083 MBOE and the Company produced 3,294 MBOE during the year ended December 31, 2012, resulting in a net decrease of 8,377 MBOE. An increase of 12,927 MBOE in proved oil and natural gas reserves was a result of extensions and discoveries during the year, which was primarily attributable to drilling operations in the Eagle Ford shale play in South Texas. The Company’s oil and natural gas reserves decreased by 18,010 MBOE during the year as a result of revisions to previous estimates, primarily resulting from lower natural gas prices in 2012. The Company’s proved developed oil and natural gas reserves increased to 13,771 MBOE at December 31, 2012 from 10,843 MBOE at December 31, 2011, primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford shale. At December 31, 2012, the Company’s proved reserves were made up of approximately 44% oil and 56% natural gas.

The Company’s proved oil and natural gas reserves increased to 32,196 MBOE at December 31, 2011 from 21,387 MBOE at December 31, 2010. The Company increased its proved oil and natural gas reserves by 13,382 MBOE and produced 2,573 MBOE during the year ended December 31, 2011, resulting in a net gain of 10,809 MBOE. A total of 13,439 MBOE of the increase in proved oil and natural gas reserves was a result of extensions and discoveries during the year, all of which was attributable to drilling operations in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana. The Company’s oil and natural gas reserves decreased by 57 MBOE during the year as a result of revisions to previous estimates, representing the net impact of small changes in prior estimates of proved reserves on a well-by-well basis. The Company’s proved developed oil and natural gas reserves increased to 10,843 MBOE at December 31, 2011 from 7,342 MBOE at December 31, 2010, primarily due to proved developed reserves added as a result of drilling operations in the Eagle Ford and Haynesville shale plays. At December 31, 2011, the Company’s proved reserves were made up of approximately 12% oil and 88% natural gas.

The Company’s proved oil and natural gas reserves increased to 21,387 MBOE at December 31, 2010 from 10,758 MBOE at December 31, 2009. The Company increased its proved oil and natural gas reserves by 12,062 MBOE and produced 1,433 MBOE during the year ended December 31, 2010, resulting in a net gain of 10,629 MBOE. A total of 11,851 MBOE of the increase in proved oil and natural gas reserves was a result of extensions and discoveries during the year, almost all of which was attributable to drilling operations in the Haynesville shale play in Northwest Louisiana. A total of 211 MBOE of the increase in proved oil and natural gas reserves was attributable to revisions of previous estimates, representing the net impact of small changes in prior estimates of proved reserves on a well-by-well basis. The Company’s proved developed oil and natural gas reserves increased to 7,342 MBOE at December 31, 2010 from 4,331 MBOE at December 31, 2009, primarily due to proved developed reserves added as a result of drilling operations in the Haynesville shale play. At December 31, 2010, the Company’s proved reserves were made up of approximately 1% oil and 99% natural gas.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is not intended to provide an estimate of the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair market value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, potential improvements in industry technology and operating practices, the risks inherent in reserves estimates and perhaps different discount rates.

As noted previously, for the period January through December 2012, average oil and natural gas prices were $91.21 per barrel and $2.757 per MMBtu, respectively. For the period January through December 2011, average oil and natural gas prices were $92.71 per barrel and $4.118 per MMBtu, respectively. For the period January through December 2010, average oil and natural gas prices were $75.96 per barrel and $4.376 per MMBtu, respectively.

Future net cash flows were computed by applying these oil and natural gas prices, adjusted for all associated transportation costs, gravity and energy content, and regional price differentials, to year-end quantities of proved oil and natural gas reserves and accounting for any future production and development costs associated with producing these reserves; neither prices nor costs were escalated with time in these computations.

Future income taxes were computed by applying the statutory tax rate to the excess of future net cash flows relating to proved oil and natural gas reserves less the tax basis of the associated properties. Tax credits and net operating loss carryforwards available to the Company were also considered in the computation of future income taxes. Future net cash flows after income taxes were discounted using a 10% annual discount rate to derive the standardized measure of discounted future net cash flows.

The following table presents the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2012, 2011 and 2010 (in thousands).


	Year ended December 31,
	2012			2011			2010
Future cash inflows	$	1,273,882		$	924,796		$	470,386
Future production costs		(325,413	)		(194,538	)		(107,183	)
Future development costs		(244,283	)		(235,469	)		(107,277	)
Future income tax expense		(77,821	)		(83,840	)		(35,352	)

Future net cash flows		626,365			410,949			220,574
10% annual discount for estimated timing of cash flows		(231,729	)		(195,476	)		(109,497	)

Standardized measure of discounted future net cash flows	$	394,636		$	215,473		$	111,077

The following table summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 2012, 2011 and 2010 (in thousands).


	Year ended December 31,
	2012			2011			2010
Balance, beginning of period	$	215,473		$	111,077		$	65,061
Net change in sales and transfer prices and in production (lifting) costs related to future production		(60,892	)		53,903			7,632
Changes in estimated future development costs		16,937			(64,958	)		(36,821	)
Sales and transfers of oil and natural gas produced during the period		(116,142	)		(53,478	)		(26,776	)
Net change due to extensions and discoveries		358,159			182,282			94,265
Net change due to revisions in estimates of reserves quantities		(56,850	)		(653	)		1,676
Previously estimated development costs incurred during the period		9,750			1,023			7,125
Accretion of discount		24,873			11,987			7,036
Other		(290	)		(1,335	)		1,035
Net change in income taxes		3,618			(24,375	)		(9,156	)

Standardized measure of discounted future net cash flows	$	394,636		$	215,473		$	111,077

Subsequent Events

12 Months Ended

Dec. 31, 2012

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

NOTE 18 — SUBSEQUENT EVENTS

On March 11, 2013, the borrowing base under the Company’s Credit Agreement was increased to $255.0 million based on the lenders’ review of its proved oil and natural gas reserves at December 31, 2012. At that time, the Credit Agreement was also amended to include Capital One, N.A., BMO Harris Financing, Inc. (Bank of Montreal) and IberiaBank in the Company’s lending group, which also includes RBC as administrative agent, Comerica Bank, Citibank, N.A., The Bank of Nova Scotia and SunTrust Bank. At March 14, 2013, the Company had $180.0 million in borrowings and $1.3 million in letters of credit outstanding under its Credit Agreement. The Company incurred $0.3 million of additional deferred loan costs in connection with the borrowing base redetermination and amendment of the Credit Agreement. These costs will be included with the remaining unamortized portion of the deferred loan costs of $1.6 million at December 31, 2012 to be amortized over the term of the agreement.

In March 2013, the Company granted awards of options to purchase 507,500 and 284,292 shares of the Company’s common stock at exercise prices of $8.21 per share and $8.18 per share, respectively, to certain of its employees. The fair value of these awards was approximately $2.8 million. The Company also granted awards of 324,771 shares of restricted stock to certain of its employees in March 2013. The fair value of these restricted stock awards was approximately $2.4 million. All of these awards vest over a term of three to four years.

In February 2013, options to purchase 408,000 shares of the Company’s common stock at $10.00 per share expired unexercised or were forfeited.

During the first quarter of 2013, the Company entered into several additional costless collar transactions to mitigate its risks associated with fluctuations in oil prices, including contracts with a new counterparty, The Bank of Nova Scotia (or affiliates thereof). The following table summarizes these contracts.


Commodity	Calculation Period		Notional Quantity (Bbls/month)		Price Floor ($/Bbl)		Price Ceiling ($/Bbl)
Oil		07/01/2013 - 12/31/2013		20,000		90.00		102.80
Oil		01/01/2014 - 12/31/2014		15,000		85.00		97.50
Oil		01/01/2014 - 12/31/2014		30,000		85.00		98.00
Oil		01/01/2014 - 12/31/2014		15,000		87.00		97.00
Oil		01/01/2014 - 12/31/2014		20,000		90.00		97.00
Oil		01/01/2014 - 12/31/2014		15,000		90.00		97.90
Oil		01/01/2014 - 12/31/2014		15,000		90.00		98.00

During the first quarter of 2013, the Company entered into several additional costless collar transactions to mitigate its risks associated with fluctuations in natural gas prices, including contracts with a new counterparty, The Bank of Nova Scotia (or affiliates thereof). The following table summarizes these contracts.


Commodity	Calculation Period		Notional Quantity (MMBtu/month)		Price Floor ($/MMBtu)		Price Ceiling ($/MMBtu)
Natural Gas		04/01/2013 - 12/31/2013		100,000		3.25		4.41
Natural Gas		04/01/2013 - 12/31/2013		100,000		3.25		4.44
Natural Gas		04/01/2013 - 12/31/2013		100,000		3.50		4.37
Natural Gas		07/01/2013 - 12/31/2013		150,000		3.00		4.24
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.00		5.15
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.25		5.21
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.25		5.22
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.50		4.90

During the first quarter of 2013, the Company entered into several additional swap transactions to mitigate its risks associated with fluctuations in natural gas liquids prices. The following table summarizes these contracts.


Commodity	Calculation Period		Notional Quantity (Gal/month)		Fixed Price ($/Gal)
Normal Butane		03/01/2013 - 12/31/2013		21,000		1.575
Normal Butane		03/01/2013 - 12/31/2013		117,000		1.575
Normal Butane		01/01/2014 - 12/31/2014		17,500		1.540
Normal Butane		01/01/2014 - 12/31/2014		45,500		1.550
Isobutane		03/01/2013 - 12/31/2013		43,500		1.675
Isobutane		03/01/2013 - 12/31/2013		23,000		1.675
Isobutane		01/01/2014 - 12/31/2014		22,000		1.640
Isobutane		01/01/2014 - 12/31/2014		37,000		1.640
Natural Gasoline		03/01/2013 - 12/31/2013		36,000		2.105
Natural Gasoline		03/01/2013 - 12/31/2013		90,500		2.148
Natural Gasoline		01/01/2014 - 12/31/2014		30,000		1.970
Natural Gasoline		01/01/2014 - 12/31/2014		41,000		2.000

During the first quarter of 2013, the Company extended one of its drilling rig contracts in South Texas for an additional six months. Should the Company elect to terminate the contract and if the drilling contractor were unable to secure work for the rig or if the drilling contractor were unable to secure work for the rig at the same daily rate being charged to the Company prior to the end of its term, the Company would incur termination obligations. The Company’s maximum outstanding aggregate termination obligations under this contract were approximately $2.1 million at March 14, 2013.

In January and February 2013, the Company agreed to participate in the drilling and completion of various non-operated wells in the Eagle Ford shale and the Haynesville shale. If all of these wells are drilled and completed, the Company will have minimum outstanding aggregate commitments for its participation in these wells of approximately $5.6 million subsequent to December 31, 2012, which it expects to incur within the next few months.

In January 2013, the Company entered into the fourth amendment to its office lease agreement. This amendment increased the square footage of its corporate headquarters by 7,782 square feet, thereby increasing the size of its corporate headquarters from 28,743 square feet to 36,525 square feet effective January 1, 2013. The future minimum lease payments required under the office lease agreement as of January 1, 2013 are as follows (in thousands).


Year ending December 31,	Amount
2013	$	643
2014		734
2015		752
2016		771
2017		789
Thereafter		3,813

Total	$	7,502

Selected Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2012

Selected Quarterly Financial Information (Unaudited) [Abstract]

SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

NOTE 19 — SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The following table presents selected unaudited quarterly financial information for 2012 (in thousands, except per share data).


	December 31			September 30			June 30			March 31
2012
Oil and natural gas revenues	$	52,748		$	38,008		$	36,078		$	29,164
Realized gain on derivatives		2,813			3,371			4,713			3,063
Unrealized (loss) gain on derivatives		(3,653	)		(12,993	)		15,114			(3,270	)
Expenses		72,377			38,087			66,263			21,857
Other expense		(907	)		(89	)		(31	)		(235	)
(Loss) income before income taxes		(21,376	)		(9,790	)		(10,389	)		6,865
Income tax (benefit) provision		(188	)		(593	)		(3,713	)		3,064

Net (loss) income	$	(21,188	)	$	(9,197	)	$	(6,676	)	$	3,801


Earnings (loss) per common share
Basic
Class A	$	(0.38	)	$	(0.17	)	$	(0.12	)	$	0.08

Class B	$	0.00		$	0.00		$	0.00		$	0.15

Diluted
Class A	$	(0.38	)	$	(0.17	)	$	(0.12	)	$	0.08

Class B	$	0.00		$	0.00		$	0.00		$	0.15

The following table presents selected unaudited quarterly financial information for 2011 (in thousands, except per share data).


	December 31			September 30			June 30			March 31
2011
Oil and natural gas revenues	$	14,991		$	17,447		$	20,864		$	13,698
Realized gain on derivatives		2,869			1,435			952			1,850
Unrealized gain (loss) on derivatives		3,604			2,870			332			(1,668	)
Expenses		15,784			15,469			14,953			48,347
Other expense		(309	)		(89	)		(89	)		(35	)
Income (loss) before income taxes		5,371			6,194			7,106			(34,502	)
Income tax provision (benefit)		1,430			–			(46	)		(6,906	)

Net income (loss)	$	3,941		$	6,194		$	7,152		$	(27,596	)


Earnings (loss) per common share
Basic
Class A	$	0.09		$	0.14		$	0.17		$	(0.65	)

Class B	$	0.16		$	0.21		$	0.23		$	(0.58	)

Diluted
Class A	$	0.09		$	0.14		$	0.17		$	(0.65	)

Class B	$	0.16		$	0.21		$	0.23		$	(0.58	)

- Definition

The entire disclosure for the quarterly financial data in the annual financial statements. The disclosure may include a tabular presentation of financial information for each fiscal quarter for the current and previous year, including revenues, gross profit, income or loss before extraordinary items and earnings per share data. It also includes an indication if the information in the note is unaudited, comments on the aggregate effect of year-end adjustments, and an explanation of matters or transactions that affect comparability or are pertinent to an understanding of the information furnished.

+ References + Details

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Summary of Significant Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

Reclassifications

Reclassifications

Use of Estimates

Use of Estimates

Cash and Cash Equivalents

Cash and Cash Equivalents

Certificates of Deposit

Certificates of Deposit

Accounts Receivable

Accounts Receivable

Lease and Well Equipment Inventory

Lease and Well Equipment Inventory

Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of equipment scheduled for use in future well operations or equipment held for sale.

