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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2012	Feb. 22, 2013
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Entity Registrant Name	Diamondback Energy, Inc.
Entity Central Index Key	0001539838
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		36,986,532
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float	$ 393,334,919

Combined Consolidated Balance Sheet - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 26,358	$ 6,959
Accounts receivable:
Joint interest and other	5,959	3,734
Oil and natural gas sales	8,081	839
Related party	772	12,937
Inventories	6,195	6,007
Deferred income taxes	1,857	0
Prepaid expenses and other	1,053	336
Total current assets	50,275	30,812
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting ($121,245,000 and $4,528,000 excluded from amortization at December 31, 2012 and December 31, 2011, respectively)	697,742	339,831
Other property and equipment	2,337	1,017
Accumulated depletion, depreciation, amortization and impairment	(145,837)	(119,699)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	554,242	221,149
Investments-equity method	0	10,310
Other assets	2,184	1,307
Total assets	606,701	263,578
Current liabilities:
Accounts payable trade	12,141	8,770
Accounts payable-related party	18,813	3,230
Accrued capital expenditures	29,397	13,919
Other accrued liabilities	10,649	4,894
Revenues and royalties payable	3,270	3,165
Derivative instruments	4,817	8,320
Note payable-short term	145	0
Total current liabilities	79,232	42,298
Note payable–long term	193	0
Note payable–credit facility–long term	0	85,000
Derivative instruments-long term	388	6,139
Asset retirement obligations-long term	2,125	1,104
Deferred income taxes-noncurrent	62,695	0
Total liabilities	144,633	134,541
Commitments and contingencies (Note 13)
Members' equity	0	129,037
Stockholders' equity:
Common stock, $0.01 par value, 100,000,000 shares authorized, 36,986,532 issued and outstanding at December 31, 2012; zero issued and outstanding at December 31, 2011	370	0
Additional paid-in capital	513,772	0
Accumulated deficit	(52,074)	0
Total stockholders' equity/members' equity	462,068	129,037
Total liabilities and stockholders' equity/members' equity	$ 606,701	$ 263,578

Combined Consolidated Balance Sheet (Parentheticals) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Statement of Financial Position [Abstract]
Oil and natural gas properties, amortization	$ 121,245	$ 4,528
Common Stock, Par Value	$ 0.01	$ 0.01
Common Stock, Shares Authorized	100,000,000	100,000,000
Common Stock, Shares, Issued	36,986,532	0
Common Stock, Shares, Outstanding	36,986,532	0

Statements of Combined Consolidated Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues:
Oil sales	$ 65,704	$ 2,582	$ 75
Oil sales - related party	0	38,873	21,403
Natural gas sales	1,369	1,061	1,400
Natural gas sales - related party	1,010	586	0
Natural gas liquid sales	3,839	3,169	3,564
Natural gas liquid sales - related party	3,040	1,604	0
Oil and natural gas services - related party	0	1,491	811
Total revenues	74,962	49,366	27,253
Costs and expenses:
Lease operating expenses	15,777	8,470	3,040
Lease operating expenses - related party	1,016	2,127	1,549
Production taxes	3,404	574	354
Production taxes - related party	287	1,792	993
Gathering and transportation	124	53	106
Gathering and transportation - related party	300	149	0
Oil and natural gas services	0	1,207	228
Oil and natural gas services - related party	0	526	583
Depreciation, depletion and amortization	26,273	15,601	8,145
General and administrative expenses	9,178	495	380
General and administrative expenses - related party	1,198	3,160	2,656
Asset retirement obligation accretion expense	98	65	38
Total costs and expenses	57,655	34,219	18,072
Income from operations	17,307	15,147	9,181
Other income (expense)
Interest income	3	11	34
Interest expense	(3,610)	(2,528)	(836)
Other income - related party	2,132	0	0
Gain (loss) on derivative instruments	2,617	(13,009)	(148)
Loss from equity investment	(67)	(7)	0
Total other income (expense), net	1,075	(15,533)	(950)
Income (loss) before income taxes	18,382	(386)	8,231
Provision for income taxes
Deferred income tax provision	54,903	0	0
Net income (loss)	(36,521)	(386)	8,231
Pro forma information (unaudited)
Income before income taxes, as reported	18,382	$ (386)	$ 8,231
Pro forma provision for income taxes	6,553
Pro forma net income	$ 11,829
Pro forma earnings per common share
Basic (in dollars per share)	$ 0.60
Diluted (in dollars per share)	$ 0.60
Pro forma weighted average common shares outstanding
Basic (in shares)	19,720,734
Diluted (in shares)	19,723,774

Combined Consolidated Statement of Stockholders' Equity/Members' Equity - USD ($) $ in Thousands	Total	Members' Equity	Common Stock	Additional Paid-in Capital	Accumulated Deficit
Balance at beginning of period at Dec. 31, 2009	$ 84,202	$ 84,202
Increase (Decrease) in Stockholders' Equity
Contributions	28,508	28,508
Distributions of equity method investments	(5,579)	(5,579)
Net income (loss)	8,231	8,231
Balance at end of period at Dec. 31, 2010	115,362	115,362
Increase (Decrease) in Stockholders' Equity
Contributions	13,517	13,517
Equity based compensation	544	544
Net income (loss)	(386)	(386)
Balance at end of period at Dec. 31, 2011	$ 129,037	129,037
Balance at end of period, shares at Dec. 31, 2011	0
Increase (Decrease) in Stockholders' Equity
Contributions	$ 4,008	4,008
Distributions of equity method investments	(10,504)	(10,504)
Equity based compensation	873	873
Earnings prior to merger	15,553	15,553
Common shares issued upon Merger		$ (138,967)	$ 147	$ 138,820
Common shares issued upon Merger, shares			14,697,496
Common shares issued upon acquisition of Gulfport properties	138,496		$ 79	138,417
Common shares issued upon acquisition of Gulfport properties, shares			7,914,036
Common shares issued at initial public offering, net of offering costs	234,144		$ 144	234,000
Common Shares issued ar initial public offering, net of offering costs, shares			14,375,000
Stock-based compensation	2,535			2,535
Net income (loss)	(36,521)
Net loss subsequent to merger	(52,074)				$ (52,074)
Balance at end of period at Dec. 31, 2012	$ 462,068		$ 370	$ 513,772	$ (52,074)
Balance at end of period, shares at Dec. 31, 2012	36,986,532		36,986,532

Statements of Combined Consolidated Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash flows from operating activities:
Net income (loss)	$ (36,521)	$ (386)	$ 8,231
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for deferred income taxes	54,903	0	0
Asset retirement obligation accretion expense	98	65	38
Depreciation, depletion, and amortization	26,273	16,104	8,145
Amortization of debt issuance costs	494	250	163
(Gain) loss on derivative instruments	(2,617)	13,009	148
Loss from equity investment	67	0	0
Equity-based compensation expense	3,482	544	0
Gain on sale of assets	(37)	(23)	(5)
Changes in operating assets and liabilities:
Accounts receivable	(5,036)	(1,547)	(1,822)
Accounts receivable-related party	6,096	(4,133)	(6,793)
Inventories	(639)	(872)	(4,897)
Prepaid expenses and other	(606)	(202)	(326)
Accounts payable and accrued liabilities	7,151	2,656	1,954
Accounts payable and accrued liabilities-related party	(1,218)	830	(409)
Revenues and royalties payable	105	2,666	499
Revenues and royalties payable-related party	(2,303)	2,037	266
Net cash provided by operating activities	49,692	30,998	5,192
Cash flows from investing activities:
Additions to oil and natural gas properties	(102,122)	(58,160)	(7,624)
Additions to oil and natural gas properties-related party	(9,675)	(22,014)	(36,950)
Acquisition of Gulfport properties	(63,590)	0	0
Proceeds from sale of oil and natural gas properties	0	0	1,250
Purchase of other property and equipment	(1,102)	(7,065)	(11,741)
Proceeds from sale of property and equipment	48	55	20
Settlement of non-hedge derivative instruments	(8,963)	(4,127)	(3,963)
Receipt on derivative margins	2,326	4,203	3,772
Deconsolidation of Bison	0	(10)	0
Proceeds from sale of membership interest in equity investment	0	6,010	0
Net cash used in investing activities	(183,078)	(81,108)	(55,236)
Cash flows from financing activities:
Proceeds from borrowings on credit facility	15,000	40,233	61,066
Repayment on credit facility	(100,000)	0	(23,950)
Proceeds from note payable- related party	30,000	0	0
Payment of note payable- related party	(30,050)	0	0
Debt issuance costs	(450)	(770)	(718)
Initial public offering costs	(2,887)	(30)	0
Proceeds from initial public offering	237,164	0	0
Contributions by members	4,008	13,517	20,914
Distributions to members	0	0	(5,579)
Net cash provided by financing activities	152,785	52,950	51,733
Net increase in cash and cash equivalents	19,399	2,840	1,689
Cash and cash equivalents at beginning of period	6,959	4,119	2,430
Cash and cash equivalents at end of period	26,358	6,959	4,119
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	3,017	2,265	600
Supplemental disclosure of non-cash transactions:
Asset retirement obligation incurred, including changes in estimate	386	297	223
Distribution of equity method investments	10,504	0	0
Note payable exchanged for equipment	411	0	0
Property Contributed	0	0	7,594
Common stock issued as a result of the Gulfport transaction	138,496	0	0
Asset retirement obligation acquired as a result of the Gulfport transaction	562	0	0
Post-closing adjustment payable as a result of the Gulfport transaction	$ 18,550	$ 0	$ 0

Organization and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Summary of Significant Accounting Policies

ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Description of the Business

Diamondback Energy, Inc. (“Diamondback” or the “Company”) together with its subsidiaries, is an independent oil and gas company currently focused on the acquisition, development, exploration, and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on December 30, 2011, and did not conduct any material business operations until October 11, 2012 when Diamondback merged with its parent entity, Diamondback Energy LLC, with Diamondback continuing as the surviving entity (the “Merger”). Prior to the Merger, Diamondback Energy LLC was a holding company and did not conduct any material business operations other than its ownership of the Company’s common stock and the membership interests in Windsor Permian LLC (“Windsor Permian”). As a result of the Merger, Windsor Permian became a wholly-owned subsidiary of Diamondback. Also on October 11, 2012, Wexford Capital LP (“Wexford”), our equity sponsor, caused all of the outstanding equity interests in Windsor UT LLC (“Windsor UT”) to be contributed to Windsor Permian prior to the Merger in a transaction referred to as the “Windsor UT Contribution”. The Windsor UT Contribution was treated as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. The operations of Windsor Permian and Windsor UT, as limited liability companies, were not subject to federal income taxes. On the date of the Merger, a corresponding “first day” tax expense to net income from continuing operations was recorded to establish a net deferred tax liability for differences between the tax and book basis of Diamondback’s assets and liabilities. This charge was $54,142,000. We refer to the historical results of Windsor Permian and Windsor UT prior to October 11, 2012 as our “Predecessors”.