Property and Equipment

Property and Equipment

Asset Retirement Obligations

Asset Retirement Obligations

Derivative Financial Instruments

Derivative Financial Instruments

Revenue Recognition

Revenue Recognition

Stock-Based Compensation

Stock-Based Compensation

Income Taxes

Income Taxes

Earnings Per Common Share

Earnings Per Common Share


	Year ended December 31,
	2012			2011			2010
Net income (loss) — numerator
Net (loss) income	$	(33,261	)	$	(10,309	)	$	6,377
Less dividends to Class B shareholders — distributed earnings		(28	)		(275	)		(275	)

Undistributed (loss) earnings	$	(33,289	)	$	(10,584	)	$	6,102

Weighted average common shares outstanding — denominator
Basic
Class A		53,852			41,687			40,007
Class B		105			1,031			1,031

Total		53,957			42,718			41,038

Diluted
Class A
Weighted average common shares outstanding for basic earnings (loss) per share		53,852			41,687			40,007
Dilutive effect of options		–			–			96

Class A weighted average common shares outstanding — diluted		53,852			41,687			40,103
Class B
Weighted average common shares outstanding — no associated dilutive shares		105			1,031			1,031

Total diluted weighted average common shares outstanding		53,957			42,718			41,134


	Year ended December 31,
	2012			2011			2010
Earnings (loss) per common share
Basic
Class A
Distributed earnings	$	–		$	–		$	–
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.62	)	$	(0.25	)	$	0.15

Class B
Distributed earnings	$	0.27		$	0.27		$	0.27
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.35	)	$	0.02		$	0.42

Diluted
Class A
Distributed earnings	$	–		$	–		$	–
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.62	)	$	(0.25	)	$	0.15

Class B
Distributed earnings	$	0.27		$	0.27		$	0.27
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.35	)	$	0.02		$	0.42

Fair Value Measurements

Fair Value Measurements

Credit Risk

Credit Risk

Risks and Uncertainties

Risks and Uncertainties

Recent Accounting Pronouncements

Recent Accounting Pronouncements

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Summary of Significant Accounting Policies [Abstract]

Reconciliations of basic and diluted distributed and undistributed earnings (loss) per common share


	Year ended December 31,
	2012			2011			2010
Net income (loss) — numerator
Net (loss) income	$	(33,261	)	$	(10,309	)	$	6,377
Less dividends to Class B shareholders — distributed earnings		(28	)		(275	)		(275	)

Undistributed (loss) earnings	$	(33,289	)	$	(10,584	)	$	6,102

Weighted average common shares outstanding — denominator
Basic
Class A		53,852			41,687			40,007
Class B		105			1,031			1,031

Total		53,957			42,718			41,038

Diluted
Class A
Weighted average common shares outstanding for basic earnings (loss) per share		53,852			41,687			40,007
Dilutive effect of options		–			–			96

Class A weighted average common shares outstanding — diluted		53,852			41,687			40,103
Class B
Weighted average common shares outstanding — no associated dilutive shares		105			1,031			1,031

Total diluted weighted average common shares outstanding		53,957			42,718			41,134


	Year ended December 31,
	2012			2011			2010
Earnings (loss) per common share
Basic
Class A
Distributed earnings	$	–		$	–		$	–
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.62	)	$	(0.25	)	$	0.15

Class B
Distributed earnings	$	0.27		$	0.27		$	0.27
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.35	)	$	0.02		$	0.42

Diluted
Class A
Distributed earnings	$	–		$	–		$	–
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.62	)	$	(0.25	)	$	0.15

Class B
Distributed earnings	$	0.27		$	0.27		$	0.27
Undistributed (loss) earnings	$	(0.62	)	$	(0.25	)	$	0.15

Total	$	(0.35	)	$	0.02		$	0.42

Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Property and Equipment [Abstract]

Summary of the Company's property and equipment


	December 31,
	2012			2011
Oil and natural gas properties
Evaluated (subject to amortization)	$	763,527		$	423,945
Unproved and unevaluated (not subject to amortization)
Incurred in 2012		36,488			–
Incurred in 2011		24,138			60,934
Incurred in 2010		70,417			80,593
Incurred in 2009 and prior		18,632			21,071

Total unproved and unevaluated		149,675			162,598

Total oil and natural gas properties		913,202			586,543
Accumulated depletion		(344,609	)		(201,543	)

Net oil and natural gas properties		568,593			385,000
Other property and equipment
Computer equipment		834			787
Furniture		793			458
Software		1,355			1,111
Other equipment		196			194
Leasehold improvements		644			627
Support equipment and facilities		23,436			15,587

Total other property and equipment		27,258			18,764
Accumulated depreciation		(4,761	)		(3,899	)

Net other property and equipment		22,497			14,865

Net property and equipment	$	591,090		$	399,865

Breakdown of the Company's unproved and unevaluated property costs not subject to amortization


Description	2012		2011		2010		2009 and prior		Total
Costs incurred for
Property acquisition	$	29,165	$	21,748	$	70,417	$	18,632	$	139,962
Exploration wells		4,680		1,932		–		–		6,612
Development wells		2,573		–		–		–		2,573
Capitalized interest		70		458		–		–		528

Total	$	36,488	$	24,138	$	70,417	$	18,632	$	149,675

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligations [Abstract]

Schedule of changes in Company's asset retirement obligations


	Year ended December 31,
	2012		2011
Beginning asset retirement obligations	$	4,270	$	3,695
Liabilities incurred during period		1,243		187
Revisions in estimated cash flows		–		312
Liabilities settled during period		–		(133	)
Accretion expense		256		209

Ending asset retirement obligations	$	5,769	$	4,270

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Taxes [Abstract]

Summary of net deferred tax position


	December 31,
	2012			2011
Current deferred tax assets
Property and equipment	$	233		$	113
Other		869
Net operating loss carryforwards		–			13

Total current deferred tax assets		1,102			126

Valuation allowance on current deferred tax assets		(202	)		–

Total current deferred tax assets, net of valuation allowance		900			126
Current deferred tax liabilities
Unrealized gain on derivatives		(1,311	)		(2,998	)
Other		–			(152	)

Total current deferred tax liabilities		(1,311	)		(3,150	)

Net current deferred tax liability	$	(411	)	$	(3,024	)

Non-current deferred tax assets
Net operating loss carryforwards	$	44,654		$	24,034
Alternative minimum tax carryforward		6,660			6,660

Total non-current deferred tax assets		51,314			30,694

Valuation allowance on non-current deferred tax assets		(10,058	)		–

Total non-current deferred tax assets, net of valuation allowance		41,256			30,694
Non-current deferred tax liabilities
Unrealized gain on derivatives		(262	)		(324	)
Property and equipment		(36,363	)		(27,070	)
Other		(4,220	)		(1,706	)

Total non-current deferred tax liabilities		(40,845	)		(29,100	)

Net non-current deferred tax asset	$	411		$	1,594

Income tax expense reconciled to the tax computed at the statutory federal rate


	Year ended December 31,
	2012			2011			2010
Current income tax (benefit) provision
State income tax	$	–		$	(46	)	$	–
Federal alternative minimum tax		–			–			(1,411	)

Net current income tax benefit		–			(46	)		(1,411	)
Deferred income tax provision (benefit)
Federal tax expense at statutory rate (34%)		(11,767	)		(5,319	)		3,365
Statutory depletion carryforward		–			231			(157	)
State income tax		(819	)		(435	)		–
Change in state rate applied		–			–			275
Nondeductible expense		(122	)		48			38
Permanent differences⁽¹⁾		1,018			–			–
Federal alternative minimum tax		–			–			1,411
Change in valuation allowance		10,260			–			–

Net deferred income tax (benefit) provision		(1,430	)		(5,475	)		4,932

Total income tax (benefit) provision	$	(1,430	)	$	(5,521	)	$	3,521

⁽¹⁾

Amount is primarily attributable to stock-based compensation.

Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2012

Stock-Based Compensation [Abstract]

Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan


Stock option pricing model		Binomial Lattice
Expected option life		5.41 years
Risk-free interest rate		2.58%
Volatility		46.17%
Dividend yield		0.0%
Estimated forfeiture rate		11.15%
Weighted average fair value of stock option awards granted during the year		$3.02


	2012	2011
Stock option pricing model	Black Scholes Merton	Black Scholes Merton
Expected option life	0.89 years	1.04 years
Risk-free interest rate	0.25%	0.37%
Volatility	54.28%	61.41%
Dividend yield	0.00%	0.00%
Estimated forfeiture rate	0.70%	1.04%


Stock option pricing model		Black Scholes Merton
Expected option life		4.44 years
Risk-free interest rate		0.71%
Volatility		71.16%
Dividend yield		0.00%
Estimated forfeiture rate		5.46%
Weighted average fair value of stock option awards granted during the year		$5.95

Summarized information about stock options outstanding


	Number of options			Weighted average exercise price
Options outstanding at December 31, 2011		1,025		$	9.75
Options granted		656			10.79
Options exercised		(296	)		9.00
Options forfeited		(248	)		11.43
Options expired		(70	)		9.95

Options outstanding at December 31, 2012		1,067		$	10.19

Summarized information about outstanding and exercisable stock option


	Options outstanding at December 31, 2012						Options exercisable at December 31, 2012
Range of exercise prices	Shares outstanding		Weighted average remaining contractual life		Weighted average exercise price		Shares exercisable		Weighted average exercise price
$7.50-$9.00		139		6.34 years	$	8.77		66	$	8.75
$10.00-$13.33		928		2.37 years	$	10.41		459	$	10.32

Summary of the non-vested restricted stock and restricted stock units


	Restricted Stock										Restricted Stock Units
	Service Based					Performance Based					Service Based					Performance Based
Non-vested restricted stock and restricted stock units	Shares			Weighted average fair value		Shares			Weighted average fair Value⁽¹⁾		Shares			Weighted average fair value		Shares			Weighted average fair Value⁽¹⁾
Non-vested at January 1, 2012		8		$	11.00		–		$	–		–		$	–		–		$	–
Granted		207			9.66		117			13.24		54			10.04		117			–
Vested		(18	)		8.72		–			–		–			–		–			–
Forfeited		(15	)		10.76		(7	)		13.24		(2	)		11.02		(7	)		–

Non-vested at December 31, 2012		182		$	9.72		110		$	13.24		52		$	10.00		110		$	–

⁽¹⁾	The fair value of these restricted stock units is reflected in the fair value of the performance based restricted stock, which was estimated based on the most likely outcome of the award as determined by the Monte Carlo method.

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2012

Open Option Contracts Written [Line Items]

Summary of contracts for oil and natural gas


Commodity	Calculation Period		Notional Quantity (Bbl/month)		Price Floor ($/Bbl)		Price Ceiling ($/Bbl)		Fair Value of Asset (thousands)
Oil		01/01/2013 - 03/31/2013		20,000		90.00		110.00	$	122
Oil		01/01/2013 - 12/31/2013		20,000		85.00		102.25		96
Oil		01/01/2013 - 12/31/2013		20,000		90.00		115.00		980
Oil		01/01/2013 - 12/31/2013		20,000		85.00		110.40		471
Oil		01/01/2013 - 12/31/2013		20,000		85.00		108.80		418
Oil		01/01/2013 - 06/30/2014		8,000		90.00		114.00		666
Oil		01/01/2013 - 06/30/2014		12,000		90.00		115.50		1,036

Total open oil costless collar contracts										3,789

Commodity	Calculation Period		Notional Quantity (MMBtu/month)		Price Floor ($/MMBtu)		Price Ceiling ($/MMBtu)		Fair Value of Asset (Liability) (thousands)
Natural Gas		01/01/2013 - 07/31/2013		150,000		4.50		5.75		1,154
Natural Gas		01/01/2013 - 12/31/2013		100,000		3.00		3.83		(146	)
Natural Gas		01/01/2013 - 12/31/2013		100,000		3.00		4.95		40
Natural Gas		01/01/2013 - 12/31/2013		100,000		3.00		4.96		41
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.25		5.37		19
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.25		5.42		27

Total open natural gas costless collar contracts										1,135


Commodity	Calculation Period		Notional Quantity (Bbl/month)		Fixed Price ($/Bbl)		Fair Value of Liability (thousands)
Oil		01/01/2013 - 12/31/2013		10,000		90.20		(362	)
Oil		01/01/2013 - 12/31/2013		10,000		90.65		(308	)

Total open oil swap contracts								(670	)



Commodity	Calculation Period		Notional Quantity (Gal/month)		Fixed Price ($/Gal)		Fair Value of Asset (Liability) (thousands)
Purity Ethane		01/01/2013 - 12/31/2013		110,000		0.335		106
Purity Ethane		01/01/2013 - 12/31/2013		110,000		0.355		133
Propane		01/01/2013 - 12/31/2013		53,000		0.953		13
Propane		01/01/2013 - 12/31/2013		53,000		1.001		43
Normal Butane		01/01/2013 - 12/31/2013		14,700		1.455		(29	)
Normal Butane		01/01/2013 - 12/31/2013		14,700		1.560		(10	)
Isobutane		01/01/2013 - 12/31/2013		7,000		1.515		(18	)
Isobutane		01/01/2013 - 12/31/2013		7,000		1.625		(9	)
Natural Gasoline		01/01/2013 - 12/31/2013		12,000		2.025		(8	)
Natural Gasoline		01/01/2013 - 12/31/2013		12,000		2.085		1
Natural Gasoline		01/01/2013 - 12/31/2013		12,000		2.102		3

Total open NGL swap contracts							$	225

Total open derivative financial instruments							$	4,479

Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated balance sheets


Type of Instrument	Location in Balance Sheet	December 31, 2012			December 31, 2011
Derivative Instrument
Oil	Current assets: Derivative instruments	$	3,064		$	–
Oil	Other assets: Derivative instruments		725			–
Oil	Current liabilities: Derivative instruments		(670	)		(171	)
Oil	Long-term liabilities: Derivative instruments		–			(383	)
Natural Gas	Current assets: Derivative instruments		1,089			8,989
Natural Gas	Other assets: Derivative instruments		46			847
Natural Gas	Long-term liabilities: Derivative instruments		–			–
NGL’s	Current assets: Derivative instruments		225			–
NGL’s	Long-term liabilities: Derivative instruments		–			–

Total		$	4,479		$	9,282

Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations


Type of Instrument	Location in Statement of Operations	Year Ended December 31,
Type of Instrument	Location in Statement of Operations	2012			2011			2010
Derivative Instrument
Oil	Revenues: Realized gain on derivatives	$	2,047		$	–		$	–
Natural Gas	Revenues: Realized gain on derivatives		11,892			7,106			5,299
NGL’s	Revenues: Realized gain on derivatives		21			–			–

Realized gain on derivatives			13,960			7,106			5,299
Oil	Revenues: Unrealized gain (loss) on derivatives		3,673			(554	)		–
Natural Gas	Revenues: Unrealized (loss) gain on derivatives		(8,700	)		5,692			3,139
NGL’s	Revenues: Unrealized gain on derivatives		225			–			–

Unrealized (loss) gain on derivatives			(4,802	)		5,138			3,139

Total		$	9,158		$	12,244		$	8,438

- Definition

Tabular disclosure of the location and amount of gains and losses reported in the statement of financial performance, or when applicable, the statement of financial position. For example, (a) gains and losses recognized in the income statement on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges and (b) gains and losses initially recognized in other comprehensive income on derivative instruments designated and qualifying as cash flow hedges.

+ References + Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Measurements [Abstract]

Summary of the valuation of the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis


Description	Fair Value Measurements at December 31, 2012 using
	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Certificates of deposit	$	–	$	230		$	–	$	230
Oil, natural gas and NGL derivatives		–		5,149			–		5,149
Oil, natural gas and NGL derivatives		–		(670	)		–		(670	)

Total	$	–	$	4,709		$	–	$	4,709


Description	Fair Value Measurements at December 31, 2011 using
	Level 1		Level 2			Level 3		Total
Assets (Liabilities)
Certificates of deposit	$	–	$	1,335		$	–	$	1,335
Oil and natural gas derivatives		–		9,836			–		9,836
Oil and natural gas derivatives		–		(554	)		–		(554	)

Total	$	–	$	10,617		$	–	$	10,617

Additions to asset retirement obligations and lease and well equipment inventory at fair value on a non-recurring basis


Description	Fair Value Measurements at December 31, 2012 using
	Level 1		Level 2		Level 3			Total
Assets (Liabilities)
Asset retirement obligations	$	–	$	–	$	(1,243	)	$	(1,243	)
Lease and well equipment inventory		–		–		34			34

Total	$	–	$	–	$	(1,209	)	$	(1,209	)


Description	Fair Value Measurements at December 31, 2011 using
	Level 1		Level 2		Level 3			Total
Assets (Liabilities)
Asset retirement obligations	$	–	$	–	$	(187	)	$	(187	)
Lease and well equipment inventory		–		–		1,343			1,343

Total	$	–	$	–	$	1,156		$	1,156

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies [Abstract]

Schedule of future minimum lease payments required under the office lease agreement


Year ending December 31,	Amount
2013	$	575
2014		575
2015		589
2016		604
2017		618
Thereafter		2,995

Total	$	5,956

Summary of aggregate undiscounted minimum commitments


Year ending December 31, 2012	Amount
2013	$	5,985
2014		4,731
2015		2,992
2016		1,800
2017		1,195

Total	$	16,703

Supplemental Disclosures (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Disclosures [Abstract]

Summary of current accrued liabilities


	December 31,
	2012		2011
Accrued evaluated and unproved and unevaluated property costs	$	45,592	$	18,185
Accrued support equipment and facilities costs		1,382		216
Accrued cost to issue equity		–		332
Accrued stock-based compensation		65		2,860
Accrued lease operating expenses		5,218		575
Accrued interest on borrowings under Credit Agreement		255		34
Accrued asset retirement obligations		660		334
Accrued partners’ share of joint interest charges		3,597		51
Other		2,410		2,852

Total accrued liabilities	$	59,179	$	25,439

Supplemental disclosures of cash flow information


	Year ended December 31,
	2012			2011			2010
Cash paid (refunded) for income taxes	$	–		$	–		$	(2,156	)
Cash paid for interest expense, net of amounts capitalized		780			634			–
Asset retirement obligations related to mineral properties		1,195			488			862
Asset retirement obligations related to support equipment and facilities		49			12			126
Increase in liabilities for oil and natural gas properties capital expenditures		24,847			1,864			15,531
Increase in liabilities for support equipment and facilities		1,112			175			40
Issuance of treasury stock for Board and advisor services		–			–			47
Issuance of restricted stock units for Board and advisor services		73			–			–
Issuance of common stock for Board and advisor services		71			230			198
(Decrease) increase in liabilities for accrued cost to issue equity		(332	)		(27	)		359
Stock based compensation expense recognized as liability		(1,092	)		2,102			164
Transfer of inventory to oil and natural gas properties		69			96			353

Supplemental Oil and Natural Gas Disclosures (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Oil and Natural Gas Disclosures (Unaudited) [Abstract]

Summarizes costs incurred and capitalized by the Company in the acquisition, exploration, and development of oil and natural gas properties


	Year ended December 31,
	2012		2011		2010
Property acquisition costs
Proved	$	–	$	–	$	–
Unproved and unevaluated		28,672		41,497		100,730
Exploration costs		115,084		108,662		60,719
Development costs		190,891		12,511		14,348

Total costs incurred	$	334,647	$	162,670	$	175,797

Summary of results of operations from oil and gas producing activities, excluding corporate overhead and interest costs


	Year ended December 31,
	2012			2011			2010
Oil and natural gas revenues	$	155,998		$	67,000		$	34,042
Production taxes and marketing expenses		11,672			6,278			1,982
Lease operating expenses		28,184			7,244			5,284
Depletion, depreciation and amortization		79,592			31,619			15,423
Accretion of asset retirement obligations		256			209			155
Full-cost ceiling impairment		63,475			35,673			–

Net operating (loss) income		(27,181	)		(14,023	)		11,198
Income tax (benefit) provision		(9,595	)		(5,019	)		3,983

Results of oil and natural gas operations	$	(17,586	)	$	(9,004	)	$	7,215

Depletion, depreciation and amortization per BOE	$	24.16		$	12.29		$	10.76

Summary of Estimated reserves


	Net Proved Reserves
	Oil			Gas			Oil Equivalent
	(MBbl)			(MMcf)			(MBOE)


Total at December 31, 2009		103			63,929			10,758
Revisions of prior estimates		66			874			211
Extensions and discoveries		16			71,009			11,851
Production		(33	)		(8,400	)		(1,433	)

Total at December 31, 2010		152			127,412			21,387
Revisions of prior estimates		51			(646	)		(57	)
Extensions and discoveries		3,745			58,164			13,439
Production		(154	)		(14,512	)		(2,573	)

Total at December 31, 2011		3,794			170,418			32,196
Revisions of prior estimates		(782	)		(103,375	)		(18,010	)
Extensions and discoveries		8,687			25,443			12,927
Production		(1,214	)		(12,479	)		(3,294	)

Total at December 31, 2012		10,485			80,007			23,819

Proved Developed Reserves

December 31, 2009		103			25,369			4,331
December 31, 2010		152			43,143			7,342
December 31, 2011		1,419			56,547			10,843
December 31, 2012		4,764			54,040			13,771

Proved Undeveloped Reserves

December 31, 2009		–			38,560			6,427
December 31, 2010		–			84,269			14,045
December 31, 2011		2,375			113,871			21,353
December 31, 2012		5,721			25,967			10,048

Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves


	Year ended December 31,
	2012			2011			2010
Future cash inflows	$	1,273,882		$	924,796		$	470,386
Future production costs		(325,413	)		(194,538	)		(107,183	)
Future development costs		(244,283	)		(235,469	)		(107,277	)
Future income tax expense		(77,821	)		(83,840	)		(35,352	)

Future net cash flows		626,365			410,949			220,574
10% annual discount for estimated timing of cash flows		(231,729	)		(195,476	)		(109,497	)

Standardized measure of discounted future net cash flows	$	394,636		$	215,473		$	111,077

Summarizes of changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves


	Year ended December 31,
	2012			2011			2010
Balance, beginning of period	$	215,473		$	111,077		$	65,061
Net change in sales and transfer prices and in production (lifting) costs related to future production		(60,892	)		53,903			7,632
Changes in estimated future development costs		16,937			(64,958	)		(36,821	)
Sales and transfers of oil and natural gas produced during the period		(116,142	)		(53,478	)		(26,776	)
Net change due to extensions and discoveries		358,159			182,282			94,265
Net change due to revisions in estimates of reserves quantities		(56,850	)		(653	)		1,676
Previously estimated development costs incurred during the period		9,750			1,023			7,125
Accretion of discount		24,873			11,987			7,036
Other		(290	)		(1,335	)		1,035
Net change in income taxes		3,618			(24,375	)		(9,156	)

Standardized measure of discounted future net cash flows	$	394,636		$	215,473		$	111,077

- Definition

Tabular disclosure of the aggregate of costs (whether the costs are capitalized or charged to expense at the time they are incurred ) incurred for the year in oil and gas property acquisition, exploration and development activities.

+ References + Details

- Definition

Tabular disclosure of the results of operations for oil and gas producing activities for the year.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 24
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62246-109447

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 27
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62352-109447

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
-URI http://asc.fasb.org/extlink&oid=21918352&loc=d3e511914-122862

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 23
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62136-109447

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 25
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62259-109447

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62094-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62299-109447

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 55
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=8451751&loc=d3e63071-109448

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (c)(3)
-URI http://asc.fasb.org/extlink&oid=6392692&loc=d3e7535-110849

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62395-109447

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 19
-Paragraph 59S, 59T, 59U, 59V, 59W, 59X
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

+ References + Details

- Definition

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

+ References + Details

Subsequent Events (Tables)

12 Months Ended

Dec. 31, 2012

Subsequent Event [Line Items]

Summary of contracts for oil and natural gas


Commodity	Calculation Period		Notional Quantity (Bbl/month)		Price Floor ($/Bbl)		Price Ceiling ($/Bbl)		Fair Value of Asset (thousands)
Oil		01/01/2013 - 03/31/2013		20,000		90.00		110.00	$	122
Oil		01/01/2013 - 12/31/2013		20,000		85.00		102.25		96
Oil		01/01/2013 - 12/31/2013		20,000		90.00		115.00		980
Oil		01/01/2013 - 12/31/2013		20,000		85.00		110.40		471
Oil		01/01/2013 - 12/31/2013		20,000		85.00		108.80		418
Oil		01/01/2013 - 06/30/2014		8,000		90.00		114.00		666
Oil		01/01/2013 - 06/30/2014		12,000		90.00		115.50		1,036

Total open oil costless collar contracts										3,789

Commodity	Calculation Period		Notional Quantity (MMBtu/month)		Price Floor ($/MMBtu)		Price Ceiling ($/MMBtu)		Fair Value of Asset (Liability) (thousands)
Natural Gas		01/01/2013 - 07/31/2013		150,000		4.50		5.75		1,154
Natural Gas		01/01/2013 - 12/31/2013		100,000		3.00		3.83		(146	)
Natural Gas		01/01/2013 - 12/31/2013		100,000		3.00		4.95		40
Natural Gas		01/01/2013 - 12/31/2013		100,000		3.00		4.96		41
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.25		5.37		19
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.25		5.42		27

Total open natural gas costless collar contracts										1,135


Commodity	Calculation Period		Notional Quantity (Bbl/month)		Fixed Price ($/Bbl)		Fair Value of Liability (thousands)
Oil		01/01/2013 - 12/31/2013		10,000		90.20		(362	)
Oil		01/01/2013 - 12/31/2013		10,000		90.65		(308	)

Total open oil swap contracts								(670	)



Commodity	Calculation Period		Notional Quantity (Gal/month)		Fixed Price ($/Gal)		Fair Value of Asset (Liability) (thousands)
Purity Ethane		01/01/2013 - 12/31/2013		110,000		0.335		106
Purity Ethane		01/01/2013 - 12/31/2013		110,000		0.355		133
Propane		01/01/2013 - 12/31/2013		53,000		0.953		13
Propane		01/01/2013 - 12/31/2013		53,000		1.001		43
Normal Butane		01/01/2013 - 12/31/2013		14,700		1.455		(29	)
Normal Butane		01/01/2013 - 12/31/2013		14,700		1.560		(10	)
Isobutane		01/01/2013 - 12/31/2013		7,000		1.515		(18	)
Isobutane		01/01/2013 - 12/31/2013		7,000		1.625		(9	)
Natural Gasoline		01/01/2013 - 12/31/2013		12,000		2.025		(8	)
Natural Gasoline		01/01/2013 - 12/31/2013		12,000		2.085		1
Natural Gasoline		01/01/2013 - 12/31/2013		12,000		2.102		3

Total open NGL swap contracts							$	225

Total open derivative financial instruments							$	4,479

Schedule of future minimum lease payments required under the office lease agreement


Year ending December 31,	Amount
2013	$	575
2014		575
2015		589
2016		604
2017		618
Thereafter		2,995

Total	$	5,956

Subsequent Event [Member]

Subsequent Event [Line Items]

Summary of contracts for oil and natural gas


Commodity	Calculation Period		Notional Quantity (Bbls/month)		Price Floor ($/Bbl)		Price Ceiling ($/Bbl)
Oil		07/01/2013 - 12/31/2013		20,000		90.00		102.80
Oil		01/01/2014 - 12/31/2014		15,000		85.00		97.50
Oil		01/01/2014 - 12/31/2014		30,000		85.00		98.00
Oil		01/01/2014 - 12/31/2014		15,000		87.00		97.00
Oil		01/01/2014 - 12/31/2014		20,000		90.00		97.00
Oil		01/01/2014 - 12/31/2014		15,000		90.00		97.90
Oil		01/01/2014 - 12/31/2014		15,000		90.00		98.00


Commodity	Calculation Period		Notional Quantity (MMBtu/month)		Price Floor ($/MMBtu)		Price Ceiling ($/MMBtu)
Natural Gas		04/01/2013 - 12/31/2013		100,000		3.25		4.41
Natural Gas		04/01/2013 - 12/31/2013		100,000		3.25		4.44
Natural Gas		04/01/2013 - 12/31/2013		100,000		3.50		4.37
Natural Gas		07/01/2013 - 12/31/2013		150,000		3.00		4.24
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.00		5.15
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.25		5.21
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.25		5.22
Natural Gas		01/01/2014 - 12/31/2014		100,000		3.50		4.90


Commodity	Calculation Period		Notional Quantity (Gal/month)		Fixed Price ($/Gal)
Normal Butane		03/01/2013 - 12/31/2013		21,000		1.575
Normal Butane		03/01/2013 - 12/31/2013		117,000		1.575
Normal Butane		01/01/2014 - 12/31/2014		17,500		1.540
Normal Butane		01/01/2014 - 12/31/2014		45,500		1.550
Isobutane		03/01/2013 - 12/31/2013		43,500		1.675
Isobutane		03/01/2013 - 12/31/2013		23,000		1.675
Isobutane		01/01/2014 - 12/31/2014		22,000		1.640
Isobutane		01/01/2014 - 12/31/2014		37,000		1.640
Natural Gasoline		03/01/2013 - 12/31/2013		36,000		2.105
Natural Gasoline		03/01/2013 - 12/31/2013		90,500		2.148
Natural Gasoline		01/01/2014 - 12/31/2014		30,000		1.970
Natural Gasoline		01/01/2014 - 12/31/2014		41,000		2.000

Schedule of future minimum lease payments required under the office lease agreement


Year ending December 31,	Amount
2013	$	643
2014		734
2015		752
2016		771
2017		789
Thereafter		3,813

Total	$	7,502

Selected Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Selected Quarterly Financial Information (Unaudited) [Abstract]

Unaudited quarterly financial information


	December 31			September 30			June 30			March 31
2012
Oil and natural gas revenues	$	52,748		$	38,008		$	36,078		$	29,164
Realized gain on derivatives		2,813			3,371			4,713			3,063
Unrealized (loss) gain on derivatives		(3,653	)		(12,993	)		15,114			(3,270	)
Expenses		72,377			38,087			66,263			21,857
Other expense		(907	)		(89	)		(31	)		(235	)
(Loss) income before income taxes		(21,376	)		(9,790	)		(10,389	)		6,865
Income tax (benefit) provision		(188	)		(593	)		(3,713	)		3,064

Net (loss) income	$	(21,188	)	$	(9,197	)	$	(6,676	)	$	3,801


Earnings (loss) per common share
Basic
Class A	$	(0.38	)	$	(0.17	)	$	(0.12	)	$	0.08