Immediately after the Merger on October 11, 2012, Diamondback acquired from Gulfport Energy Corporation (“Gulfport”) all of its oil and natural gas interests in the Permian Basin (the “Gulfport properties”) in exchange for shares of Diamondback common stock and a promissory note in a transaction referred to as the Gulfport transaction. The Gulfport transaction was treated as a business combination accounted for under the acquisition method of accounting with the identifiable assets and liabilities recognized at fair value on the date of transfer. See Note 2—Acquisitions for information regarding the acquisition.

On October 17, 2012, the Company completed its initial public offering (“IPO”) of 14,375,000 shares of common stock, which included 1,875,000 shares of common stock issued pursuant to the over-allotment option exercised by the underwriters. The stock was priced at $17.50 per share and the Company received net proceeds of approximately $234.1 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

Basis of Presentation

Transfers of a business between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. As discussed above, the Windsor UT contribution was accounted for as a transaction between entities under common control thus the accompanying combined consolidated financial statements and related notes of the Company have been retrospectively adjusted to include the historical results of Windsor UT at historical carrying values and their operations as if they were combined for all periods presented. The accompanying financial statements and related notes presented herein represent the combined financial position of our Predecessors for periods prior to October 11, 2012, the combined results of operations, cash flows and equity of our Predecessors through October 11, 2012, and the Company and its wholly-owned subsidiaries consolidated financial position, results of operations, cash flows and equity subsequent to October 11, 2012. All intercompany balances and transactions are eliminated in consolidation.

Use of Estimates

Certain amounts included in or affecting the Company’s combined consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the combined consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the combined consolidated financial statements. Actual results could differ from those estimates.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, stock-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.

Reclassifications

The Company has reclassified certain prior year amounts to conform with the current year’s presentation. In the 2011 combined consolidated balance sheet, $92,000 of prepaid costs related to oil and natural gas properties has been reclassified from “Prepaid expenses and other” to “Other assets”.

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents.

Accounts Receivable

Accounts receivable consist of receivables from joint interest owners on properties the Company operates and oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments are received within three months after the production date.

Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2012 or December 31, 2011.

Derivative Instruments

The Company is required to recognize its derivative instruments on the combined consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized change in fair value on derivative instruments in the combined consolidated statements of operations.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivatives and notes payable. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The note payable is carried at cost, which approximates fair value due to the nature of the instrument and relatively short maturity. Derivatives are recorded at fair value (see Note 12—Fair Value Measurements).

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 5—Equity Method Investments). Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $23.90, $25.41, and $17.78 for the years ended December 31, 2012, 2011, and 2010, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $25,772,000, $15,377,000 and $7,373,000 for the years ended December 31, 2012, 2011 and 2010, respectively.

Under the full-cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling limitation is the estimated after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10%. Estimated future net cash flows exclude future cash flows associated with settling accrued asset retirement obligations. Estimated future net cash flows are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production. Any excess of the net book value of proved oil and natural gas properties, less related deferred income taxes, over the ceiling is charged to expense. No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2012, 2011 or 2010.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

Other Property and Equipment

Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the combined consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. Depreciation expense was $501,000, $727,000 and $772,000 for the years ended December 31, 2012, 2011 and 2010, respectively.

Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability in accordance with ASC Topic 410, Asset Retirement and Environmental Obligations (“ASC Topic 410”), which provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

ASC Topic 410 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. ASC Topic 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and that the corresponding cost be capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.

Impairment of Long-Lived Assets

Other property and equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no such impairment losses for the years ended December 31, 2012, 2011 or 2010.

Capitalized Interest

The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2012 and 2011, the Company did not capitalize any interest expense and during the year ended December 31, 2010, the Company capitalized $150,000 of interest expense.

Inventories

Inventories are stated at the lower of cost or market and consist of the following:



	December 31,
	2012		2011
Tubular goods and equipment	$	5,725,000	$	5,631,000
Crude oil	470,000		376,000
	$	6,195,000	$	6,007,000

The Company’s tubular goods and equipment is primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. As of December 31, 2012, the Company estimated that all of its tubular goods and equipment will be utilized within one year. The total inventory includes tubular goods held by others of zero at December 31, 2012 and $1,094,000 at December 31, 2011.

Debt issuance costs

The Company amortizes debt issuance costs related to its credit facility as interest expense over the scheduled maturity period of the debt. Unamortized debt issuance costs were $1,115,000 and $1,168,000 as of December 31, 2012 and December 31, 2011, respectively. The Company includes the unamortized costs in other assets in its combined consolidated balance sheets.

Revenue and Royalties Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds applicable to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying combined consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.

Revenue Recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. The Company did not have any gas imbalances as of December 31, 2012 or December 31, 2011. Revenues from oil and natural gas services are recognized as services are provided.

Investments

Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments for the years ended December 31, 2012 or December 31, 2011. For additional information on the Company’s investments, see Note 5—Equity Method Investments.

Accounting for Stock-Based Compensation

The Company accounts for stock-based compensation in accordance with the provisions of ASC Topic 718, “Compensation—Stock Compensation”. The Company grants various types of stock-based awards including stock options and restricted stock units. These plans and related accounting policies are defined and described more fully in Note 8—Stock and Equity Based Compensation. Stock compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period.

Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, LP (53%); Occidental Energy Marketing, Inc. (16%); and Andrews Oil Buyers, Inc. (10%). For the years ended December 31, 2011 and December 31, 2010, Windsor Midstream LLC, a related party, accounted for 79% of the Company’s revenue in both periods. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Environmental Compliance and Remediation

Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.

Income Taxes

Diamondback uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Company and the Predecessor are subject to margin tax in the state of Texas. During the years ended December 31, 2012, 2011 and 2010 there was no margin tax expense. The Company’s 2008, 2009, 2010 and 2011 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2012 and December 31, 2011, the Company had no unrecognized tax benefits that would have a material impact on the effective rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2012, 2011 and 2010 there was no interest or penalties associated with uncertain tax positions recognized in the Company’s combined consolidated financial statements.

Unaudited Pro Forma Income Taxes

Diamondback Energy, Inc. was formed as a holding company on December 30, 2011, and did not conduct any material business operations prior to the Merger. Diamondback Energy, Inc. is a C-Corp under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision as if the Company and the Predecessors were subject to income taxes since December 31, 2011. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences.

Unaudited Pro Forma Earnings per Share

The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued upon the Merger were outstanding for the entire year. Diluted earnings per share reflects the potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock awards and units were fully vested. During periods in which the Company realizes a net loss, options and restricted stock awards would not be dilutive to net loss per share and conversion into common stock is assumed not to occur.

New Pronouncements Issued but Not Yet Adopted

In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Disclosures about Offsetting Assets and Liabilities. In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The guidance in ASU No. 2013-01 limits the scope of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions to the extent that they are (1) offset in the financial statements or (2) subject to an enforceable master netting arrangement or similar agreement. The disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) and International Financial Reporting Standards related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU No. 2011-11and ASU No. 2013-01 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. The Company does not expect the adoption of this guidance to have a significant impact on its financial position, results of operations or cash flow.

- Definition

The entire disclosure for the organization, consolidation and basis of presentation of financial statements disclosure, and significant accounting policies of the reporting entity. May be provided in more than one note to the financial statements, as long as users are provided with an understanding of (1) the significant judgments and assumptions made by an enterprise in determining whether it must consolidate a VIE and/or disclose information about its involvement with a VIE, (2) the nature of restrictions on a consolidated VIE's assets reported by an enterprise in its statement of financial position, including the carrying amounts of such assets, (3) the nature of, and changes in, the risks associated with an enterprise's involvement with the VIE, and (4) how an enterprise's involvement with the VIE affects the enterprise's financial position, financial performance, and cash flows. Describes procedure if disclosures are provided in more than one note to the financial statements.

+ References + Details

Acquisitions

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

Acquisitions

ACQUISITIONS

On May 7, 2012, the Company entered into an agreement with Gulfport in which Gulfport agreed to sell to the Company, subject to certain conditions, all of its oil and natural gas interests in the Permian Basin in exchange for shares of the Company’s common stock and a promissory note in a transaction referred to as the Gulfport transaction, with such consideration being subject to a post-closing adjustment. The Gulfport transaction was completed on October 11, 2012 for the purpose of expanding the Company’s acreage position. The acquisition was accounted for according to the guidance provided in ASC 805, Business Combinations, which requires application of the acquisition method. This methodology requires the recording of net assets acquired and consideration transferred at fair value.

The acquisition-date fair value of the consideration transferred totaled $220,636,000, which consisted of the following:



Common Stock (7,914,036 shares)	$	138,496,000
Promissory note paid in full from IPO proceeds	63,590,000
Closing adjustment payable	18,550,000
Total	$	220,636,000

The fair value of the 7,914,036 common shares issued was determined based on the IPO pricing of $17.50 per common share on October 11, 2012. The closing adjustment payable balance is a result of the working capital adjustment.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the acquisition date. As shown above, consideration transferred in the transaction was $220,636,000, resulting in no goodwill or bargain purchase gain.



Proved oil and natural gas properties	$	115,760,000
Unevaluated oil and natural gas properties	111,373,000
Asset retirement obligations	(562,000		)
Deferred income tax liability	(5,935,000		)
Total fair value of net assets	$	220,636,000

The Company has included in its combined consolidated statements of operations revenues of $7,353,000 and direct operating expenses of $2,260,000 for the period from October 11, 2012 to December 31, 2012 due to the acquisition. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion. The following unaudited summary pro forma combined consolidated statement of operations data of Diamondback for the years ended December 31, 2012 and 2011 has been prepared to give effect to the acquisition as if it had occurred on January 1, 2011. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisition occurred on January 1, 2011. The pro forma data also necessarily exclude various operation expenses related to the Gulfport properties and the financial statements should not be viewed as indicative of operations in future periods. As the current operator of the properties acquired by the Company upon completion of the Gulfport transaction, the Company does not expect any material impact from these transactions on its existing employees or infrastructure.



	Pro Forma
	(Unaudited)
	Year Ended December 31,
	2012			2011
Pro forma total revenues	$	97,455,000		$	72,418,000
Pro forma income from operations	24,064,000			23,189,000
Pro forma net income (loss)	(29,764,000		)	7,666,000		⁽¹⁾

(1) For 2011, this amount does not include a pro forma income tax provision relating to becoming subject to income taxes as a result of the Merger.

Property and Equipment

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Property and Equipment

PROPERTY AND EQUIPMENT

Property and equipment includes the following:



	December 31,
	2012			2011
Oil and natural gas properties:
Subject to depletion	$	576,497,000		$	335,303,000
Not subject to depletion-acquisition costs
Incurred in 2012	117,395,000			—
Incurred in 2011	1,670,000			1,689,000
Incurred in 2010	1,647,000			2,306,000
Incurred in 2009	533,000			533,000
Total not subject to depletion	121,245,000			4,528,000

Gross oil and natural gas properties	697,742,000			339,831,000
Less accumulated depreciation, depletion, amortization and impairment	(145,102,000		)	(119,366,000		)
Oil and natural gas properties, net	552,640,000			220,465,000

Other property and equipment	2,337,000			1,017,000
Less accumulated depreciation	(735,000		)	(333,000		)
Other property and equipment, net	1,602,000			684,000

Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	554,242,000		$	221,149,000

Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized internal costs were approximately $4,872,000, $871,000 and zero for the years ended December 31, 2012, 2011 and 2010, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years.