Class B	$	0.00		$	0.00		$	0.00		$	0.15

Diluted
Class A	$	(0.38	)	$	(0.17	)	$	(0.12	)	$	0.08

Class B	$	0.00		$	0.00		$	0.00		$	0.15


	December 31			September 30			June 30			March 31
2011
Oil and natural gas revenues	$	14,991		$	17,447		$	20,864		$	13,698
Realized gain on derivatives		2,869			1,435			952			1,850
Unrealized gain (loss) on derivatives		3,604			2,870			332			(1,668	)
Expenses		15,784			15,469			14,953			48,347
Other expense		(309	)		(89	)		(89	)		(35	)
Income (loss) before income taxes		5,371			6,194			7,106			(34,502	)
Income tax provision (benefit)		1,430			–			(46	)		(6,906	)

Net income (loss)	$	3,941		$	6,194		$	7,152		$	(27,596	)


Earnings (loss) per common share
Basic
Class A	$	0.09		$	0.14		$	0.17		$	(0.65	)

Class B	$	0.16		$	0.21		$	0.23		$	(0.58	)

Diluted
Class A	$	0.09		$	0.14		$	0.17		$	(0.65	)

Class B	$	0.16		$	0.21		$	0.23		$	(0.58	)

Nature of Operations (Details)	Dec. 31, 2012 Subsidiaries
Nature of Operations (Textual) [Abstract]
Number of wholly owned subsidiaries	4

Summary of Significant Accounting Policies (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net income (loss) - numerator
Net (loss) income	$ (21,188)	$ (9,197)	$ (6,676)	$ 3,801	$ 3,941	$ 6,194	$ 7,152	$ (27,596)	$ (33,261)	$ (10,309)	$ 6,377
Less dividends to Class B shareholders - distributed earnings									(28)	(275)	(275)
Undistributed (loss) earnings									$ (33,289)	$ (10,584)	$ 6,102
Weighted average common shares outstanding - denominator
Weighted average common shares outstanding for basic earnings (loss) per share									53,957	42,718	41,038
Diluted									53,957	42,718	41,134
Class A [Member]
Weighted average common shares outstanding - denominator
Weighted average common shares outstanding for basic earnings (loss) per share									53,852	41,687	40,007
Dilutive effect of options											96
Diluted									53,852	41,687	40,103
Basic
Distributed earnings
Undistributed (loss) earnings									(0.62)	(0.25)	0.15
Total	$ (0.38)	$ (0.17)	$ (0.12)	$ 0.08	$ 0.09	$ 0.14	$ 0.17	$ (0.65)	(0.62)	(0.25)	0.15
Diluted
Distributed earnings
Undistributed (loss) earnings									(0.62)	(0.25)	0.15
Total	(0.38)	(0.17)	(0.12)	0.08	0.09	0.14	0.17	(0.65)	$ (0.62)	$ (0.25)	$ 0.15
Class B [Member]
Weighted average common shares outstanding - denominator
Weighted average common shares outstanding for basic earnings (loss) per share									105	1,031	1,031
Diluted									105	1,031	1,031
Basic
Distributed earnings									$ 0.27	$ 0.27	$ 0.27
Undistributed (loss) earnings									(0.62)	(0.25)	0.15
Total	0.00	0.00	0.00	0.15	0.16	0.21	0.23	(0.58)	(0.35)	0.02	0.42
Diluted
Distributed earnings									0.27	0.27	0.27
Undistributed (loss) earnings									(0.62)	(0.25)	0.15
Total	$ 0.00	$ 0.00	$ 0.00	$ 0.15	$ 0.16	$ 0.21	$ 0.23	$ (0.58)	$ (0.35)	$ 0.02	$ 0.42

Summary of Significant Accounting Policies (Details Textual)	3 Months Ended					6 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2012 USD ($) Subsidiaries	Sep. 30, 2012 USD ($)	Jun. 30, 2012 USD ($)	Mar. 31, 2012 USD ($)	Mar. 31, 2011 USD ($)	Jun. 30, 2012 USD ($)	Sep. 30, 2012 USD ($)	Dec. 31, 2012 USD ($) Subsidiaries	Dec. 31, 2012 USD ($) Subsidiaries $ / MMBTU	Dec. 31, 2012 USD ($) Subsidiaries $ / bbl	Dec. 31, 2012 USD ($) Subsidiaries $ / shares	Dec. 31, 2012 USD ($) Subsidiaries	Dec. 31, 2012 USD ($) Subsidiaries shares	Dec. 31, 2012 USD ($) Subsidiaries	Dec. 31, 2011 USD ($) $ / MMBTU	Dec. 31, 2011 USD ($) $ / bbl	Dec. 31, 2011 USD ($) $ / shares	Dec. 31, 2011 USD ($)	Dec. 31, 2011 USD ($) shares	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2010 USD ($) $ / MMBTU	Dec. 31, 2010 USD ($) $ / bbl	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Summary of Significant Accounting Policies (Textual) [Abstract]
Dividends paid														$ 96,000						$ 275,000				$ 275,000
Restricted stock \| shares													162,368						0
Interest expense														$ (1,002,000)						(683,000)				(3,000)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Vested Period								4 years
Summary of Significant Accounting Policies (Additional Textual) [Abstract]
Number of wholly owned subsidiaries \| Subsidiaries	4							4	4	4	4	4	4	4
Liquid investments with an original maturity								30 days or less
Cash equivalents	$ 2,095,000							$ 2,095,000	$ 2,095,000	$ 2,095,000	$ 2,095,000	$ 2,095,000	$ 2,095,000	$ 2,095,000	$ 10,284,000	$ 10,284,000	$ 10,284,000	$ 10,284,000	$ 10,284,000	10,284,000	$ 21,060,000	$ 21,060,000	$ 21,060,000	21,060,000	$ 104,230,000
Wrote off receivables														0						24,229				0
Capitalized general and administrative costs														2,600,000						2,000,000				1,600,000
Capitalized interest expense														1,600,000						1,300,000				0
Present value discounted percent of future net revenues of proved oil and natural gas reserves																		10.00%
Average oil and natural gas prices									2.757	91.21					4.118	92.71						4.376	75.96
Net capitalized costs less related deferred income taxes exceeded the full-cost ceiling	$ 17,300,000	$ 2,300,000	$ 21,300,000		$ 23,000,000	$ 21,300,000	$ 2,300,000							17,300,000
Impairment charge of net capitalized costs					35,700,000	33,200,000	3,600,000							63,475,000						35,673,000				0
Deferred income tax credit					$ 12,700,000	$ 11,900,000	$ 1,300,000							3,618,000,000						(24,375,000)				(9,156,000)
Stock-based compensation (non-cash) expense														100,000						2,400,000				900,000
Common stock and restricted stock unit expense														100,000						200,000				200,000
Percentage being realized up on ultimate settlement												50.00%
Interest or penalties expense														0						0				0
Dividends declared														$ 27,643						274,853				274,853
Working interest percentage												25.00%
Billing date	30 days							30 days	30 days	30 days	30 days	30 days	30 days	30 days
Outstanding days of account receivable								60 days
Stock-based compensation	$ 0							$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
Granted stock Option														(589,000)						$ 2,362,000				824,000
Oil And Natural Gas Properties [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Interest expense																								$ (3,235,000)
Machinery and Equipment [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Useful life using the straight-line								30 years
Maximum [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Short-term investments with an original maturity								1 year
Accounts receivable due period								60 days
Useful life								10 years													5 years				4 years
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Vested Period								4 years
Minimum [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Short-term investments with an original maturity								30 days
Accounts receivable due period								30 days
Useful life								5 years													3 years				2 years
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Vested Period								3 years
Class A [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Dividends paid														0
Initial Public Offering														$ 1,030,700
Class B [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Cumulative annual dividends per share rate \| $ / shares																	$ 0.26
Total Dividend paid				$ 96,356
Class B [Member] \| Maximum [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Cumulative annual dividends per share rate \| $ / shares											$ 0.66
Class B [Member] \| Minimum [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Cumulative annual dividends per share rate \| $ / shares											$ 0.26
Stock options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Total options to purchase shares of the Company's common stock and restricted stock excluded from the calculations \| shares													1,067,069						1,024,500
Vested Period								3 years
Restricted stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Total options to purchase shares of the Company's common stock and restricted stock excluded from the calculations \| shares													305,807

Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Oil and natural gas properties
Evaluated (subject to amortization)	$ 763,527	$ 423,945
Unproved and unevaluated (not subject to amortization)
Incurred in 2012	36,488
Incurred in 2011	24,138	60,934
Incurred in 2010	70,417	80,593
Incurred in 2009 and prior	18,632	21,071
Total unproved and unevaluated	149,675	162,598
Total oil and natural gas properties	913,202	586,543
Accumulated depletion	(344,609)	(201,543)
Net oil and natural gas properties	568,593	385,000
Other property and equipment
Other property and equipment	27,258	18,764
Accumulated depreciation	(4,761)	(3,899)
Net other property and equipment	22,497	14,865
Net property and equipment	591,090	399,865
Computer equipment [Member]
Other property and equipment
Other property and equipment	834	787
Furniture [Member]
Other property and equipment
Other property and equipment	793	458
Software [Member]
Other property and equipment
Other property and equipment	1,355	1,111
Other equipment [Member]
Other property and equipment
Other property and equipment	196	194
Leasehold improvements [Member]
Other property and equipment
Other property and equipment	644	627
Support equipment and facilities [Member]
Other property and equipment
Other property and equipment	$ 23,436	$ 15,587

Property and Equipment (Details 1) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization
Costs incurred for Property acquisition	$ 139,962
Exploration wells	6,612
Amount for development wells	2,573
Capitalized interest	528
Total unproved and unevaluated	149,675	$ 162,598
2012 [Member]
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization
Costs incurred for Property acquisition	29,165
Exploration wells	4,680
Amount for development wells	2,573
Capitalized interest	70
Total unproved and unevaluated	36,488
2011 [Member]
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization
Costs incurred for Property acquisition	21,748
Exploration wells	1,932
Capitalized interest	458
Total unproved and unevaluated	24,138
2010 [Member]
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization
Costs incurred for Property acquisition	70,417
Total unproved and unevaluated	70,417
2009 and prior [member]
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization
Costs incurred for Property acquisition	18,632
Total unproved and unevaluated	$ 18,632

Property and Equipment (Details Textual) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2010	Dec. 31, 2009
Property and Equipment (Textual) [Abstract]
Amortization costs	$ 7,300
Amount for exploration wells	6,612
Amount for development wells	2,573
Anticipated amount for wells	7,300
Well costs excluded from amortization	$ 1,900
Maximum [Member]
Property, Plant and Equipment [Line Items]
Evaluation of properties and amortization Cost are expected to be completed	10 years	5 years	4 years
Minimum [Member]
Property, Plant and Equipment [Line Items]
Evaluation of properties and amortization Cost are expected to be completed	5 years	3 years	2 years

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Changes in the Company's asset retirement obligations
Beginning asset retirement obligations	$ 4,270	$ 3,695
Liabilities incurred during period	1,243	187
Revisions in estimated cash flows		312
Liabilities settled during period		(133)
Accretion expense	256	209	$ 155
Ending asset retirement obligations	$ 5,769	$ 4,270	$ 3,695

Asset Retirement Obligations (Details Textual) - USD ($)	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligations (Textual) [Abstract]
Asset retirement obligations were classified as current liabilities and included in accrued liabilities	$ 660,303	$ 334,500

Asset Sales and Impairment (Details Textual) - USD ($)	12 Months Ended
Asset Sales and Impairment (Details Textual) - USD ($)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Asset Sales and Impairment (Textual) [Abstract]
Carrying value of inventory	$ 0
Loss incurred on equipment sold		$ 113,757
Net loss incurred in South Pipeline asset			$ 173,690
Inventory Asset impairment or sales occurred	0
Remaining balance of drilling rig parts	0
Sold equipment	60,000
Drilling rig [Member]
Change in Accounting Estimate [Line Items]
Impairment charge for equipments held in inventory	425,000	17,500	50,000
Pipe and other equipment [Member]
Change in Accounting Estimate [Line Items]
Impairment charge for equipments held in inventory	$ 60,464	$ 22,276	$ 0

Revolving Credit Agreement (Details Textual) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Sep. 30, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Mar. 14, 2013	Mar. 11, 2013	Dec. 20, 2012	Sep. 28, 2012	Feb. 28, 2012	Jan. 31, 2012	May 31, 2011
Revolving Credit Agreement (Textual) [Abstract]
Additional borrowings for working capital requirements		$ 150,000								$ 10,000
Conforming borrowing base		220,000					$ 180,000
Borrowing base		$ 255,000
Repay deficit in agreement Period		6 months
Net cash proceeds from secondary public offering		$ 146,510	$ 592	$ 20,652
Borrowed under credit agreement		150,000								$ 123,000	$ 25,000
Additional deferred loan cost	$ 800	100
Deferred Loan fees		800
Deferred Loan Costs		1,600
Outstanding letters of credit		1,100
Available for additional borrowings		$ 63,900
Outstanding borrowings bore interest effective rate		3.30%
Revolving Credit Agreement (Additional Textual) [Abstract]
Credit Agreement, maturity date		Dec. 29, 2016
The borrowing base under the Credit Agreement determined		semi-annually
Percentage of reserves required to maintain		100.00%
Total debt outstanding to EBITDA		4.0
Current ratio		1.0
Federal Funds Effective Plus Rate		0.50%
Second amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Senior secured revolving credit maximum facility								$ 400,000
Company amended and restated its senior secured revolving credit agreement	2012-9-28
Borrowed under credit agreement			113,000
Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Senior secured revolving credit maximum facility								500,000
Conforming borrowing base								165,000
Net cash proceeds from secondary public offering	$ 25,000
Conforming borrowing base description		The borrowing base will automatically be reduced to an amount equal to the conforming borrowing base on the earlier of (i) December 31, 2013 or (ii) the closing of a secondary public offering of equity interests by the Company that results in net cash proceeds to the Company in an amount greater than or equal to $25 million.
Conforming borrowing base date		Dec. 31, 2013
Subsequent Event [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional borrowings for working capital requirements		$ 30,000
Senior secured revolving credit maximum facility						$ 255,000
Borrowed under credit agreement		180,000
Additional deferred loan cost					$ 300
Outstanding letters of credit		1,300			$ 1,300
Available for additional borrowings		$ 73,700
Base rate loan [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings interest rate description		If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate plus 1.0% plus, in each case, an amount from 0.75% to 2.25% of such outstanding loan depending on the level of borrowings under the Credit Agreement
LIBOR rate [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings interest rate		1.00%
Eurodollar Loan [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings interest rate description		If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which RBC is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.75% to 3.25% of such outstanding loan depending on the level of borrowings under the Credit Agreement.
Maximum [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowing base							215,000		$ 125,000
Credit facility fee		0.50%
Maximum [Member] \| Second amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings under the credit agreement			400,000
Maximum [Member] \| Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowing base								200,000
Maximum [Member] \| Base rate loan [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate		2.25%
Maximum [Member] \| Eurodollar Loan [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate		3.25%
Minimum [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowing base							$ 200,000		$ 100,000
Credit facility fee		0.375%
Minimum [Member] \| Second amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowings under the credit agreement			$ 125,000
Minimum [Member] \| Third amended credit agreement [Member]
Revolving Credit Agreement (Textual) [Abstract]
Borrowing base								$ 125,000
Minimum [Member] \| Base rate loan [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate		0.75%
Minimum [Member] \| Eurodollar Loan [Member]
Revolving Credit Agreement (Textual) [Abstract]
Additional interest rate		1.75%

Income Taxes (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Current deferred tax assets
Property and equipment	$ 233	$ 113
Other	869
Net operating loss carryforwards		13
Total current deferred tax assets	1,102	126
Valuation allowance on current deferred tax assets	(202)
Total current deferred tax assets, net of valuation allowance	900	126
Current deferred tax liabilities
Unrealized gain on derivatives	(1,311)	(2,998)
Other		(152)
Total current deferred tax liabilities	(1,311)	(3,150)
Net current deferred tax liability	(411)	(3,024)
Non-current deferred tax assets
Net operating loss carryforwards	44,654	24,034
Alternative minimum tax carryforwards	6,660	6,660
Total non-current deferred tax assets	51,314	30,694
Valuation allowance on non-current deferred tax assets	(10,058)
Total non-current deferred tax assets, net of valuation allowance	41,256	30,694
Non-current deferred tax liabilities
Property and equipment	(36,363)	(27,070)
Unrealized gain on derivatives	(262)	(324)
Other	(4,220)	(1,706)
Total non-current deferred tax liabilities	40,845	29,100
Net non-current deferred tax assets	$ 411	$ 1,594

Income Taxes (Details 1) - USD ($) $ in Thousands	3 Months Ended							12 Months Ended
Income Taxes (Details 1) - USD ($) $ in Thousands	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current income tax (benefit) provision
State income tax									$ (46)
Federal alternative minimum tax										$ (1,411)
Net current income tax benefit									(46)	(1,411)
Deferred income tax provision (benefit)
Federal tax expense at statutory rate (34%)								$ (11,767)	(5,319)	3,365
Statutory depletion carryforward									231	(157)
State income tax								(819)	(435)
Change in state rate applied										275
Nondeductible expense								(122)	48	38
Permanent differences								1,018
Federal alternative minimum tax										1,411
Change in valuation allowance								10,260
Net deferred income tax (benefit) provision								(1,430)	(5,475)	4,932
Total income tax (benefit) provision	$ (188)	$ (593)	$ (3,713)	$ 3,064	$ 1,430	$ (46)	$ (6,906)	$ (1,430)	$ (5,521)	$ 3,521

Income Taxes (Details Textual) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended	9 Months Ended	12 Months Ended
Income Taxes (Details Textual) - USD ($) $ in Thousands	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2011	Jun. 30, 2012	Sep. 30, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Taxes (Textual) [Abstract]
Net capitalized costs less related deferred income taxes exceeded the full-cost ceiling	$ 17,300	$ 2,300	$ 21,300	$ 23,000	$ 21,300	$ 2,300	$ 17,300
Impairment charge of net capitalized costs				35,700	33,200	3,600	63,475	$ 35,673	$ 0
Deferred income tax credit				$ 12,700	$ 11,900	1,300	3,618,000	$ (24,375)	$ (9,156)
Increase in valuation allowance							7,900
Valuation allowance against net deferred tax assets	10,300	$ 2,400				$ 2,400	$ 10,300
Texas [Member]
Operating Loss Carryforwards [Line Items]
Open tax year							2012	2011	2010	2009
New Mexico [Member]
Operating Loss Carryforwards [Line Items]
Open tax year							2012	2011	2010	2009
Louisiana [Member]
Operating Loss Carryforwards [Line Items]
Open tax year							2012	2011	2010	2009
Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	123,300						$ 123,300
Operating loss carryforwards, expiration dates							December 31, 2027
Open tax year							2012	2011	2010	2009
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 30,300						$ 30,300
Operating loss carryforwards, expiration dates							beginning in 2027
State and Local Jurisdiction [Member] \| New Mexico [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, expiration dates							various dates beginning December 31, 2013

Stock-Based Compensation (Details) - $ / shares	12 Months Ended
Stock-Based Compensation (Details) - $ / shares	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan
Stock option pricing model			Binomial Lattice
Expected option life			5 years 4 months 28 days
Risk-free interest rate			2.58%
Volatility			46.17%
Dividend yield			0.00%
Estimated forfeiture rate			11.15%
Weighted average fair value of stock option awards granted during the year	$ 5.95		$ 3.02
2012 Incentive Plan [Member]
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan
Stock option pricing model	Black Scholes Merton
Expected option life	4 years 5 months 9 days
Risk-free interest rate	0.71%
Volatility	71.16%
Dividend yield	0.00%
Estimated forfeiture rate	5.46%
2003 Stock and Incentive Plan [Member]
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan
Stock option pricing model	Black Scholes Merton	Black Scholes Merton
Expected option life	10 months 21 days	1 year 15 days
Risk-free interest rate	0.25%	0.37%
Volatility	54.28%	61.41%
Dividend yield	0.00%	0.00%
Estimated forfeiture rate	0.70%	1.04%

Stock-Based Compensation (Details 1) - $ / shares	12 Months Ended
Stock-Based Compensation (Details 1) - $ / shares	Dec. 31, 2012	Dec. 31, 2011
Summarized information about stock options outstanding
Number of options, Options outstanding Beginning Balance	1,025,000
Number of options, Options granted	656,000	0
Number of options, Options exercised	(296,000)
Number of options, Options forfeited	(248,000)
Number of options, Options expired	(70,000)
Number of options, Options outstanding Ending Balance	1,067,000	1,025,000
Weighted average exercise price, Options outstanding Beginning Balance	$ 9.75
Weighted average exercise price, Options granted	10.79
Weighted average exercise price, Options exercised	9.00
Weighted average exercise price, Options forfeited	11.43
Weighted average exercise price, Options expired	9.95
Weighted average exercise price, Options outstanding Ending Balance	$ 10.19	$ 9.75

Stock-Based Compensation (Details 2) shares in Thousands	12 Months Ended
Stock-Based Compensation (Details 2) shares in Thousands	Dec. 31, 2012 $ / shares shares
Range One [Member]
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	$ 7.50
Range of exercise prices, Upper limit	$ 9.00
Shares outstanding \| shares	139
Weighted average remaining contractual price	6 years 4 months 2 days
Weighted average exercise price	$ 8.77
Shares exercisable \| shares	66
Weighted average exercise price	$ 8.75
Range Two [Member]
Summarized information about outstanding and exercisable stock option
Range of exercise prices, Lower limit	10.00
Range of exercise prices, Upper limit	$ 13.33
Shares outstanding \| shares	928
Weighted average remaining contractual price	2 years 4 months 13 days
Weighted average exercise price	$ 10.41
Shares exercisable \| shares	459
Weighted average exercise price	$ 10.32

Stock-Based Compensation (Details 3)	12 Months Ended
Stock-Based Compensation (Details 3)	Dec. 31, 2012 $ / shares shares
Summary of non-vested stock options
Shares Forfeited \| shares	(21,876)
Restricted Stock Service Based [Member]
Summary of non-vested stock options
Non-vested Shares, Beginning Balance \| shares	8,000
Shares Granted \| shares	207,000
Shares Vested \| shares	(18,000)
Shares Forfeited \| shares	(15,000)
Non-vested Shares, Ending Balance \| shares	182,000
Weighted average fair value, Beginning Balance \| $ / shares	$ 11.00
Weighted average fair value, Granted \| $ / shares	9.66
Weighted average fair value, Vested \| $ / shares	8.72
Weighted average fair value, Forfeited \| $ / shares	10.76
Weighted average fair value, Ending Balance \| $ / shares	$ 9.72
Restricted Stock Performance Based [Member]
Summary of non-vested stock options
Non-vested Shares, Beginning Balance \| shares
Shares Granted \| shares	117,000
Shares Forfeited \| shares	(7,000)
Non-vested Shares, Ending Balance \| shares	110,000
Weighted average fair value, Beginning Balance \| $ / shares
Weighted average fair value, Granted \| $ / shares	13.24
Weighted average fair value, Forfeited \| $ / shares	13.24
Weighted average fair value, Ending Balance \| $ / shares	$ 13.24
Restricted Stock Units Service Based [Member]
Summary of non-vested stock options
Non-vested Shares, Beginning Balance \| shares
Shares Granted \| shares	54,000
Shares Forfeited \| shares	(2,000)
Non-vested Shares, Ending Balance \| shares	52,000
Weighted average fair value, Beginning Balance \| $ / shares
Weighted average fair value, Granted \| $ / shares	10.04
Weighted average fair value, Forfeited \| $ / shares	11.02
Weighted average fair value, Ending Balance \| $ / shares	$ 10.00
Restricted Stock Units Performance Based [Member]
Summary of non-vested stock options
Non-vested Shares, Beginning Balance \| shares
Shares Granted \| shares	117,000
Shares Forfeited \| shares	(7,000)
Non-vested Shares, Ending Balance \| shares	110,000
Weighted average fair value, Beginning Balance \| $ / shares
Weighted average fair value, Granted \| $ / shares
Weighted average fair value, Vested \| $ / shares
Weighted average fair value, Forfeited \| $ / shares
Weighted average fair value, Ending Balance \| $ / shares

Stock Based Compensation (Details Textual)	12 Months Ended
Stock Based Compensation (Details Textual)	Dec. 31, 2012 USD ($) $ / shares shares	Dec. 31, 2011 USD ($) Employees $ / shares shares	Dec. 31, 2010 USD ($) Employees $ / shares shares	Dec. 31, 2009 Employees
Maximum shares of common stock provided \| shares	4,000,000
Vesting period of shares	4 years
Estimated fair value of options \| $ / shares		$ 12.00
Stock compensation expense attributable to stock based awards	$ 100,000	$ 2,400,000	$ 900,000
Weighted average remaining requisite service period of unvested stock awards	2 years 9 months 29 days
Restricted stock or unit expenses	$ 758,000
Fair value of option shares vested	$ 300,000	1,000,000	$ 2,400,000
Number of options, Options forfeited \| shares	(248,000)
Stock Based Compensation (Textual) [Abstract]
Additional general and administration expenses		1,100,000
Weighted average grant date fair value for options \| $ / shares	$ 5.95		$ 3.02
Aggregate intrinsic value	$ 0
Aggregate intrinsic value exercisable	$ 0
Quoted closing market price \| $ / shares	$ 8.20
Weighted average contractual term	1 year 22 days
Total intrinsic value of options exercised	$ 900,000	200,000	$ 2,200,000
Tax related benefits realized from the exercise of stock options	$ 0	$ 0	800,000
Options expired unexercised or were forfeited, share price \| $ / shares	$ 10.00
Number of options, Options granted \| shares	656,000	0
Granted option share purchase price, per share \| $ / shares	$ 10.79
Stock based current liability	$ 100,000	$ 2,900,000
Stock based long term liability	300,000	300,000
Liability based awards	0	100,000	400,000
Aggregate intrinsic value for the restricted stock and restricted stock units outstanding	3,700,000
Unrecognized compensation expense related to unvested stock options	2,300,000
Tax benefits recognized for stock based compensation	300,000	$ 900,000	300,000
Shares were repurchased to the termination of the Repurchase Program \| shares		0
Number of employees \| Employees		4
Aggregate amount of loan, secured	$ 200,000
Loans granted prior to termination of loan program		$ 0
Restricted stock [Member]
Vesting period of shares	3 years
Stock compensation expense attributable to stock based awards	$ 100,000	200,000	200,000
Weighted average remaining requisite service period of unvested stock awards	2 years 2 months 23 days
Defer issuance term	2 years
Vesting Period, beginning date	Mar. 19, 2012
Vesting period, end date	Apr. 15, 2015
Additional restricted stock vesting \| shares	116,841
Restricted stock or unit expenses	$ 700,000	44,000	100,000
Unrecognized compensation expense related to unvested restricted stock and restricted stock units	3,000,000
Fair value of restricted stock and restricted stock units vested	$ 44,000	44,000	46,330
Restricted stock grants \| shares	13,833
Number of options, Options forfeited \| shares	(408,000)
Stock options [Member]
Maximum vesting period	5 years
Maximum vesting period	10 years
Stock compensation expense attributable to stock based awards	$ (700,000)	$ 2,100,000	$ 600,000
Performance shares [Member]
Maximum shares of common stock provided \| shares	116,841
Maximum [Member]
Vesting period of shares	4 years
Maximum [Member] \| Restricted stock [Member]
Vesting period of shares	4 years
Minimum [Member]
Vesting period of shares	3 years
Minimum [Member] \| Restricted stock [Member]
Vesting period of shares	1 year
Class A [Member]
Maximum shares that may be issued pursuant to options or restricted stock grants \| shares	3,481,569
Estimated fair value of options \| $ / shares			$ 11.00
Company repurchased shares \| shares			117,505
Repurchased common stock, price per share \| $ / shares			$ 11.00
Number of Employees \| Employees			13	10

Employee Benefit Plans (Details) - USD ($)	1 Months Ended	12 Months Ended
Employee Benefit Plans (Details) - USD ($)	Jul. 31, 2003	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Employee Benefit Plan (Textual) [Abstract]
Employees annual compensation	3.00%
Safe Harbor match		$ 200,000	$ 200,000	$ 200,000
Discretionary matching contributions		300,000	$ 200,000	$ 200,000
No additional discretionary contributions		$ 0