- 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 Obligation

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

ASSET RETIREMENT OBLIGATION

The following table describes the changes to the Company’s ARO liability for the following periods:



	Year Ended December 31,
	2012			2011		2010
Asset retirement obligation, beginning of period	$	1,104,000		$	742,000	$	482,000
Additional liability incurred	201,000			297,000		222,000
Liabilities acquired	562,000			—		—
Liabilities settled	(5,000		)	—		—
Accretion expense	98,000			65,000		38,000
Revisions in estimated liabilities	185,000			—		—
Asset retirement obligation, end of period	2,145,000			1,104,000		742,000
Less current portion	20,000			—		—
Asset retirement obligations - long-term	$	2,125,000		$	1,104,000	$	742,000

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

During 2012, the Company recorded $562,000 in additional abandonment liabilities on properties acquired in the Gulfport transaction. Increases in estimated costs to plug and abandon the properties resulted in an upward revision of $185,000.

Equity Method Investments

12 Months Ended

Dec. 31, 2012

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

EQUITY METHOD INVESTMENTS

Bison Drilling and Field Services LLC

On November 15, 2010, the Company had formed a wholly owned subsidiary, Bison Drilling and Field Services LLC (“Bison”), formerly known as Windsor Drilling LLC. In addition, on March 2, 2010, the Company had formed a wholly owned subsidiary, West Texas Field Services LLC, which, on January 1, 2011, contributed all of its assets and liabilities to Bison and West Texas Field Services LLC was subsequently dissolved on June 12, 2012. Bison owned and operated drilling rigs and various oil and natural gas well servicing equipment.

Beginning on March 31, 2011, various related party investors contributed capital to Bison diluting the Company’s ownership interest. The Company assessed its ability to exercise financial control over Bison and based on the results of its assessment, the Company concluded it maintained significant influence but it no longer had the ability to exercise control over Bison. The Company deconsolidated Bison for financial reporting purposes as of March 31, 2011 and the previously consolidated amounts were removed from the combined consolidated balance sheet and reflected as an equity method investment. The Company eliminated intercompany profits or losses in relation to its continuing involvement with Bison, proportionate to its equity interest. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the combined consolidated statements of operations. However, because substantially all of Bison’s earnings were generated by performing services on properties owned and operated by the Company, the Company’s share of Bison’s earnings have been credited to oil and natural gas properties.

An entity is required to deconsolidate a subsidiary when the entity ceases to have a controlling financial interest in the subsidiary. Upon deconsolidation of a subsidiary, an entity recognizes a gain or loss on the transaction and measures any retained investment in the subsidiary at fair value. The gain or loss includes any gain or loss associated with the difference between the fair value of the retained investment in the subsidiary and its carrying amount at the date the subsidiary is deconsolidated.

The Company internally reviewed the balance sheet of Bison to determine its fair value. At the time of the transaction Bison was still a recently formed company and had not yet built value in its operations. Bison’s assets consisted primarily of four recently purchased drilling rigs. Two of the drilling rigs were purchased at market price from a third party in December 2010 and the second two were purchased from the same third party in April 2011. The Company also reviewed pricing of similar rigs in the market through retail and auction transactions. Because the rigs had just recently been purchased and this purchase price was in line with other outside transactions the Company determined that Bison’s book value equaled fair value. There was no gain or loss recorded and the retained investment was recorded at fair value which equaled book value.

In September 2011, the Company completed the sale of 25% of its membership interest in Bison to a related party. The Company internally reviewed the fair value of Bison and because the effective date of this transaction was May 1, 2011 and was within thirty days of the above valuation the Company concluded the value of Bison had not changed. The Company determined that fair value equaled book value at the date of this transaction. There was no gain or loss recorded and the retained investment was recorded at fair value which equaled book value.

As of December 31, 2011, the Company had a 27.7% ownership in Bison. The table below summarizes financial information for Bison as of December 31, 2011.



	December 31, 2011
Current Assets	$	4,438,000
Property and equipment, net	21,708,000
Other assets	880,000
Current liabilities	2,419,000
Equity	24,607,000

As of June 15, 2012, the Company distributed its remaining interest in Bison to an entity which is controlled and managed by Wexford. As the transaction was between entities under common control, the Company has recognized the distribution of $6,437,000 as an equity transaction. Bison continues to be a related party with the Company.

Muskie Holdings LLC

During 2011, the Company paid approximately $4,200,000 for land and various other capital items related to the land. On October 7, 2011, the Company contributed these assets to a newly formed entity, Muskie Holdings LLC, a Delaware limited liability company, for a 48.6% equity interest. Through additional contributions to Muskie from a related party and various Wexford portfolio companies, the Company’s interest in Muskie decreased to 33% as of June 15, 2012. Muskie generated a loss during the period January 1, 2012 through June 15, 2012 and the Company has recorded its share of this loss.

The table below summarizes financial information for Muskie as of December 31, 2011.



	December 31, 2011
Current assets	$	994,000
Property and equipment, net	7,585,000
Current liabilities	27,000
Equity	8,552,000

As of June 15, 2012, the Company distributed its remaining interest in Muskie to an entity which is controlled and managed by Wexford. As the transaction was between entities under common control, the Company has recognized the distribution of $4,067,000 as an equity transaction. Muskie continues to be a related party with the Company.

- Definition

The entire disclosure for equity method investments and joint ventures. Equity method investments are investments that give the investor the ability to exercise significant influence over the operating and financial policies of an investee. Joint ventures are entities owned and operated by a small group of businesses as a separate and specific business or project for the mutual benefit of the members of the group.

+ References + Details

Debt

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Debt

DEBT

Credit Facility-Wells Fargo Bank

On October 15, 2010, the Company entered into a secured loan agreement with BNP Paribas (“BNP”) as the administrative agent, sole book runner and lead arranger, as amended, providing for a revolving credit facility. On May 10, 2012, the revolving credit agreement was further amended to provide for the resignation of BNP, and the appointment of Wells Fargo Bank, National Association, as administrative agent for the lenders. The aggregate maximum credit amount under the revolving credit agreement is $250.0 million notwithstanding future redeterminations of the borrowing base. The outstanding borrowings bear interest at a rate elected by the Company that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base.

Principal may be optionally repaid from time to time and is required to be paid (i) if the loan amount exceeds the borrowing base and (ii) at the maturity date of October 15, 2014. The Company is obligated to pay, quarterly, a commitment fee equal to 0.5% per year of the unused portion of the borrowing base. The loan is secured by substantially all of the Company’s assets. The borrowing base is re-determined semi-annually with effective dates of April 1st and October 1st (a “scheduled redetermination”). In addition, the Company may request an additional three redeterminations of the borrowing base during any 12 months period. The borrowing base was $45.0 million at December 31, 2010. The borrowing base increased throughout 2011 through various redeterminations and at December 31, 2011 the borrowing base was $100.0 million. The borrowing base increased in 2012 through redeterminations and at December 31, 2012 the borrowing base was $135.0 million. In connection with the IPO, the Company repaid all outstanding borrowings under its revolving credit facility and as of December 31, 2012 had no outstanding borrowings. As of December 31, 2011, the Company had outstanding borrowings of $85.0 million which bore a weighted average interest rate of 3.30%.

The agreement contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sales of assets, mergers and consolidations, dividends and distributions, and changes in management and require the maintenance of various financial ratios defined below.

The current lenders and their percentage commitments in the revolving credit facility are Wells Fargo Bank, N.A. (45%), Amegy Bank, N.A. (25%), U.S. Bank, N.A. (25%) and West Texas National Bank (5%).

As of July 24, 2012, the revolving credit agreement was amended and restated to include Diamondback Energy LLC and its subsidiaries as additional guarantors to the facility. The covenant prohibiting additional indebtedness was also amended to allow the issuance of unsecured debt of up to $250.0 million and, in connection with any such issuance, the reduction of the borrowing base by 25% of the principal amount of such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. The amendment also provided that redemptions of any unsecured debt will be restricted unless certain liquidity requirements are met. Further, the amendment modified certain financial ratios, the current requirements of which are described below.



Financial Covenant			Required Ratio
Ratio of EBITDAX to interest expense, as defined in the credit agreement			Not less than 2.5 to 1.0
Ratio of total debt to EBITDAX			Not greater than 4.0 to 1.0
Ratio of debt under revolving credit agreement to EBITDAX			Not greater than 3.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement			Not less than 1.0 to 1.0

The revolving credit agreement defines EBITDAX, for any period, as the sum of consolidated net income for such period plus the following expenses or charges to the extent deducted from consolidated net income for such period: interest; income taxes; depreciation, depletion, amortization and exploration expenses; extraordinary items and other similar non-cash charges, including expenses related to stock-based compensation and hedging, minus all non-cash income added to consolidated net income.

As of July 31, 2012, the first amendment to the amended and restated credit agreement was executed, which provided for the issuance to Gulfport of the Gulfport transaction note and the payment of the Gulfport transaction note from the proceeds of the IPO.

As of September 28, 2012, the second amendment to the amended and restated credit agreement was executed, which among other things provided for an increase in permitted subordinated debt in a maximum principal amount not to exceed $45.0 million, including any such indebtedness evidenced by the Company’s subordinated note with an affiliate of Wexford described in more detail under “-Subordinated Note” below, waived compliance with the Company’s current ratio covenant for the quarter ending September 30, 2012 and increased the aggregate limitation on lease payments during any period of 12 months consecutive calendar months from $250,000 to $550,000.

As of December 31, 2012 and December 31, 2011, the Company was in compliance with all financial covenants under the revolving credit facility. The lenders may accelerate all of the indebtedness under the revolving credit facility upon the occurrence of any event of default unless the Company cures any such default within any applicable grace period. For payments of principal and interest under the revolving credit facility, the Company generally has a three business day grace period, and a 30-day cure period for most covenant defaults, but not for defaults of certain specific covenants, including the financial covenants and negative covenants.

Subordinated Note

Effective May 14, 2012, the Company issued a subordinated note to an affiliate of Wexford pursuant to which, as amended, the Wexford affiliate could, from time to time, advance up to an aggregate of $45.0 million. These advances were solely at the lender’s discretion and neither Wexford nor any of its affiliates had any commitment or obligation to provide further capital support to the Company. In connection with the IPO, the Company repaid all outstanding borrowings under the subordinated note and the subordinated note was canceled.

The note bore interest at a rate equal to LIBOR plus 0.28% or 8% per annum, whichever was lower. Interest was due quarterly in arrears beginning on July 1, 2012. Interest payments were payable in kind by adding such amounts to the principal balance of the note. The unpaid principal balance and all accrued interest on the note were due and payable in full on January 31, 2015 or the earlier completion of an initial public offering. Any indebtedness evidenced by this note was subordinate in the right of payment to any indebtedness outstanding under the Company’s revolving credit facility.

Note Payable

The Company entered into an installment payment contract with EMC Corporation for the purchase of computer equipment. The contract is payable in equal installments over a period of 36 months. As of December 31, 2012, there was $338,000 outstanding under this note.

- 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

Stockholders' Equity and Earnings Per Share

12 Months Ended

Dec. 31, 2012

Equity [Abstract]

Stockholders' Equity and Earnings Per Share

STOCKHOLDERS’ EQUITY & PRO FORMA EARNINGS PER SHARE

Common Stock Offering

On October 11, 2012, the Company priced 12,500,000 shares of common stock in the IPO at $17.50 per share, and on October 12, 2012, shares of the Company’s common stock began trading on the Nasdaq Global Select Market under the symbol “FANG”. On October 17, 2012, the Company closed the IPO. On October 23, 2012, the underwriters purchased an additional 1,875,000 shares of common stock following the exercise in full of the over-allotment option. The Company received net proceeds of approximately $234.1 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

The authorized capital stock of the Company consists of 100.0 million shares of common stock, par value $0.01 per share, and 10.0 million shares of preferred stock, par value $0.01 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors. At December 31, 2012, there were no shares of preferred stock outstanding.

Unaudited Pro Forma Earnings Per Share

The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued upon the Merger were outstanding for the entire year. Certain options to purchase shares of the Company’s common stock were excluded from the dilution calculation because the options were antidilutive. A reconciliation of the components of pro forma basic and diluted earnings per common share is presented in the table below:



	2012
				Per
	Income		Shares	Share
Basic:
Pro forma net income attributable to common stock	$	11,829,000	19,720,734	$	0.60
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	—	3,040
Diluted:
Pro forma net income attributable to common stock	$	11,829,000	19,723,774	$	0.60

- 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

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21484-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SAB TOPIC 4.E)
-URI http://asc.fasb.org/extlink&oid=6228006&loc=d3e74512-122707

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21488-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.29-31)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 4
-Subparagraph (SAB TOPIC 4.C)
-URI http://asc.fasb.org/extlink&oid=6959260&loc=d3e187143-122770

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 30
-Section 50
-Paragraph 2
-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
-SubTopic 10
-Section 50
-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
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 2
-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
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 11
-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
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 12
-Paragraph 10
-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
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 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.

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph d
-Article 4

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 29, 30, 31
-Article 5

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section E

Reference 20: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Article 4

Reference 21: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

Reference 22: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 129
-Paragraph 2, 3, 4, 5, 6, 7, 8
-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
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Article 3

+ Details

Stock and Equity Based Compensation

12 Months Ended

Dec. 31, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock Compensation Plans

STOCK AND EQUITY BASED COMPENSATION

On October 10, 2012, the Board of Directors approved the Diamondback Energy, Inc. 2012 Equity Incentive Plan (the “2012 Plan”), which is intended to provide eligible employees with equity-based incentives. The 2012 Plan provides for the granting of incentive stock options, nonstatutory stock options, restricted awards (restricted stock and restricted stock units), performance awards, and stock appreciation rights, or any combination of the foregoing. A total of 2.5 million shares of the Company’s common stock has been reserved for issuance pursuant to this plan. Previous to the 2012 Plan, each of the Company’s Executive Officers was provided with an option to acquire a percentage membership interest in Windsor Permian. In connection with the IPO and the 2012 Plan, these options were canceled and replaced with the right to receive a cash payment, restricted stock units and stock options. Such grant of new awards is deemed to be a modification of old awards and was accounted for as a modification of the original awards. The modification date for these awards was October 11, 2012 which was the date of IPO pricing of $17.50 per share. Eight employees were affected by this modification. As a result of the modification, incremental compensation cost of $4,588,000 was recognized on the modification date to recognize the portion of awards that are vested and includes cash payments of $2,813,000. In addition to the compensation expense recognized on the modification date, $5,866,000 of compensation expense will be recognized over the remaining service period and a liability of $333,000 will be recognized ratably over one year as the Company’s chief executive officer is entitled to receive a cash payment on the first anniversary date of the IPO, subject to his continued employment with the Company. The modification did not change the original vesting or exercise periods. As a result, options vest in four equal annual installments commencing on the first anniversary of the original date of grant and are exercisable for 5 years from the original date of grant.

The following table presents the effects of the equity and stock-based compensation plans and related costs:



	2012		2011
General and administrative expenses	$	3,757,000	$	438,000
Stock-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	2,537,000		106,000
Related income tax benefit	930,000		—

Stock Options

In accordance with the 2012 Plan, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. The shares issued under the 2012 Plan will consist of new shares of Company stock. Unless otherwise specified in an agreement, options become exercisable ratably over a five-year period. However, as described above, options associated with the modification vest in four equal annual installments and are exercisable for 5 years from the date of grant.

The fair value of the stock options on the date of grant is expensed over the applicable vesting period. The Company estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The Company does not have a long history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards and remaining vesting term at the modification date. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero. All such amounts represent the weighted-average amounts for each year.



	2012
Grant-date fair value	$	4.41
Expected volatility	40.0		%
Expected dividend yield	0.0		%
Expected term (in years)	3.8
Risk-free rate	0.33		%

The following table presents a summary of the Company’s outstanding stock options.



		Weighted Average
		Exercise		Remaining	Intrinsic
	Options	Price		Term	Value
				(In years)
Outstanding at December 31, 2011	—	$	—
Granted	850,000	$	17.50
Exercised	—	$	—
Outstanding at December 31, 2012	850,000	$	17.50	3.58	$	1,377,000

Vested and Expected to vest at December 31, 2012	850,000	$	17.50	3.58	$	1,377,000
Exercisable at December 31, 2012	212,500	$	17.50	3.55	$	344,000

As of December 31, 2012, the unrecognized compensation cost related to unvested stock options was $2,462,000. Such cost is expected to be recognized over a weighted-average period of 2.6 years.

Restricted Stock Awards and Units

Through the 2012 Plan, approved by the Board of Directors, the Company has restricted stock and restricted stock unit plans for eligible employees. The Company estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents a summary of the Company’s restricted stock awards and units.



			Weighted Average
	Restricted Stock		Grant-Date
	Awards & Units		Fair Value
Unvested at December 31, 2011	—		$	—
Granted	279,046		$	17.50
Vested	(72,539	)	$	17.50
Forfeited	—		$	—
Unvested at December 31, 2012	206,507		$	17.50

The aggregate fair value of restricted stock awards and units that vested during 2012 was $1,269,000. As of December 31, 2012, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $3,228,000. Such cost is expected to be recognized over a weighted-average period of 2.5 years.

Equity-Based Compensation

During the year ended December 31, 2011, Windsor Permian granted to its executive officers options to acquire membership interests in Windsor Permian. Such options vested in four equal annual installments commencing on the first anniversary of the date of grant and were exercisable for 5 years from the date of grant. Summarized below are the grant dates with the total exercise prices and total fair values of the underlying options:



Grants Made During the Months Ended	Membership Interest Granted	Exercise Price		Fair Value at Date of Grant
April 2011	1.00%	$	3,600,000	$	1,453,000
August 2011	1.20%	6,000,000		1,384,000
September 2011	1.25%	5,900,000		1,533,000
November 2011	0.25%	1,250,000		288,000
	3.70%	$	16,750,000	$	4,658,000

At December 31, 2011, for outstanding options, the intrinsic value was $113,000 and the weighted-average remaining contractual terms were 4.6 years. Also, at December 31, 2011, no options were exercisable.

The Company accounted for such options issued using a fair-value-based method calculated on the grant-date of the award. The resulting cost was recognized on a straight-line basis over the vesting period of the entire option.

The fair value of the options issued was estimated using the Black-Scholes option-pricing model. One of the inputs to this model was the estimate of the fair value of the underlying membership interest on the date of grant. The other inputs include an estimate of the expected volatility of the membership interest, an option’s expected term, the risk-free interest rate over the option’s expected term, the option’s exercise price, and expectations regarding dividends.

Windsor Permian did not have a history of market prices for its membership interests because such interests were not publicly traded. The expected volatility was determined using the historical volatility for a peer group of companies. The expected term for options issued was determined based on the contractual term of the awards. The weighted-average risk-free interest rate was based on the daily U.S. treasury yield curve rate whose term was consistent with the expected life of the options. Windsor Permian did not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero.

A summary of the significant assumptions used to estimate the fair value of the options to acquire membership interests during the year ended December 31, 2011 was as follows:



Expected term	5 years
Risk-free interest rate	0.96%
Expected volatility	45.5%
Expected dividend yield	0.00%

These equity-based awards were canceled and replaced with the right to receive a cash payment, restricted stock units and stock options as described in the above sections of this Note.

- 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
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-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
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-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