Common Stock (Details)	1 Months Ended			12 Months Ended
Common Stock (Details)	Feb. 29, 2012 USD ($) shares	Jan. 31, 2011 USD ($) shares	May 31, 2010 USD ($) $ / shares shares	Dec. 31, 2012 USD ($) $ / shares shares	Dec. 31, 2011 USD ($) $ / shares shares	Dec. 31, 2010 USD ($) Shareholders $ / shares shares	Mar. 31, 2012	Mar. 02, 2012 shares	Feb. 07, 2012 shares	Feb. 02, 2012 $ / shares	Jan. 31, 2012 shares	Oct. 31, 2010 $ / shares
Common Stock (Textual) [Abstract]
Dividends declared \| $				$ 27,643	$ 274,853	$ 274,853
Company's common stock began trading, date				Feb. 01, 2012
Initial public offering closure date				Mar. 07, 2012			Feb. 07, 2012
Initial offering period				30 days
Issuance of common stock				12,209,167
Share issued to options				296,000
Proceeds from stock options exercised for additional shares \| $				$ 2,660,000	837,000	1,978,000
Options expired unexercised or were forfeited, share price \| $ / shares				$ 10.00
Proceeds from issuance of common stock \| $				$ 146,510,000	$ 592,000	$ 20,652,000
Common Stock (Additional Textual) [Abstract]
Repay in borrowings then outstanding under its Credit Agreement in full \| $	$ 123,000,000
Private offering and sale of additional shares of the company's class A common stock \| $ / shares				$ 10.00
Number of shareholders from whom the share purchased \| Shareholders						5
Purchased shares of common stock class A from five shareholders						1,000,000
Purchased shares of common stock class A from five shareholders per share price \| $ / shares						$ 9.00
Purchased shares of common stock class A from five shareholders value \| $						$ 9,000,000
Forfeitures of non-vested restricted stock awards				21,876
Treasury Stock [Member]
Common Stock (Textual) [Abstract]
Issuance of common stock						6,000
Class A [Member]
Common Stock (Textual) [Abstract]
Common stock, shares issued				56,778,718	42,916,668
Issuance of common stock						6,000
Company repurchased shares						117,505
Class A [Member] \| Common Stock [Member]
Common Stock (Textual) [Abstract]
Common stock, shares issued			11,000			1,900,000
Net Proceeds \| $						$ 20,500,000
Conversion of Class B common stock to Class A common stock, shares	1,030,700			(1,031,000)
Share issued to options	295,500			296,000	93,000	393,000
Proceeds from stock options exercised for additional shares \| $	$ 2,700,000
Options expired unexercised or were forfeited, share price \| $ / shares			$ 9.00									$ 11.00
Proceeds from issuance of common stock \| $		$ 600,000	$ 99,000
Issuance of additional shares of common stock		53,772
Common Stock (Additional Textual) [Abstract]
Private offering and sale of additional shares of the company's class A common stock \| $ / shares			$ 9.00									$ 11.00
Class A [Member] \| Treasury Stock [Member]
Common Stock (Textual) [Abstract]
Purchased shares of common stock class A						1,100,000
Class A [Member] \| Maximum [Member] \| Treasury Stock [Member]
Common Stock (Textual) [Abstract]
Options expired unexercised or were forfeited, share price \| $ / shares						$ 9.00
Purchased shares of common stock class A per share price \| $ / shares						11.00
Common Stock (Additional Textual) [Abstract]
Private offering and sale of additional shares of the company's class A common stock \| $ / shares						9.00
Class A [Member] \| Minimum [Member] \| Treasury Stock [Member]
Common Stock (Textual) [Abstract]
Options expired unexercised or were forfeited, share price \| $ / shares						7.50
Purchased shares of common stock class A per share price \| $ / shares						9.00
Common Stock (Additional Textual) [Abstract]
Private offering and sale of additional shares of the company's class A common stock \| $ / shares						$ 7.50
Class B [Member]
Common Stock (Textual) [Abstract]
Cumulative annual dividends per share rate \| $ / shares					$ 0.26
Common stock, shares issued				0	1,030,700
Class B [Member] \| Common Stock [Member]
Common Stock (Textual) [Abstract]
Conversion of Class B common stock to Class A common stock, shares				1,031,000
Class B [Member] \| Maximum [Member]
Common Stock (Textual) [Abstract]
Cumulative annual dividends per share rate \| $ / shares				$ 0.66
Class B [Member] \| Minimum [Member]
Common Stock (Textual) [Abstract]
Cumulative annual dividends per share rate \| $ / shares				$ 0.26
Matador Resources Company [Member]
Common Stock (Textual) [Abstract]
Common stock, shares issued									11,666,667
Matador Resources Company [Member] \| Over-allotments [Member]
Common Stock (Textual) [Abstract]
Option to purchase additional shares from company								542,500
Initial Public Offering [Member]
Common Stock (Textual) [Abstract]
Initial offering price per share \| $ / shares										$ 12.00
Initial public offering of its common stock description				On August 12, 2011, the Company filed a Form S-1 Registration Statement under the Securities Act of 1933 to commence the initial public offering of its common stock (the “Initial Public Offering”). The Company’s Registration Statement (File 333-176263), as amended, was declared effective by the SEC on February 1, 2012. The underwriters for the Company’s Initial Public Offering were RBC Capital Markets, LLC; Citigroup Global Markets, Inc.; Jefferies & Company, Inc.; Howard Weil Incorporated; Stifel, Nicolaus & Company, Incorporated; Simmons & Company International; Stephens Inc.; and Comerica Securities, Inc.
Common stock, shares issued											13,333,334
Issuance of common stock	11,666,667
Initial Public Offering [Member] \| Over-allotments [Member]
Common Stock (Textual) [Abstract]
Initial offering price per share \| $ / shares				$ 12.00
Option to purchase additional shares								1,550,000
Net Proceeds \| $				$ 133,600,000
Selling shareholders [Member]
Common Stock (Textual) [Abstract]
Initial offering price per share \| $ / shares				$ 12.00
Common stock, shares issued											1,550,000
Additional issuance of common stock									2,000,000
Company offering shares									700,000
Shareholders offering for sales									1,300,000
Selling shareholders [Member] \| Over-allotments [Member]
Common Stock (Textual) [Abstract]
Option to purchase additional shares from selling shareholders								1,007,500

Derivative Financial Instruments (Details) $ in Thousands	12 Months Ended
Derivative Financial Instruments (Details) $ in Thousands	Dec. 31, 2012 USD ($) bbl / mo MMBTU / mo $ / MMBTU $ / bbl	Dec. 31, 2011 USD ($)
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability) \| $	$ 4,479	$ 9,282
Open costless collar contracts [Member] \| Oil contract 1 [Member]
Summary of contracts for oil and natural gas
Calculation Period	07/01/2013 - 12/31/2013
Notional Quantity \| bbl / mo	20,000
Price Floor	90.00
Price Ceiling	102.80
Open costless collar contracts [Member] \| Oil contract 2 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	15,000
Price Floor	85.00
Price Ceiling	97.50
Open costless collar contracts [Member] \| Oil contract 3 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	30,000
Price Floor	85.00
Price Ceiling	98.00
Open costless collar contracts [Member] \| Oil contract 4 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	15,000
Price Floor	87.00
Price Ceiling	97.00
Open costless collar contracts [Member] \| Oil contract 5 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	20,000
Price Floor	90.00
Price Ceiling	97.00
Open costless collar contracts [Member] \| Oil contract 6 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	15,000
Price Floor	90.00
Price Ceiling	97.90
Open costless collar contracts [Member] \| Oil contract 7 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	15,000
Price Floor	90.00
Price Ceiling	98.00
Open costless collar contracts [Member] \| Natural Gas contract 1 [Member]
Summary of contracts for oil and natural gas
Calculation Period	04/01/2013 - 12/31/2013
Notional Quantity \| MMBTU / mo	100,000
Price Floor \| $ / MMBTU	3.25
Price Ceiling \| $ / MMBTU	4.41
Open costless collar contracts [Member] \| Natural Gas contract 2 [Member]
Summary of contracts for oil and natural gas
Calculation Period	04/01/2013 - 12/31/2013
Notional Quantity \| MMBTU / mo	100,000
Price Floor \| $ / MMBTU	3.25
Price Ceiling \| $ / MMBTU	4.44
Open costless collar contracts [Member] \| Natural Gas contract 3 [Member]
Summary of contracts for oil and natural gas
Calculation Period	04/01/2013 - 12/31/2013
Notional Quantity \| MMBTU / mo	100,000
Price Floor \| $ / MMBTU	3.50
Price Ceiling \| $ / MMBTU	4.37
Open costless collar contracts [Member] \| Natural Gas contract 4 [Member]
Summary of contracts for oil and natural gas
Calculation Period	07/01/2013 - 12/31/2013
Notional Quantity \| MMBTU / mo	150,000
Price Floor \| $ / MMBTU	3.00
Price Ceiling \| $ / MMBTU	4.24
Open costless collar contracts [Member] \| Natural Gas contract 5 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| MMBTU / mo	100,000
Price Floor \| $ / MMBTU	3.00
Price Ceiling \| $ / MMBTU	5.15
Open costless collar contracts [Member] \| Natural Gas contract 6 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| MMBTU / mo	150,000
Price Floor \| $ / MMBTU	3.25
Price Ceiling \| $ / MMBTU	5.21
Open costless collar contracts [Member] \| Oil [Member]
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability) \| $	$ 3,789
Open costless collar contracts [Member] \| Oil [Member] \| Oil contract 1 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 - 03-31-2013
Notional Quantity \| bbl / mo	20,000
Price Floor	90.00
Price Ceiling	110.00
Fair Value of Asset (Liability) \| $	$ 122
Open costless collar contracts [Member] \| Oil [Member] \| Oil contract 2 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| bbl / mo	20,000
Price Floor	85.00
Price Ceiling	102.25
Fair Value of Asset (Liability) \| $	$ 96
Open costless collar contracts [Member] \| Oil [Member] \| Oil contract 3 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| bbl / mo	20,000
Price Floor	90.00
Price Ceiling	115.00
Fair Value of Asset (Liability) \| $	$ 980
Open costless collar contracts [Member] \| Oil [Member] \| Oil contract 4 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 -12-31-2013
Notional Quantity \| bbl / mo	20,000
Price Floor	85.00
Price Ceiling	110.40
Fair Value of Asset (Liability) \| $	$ 471
Open costless collar contracts [Member] \| Oil [Member] \| Oil contract 5 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| bbl / mo	20,000
Price Floor	85.00
Price Ceiling	108.80
Fair Value of Asset (Liability) \| $	$ 418
Open costless collar contracts [Member] \| Oil [Member] \| Oil contract 6 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 -06-30-2014
Notional Quantity \| bbl / mo	8,000
Price Floor	90.00
Price Ceiling	114.00
Fair Value of Asset (Liability) \| $	$ 666
Open costless collar contracts [Member] \| Oil [Member] \| Oil contract 7 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 - 06-30-2014
Notional Quantity \| bbl / mo	12,000
Price Floor	90.00
Price Ceiling	115.50
Fair Value of Asset (Liability) \| $	$ 1,036
Open costless collar contracts [Member] \| Natural Gas [Member]
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability) \| $	$ 1,135
Open costless collar contracts [Member] \| Natural Gas [Member] \| Natural Gas contract 1 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 - 07-31-2013
Notional Quantity \| MMBTU / mo	150,000
Price Floor \| $ / MMBTU	4.50
Price Ceiling \| $ / MMBTU	5.75
Fair Value of Asset (Liability) \| $	$ 1,154
Open costless collar contracts [Member] \| Natural Gas [Member] \| Natural Gas contract 2 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| MMBTU / mo	100,000
Price Floor \| $ / MMBTU	3.00
Price Ceiling \| $ / MMBTU	3.83
Fair Value of Asset (Liability) \| $	$ (146)
Open costless collar contracts [Member] \| Natural Gas [Member] \| Natural Gas contract 3 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| MMBTU / mo	100,000
Price Floor \| $ / MMBTU	3.00
Price Ceiling \| $ / MMBTU	4.95
Fair Value of Asset (Liability) \| $	$ 40
Open costless collar contracts [Member] \| Natural Gas [Member] \| Natural Gas contract 4 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| MMBTU / mo	100,000
Price Floor \| $ / MMBTU	3.00
Price Ceiling \| $ / MMBTU	4.96
Fair Value of Asset (Liability) \| $	$ 41
Open costless collar contracts [Member] \| Natural Gas [Member] \| Natural Gas contract 5 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2014 - 12-31-2014
Notional Quantity \| MMBTU / mo	100,000
Price Floor \| $ / MMBTU	3.25
Price Ceiling \| $ / MMBTU	5.37
Fair Value of Asset (Liability) \| $	$ 19
Open costless collar contracts [Member] \| Natural Gas [Member] \| Natural Gas contract 6 [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2014 - 12-31-2014
Notional Quantity \| MMBTU / mo	100,000
Price Floor \| $ / MMBTU	3.25
Price Ceiling \| $ / MMBTU	5.42
Fair Value of Asset (Liability) \| $	$ 27
Open Swap Contracts [Member] \| Oil [Member]
Summary of contracts for oil and natural gas
Fair Value of Asset (Liability) \| $	$ (670)
Open Swap Contracts [Member] \| Oil [Member] \| Open Swap Contracts for Oil One [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| bbl / mo	10,000
Price Floor	90.20
Fair Value of Asset (Liability) \| $	$ (362)
Open Swap Contracts [Member] \| Oil [Member] \| Open Swap Contracts for Oil Two [Member]
Summary of contracts for oil and natural gas
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| bbl / mo	10,000
Price Floor	90.65
Fair Value of Asset (Liability) \| $	$ (308)

Derivative Financial Instruments (Details 1) $ in Thousands	12 Months Ended
Derivative Financial Instruments (Details 1) $ in Thousands	Dec. 31, 2012 USD ($) gal / mo $ / Gallons	Dec. 31, 2011 USD ($)
Open Swap Contracts For Natural Gas Liquid
Fair Value of Asset (Liability)	$ 4,479	$ 9,282
NGL's [Member] \| Open Swap Contract [Member]
Open Swap Contracts For Natural Gas Liquid
Fair Value of Asset (Liability)	$ 225
NGL's [Member] \| Open Swap Contract [Member] \| Purity Ethane contract 1 [Member]
Open Swap Contracts For Natural Gas Liquid
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| gal / mo	110,000
Fixed Price \| $ / Gallons	0.335
Fair Value of Asset (Liability)	$ 106
NGL's [Member] \| Open Swap Contract [Member] \| Purity Ethane contract 2 [Member]
Open Swap Contracts For Natural Gas Liquid
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| gal / mo	110,000
Fixed Price \| $ / Gallons	0.355
Fair Value of Asset (Liability)	$ 133
NGL's [Member] \| Open Swap Contract [Member] \| Propane contract 1 [Member]
Open Swap Contracts For Natural Gas Liquid
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| gal / mo	53,000
Fixed Price \| $ / Gallons	0.953
Fair Value of Asset (Liability)	$ 13
NGL's [Member] \| Open Swap Contract [Member] \| Propane contract 2 [Member]
Open Swap Contracts For Natural Gas Liquid
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| gal / mo	53,000
Fixed Price \| $ / Gallons	1.001
Fair Value of Asset (Liability)	$ 43
NGL's [Member] \| Open Swap Contract [Member] \| Normal Butane contract 1 [Member]
Open Swap Contracts For Natural Gas Liquid
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| gal / mo	14,700
Fixed Price \| $ / Gallons	1.455
Fair Value of Asset (Liability)	$ (29)
NGL's [Member] \| Open Swap Contract [Member] \| Normal Butane contract 2 [Member]
Open Swap Contracts For Natural Gas Liquid
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| gal / mo	14,700
Fixed Price \| $ / Gallons	1.560
Fair Value of Asset (Liability)	$ (10)
NGL's [Member] \| Open Swap Contract [Member] \| Isobutane contract 1 [Member]
Open Swap Contracts For Natural Gas Liquid
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| gal / mo	7,000
Fixed Price \| $ / Gallons	1.515
Fair Value of Asset (Liability)	$ (18)
NGL's [Member] \| Open Swap Contract [Member] \| Isobutane contract 2 [Member]
Open Swap Contracts For Natural Gas Liquid
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| gal / mo	7,000
Fixed Price \| $ / Gallons	1.625
Fair Value of Asset (Liability)	$ (9)
NGL's [Member] \| Open Swap Contract [Member] \| Natural Gasoline contract 1 [Member]
Open Swap Contracts For Natural Gas Liquid
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| gal / mo	12,000
Fixed Price \| $ / Gallons	2.025
Fair Value of Asset (Liability)	$ (8)
NGL's [Member] \| Open Swap Contract [Member] \| Natural Gasoline contract 2 [Member]
Open Swap Contracts For Natural Gas Liquid
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| gal / mo	12,000
Fixed Price \| $ / Gallons	2.085
Fair Value of Asset (Liability)	$ 1
NGL's [Member] \| Open Swap Contract [Member] \| Natural Gasoline contract 3 [Member]
Open Swap Contracts For Natural Gas Liquid
Calculation Period	01-01-2013 - 12-31-2013
Notional Quantity \| gal / mo	12,000
Fixed Price \| $ / Gallons	2.102
Fair Value of Asset (Liability)	$ 3