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2012
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS Administrative Services An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement which began March 1, 2008. Through December 31, 2011, amounts charged to the Company included those costs directly attributable to the Company as well as indirect costs allocated to the Company. The reimbursement amount for indirect costs is determined by the affiliate’s management based on estimates of time devoted to the Company. During the years ended December 31, 2012, 2011 and 2010, the Company incurred total costs of $4,419,000, $10,110,000 and $7,996,000, respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration and development of proved oil and natural gas properties have been capitalized. The expensed costs were partially offset in general and administrative expenses by overhead reimbursements of $2,548,000, $1,954,000 and $1,389,000 for the years ended December 31, 2012, 2011 and 2010, respectively. As of December 31, 2012, the Company owed the administrative services affiliate $13,000 and as of December 31, 2011, the Company owed the administrative services affiliate $773,000. These amounts are included in accounts payable-related party in the accompanying combined consolidated balance sheets. Effective January 1, 2012, the Company entered into an additional shared services agreement with this entity. Under this agreement, the Company provides this entity and, at its request, certain affiliates, with consulting, technical and administrative services. The initial term of the additional shared services agreement is two years. Upon expiration of the initial term the agreement will continue on a month-to-month basis until canceled by either party upon thirty days prior written notice. Costs that are attributable to and billed to other affiliates are reported as other income-related party. For the year ended December 31, 2012, the affiliate reimbursed the Company $2,132,000 for services under the shared services agreement and at December 31, 2012, the affiliate owed the Company $1,000 and this amount is included in accounts receivable-related party in the accompanying combined consolidated balance sheets. Operating Services The Company is the operator of substantially all of its properties. As operator of these properties, the Company is responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties. As of December 31, 2012, the Company had no amounts due to affiliated parties related to operating services of the properties. As of December 31, 2011, the Company had an amount due to an affiliated party related to revenue distributions payable of $2,303,000. This amount is included in accounts payable-related party in the accompanying combined consolidated balance sheets. This affiliated party was an affiliate of Wexford. As of December 31, 2012 and December 31, 2011, amounts due from an affiliate related to joint interest billings and included in accounts receivable-related party in the accompanying combined consolidated balance sheets are $742,000 and $8,590,000, respectively. This affiliated party was an affiliate of Wexford. Drilling Services Bison has performed drilling and field services for the Company under master drilling agreements. Under the Company’s master drilling agreement with Bison, effective as of January 1, 2012, Bison committed to accept orders from the Company for the use of at least two of its rigs, and at December 31, 2012 was providing drilling services to the Company using four of its rigs. This master drilling agreement is terminable by either party on 30 days prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. For the three months ended March 31, 2011, Bison was a wholly-owned subsidiary and intercompany amounts were eliminated in consolidation. The Company owed Bison $120,000 as of December 31, 2012 and $154,000 as of December 31, 2011. Completion and Well Servicing Services The Company contracted with an affiliate for certain of its well completion services. Effective August 24, 2011, the affiliate was sold to a non-related third party. While still an affiliate of the Company, the Company was billed $12,511,000 and $7,709,000 during the years ended December 31, 2011 and 2010, respectively. Such amounts are capitalized in oil and natural gas properties in the accompanying combined consolidated balance sheet. At December 31, 2012 and December 31, 2011, the entity was no longer a related party. Marketing Services The Company entered into an agreement on March 1, 2009 with an entity under common management that purchased and received a significant portion of the Company’s oil volumes. December 1, 2011, the Company ceased all sales of its production under this agreement and effective January 1, 2012 the agreement with the affiliate was canceled. The Company’s revenues from the affiliate were $38,873,000 and $21,403,000 during the years ended December 31, 2011 and 2010, respectively, and such amounts are included in oil sales–related party in the accompanying combined consolidated statements of operations. As of December 31, 2011, the Company had an accounts receivable-related party balance with the affiliate of $4,347,000 and such amount is included in the accompanying combined consolidated balance sheets. MidMar The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with MidMar Gas LLC (“MidMar”), an entity affiliated with Wexford that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, MidMar is obligated to purchase from the Company, and the Company is obligated to sell to MidMar, all of the gas conforming to certain quality specifications produced from certain of the Company’s Permian Basin acreage. Following the expiration of the initial ten year term, the agreement will continue on a year-to-year basis until terminated by either party on 30 days’ written notice. Under the gas purchase agreement, MidMar is obligated to pay the Company 87% of the net revenue received by MidMar for all components of the Company’s dedicated gas, including the liquid hydrocarbons, and the sale of residue gas, in each case extracted, recovered or otherwise processed at MidMar’s gas processing plant, and 94.56% of the net revenue received by MidMar from the sale of such gas components and residue gas, extracted, recovered or otherwise processed at Chevron’s Headlee plant. MidMar paid the Company $2,958,000, $3,128,000 and $1,066,000 during the years ended December 31, 2012, 2011 and 2010, respectively. As of December 31, 2012 and 2011, MidMar owed the Company $6,000 and $462,000, respectively, for the Company’s portion of the net proceeds from the sale of gas, gas products and residue gas. Midland Lease Effective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with a five-year term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $155,000 and $40,000, during the years ended December 31, 2012 and 2011, respectively. The current monthly rent under the lease will increase approximately 4% annually on June 1 of each year during the lease term. Oklahoma City Lease Effective January 1, 2012, the Company occupied corporate office space in Oklahoma City, Oklahoma under a lease with a 67 month term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $329,000 during the year ended December 31, 2012. The monthly rent under the lease increased 9% on August 1, 2012 with no further escalations for the remaining term of the lease. Advisory Services Agreement & Professional Services from Wexford The Company entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of October 11, 2012, under which Wexford provides the Company with general financial and strategic advisory services related to the business in return for an annual fee of $500,000, plus reasonable out-of-pocket expenses. The Advisory Services Agreement has a term of two years commencing on October 18, 2012, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Company terminates such agreement, it is obligated to pay all amounts due through the remaining term. In addition, the Company agreed to pay Wexford to-be-negotiated market-based fees approved by the Company’s independent directors for such services as may be provided by Wexford at the Company’s request in connection with future acquisitions and divestitures, financings or other transactions in which the Company may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to the Company’s day-to-day business or operations. The Company has agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. The Company incurred total costs of $191,000 during the year ended December 31, 2012 under the Advisory Services Agreement. As of December 31, 2012 the Company owed Wexford $113,000 and this amount is included in accounts payable-related party in the accompanying combined consolidated balance sheets. The Company did not incur any costs for professional services from Wexford during the years ended December 31, 2011 and 2010.

- 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

Income Taxes

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. As discussed in Note 1, Diamondback Energy LLC merged with and into Diamondback on October 11, 2012 and accordingly Diamondback will file a consolidated return for the period October 11, 2012 through December 31, 2012. Prior to the Merger, the Predecessors were not subject to corporate income taxes.

The components of federal income tax provision for the year ended December 31, 2012 are as follows:



Deferred tax provision:
Deferred recognized at date of Merger - change in tax status of Predecessors	$	54,142,000
Deferred as a result of operations from October 11, 2012 through December 31, 2012	761,000
Total provision for income taxes	$	54,903,000

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:



Income tax expense at the federal statutory rate (35%)	$	6,434,000
Deduction for pre-merger LLC earnings	(5,717,000		)
Income tax expense at 35% for period from October 11, 2012 through December 31, 2012	717,000
Income tax expense relating to change in tax status	54,142,000
State income tax	42,000
Non-deductible expenses	2,000
Provision for income taxes	$	54,903,000

The components of the Company’s deferred tax assets and liabilities as of December 31, 2012 are as follows:



Current:
Deferred tax assets
Derivative instruments	$	1,857,000
Total current deferred tax assets	1,857,000
Noncurrent:
Deferred tax assets
Net operating loss carryforwards (subject to 20 year expiration)	1,577,000
Stock based compensation	930,000
Total noncurrent deferred tax assets	2,507,000
Deferred tax liabilities
Oil and natural gas properties and equipment	64,636,000
Other	566,000
Total noncurrent deferred tax liabilities	65,202,000
Net noncurrent deferred tax liabilities	62,695,000
Net deferred tax liabilities	$	60,838,000

At December 31, 2012, the Company has a net operating loss carryforward of $4,506,000 that will begin expiring in approximately 2033.

- 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

Derivatives

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

DERIVATIVES

All derivative financial instruments are recorded at fair value. The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in the combined consolidated statements of operations under the caption “Gain (loss) on derivative instruments.”

The Company has used price swap derivatives to reduce price volatility associated with certain of its oil sales. In these swaps, the Company receives the fixed price per the contract and pays a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The counterparties to the Company’s derivative contracts are BNP Paribas (“BNP”) and Hess Corporation (“Hess”), who the Company believes are acceptable credit risks.

On October 4, 2011, in order to lock-in prices on the anticipated base level of production, while at the same time providing downside protection for the borrowing base under the revolving credit facility, the Company executed with BNP, West Texas Intermediate light sweet crude oil swaps on the NYMEX for calendar year 2012 and 2013 of one thousand barrels per day priced at $78.50 and $80.55, respectively.

Set forth below are the summarized amounts, terms and fair values of outstanding instruments held as of December 31, 2012 and December 31, 2011.



			December 31,
Description and Production Period	Volume (Bbls)	Original Strike Price (per Bbl)	2012		2011
			Fair Value Liability		Fair Value Liability
			Fair Value Liability		Fair Value Liability
Crude Oil Swaps:
January – November 2012	335,000	$78.50	$	—	$	6,833,000
December 2012	31,000	$78.50	302,000		594,000
January – December 2013	365,000	$80.55	4,614,000		5,545,000

The Company enters into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, the Company receives a floating price for the hedged commodity and pays a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

In December 2007, the Company placed a swap contract with Hess covering 1,680,000 Bbls of crude oil for the period from January 2008 to December 2012 at various fixed prices. In April 2008, the Company entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of crude oil swaps. In June 2009, the Company entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of crude oil swaps.

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of December 31, 2012 and December 31, 2011, respectively.



				December 31,
Description and Production Period	Volume (Bbls)	Original Strike Price (per Bbl)	Lock-in Price(per Bbl)	2012		2011
				Fair Value Liability		Fair Value Liability
				Fair Value Liability		Fair Value Liability
Crude Oil Swaps:
December 2011	22,500	$82.90	$98.50–$102.20	$	—	$	379,000
January-November 2012	247,500	$85.07	$98.25–$101.80	—		3,554,000
December 2012	22,500	$85.07	$98.25–$101.80	323,000		323,000

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of December 31, 2012 and December 31, 2011, respectively.



				December 31,
Description and Production Period	Volume (Bbls)	Original Strike Price (per Bbl)	Lock-in Price(per Bbl)	2012		2011
				Fair Value Asset		Fair Value Asset
				Fair Value Asset		Fair Value Asset
Crude Oil Swaps:
December 2011	7,500	$82.90	$78.42	$	—	$	34,000
January-November 2012	82,500	$85.07	$80.52	—		375,000
December 2012	7,500	$85.07	$80.52	34,000		34,000

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following summarizes the loss on derivative instruments included in the combined consolidated statements of operations:



	Year Ended December 31,
	2012			2011			2010
Unrealized gain (loss) on open non-hedge derivative instruments	$	8,057,000		$	(12,972,000	)	$	—
Loss on settlement of non-hedge derivative instruments	(5,440,000		)	(37,000		)	(148,000		)
Gain (loss) on derivative instruments	$	2,617,000		$	(13,009,000	)	$	(148,000	)

The Company is required to provide margin deposits to Hess whenever its unrealized losses exceed predetermined credit limits. The Company had a margin deposit held by Hess of zero and $2,326,000 as of December 31, 2012 and December 31, 2011, respectively, which earns interest that is remitted to the Company. As the Company has a master netting agreement with Hess, the Company has offset this margin deposit against its derivative positions.

- 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 Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

The Company measures and discloses fair value in accordance with ASC Topic 820, Fair Value Measurements and Disclosures (“ASC Topic 820”). Fair value is defined as 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. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

ASC Topic 820 describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and December 31, 2011.



		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Cash Collateral⁽¹⁾			Net Fair Value
Financial Liabilities
		December 31, 2012
Derivative instruments		$	—	$	5,205,000	$	—	$	—		$	5,205,000

		December 31, 2011
Derivative instruments		$	—	$	16,785,000	$	—	$	(2,326,000	)	$	14,459,000
(1)	Represents the impact of netting cash collateral with a counterparty with which the right of offset exists.

Level 2 Fair Value Measurements

Derivative instruments-The fair values of the Company’s crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

- 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

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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

Lease Commitments

The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2012.



Year Ending December 31,	Office and Equipment Leases

2013	$	485,000
2014	491,000
2015	501,000
2016	412,000
2017	281,000
Thereafter	25,000
Total	$	2,195,000

In March 2011, the Company began leasing field office space in Midland, Texas from an unrelated party. The lease term is 84 months with equal monthly installments that escalate 3% annually on March 1st of each year. In May 2011, the Company began leasing corporate office space in Midland, Texas from an entity controlled by an affiliate of Wexford. The lease term is 5 years with monthly rent under the lease set to increase approximately 4% annually on June 1st of each year. Effective January 1, 2012, the Company occupied corporate office space in Oklahoma City, Oklahoma under a lease with a 67 month term. The office space is owned by an entity controlled by an affiliate of Wexford. The monthly rent under the lease increased 9% on August 1, 2012 with no further escalations for the remaining term of the lease. The related party leases are also disclosed in Note 9—Related Party Transactions. The following table presents rent expense for the years ended December 31, 2012, 2011 and 2010.



	For the years ended
	December 31,
	2012		2011		2010
Rent Expense	$	547,000	$	74,000	$	—

Fracturing and well stimulation agreement

The Company has a contractual obligation with a third-party service provider for fracturing and well stimulation services. The following is a schedule of minimum future expenditures for fracturing and well stimulation service services as of December 31, 2012.



Year Ending December 31,	Fracturing and Well Stimulation Service Agreements

2013	$	14,400,000
2014	3,600,000
Total	$	18,000,000

Drilling contracts

The Company has committed to short term drilling contracts with Bison Drilling and Field Services LLC under a master service agreement. This master drilling agreement is terminable by either party on 30 day prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. Refer to the related party footnote for additional disclosure regarding Bison.

Defined contribution plan

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at their date of hire. The plan allows eligible employees to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee’s compensation and may make additional discretionary contributions for eligible employees. Employer contributions vest in equal annual installments over a 4 year period. The Company paid $86,000 in contributions to the plan for the year ended December 31, 2012. Prior to 2012, the previous plan was sponsored under the shared service agreements discussed in Note 9—Related Party Transactions and the Company did not directly contribute to the previous plan.

- Definition

The entire disclosure for commitments and contingencies.

+ References

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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Subsequent Events

12 Months Ended

Dec. 31, 2012

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTS

On February 1, 2013, the Company entered into a new commodity contract with Wells Fargo. The derivative is a fixed price oil swap that will settle against the average of the prompt month Brent Crude futures price derived from the International Petroleum Exchange. The following table presents the terms of the contract:



	Aggregate
	volumes (Bbls)	Swap Price		Contract Period
Fixed-Price Swap	365,000	$	109.70	May 2013	-	April 2014

On January 22, 2013, the Company merged Windsor UT into Windsor Permian and the surviving entity was subsequently renamed Diamondback O&G LLC. This merger consolidates the oil and natural gas interests into one company, Diamondback O&G LLC, which is a wholly-owned subsidiary of the Company.

On January 28, 2013, the Company entered into a master drilling agreement effective as of January 1, 2013 with Bison Drilling and Field Services LLC (“Bison”). This agreement supersedes the previous master drilling agreement that was effective as of January 1, 2012. Bison committed to accept orders from the Company for the use of at least two of its rigs, that the Company may require from time-to-time, in the Company’s sole discretion, that one of the rigs be used for horizontal wells. The master drilling agreement provides fixed day rate agreements for vertical and horizontal wells, is terminable by either party on 30 days prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement.

On January 28, 2013, the Company entered into a master field services agreement effective as of January 1, 2013 with Bison. Under the master field services agreement, the Company may order certain field services and purchase or lease goods, equipment or facilities from Bison provided, however, that the Company is not obligated to place, and Bison is not obligated to accept, orders for such services or goods. The master field services agreement is terminable by either party on 30 days’ prior written notice, although neither party will be relieved of its respective obligations arising from a field services contract being performed prior to the termination of the master field services agreement.

Supplemental Information on Oil and Gas Exploration and Production Activities

12 Months Ended

Dec. 31, 2012

Extractive Industries [Abstract]

Oil and Gas Exploration and Production Industries Disclosures [Text Block]

(Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:



	December 31,
	2012			2011
Oil and Natural Gas Properties:
Proved properties	$	576,497,000		$	335,303,000
Unproved properties	121,245,000			4,528,000
Total Oil and Natural Gas Properties	697,742,000			339,831,000
Less Accumulated depreciation, depletion, amortization and impairment	(145,102,000		)	(119,366,000		)
Net oil and natural gas properties capitalized	$	552,640,000		$	220,465,000

Costs incurred in oil and natural gas activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:



	Year Ended December 31,
	2012		2011		2010

Acquisition costs
Proved properties	$	115,760,000	$	—	$	—
Unproved properties	117,395,000		3,704,000		9,930,000
Development costs	106,261,000		75,374,000		48,817,000
Exploration costs	17,547,000		11,226,000		3,920,000
Capitalized asset retirement costs	948,000		297,000		222,000
Total	$	357,911,000	$	90,601,000	$	62,889,000

Results of Operations from Oil and Natural Gas Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and natural gas liquids operations.



	Year Ended December 31,
	2012			2011			2010

Oil, natural gas and natural gas liquid sales	$	74,962,000		$	47,875,000		$	26,442,000
Lease operating expenses	(16,793,000		)	(10,597,000		)	(4,589,000		)
Production taxes	(3,691,000		)	(2,366,000		)	(1,347,000		)
Gathering and transportation	(424,000		)	(202,000		)	(106,000		)
Depreciation, depletion, and amortization	(25,772,000		)	(15,377,000		)	(7,373,000		)
Results of operations from oil, natural gas and natural gas liquids before income taxes	$	28,282,000		$	19,333,000		$	13,027,000

Pro forma information
Pro forma income tax⁽¹⁾	10,083,000
Pro forma results of operations	$	18,199,000



(1	)	Diamondback Energy, Inc. was formed as a holding company on December 30, 2011, and did not conduct any material business operations prior to the Merger. Diamondback Energy, Inc. is a C-Corp under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision as if the Company and the Predecessors were subject to income taxes since December 31, 2011. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences.

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2012 and 2011 were prepared by Ryder Scott Company, L.P., and as of December 31, 2010 were prepared by Pinnacle Energy Services, LLC, both independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The changes in estimated proved reserves are as follows:



			Natural Gas
	Oil		Liquids		Natural Gas
	(Bbls)		(Bbls)		(Mcf)
Proved Developed and Undeveloped Reserves:
As of January 1, 2010	29,230,940		7,522,225		27,481,820
Extensions and discoveries	2,402,204		1,463,206		14,043,737
Revisions of previous estimates	(11,722,263	)	(3,072,486	)	(18,506,630	)
Purchase of reserves in place	—		—		—
Production	(280,721	)	(79,978	)	(323,847	)
Sales of reserves in place	—		—		—

As of December 31, 2010	19,630,160		5,832,967		22,695,080

Extensions and discoveries	1,799,175		466,538		1,884,192
Revisions of previous estimates	(2,879,429	)	(1,163,130	)	(3,614,167	)
Purchase of reserves in place	—		—		—
Production	(449,433	)	(86,815	)	(413,640	)
Sales of reserves in place	—		—		—

As of December 31, 2011	18,100,473		5,049,560		20,551,465

Extensions and discoveries	3,106,433		869,741		3,759,684
Revisions of previous estimates	(1,464,243	)	(5,811	)	383,335
Purchase of reserves in place	7,210,482		2,521,053		10,709,180
Production	(756,286	)	(183,114	)	(833,516	)
Sales of reserves in place	—		—		—

As of December 31, 2012	26,196,859		8,251,429		34,570,148

Proved Developed Reserves:
January 1, 2010	1,954,060		591,532		2,453,750
December 31, 2010	3,371,460		1,126,431		4,336,720
December 31, 2011	3,949,099		1,263,711		5,285,945
December 31, 2012	7,189,367		2,999,440		12,864,941

Proved Undeveloped Reserves:
January 1, 2010	27,276,880		6,930,693		25,028,070
December 31, 2010	16,258,700		4,706,536		18,358,360
December 31, 2011	14,151,375		3,785,850		15,265,520
December 31, 2012	19,007,492		5,251,989		21,705,207

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

The Company experienced downward reserve revisions in estimated proved oil and natural gas liquid reserves in 2012. These downward revisions were primarily a result from lower product pricing in 2012 as compared to 2011 causing wells to reach their economic limit sooner. The upward revision in natural gas reserves is the result of higher producing natural gas to oil ratios than previously projected, which more than offset the reduction resulting from lower natural gas prices.

The Company experienced downward reserve revisions in estimated proved reserves in 2011. These downward revisions were primarily the result of negative revisions in proved undeveloped wells due to offset well performance; exclusion of proved undeveloped locations that were not scheduled to be drilled within the next five years; and the movement of reserves previously categorized as proved undeveloped to probable reserves due to changes in booking methodology used by our independent petroleum engineers as well as performance of wells in one prospect area.

The Company experienced downward reserve revisions in 2010, due to undeveloped locations being scheduled for development beyond five years and thus being excluded from proved reserves.

Standardized Measure of Discounted Future Net Cash Flows

The following information has been prepared in accordance with the provisions of the FASB Codification, Topic 932– “Extractive Activities—Oil and Gas.” The standardized measure of discounted future net cash flows are based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2012, 2011 and 2010.



	December 31,
	2012			2011			2010
Future cash inflows	$	2,769,485,000		$	2,049,520,000		$	1,856,294,000
Future development costs	(541,445,000		)	(410,350,000		)	(398,305,000		)
Future production costs	(773,611,000		)	(497,808,000		)	(384,916,000		)
Future production taxes	(140,758,000		)	(104,856,000		)	(126,090,000		)
Future income tax expenses	(334,903,000		)	—			—

Future net cash flows	978,768,000			1,036,506,000			946,983,000
10% discount to reflect timing of cash flows	(611,548,000		)	(671,894,000		)	(607,982,000		)

Standardized measure of discounted future net cash flows	$	367,220,000		$	364,612,000		$	339,001,000

In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.



	December 31,
	2012		2011		2010
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	88.13	$	93.09	$	77.61
Natural gas (per Mcf)	$	2.86	$	3.91	$	4.14
Natural gas liquids (per Bbl)	$	43.88	$	56.33	$	40.74

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:



	Year Ended December 31,
	2012			2011			2010
Standardized measure of discounted future net cash flows at the beginning of the period	$	364,612,000		$	339,001,000		$	392,919,000
Sales of oil and natural gas, net of production costs	(54,208,000		)	(34,711,000		)	(20,401,000		)
Purchase of minerals in place	107,897,000			—			—
Extensions and discoveries, net of future development costs	79,293,000			73,571,000			59,414,000
Previously estimated development costs incurred during the period	88,849,000			87,530,000			52,932,000
Net changes in prices and production costs	(76,515,000		)	82,364,000			178,198,000
Changes in estimated future development costs	8,309,000			(82,855,000		)	(23,992,000		)
Revisions of previous quantity estimates	(22,882,000		)	(98,533,000		)	(292,306,000		)
Sales of reserves in place, net of future development costs	—			—			—
Accretion of discount	36,461,000			33,900,000			39,292,000
Net change in income taxes	(125,542,000		)	—			—
Net changes in timing of production and other	(39,054,000		)	(35,655,000		)	(47,055,000		)

Standardized measure of discounted future net cash flows at the end of the period	$	367,220,000		$	364,612,000		$	339,001,000

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

QUARTERLY FINANCIAL DATA (Unaudited)

The Company’s unaudited quarterly financial data for 2012 and 2011 is summarized below.



	2012
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Revenues	$	16,351,000	$	16,030,000	$	16,814,000	$	25,767,000
Income from operations	6,737,000		4,307,000		4,086,000		2,177,000
Income tax expense	—		—		—		54,903,000
Net income (loss)	$	1,477,000	$	13,624,000	$	452,000	$	(52,074,000	)

Pro forma information
Income before income taxes	$	1,477,000	$	13,624,000	$	452,000	$	2,829,000
Pro forma provision for income taxes	526,000		4,857,000		161,000		1,009,000
Pro forma net income	$	951,000	$	8,767,000	$	291,000	$	1,820,000
Pro forma earnings per share:
Basic	$	0.06	$	0.60	$	0.02	$	0.05
Diluted	$	0.06	$	0.60	$	0.02	$	0.05

	2011
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Revenues	$	12,087,000	$	11,572,000	$	11,216,000	$	14,491,000
Income from operations	3,328,000		4,067,000		2,928,000		4,824,000
Net income (loss)	$	2,824,000	$	3,453,000	$	2,205,000	$	(8,868,000	)

Pro Forma Income Taxes

Pro Forma Earnings per Share

- 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

Organization and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Use of Estimates

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents.