Derivative Financial Instruments (Details 2) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated balance sheets
Current assets: Derivative instruments	$ 4,378	$ 8,989
Other assets: Derivative instruments	771	847
Current liabilities: Derivative instruments	(670)	(171)
Long-term liabilities: Derivative instruments		(383)
Total Fair Value	4,479	9,282
Oil [Member] \| Current Assets [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated balance sheets
Current assets: Derivative instruments	3,064
Oil [Member] \| Other assets [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated balance sheets
Other assets: Derivative instruments	725
Oil [Member] \| Current liabilities [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated balance sheets
Current liabilities: Derivative instruments	(670)	(171)
Oil [Member] \| Long-term liabilities [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated balance sheets
Long-term liabilities: Derivative instruments		(383)
Natural Gas [Member] \| Current Assets [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated balance sheets
Current assets: Derivative instruments	1,089	8,989
Natural Gas [Member] \| Other assets [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated balance sheets
Other assets: Derivative instruments	46	$ 847
NGL's [Member] \| Current Assets [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated balance sheets
Current assets: Derivative instruments	$ 225

Derivative Financial Instruments (Details 3) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain on derivatives	$ 2,813	$ 3,371	$ 4,713	$ 3,063	$ 2,869	$ 1,435	$ 952	$ 1,850	$ 13,960	$ 7,106	$ 5,299
Unrealized gain (loss) on derivatives	$ (3,653)	$ (12,993)	$ 15,114	$ (3,270)	$ 3,604	$ 2,870	$ 332	$ (1,668)	(4,802)	5,138	3,139
Total									9,158	12,244	8,438
Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain on derivatives									13,960	7,106	5,299
Unrealized gain (loss) on derivatives									(4,802)	5,138	3,139
Oil [Member] \| Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain on derivatives									2,047
Unrealized gain (loss) on derivatives									3,673	(544)
Natural Gas [Member] \| Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain on derivatives									11,892	7,106	5,299
Unrealized gain (loss) on derivatives									(8,700)	$ 5,692	$ 3,139
NGL's [Member] \| Revenues [Member]
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations
Realized gain on derivatives									21
Unrealized gain (loss) on derivatives									$ 225

Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Assets (Liabilities)
Certificates of deposit	$ 230	$ 1,335
Oil, natural gas and NGL derivatives	4,479	9,282
Fair value on a recurring basis [Member]
Assets (Liabilities)
Certificates of deposit	230	1,335
Oil, natural gas and NGL derivatives		9,836
Total	4,709	10,617
Fair value on a recurring basis [Member] \| Oil [Member]
Assets (Liabilities)
Oil, natural gas and NGL derivatives	(670)
Fair value on a recurring basis [Member] \| Natural Gas [Member]
Assets (Liabilities)
Oil, natural gas and NGL derivatives	5,149
Fair value on a recurring basis [Member] \| Level 1 [Member]
Assets (Liabilities)
Certificates of deposit
Total
Fair value on a recurring basis [Member] \| Level 1 [Member] \| Oil [Member]
Assets (Liabilities)
Oil, natural gas and NGL derivatives
Fair value on a recurring basis [Member] \| Level 1 [Member] \| Natural Gas [Member]
Assets (Liabilities)
Oil, natural gas and NGL derivatives
Fair value on a recurring basis [Member] \| Level 2 [Member]
Assets (Liabilities)
Certificates of deposit	230	1,335
Total	4,709	10,617
Fair value on a recurring basis [Member] \| Level 2 [Member] \| Oil [Member]
Assets (Liabilities)
Oil, natural gas and NGL derivatives	(670)	(554)
Fair value on a recurring basis [Member] \| Level 2 [Member] \| Natural Gas [Member]
Assets (Liabilities)
Oil, natural gas and NGL derivatives	5,149	9,836
Fair value on a recurring basis [Member] \| Level 3 [Member]
Assets (Liabilities)
Certificates of deposit
Total
Fair value on a recurring basis [Member] \| Level 3 [Member] \| Oil [Member]
Assets (Liabilities)
Oil, natural gas and NGL derivatives
Fair value on a recurring basis [Member] \| Level 3 [Member] \| Natural Gas [Member]
Assets (Liabilities)
Oil, natural gas and NGL derivatives

Fair Value Measurements (Details 1) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Assets (Liabilities)
Lease and well equipment inventory	$ 877	$ 1,343
Fair value on a non-recurring basis [Member]
Assets (Liabilities)
Lease and well equipment inventory	34	1,343
Total	(1,209)	1,156
Fair value on a non-recurring basis [Member] \| Asset retirement obligations [Member]
Assets (Liabilities)
Asset retirement obligations	(1,243)	(187)
Fair value on a non-recurring basis [Member] \| Level 1 [Member]
Assets (Liabilities)
Lease and well equipment inventory
Total
Fair value on a non-recurring basis [Member] \| Level 1 [Member] \| Asset retirement obligations [Member]
Assets (Liabilities)
Asset retirement obligations
Fair value on a non-recurring basis [Member] \| Level 2 [Member]
Assets (Liabilities)
Lease and well equipment inventory
Total
Fair value on a non-recurring basis [Member] \| Level 2 [Member] \| Asset retirement obligations [Member]
Assets (Liabilities)
Asset retirement obligations
Fair value on a non-recurring basis [Member] \| Level 3 [Member]
Assets (Liabilities)
Lease and well equipment inventory	34	1,343
Total	(1,209)	1,156
Fair value on a non-recurring basis [Member] \| Level 3 [Member] \| Asset retirement obligations [Member]
Assets (Liabilities)
Asset retirement obligations	$ (1,243)	$ (187)

Fair Value Measurements (Details Textual) - USD ($)	12 Months Ended
Fair Value Measurements (Details Textual) - USD ($)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fair Value Measurements (Additional Textual) [Abstract]
Additions to asset retirement obligations	$ 1,200,000	$ 200,000
Drilling rig [Member]
Fair Value Measurements (Textual) [Abstract]
Impairment charge for equipments held in inventory	425,000	17,500	$ 50,000
Pipe and other equipment [Member]
Fair Value Measurements (Textual) [Abstract]
Impairment charge for equipments held in inventory	$ 60,464	$ 22,276	$ 0

- Definition

Charge to cost of goods sold that represents the reduction of the carrying amount of inventory, generally attributable to obsolescence or market conditions.

+ References + Details

Commitments and Contingencies (Details) $ in Thousands	Dec. 31, 2012 USD ($)
Schedule of future minimum lease payments required under the office lease agreement
2013	$ 575
2014	575
2015	589
2016	604
2017	618
Thereafter	2,995
Total	$ 5,956

Commitments and Contingencies (Details 1) $ in Thousands	Dec. 31, 2012 USD ($)
Summary of aggregate undiscounted minimum commitments
2013	$ 5,985
2014	4,731
2015	2,992
2016	1,800
2017	1,195
Total	$ 16,703

Commitments and Contingencies (Details Textual) $ in Millions	12 Months Ended
	Dec. 31, 2012 USD ($) ft² a Contract	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Aug. 01, 2012 a	May 15, 2008
Commitments and Contingencies (Additional Textual) [Abstract]
Lease commencement date	Sep. 25, 2003
Lease expiration date	Jun. 30, 2011
Lease period		Jun. 30, 2022
Effective base rent per square foot per year \| ft²	19.75
Rent expense, including fees for operating expenses and consumption of electricity	$ 0.6	$ 0.5	$ 0.4
Contract for the first rig was renegotiated period	March of 2013
Effective date of which company entered into agreement	Sep. 01, 2012
Natural gas processing and transportation agreement	5 years
Number of drilling rig contracts \| Contract	2
Maximum termination outstanding obligations of contracts	$ 5.1
Minimum delivery commitment to avoid paying gas deficiency fee	80.00%
Percentage of minimum delivery commitment to anticipated production	80.00%
Issue on the deep rights below the Cotton Valley formation \| a	1,805
Right to participate in working capital	25.00%
Company's total revenue and overriding royalty interests on the acreage range Minimum	2.00%
Company's total revenue and overriding royalty interests on the acreage range Maximum	23.00%
Loss contingency, lawsuit filing date	May 15, 2008
Royalty owner undivided interest in mineral					0.167
Acres reformed by court \| a				169
Rights on remaining acres \| a				1,636
Contract One [Member]
Commitments and Contingencies (Textual) [Abstract]
Term of new contract drilling rig	365 days
Contract Two [Member]
Commitments and Contingencies (Textual) [Abstract]
Term of new contract drilling rig	270 days
Maximum [Member]
Commitments and Contingencies (Textual) [Abstract]
Potential loss to the company	$ 6.0
Minimum [Member]
Commitments and Contingencies (Textual) [Abstract]
Potential loss to the company	0.0
Lease agreements [Member]
Commitments and Contingencies (Textual) [Abstract]
Transportation and processing fees under the agreement	$ 0.3
Lease agreements [Member] \| Area of Land [Member]
Commitments and Contingencies (Textual) [Abstract]
Office space of headquarters \| ft²	28,743

Major Customers (Details) - Purchasers	12 Months Ended
Major Customers (Details) - Purchasers	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Major Customers (Textual) [Abstract]
Number of purchasers	3
Revenue [Member]
Major Customers (Textual) [Abstract]
Total percentage of revenue and accounts receivable	74.00%	60.00%	70.00%
Accounts Receivable [Member]
Major Customers (Textual) [Abstract]
Total percentage of revenue and accounts receivable	67.00%	52.00%	56.00%

Supplemental Disclosures (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Summary of current accrued liabilities
Other	$ 2,410	$ 2,852
Total accrued liabilities	59,179	25,439
Accrued evaluated and unproved and unevaluated property costs [Member]
Summary of current accrued liabilities
Total accrued liabilities	45,592	18,185
Accrued support equipment and facilities costs [Member]
Summary of current accrued liabilities
Total accrued liabilities	1,382	216
Accrued cost to issue equity [Member]
Summary of current accrued liabilities
Total accrued liabilities		332
Accrued stock-based compensation [Member]
Summary of current accrued liabilities
Total accrued liabilities	65	2,860
Accrued lease operating expenses [Member]
Summary of current accrued liabilities
Total accrued liabilities	5,218	575
Accrued interest on borrowings under Credit Agreement [Member]
Summary of current accrued liabilities
Total accrued liabilities	255	34
Accrued asset retirement obligations [Member]
Summary of current accrued liabilities
Total accrued liabilities	660	334
Accrued partners' share of joint interest charges [Member]
Summary of current accrued liabilities
Total accrued liabilities	$ 3,597	$ 51

Supplemental Disclosures (Details 1) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Supplemental disclosures of cash flow information
Cash paid (refunded) for income taxes			$ (2,156)
Cash paid for interest expense, net of amounts capitalized	$ 780	$ 634
Asset retirement obligations related to mineral properties	1,195	488	862
Asset retirement obligations related to support equipment and facilities	49	12	126
Increase in liabilities for oil and natural gas properties capital expenditures	24,847	1,864	15,531
Increase in liabilities for support equipment and facilities	1,112	175	40
Issuance of treasury stock for Board and advisor services			47
Issuance of restricted stock units for Board and advisor services	73
Issuance of common stock for Board and advisor services	71	230	198
(Decrease) increase in liabilities for accrued cost to issue equity	(332)	(27)	359
Stock based compensation expense recognized as liability	(1,092)	2,102	164
Transfer of inventory to oil and natural gas properties	$ 69	$ 96	$ 353

Transactions With Related Parties (Details)	1 Months Ended	12 Months Ended
Transactions With Related Parties (Details)	May 31, 2010	Dec. 31, 2012
Transactions With Related Parties (Textual) [Abstract]
Royalty interest in the lease	2.50%
Working interest earned	10.00%
Working capital of the partners		50.00%

Supplemental Oil and Natural Gas Disclosures (Unaudited) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property acquisition costs
Proved
Unproved and unevaluated	28,672	41,497	100,730
Exploration costs	115,084	108,662	60,719
Development costs	190,891	12,511	14,348
Total costs incurred	$ 334,647	$ 162,670	$ 175,797

- Definition

Costs incurred, including capitalized costs and costs charged to expense, associated with the acquisition of oil and gas properties that have proved reserves.

+ References + Details

- Definition

Costs incurred, including capitalized costs and costs charged to expense, associated with the acquisition of oil and gas properties that have unproved reserves.

+ References + Details

Supplemental Oil and Natural Gas Disclosures (Unaudited) (Details 1) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2012 USD ($)	Sep. 30, 2012 USD ($)	Jun. 30, 2012 USD ($)	Mar. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Sep. 30, 2011 USD ($)	Jun. 30, 2011 USD ($)	Mar. 31, 2011 USD ($)	Dec. 31, 2012 USD ($) $ / Boe	Dec. 31, 2011 USD ($) $ / Boe	Dec. 31, 2010 USD ($) $ / Boe
Summary of results of operations from oil and gas producing activities, excluding corporate overhead and interest costs
Oil and natural gas revenues	$ 52,748	$ 38,008	$ 36,078	$ 29,164	$ 14,991	$ 17,447	$ 20,864	$ 13,698	$ 155,998	$ 67,000	$ 34,042
Production taxes and marketing expenses									11,672	6,278	1,982
Lease operating expenses									28,184	7,244	5,284
Depletion, depreciation and amortization									79,592	31,619	15,423
Accretion of asset retirement obligations									1,195	488	862
Full-cost ceiling impairment									63,475	35,673	0
Net operating (loss) income									(27,181)	(14,023)	11,198
Income tax (benefit) provision									(9,595)	(5,019)	3,983
Results of oil and natural gas operations									$ (17,586)	$ (9,004)	$ 7,215
Depletion, depreciation and amortization per BOE \| $ / Boe									24.16	12.29	10.76