Accounts Receivable

Derivative Instruments

Fair Value of Financial Instruments

Oil and Natural Gas Properties

Other Property and Equipment

Asset Retirement Obligations

Impairment of Long-Lived Assets

Capitalized Interest

Inventories

Inventories are stated at the lower of cost or market and consist of the following:



	December 31,
	2012		2011
Tubular goods and equipment	$	5,725,000	$	5,631,000
Crude oil	470,000		376,000
	$	6,195,000	$	6,007,000

Debt issuance costs

Revenue Recognition

Revenue and Royalties Payable

Revenue Recognition

Investments

Accounting for Stock-Based Compensation

Environmental Compliance and Remediation

Income Taxes

Fair Value Measurement

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

Organization and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Inventory, Stated at lower of Cost or Market

Inventories are stated at the lower of cost or market and consist of the following:



	December 31,
	2012		2011
Tubular goods and equipment	$	5,725,000	$	5,631,000
Crude oil	470,000		376,000
	$	6,195,000	$	6,007,000

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2012

Business Combinations [Abstract]

Schedule of business acquisitions

The acquisition-date fair value of the consideration transferred totaled $220,636,000, which consisted of the following:



Common Stock (7,914,036 shares)	$	138,496,000
Promissory note paid in full from IPO proceeds	63,590,000
Closing adjustment payable	18,550,000
Total	$	220,636,000

Schedule of assets acquired and liabilities assumed at acquisition date



Proved oil and natural gas properties	$	115,760,000
Unevaluated oil and natural gas properties	111,373,000
Asset retirement obligations	(562,000		)
Deferred income tax liability	(5,935,000		)
Total fair value of net assets	$	220,636,000

Schedule of business acquisition pro forma

The following unaudited summary pro forma combined consolidated statement of operations data of Diamondback for the years ended December 31, 2012 and 2011 has been prepared to give effect to the acquisition as if it had occurred on January 1, 2011. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisition occurred on January 1, 2011. The pro forma data also necessarily exclude various operation expenses related to the Gulfport properties and the financial statements should not be viewed as indicative of operations in future periods. As the current operator of the properties acquired by the Company upon completion of the Gulfport transaction, the Company does not expect any material impact from these transactions on its existing employees or infrastructure.



	Pro Forma
	(Unaudited)
	Year Ended December 31,
	2012			2011
Pro forma total revenues	$	97,455,000		$	72,418,000
Pro forma income from operations	24,064,000			23,189,000
Pro forma net income (loss)	(29,764,000		)	7,666,000		⁽¹⁾

(1) For 2011, this amount does not include a pro forma income tax provision relating to becoming subject to income taxes as a result of the Merger.

- Definition

Tabular disclosure of pro forma results of operations for a material business acquisition or series of individually immaterial business acquisitions that are material in the aggregate.

+ References + Details

- Definition

Tabular disclosure of a material business combination completed during the period, including background, timing, and recognized assets and liabilities. This table does not include leveraged buyouts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=7659399&loc=d3e1486-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7659399&loc=d3e1392-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 51
-Subparagraph a
-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 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph F4
-Subparagraph e
-Appendix F

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 52
-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 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-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

Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment [Abstract]

Property and Equipment

Property and equipment includes the following:



	December 31,
	2012			2011
Oil and natural gas properties:
Subject to depletion	$	576,497,000		$	335,303,000
Not subject to depletion-acquisition costs
Incurred in 2012	117,395,000			—
Incurred in 2011	1,670,000			1,689,000
Incurred in 2010	1,647,000			2,306,000
Incurred in 2009	533,000			533,000
Total not subject to depletion	121,245,000			4,528,000

Gross oil and natural gas properties	697,742,000			339,831,000
Less accumulated depreciation, depletion, amortization and impairment	(145,102,000		)	(119,366,000		)
Oil and natural gas properties, net	552,640,000			220,465,000

Other property and equipment	2,337,000			1,017,000
Less accumulated depreciation	(735,000		)	(333,000		)
Other property and equipment, net	1,602,000			684,000

Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	554,242,000		$	221,149,000

Asset Retirement Obligation (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

The following table describes the changes to the Company’s ARO liability for the following periods:



	Year Ended December 31,
	2012			2011		2010
Asset retirement obligation, beginning of period	$	1,104,000		$	742,000	$	482,000
Additional liability incurred	201,000			297,000		222,000
Liabilities acquired	562,000			—		—
Liabilities settled	(5,000		)	—		—
Accretion expense	98,000			65,000		38,000
Revisions in estimated liabilities	185,000			—		—
Asset retirement obligation, end of period	2,145,000			1,104,000		742,000
Less current portion	20,000			—		—
Asset retirement obligations - long-term	$	2,125,000		$	1,104,000	$	742,000

Equity Method Investments (Tables)

12 Months Ended

Dec. 31, 2012

Equity Method Investments and Joint Ventures [Abstract]

Schedule of financial information for equity method investments

As of December 31, 2011, the Company had a 27.7% ownership in Bison. The table below summarizes financial information for Bison as of December 31, 2011.



	December 31, 2011
Current Assets	$	4,438,000
Property and equipment, net	21,708,000
Other assets	880,000
Current liabilities	2,419,000
Equity	24,607,000

The table below summarizes financial information for Muskie as of December 31, 2011.



	December 31, 2011
Current assets	$	994,000
Property and equipment, net	7,585,000
Current liabilities	27,000
Equity	8,552,000

Debt (Tables)

12 Months Ended

Dec. 31, 2012

Debt Disclosure [Abstract]

Financial Covenants

Further, the amendment modified certain financial ratios, the current requirements of which are described below.



Financial Covenant			Required Ratio
Ratio of EBITDAX to interest expense, as defined in the credit agreement			Not less than 2.5 to 1.0
Ratio of total debt to EBITDAX			Not greater than 4.0 to 1.0
Ratio of debt under revolving credit agreement to EBITDAX			Not greater than 3.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement			Not less than 1.0 to 1.0

Stockholders' Equity and Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2012

Equity [Abstract]

Schedule of reconciliation of pro forma basic and diluted net income per share

A reconciliation of the components of pro forma basic and diluted earnings per common share is presented in the table below:



	2012
				Per
	Income		Shares	Share
Basic:
Pro forma net income attributable to common stock	$	11,829,000	19,720,734	$	0.60
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	—	3,040
Diluted:
Pro forma net income attributable to common stock	$	11,829,000	19,723,774	$	0.60

Stock and Equity Based Compensation (Tables)

12 Months Ended

Dec. 31, 2012

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

The effects of the stock-based compensation plans and related costs

The following table presents the effects of the equity and stock-based compensation plans and related costs:



	2012		2011
General and administrative expenses	$	3,757,000	$	438,000
Stock-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	2,537,000		106,000
Related income tax benefit	930,000		—

Significant assumptions used to estimate fair value of the options to acquire membership interests

A summary of the significant assumptions used to estimate the fair value of the options to acquire membership interests during the year ended December 31, 2011 was as follows:



Expected term	5 years
Risk-free interest rate	0.96%
Expected volatility	45.5%
Expected dividend yield	0.00%

The Company estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The Company does not have a long history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards and remaining vesting term at the modification date. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero. All such amounts represent the weighted-average amounts for each year.



	2012
Grant-date fair value	$	4.41
Expected volatility	40.0		%
Expected dividend yield	0.0		%
Expected term (in years)	3.8
Risk-free rate	0.33		%

Schedule of stock option activity

The following table presents a summary of the Company’s outstanding stock options.



		Weighted Average
		Exercise		Remaining	Intrinsic
	Options	Price		Term	Value
				(In years)
Outstanding at December 31, 2011	—	$	—
Granted	850,000	$	17.50
Exercised	—	$	—
Outstanding at December 31, 2012	850,000	$	17.50	3.58	$	1,377,000

Vested and Expected to vest at December 31, 2012	850,000	$	17.50	3.58	$	1,377,000
Exercisable at December 31, 2012	212,500	$	17.50	3.55	$	344,000

Summarized below are the grant dates with the total exercise prices and total fair values of the underlying options:



Grants Made During the Months Ended	Membership Interest Granted	Exercise Price		Fair Value at Date of Grant
April 2011	1.00%	$	3,600,000	$	1,453,000
August 2011	1.20%	6,000,000		1,384,000
September 2011	1.25%	5,900,000		1,533,000
November 2011	0.25%	1,250,000		288,000
	3.70%	$	16,750,000	$	4,658,000

Summary of restricted stock awards and units

The Company estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents a summary of the Company’s restricted stock awards and units.



			Weighted Average
	Restricted Stock		Grant-Date
	Awards & Units		Fair Value
Unvested at December 31, 2011	—		$	—
Granted	279,046		$	17.50
Vested	(72,539	)	$	17.50
Forfeited	—		$	—
Unvested at December 31, 2012	206,507		$	17.50

- Definition

Tabular disclosure of the allocation of equity-based compensation costs to a given line item on the balance sheet and income statement for the period. This may include the reporting line for the costs and the amount capitalized and expensed.

+ References + Details

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The components of federal income tax provision for the year ended December 31, 2012 are as follows:



Deferred tax provision:
Deferred recognized at date of Merger - change in tax status of Predecessors	$	54,142,000
Deferred as a result of operations from October 11, 2012 through December 31, 2012	761,000
Total provision for income taxes	$	54,903,000

Schedule of Effective Income Tax Rate Reconciliation

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:



Income tax expense at the federal statutory rate (35%)	$	6,434,000
Deduction for pre-merger LLC earnings	(5,717,000		)
Income tax expense at 35% for period from October 11, 2012 through December 31, 2012	717,000
Income tax expense relating to change in tax status	54,142,000
State income tax	42,000
Non-deductible expenses	2,000
Provision for income taxes	$	54,903,000

Schedule of Deferred Tax Assets and Liabilities

The components of the Company’s deferred tax assets and liabilities as of December 31, 2012 are as follows:



Current:
Deferred tax assets
Derivative instruments	$	1,857,000
Total current deferred tax assets	1,857,000
Noncurrent:
Deferred tax assets
Net operating loss carryforwards (subject to 20 year expiration)	1,577,000
Stock based compensation	930,000
Total noncurrent deferred tax assets	2,507,000
Deferred tax liabilities
Oil and natural gas properties and equipment	64,636,000
Other	566,000
Total noncurrent deferred tax liabilities	65,202,000
Net noncurrent deferred tax liabilities	62,695,000
Net deferred tax liabilities	$	60,838,000

At December 31, 2012, the Company has a net operating loss carryforward of $4,506,000 that will begin expiring in approximately 2033.

Derivatives (Tables)

12 Months Ended

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summarized amounts, terms and fair values of outstanding instruments:

Set forth below are the summarized amounts, terms and fair values of outstanding instruments held as of December 31, 2012 and December 31, 2011.