Supplemental Oil and Natural Gas Disclosures (Unaudited) (Details 2)	12 Months Ended
	Dec. 31, 2012 MBbls MMcf MBoe	Dec. 31, 2011 MBbls MMcf MBoe	Dec. 31, 2010 MBbls MMcf MBoe	Dec. 31, 2009 MBbls MMcf MBoe
Summary of Estimated reserves
Total \| MBoe	32,196	21,387	10,758
Revisions of prior estimates \| MBoe	(18,010)	(57)	211
Extensions and discoveries \| MBoe	12,927	13,439	11,851
Production \| MBoe	(3,294)	(2,573)	(1,433)
Total \| MBoe	23,819	32,196	21,387
Proved Developed Reserves \| MBoe	13,771	10,843	7,342	4,331
Proved oil and natural gas reserves \| MBoe	10,048	21,353	14,045	6,427
Oil [Member]
Summary of Estimated reserves
Total \| MBbls	3,794	152	103
Revisions of prior estimates \| MBbls	(782)	51	66
Extensions and discoveries \| MBbls	8,687	3,745	16
Production \| MBbls	(1,214)	(154)	(33)
Total \| MBbls	10,485	3,794	152
Proved Developed Reserves \| MBbls	4,764	1,419	152	103
Proved oil and natural gas reserves \| MBbls	5,721	2,375
Natural Gas [Member]
Summary of Estimated reserves
Total \| MMcf	170,418	127,412	63,929
Revisions of prior estimates \| MMcf	(103,375)	(646)	874
Extensions and discoveries \| MMcf	25,443	58,164	71,009
Production \| MMcf	(12,479)	(14,512)	(8,400)
Total \| MMcf	80,007	170,418	127,412
Proved Developed Reserves \| MMcf	54,040	56,547	43,143	25,369
Proved oil and natural gas reserves \| MMcf	25,967	113,871	84,269	38,560

Supplemental Oil and Natural Gas Disclosures (Unaudited) (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Future cash inflows	$ 1,273,882	$ 924,796	$ 470,386
Future production costs	(325,413)	(194,538)	(107,183)
Future development costs	(244,283)	(235,469)	(107,277)
Future income tax expense	(77,821)	(83,840)	(35,352)
Future net cash flows	626,365	410,949	220,574
10% annual discount for estimated timing of cash flows	(231,729)	(195,476)	(109,497)
Standardized measure of discounted future net cash flows	$ 394,636	$ 215,473	$ 111,077	$ 65,061

Supplemental Oil and Natural Gas Disclosures (Unaudited) (Details 4) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2011	Jun. 30, 2012	Sep. 30, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Summarizes the changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Balance, beginning of period	$ 111,077	$ 215,473	$ 215,473	$ 215,473	$ 111,077	$ 65,061
Net change in sales and transfer prices and in production (lifting) costs related to future production				(60,892)	53,903	7,632
Changes in estimated future development costs				16,937	(64,958)	(36,821)
Sales and transfers of oil and natural gas produced during the period				(116,142)	(53,478)	(26,776)
Net change due to extensions and discoveries				358,159	182,282	94,265
Net change due to revisions in estimates of reserves quantities				(56,850)	(653)	1,676
Previously estimated development costs incurred during the period				9,750	1,023	7,125
Accretion of Discount				24,873	11,987	7,036
Other				(290)	(1,335)	1,035
Net change in income taxes	$ 12,700	$ 11,900	$ 1,300	3,618,000	(24,375)	(9,156)
Standardized measure of discounted future net cash flows				$ 394,636	$ 215,473	$ 111,077

Supplemental Oil and Natural Gas Disclosures (Unaudited) (Details Textual) $ in Thousands	12 Months Ended
	Dec. 31, 2012 USD ($) MBoe $ / MMBTU	Dec. 31, 2012 USD ($) MBoe $ / bbl	Dec. 31, 2012 USD ($) MBoe	Dec. 31, 2012 USD ($) MBoe	Dec. 31, 2012 USD ($) MBoe Mcf	Dec. 31, 2012 USD ($) MBoe	Dec. 31, 2011 USD ($) MBoe $ / MMBTU	Dec. 31, 2011 USD ($) MBoe $ / bbl	Dec. 31, 2011 USD ($) MBoe	Dec. 31, 2011 USD ($) MBoe	Dec. 31, 2010 USD ($) MBoe $ / MMBTU	Dec. 31, 2010 USD ($) MBoe $ / bbl	Dec. 31, 2010 USD ($) MBoe	Dec. 31, 2010 USD ($) MBoe	Dec. 31, 2009 MBoe
Supplemental Oil and Natural Gas Disclosures (Textual) [Abstract]
Asset retirement obligations \| $	$ 5,109	$ 5,109	$ 5,109	$ 5,109	$ 5,109	$ 5,109	$ 3,935	$ 3,935	$ 3,935	$ 3,935	$ 1,000	$ 1,000	$ 1,000	$ 1,000
Capitalized internal cost \| $	$ 2,600	$ 2,600	$ 2,600	$ 2,600	$ 2,600	2,600	$ 2,000	$ 2,000	$ 2,000	2,000	$ 1,600	$ 1,600	$ 1,600	1,600
Capitalized interest expense \| $						1,600				1,300				0
Interest expense \| $						$ (1,002)				$ (683)				$ (3)
Oil and natural gas prices period															12 months
Average oil and natural gas prices	2.757	91.21					4.118	92.71			4.376	75.96
Conversion of oil to gas equivalent \| Mcf					6
Proved oil and natural gas reserves	23,819	23,819	23,819	23,819	23,819	23,819	32,196	32,196	32,196	32,196	21,387	21,387	21,387	21,387	10,758
Proved oil and natural gas reserves	10,048	10,048	10,048	10,048	10,048	10,048	21,353	21,353	21,353	21,353	14,045	14,045	14,045	14,045	6,427
Increase (Decrease) in proved oil and natural gas reserves			(5,083)						13,382				12,062
Net decrease of proved oil and natural gas reserves			8,378
Proved oil and natural gas reserves produced			3,294						2,573				1,433
Net gain									10,809				10,629
Increase in proved oil and gas reserves as a result of extensions and discoveries			12,927						13,439				11,851
Increase (Decrease) in oil and natural gas reserves, revisions of previous estimates			(18,010)						(57)				211
Proved developed oil and natural gas reserves	13,771	13,771	13,771	13,771	13,771	13,771	10,843	10,843	10,843	10,843	7,342	7,342	7,342	7,342	4,331
Proved Reserves (Natural gas)	56.00%	56.00%	56.00%	56.00%	56.00%	56.00%	88.00%	88.00%	88.00%	88.00%	99.00%	99.00%	99.00%	99.00%
Proved Reserves (Oil)	44.00%	44.00%	44.00%	44.00%	44.00%	44.00%	12.00%	12.00%	12.00%	12.00%	1.00%	1.00%	1.00%	1.00%
Annual discount rate for discounted future net cash flows				10.00%

Subsequent Events (Details)	12 Months Ended
Subsequent Events (Details)	Dec. 31, 2012 bbl / mo MMBTU / mo gal / mo $ / Gallons $ / MMBTU $ / bbl
Oil contract 1 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	07/01/2013 - 12/31/2013
Notional Quantity \| bbl / mo	20,000
Price Floor \| $ / bbl	90.00
Price Ceiling \| $ / bbl	102.80
Oil contract 2 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	15,000
Price Floor \| $ / bbl	85.00
Price Ceiling \| $ / bbl	97.50
Oil contract 3 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	30,000
Price Floor \| $ / bbl	85.00
Price Ceiling \| $ / bbl	98.00
Oil contract 4 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	15,000
Price Floor \| $ / bbl	87.00
Price Ceiling \| $ / bbl	97.00
Oil contract 5 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	20,000
Price Floor \| $ / bbl	90.00
Price Ceiling \| $ / bbl	97.00
Oil contract 6 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	15,000
Price Floor \| $ / bbl	90.00
Price Ceiling \| $ / bbl	97.90
Oil contract 7 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| bbl / mo	15,000
Price Floor \| $ / bbl	90.00
Price Ceiling \| $ / bbl	98.00
Natural Gas contract 1 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	04/01/2013 - 12/31/2013
Notional Quantity \| MMBTU / mo	100,000
Price Floor	3.25
Price Ceiling	4.41
Natural Gas contract 2 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	04/01/2013 - 12/31/2013
Notional Quantity \| MMBTU / mo	100,000
Price Floor	3.25
Price Ceiling	4.44
Natural Gas contract 3 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	04/01/2013 - 12/31/2013
Notional Quantity \| MMBTU / mo	100,000
Price Floor	3.50
Price Ceiling	4.37
Natural Gas contract 4 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	07/01/2013 - 12/31/2013
Notional Quantity \| MMBTU / mo	150,000
Price Floor	3.00
Price Ceiling	4.24
Natural Gas contract 5 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| MMBTU / mo	100,000
Price Floor	3.00
Price Ceiling	5.15
Natural Gas contract 6 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| MMBTU / mo	150,000
Price Floor	3.25
Price Ceiling	5.21
Natural Gas contract 7 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| MMBTU / mo	100,000
Price Floor	3.25
Price Ceiling	5.22
Natural Gas contract 8 [Member] \| Costless Collar Contracts [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| MMBTU / mo	100,000
Price Floor	3.50
Price Ceiling	4.90
Normal Butane Contract 1 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	03/01/2013 - 12/31/2013
Notional Quantity \| gal / mo	21,000
Commodity Fixed Price \| $ / Gallons	1.575
Normal Butane Contract 2 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	03/01/2013 - 12/31/2013
Notional Quantity \| gal / mo	117,000
Commodity Fixed Price \| $ / Gallons	1.575
Normal Butane Contract 3 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| gal / mo	17,500
Commodity Fixed Price \| $ / Gallons	1.540
Normal Butane Contract 4 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| gal / mo	45,500
Commodity Fixed Price \| $ / Gallons	1.550
Isobutane Contract 1 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	03/01/2013 - 12/31/2013
Notional Quantity \| gal / mo	43,500
Commodity Fixed Price \| $ / Gallons	1.675
Isobutane Contract 2 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	03/01/2013 - 12/31/2013
Notional Quantity \| gal / mo	23,000
Commodity Fixed Price \| $ / Gallons	1.675
Isobutane Contract 3 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| gal / mo	22,000
Commodity Fixed Price \| $ / Gallons	1.640
Isobutane Contract 4 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| gal / mo	37,000
Commodity Fixed Price \| $ / Gallons	1.640
Natural Gasoline Contract 1 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	03/01/2013 - 12/31/2013
Notional Quantity \| gal / mo	36,000
Commodity Fixed Price \| $ / Gallons	2.105
Natural Gasoline Contract 2 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	03/01/2013 - 12/31/2013
Notional Quantity \| gal / mo	90,500
Commodity Fixed Price \| $ / Gallons	2.148
Natural Gasoline Contract 3 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| gal / mo	30,000
Commodity Fixed Price \| $ / Gallons	1.970
Natural Gasoline Contract 4 [Member] \| Swap [Member]
Open Costless Collar Contracts For Natural Gas
Calculation Period	01/01/2014 - 12/31/2014
Notional Quantity \| gal / mo	41,000
Commodity Fixed Price \| $ / Gallons	2.000

Subsequent Events (Details 1) $ in Thousands	Dec. 31, 2012 USD ($)
Schedule of minimum lease payments required under the office lease agreement
2013	$ 575
2014	575
2015	589
2016	604
2017	618
Thereafter	2,995
Total	5,956
Subsequent Event [Member]
Schedule of minimum lease payments required under the office lease agreement
2013	643
2014	734
2015	752
2016	771
2017	789
Thereafter	3,813
Total	$ 7,502

Subsequent Events (Details Textual) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2012	Dec. 31, 2012 USD ($) ft² $ / shares shares	Mar. 14, 2013 USD ($)	Mar. 11, 2013 USD ($)	Sep. 30, 2012 USD ($)
Derivative [Line Items]
Outstanding letters of credit		$ 1.1
Additional deferred loan cost		$ 0.1			$ 0.8
Weighted average exercise price, Options granted \| $ / shares		$ 10.79
Vesting period of shares		4 years
Options to purchase Company's common stock, expired unexercised or were forfeited \| shares		248,000
Options expired unexercised or were forfeited, share price \| $ / shares		$ 10.00
Subsequent Events (Textual) [Abstract]
Maximum outstanding aggregate termination obligations of contracts			$ 2.1
Increase In Square Footage \| ft²		7,782
Subsequent Event [Member]
Derivative [Line Items]
Borrowing base				$ 255.0
Borrowings outstanding under the Credit Agreement			180.0
Outstanding letters of credit		$ 1.3	1.3
Additional deferred loan cost			$ 0.3
Unamortized portion of the deferred loan costs		$ 1.6
Stock option awards granted \| shares		507,500
Stock option awards granted, two \| shares		284,292
Weighted average exercise price, Options granted \| $ / shares		$ 8.21
Exercise prices common stock \| $ / shares		$ 8.18
Fair value of awards		$ 2.8
Restricted stock grants \| shares		324,771
Fair value of restricted stock awards		$ 2.4
Minimum outstanding aggregate commitments		$ 5.6
Options to purchase Company's common stock, expired unexercised or were forfeited \| shares		408,000
Options expired unexercised or were forfeited, share price \| $ / shares		$ 10.00
Maximum [Member]
Derivative [Line Items]
Increase of square footage \| ft²		36,525
Vesting period of shares		4 years
Maximum [Member] \| Subsequent Event [Member]
Derivative [Line Items]
Vesting period of shares		4 years
Minimum [Member]
Derivative [Line Items]
Increase of square footage \| ft²		28,743
Vesting period of shares		3 years
Minimum [Member] \| Subsequent Event [Member]
Derivative [Line Items]
Vesting period of shares		3 years
Open costless collar contracts [Member]
Derivative [Line Items]
Extension of drilling rig contracts	6 months

Selected Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Unaudited quarterly financial information
Oil and natural gas revenues	$ 52,748	$ 38,008	$ 36,078	$ 29,164	$ 14,991	$ 17,447	$ 20,864	$ 13,698	$ 155,998	$ 67,000	$ 34,042
Realized gain on derivatives	2,813	3,371	4,713	3,063	2,869	1,435	952	1,850	13,960	7,106	5,299
Unrealized (loss) gain on derivatives	(3,653)	(12,993)	15,114	(3,270)	3,604	2,870	332	(1,668)	(4,802)	5,138	3,139
Expenses	72,377	38,087	66,263	21,857	15,784	15,469	14,953	48,347	198,584	94,552	32,719
Other expense	(907)	(89)	(31)	(235)	(309)	(89)	(89)	(35)	(1,263)	(522)	137
(Loss) income before income taxes	(21,376)	(9,790)	(10,389)	6,865	5,371	6,194	7,106	(34,502)	(34,691)	(15,830)	9,898
Income tax (benefit) provision	(188)	(593)	(3,713)	3,064	1,430		(46)	(6,906)	(1,430)	(5,521)	3,521
Net (loss) income	$ (21,188)	$ (9,197)	$ (6,676)	$ 3,801	$ 3,941	$ 6,194	$ 7,152	$ (27,596)	$ (33,261)	$ (10,309)	$ 6,377
Class A [Member]
Basic
Basic	$ (0.38)	$ (0.17)	$ (0.12)	$ 0.08	$ 0.09	$ 0.14	$ 0.17	$ (0.65)	$ (0.62)	$ (0.25)	$ 0.15
Diluted
Diluted	(0.38)	(0.17)	(0.12)	0.08	0.09	0.14	0.17	(0.65)	(0.62)	(0.25)	0.15
Class B [Member]
Basic
Basic	0.00	0.00	0.00	0.15	0.16	0.21	0.23	(0.58)	(0.35)	0.02	0.42
Diluted
Diluted	$ 0.00	$ 0.00	$ 0.00	$ 0.15	$ 0.16	$ 0.21	$ 0.23	$ (0.58)	$ (0.35)	$ 0.02	$ 0.42