			December 31,
Description and Production Period	Volume (Bbls)	Original Strike Price (per Bbl)	2012		2011
			Fair Value Liability		Fair Value Liability
			Fair Value Liability		Fair Value Liability
Crude Oil Swaps:
January – November 2012	335,000	$78.50	$	—	$	6,833,000
December 2012	31,000	$78.50	302,000		594,000
January – December 2013	365,000	$80.55	4,614,000		5,545,000

The following table presents the terms of the contract:



	Aggregate
	volumes (Bbls)	Swap Price		Contract Period
Fixed-Price Swap	365,000	$	109.70	May 2013	-	April 2014

Summarized amounts, terms and fair values of locked-in swaps from settlements:

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of December 31, 2012 and December 31, 2011, respectively.



				December 31,
Description and Production Period	Volume (Bbls)	Original Strike Price (per Bbl)	Lock-in Price(per Bbl)	2012		2011
				Fair Value Liability		Fair Value Liability
				Fair Value Liability		Fair Value Liability
Crude Oil Swaps:
December 2011	22,500	$82.90	$98.50–$102.20	$	—	$	379,000
January-November 2012	247,500	$85.07	$98.25–$101.80	—		3,554,000
December 2012	22,500	$85.07	$98.25–$101.80	323,000		323,000

Summarized amounts, terms and fair values of locked-in swaps from settlements:

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of December 31, 2012 and December 31, 2011, respectively.



				December 31,
Description and Production Period	Volume (Bbls)	Original Strike Price (per Bbl)	Lock-in Price(per Bbl)	2012		2011
				Fair Value Asset		Fair Value Asset
				Fair Value Asset		Fair Value Asset
Crude Oil Swaps:
December 2011	7,500	$82.90	$78.42	$	—	$	34,000
January-November 2012	82,500	$85.07	$80.52	—		375,000
December 2012	7,500	$85.07	$80.52	34,000		34,000

Summarizes the loss on derivative contracts included in the consolidated statements of operations:

The following summarizes the loss on derivative instruments included in the combined consolidated statements of operations:



	Year Ended December 31,
	2012			2011			2010
Unrealized gain (loss) on open non-hedge derivative instruments	$	8,057,000		$	(12,972,000	)	$	—
Loss on settlement of non-hedge derivative instruments	(5,440,000		)	(37,000		)	(148,000		)
Gain (loss) on derivative instruments	$	2,617,000		$	(13,009,000	)	$	(148,000	)

- 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

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624163-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Fair Value Disclosures [Abstract]

Fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis:

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2012 and December 31, 2011.



		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Cash Collateral⁽¹⁾			Net Fair Value
Financial Liabilities
		December 31, 2012
Derivative instruments		$	—	$	5,205,000	$	—	$	—		$	5,205,000

		December 31, 2011
Derivative instruments		$	—	$	16,785,000	$	—	$	(2,326,000	)	$	14,459,000
(1)	Represents the impact of netting cash collateral with a counterparty with which the right of offset exists.

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Schedule of minimum future lease payments

The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2012.



Year Ending December 31,	Office and Equipment Leases

2013	$	485,000
2014	491,000
2015	501,000
2016	412,000
2017	281,000
Thereafter	25,000
Total	$	2,195,000

Schedule of rent expense

The following table presents rent expense for the years ended December 31, 2012, 2011 and 2010.



	For the years ended
	December 31,
	2012		2011		2010
Rent Expense	$	547,000	$	74,000	$	—

Schedule of minimum future expenditures for fracturing and well stimulation services



Year Ending December 31,	Fracturing and Well Stimulation Service Agreements

2013	$	14,400,000
2014	3,600,000
Total	$	18,000,000

Subsequent Events (Tables)

12 Months Ended

Dec. 31, 2012

Subsequent Events [Abstract]

Schedule of Derivative Instruments

Set forth below are the summarized amounts, terms and fair values of outstanding instruments held as of December 31, 2012 and December 31, 2011.



			December 31,
Description and Production Period	Volume (Bbls)	Original Strike Price (per Bbl)	2012		2011
			Fair Value Liability		Fair Value Liability
			Fair Value Liability		Fair Value Liability
Crude Oil Swaps:
January – November 2012	335,000	$78.50	$	—	$	6,833,000
December 2012	31,000	$78.50	302,000		594,000
January – December 2013	365,000	$80.55	4,614,000		5,545,000

The following table presents the terms of the contract:



	Aggregate
	volumes (Bbls)	Swap Price		Contract Period
Fixed-Price Swap	365,000	$	109.70	May 2013	-	April 2014

- Definition

+ References

+ Details

Supplemental Information on Oil and Gas Exploration and Production Activities (Tables)

12 Months Ended

Dec. 31, 2012

Extractive Industries [Abstract]

Aggregate capitalized costs related to oil and natural gas production activities

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:



	December 31,
	2012			2011
Oil and Natural Gas Properties:
Proved properties	$	576,497,000		$	335,303,000
Unproved properties	121,245,000			4,528,000
Total Oil and Natural Gas Properties	697,742,000			339,831,000
Less Accumulated depreciation, depletion, amortization and impairment	(145,102,000		)	(119,366,000		)
Net oil and natural gas properties capitalized	$	552,640,000		$	220,465,000

Costs incurred in oil and natural gas property acquisition, exploration, and development activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:



	Year Ended December 31,
	2012		2011		2010

Acquisition costs
Proved properties	$	115,760,000	$	—	$	—
Unproved properties	117,395,000		3,704,000		9,930,000
Development costs	106,261,000		75,374,000		48,817,000
Exploration costs	17,547,000		11,226,000		3,920,000
Capitalized asset retirement costs	948,000		297,000		222,000
Total	$	357,911,000	$	90,601,000	$	62,889,000

Results of operationf from oil and natural gas producing activities



	Year Ended December 31,
	2012			2011			2010

Oil, natural gas and natural gas liquid sales	$	74,962,000		$	47,875,000		$	26,442,000
Lease operating expenses	(16,793,000		)	(10,597,000		)	(4,589,000		)
Production taxes	(3,691,000		)	(2,366,000		)	(1,347,000		)
Gathering and transportation	(424,000		)	(202,000		)	(106,000		)
Depreciation, depletion, and amortization	(25,772,000		)	(15,377,000		)	(7,373,000		)
Results of operations from oil, natural gas and natural gas liquids before income taxes	$	28,282,000		$	19,333,000		$	13,027,000

Pro forma information
Pro forma income tax⁽¹⁾	10,083,000
Pro forma results of operations	$	18,199,000



(1	)	Diamondback Energy, Inc. was formed as a holding company on December 30, 2011, and did not conduct any material business operations prior to the Merger. Diamondback Energy, Inc. is a C-Corp under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision as if the Company and the Predecessors were subject to income taxes since December 31, 2011. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences.

Schedule of changes in estimated proved reserves

The changes in estimated proved reserves are as follows:



			Natural Gas
	Oil		Liquids		Natural Gas
	(Bbls)		(Bbls)		(Mcf)
Proved Developed and Undeveloped Reserves:
As of January 1, 2010	29,230,940		7,522,225		27,481,820
Extensions and discoveries	2,402,204		1,463,206		14,043,737
Revisions of previous estimates	(11,722,263	)	(3,072,486	)	(18,506,630	)
Purchase of reserves in place	—		—		—
Production	(280,721	)	(79,978	)	(323,847	)
Sales of reserves in place	—		—		—

As of December 31, 2010	19,630,160		5,832,967		22,695,080

Extensions and discoveries	1,799,175		466,538		1,884,192
Revisions of previous estimates	(2,879,429	)	(1,163,130	)	(3,614,167	)
Purchase of reserves in place	—		—		—
Production	(449,433	)	(86,815	)	(413,640	)
Sales of reserves in place	—		—		—

As of December 31, 2011	18,100,473		5,049,560		20,551,465

Extensions and discoveries	3,106,433		869,741		3,759,684
Revisions of previous estimates	(1,464,243	)	(5,811	)	383,335
Purchase of reserves in place	7,210,482		2,521,053		10,709,180
Production	(756,286	)	(183,114	)	(833,516	)
Sales of reserves in place	—		—		—

As of December 31, 2012	26,196,859		8,251,429		34,570,148

Proved Developed Reserves:
January 1, 2010	1,954,060		591,532		2,453,750
December 31, 2010	3,371,460		1,126,431		4,336,720
December 31, 2011	3,949,099		1,263,711		5,285,945
December 31, 2012	7,189,367		2,999,440		12,864,941

Proved Undeveloped Reserves:
January 1, 2010	27,276,880		6,930,693		25,028,070
December 31, 2010	16,258,700		4,706,536		18,358,360
December 31, 2011	14,151,375		3,785,850		15,265,520
December 31, 2012	19,007,492		5,251,989		21,705,207

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

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2012, 2011 and 2010.



	December 31,
	2012			2011			2010
Future cash inflows	$	2,769,485,000		$	2,049,520,000		$	1,856,294,000
Future development costs	(541,445,000		)	(410,350,000		)	(398,305,000		)
Future production costs	(773,611,000		)	(497,808,000		)	(384,916,000		)
Future production taxes	(140,758,000		)	(104,856,000		)	(126,090,000		)
Future income tax expenses	(334,903,000		)	—			—

Future net cash flows	978,768,000			1,036,506,000			946,983,000
10% discount to reflect timing of cash flows	(611,548,000		)	(671,894,000		)	(607,982,000		)

Standardized measure of discounted future net cash flows	$	367,220,000		$	364,612,000		$	339,001,000

Average first-day-of-the-month price for oil, natural gas and natural gas liquids

In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.



	December 31,
	2012		2011		2010
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	88.13	$	93.09	$	77.61
Natural gas (per Mcf)	$	2.86	$	3.91	$	4.14
Natural gas liquids (per Bbl)	$	43.88	$	56.33	$	40.74

Schedule of principal changes in the standardized measure of discounted future net cash flows attributable to proved reserves

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:



	Year Ended December 31,
	2012			2011			2010
Standardized measure of discounted future net cash flows at the beginning of the period	$	364,612,000		$	339,001,000		$	392,919,000
Sales of oil and natural gas, net of production costs	(54,208,000		)	(34,711,000		)	(20,401,000		)
Purchase of minerals in place	107,897,000			—			—
Extensions and discoveries, net of future development costs	79,293,000			73,571,000			59,414,000
Previously estimated development costs incurred during the period	88,849,000			87,530,000			52,932,000
Net changes in prices and production costs	(76,515,000		)	82,364,000			178,198,000
Changes in estimated future development costs	8,309,000			(82,855,000		)	(23,992,000		)
Revisions of previous quantity estimates	(22,882,000		)	(98,533,000		)	(292,306,000		)
Sales of reserves in place, net of future development costs	—			—			—
Accretion of discount	36,461,000			33,900,000			39,292,000
Net change in income taxes	(125,542,000		)	—			—
Net changes in timing of production and other	(39,054,000		)	(35,655,000		)	(47,055,000		)

Standardized measure of discounted future net cash flows at the end of the period	$	367,220,000		$	364,612,000		$	339,001,000

- 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
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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 19
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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.

+ 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

Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Data

The Company’s unaudited quarterly financial data for 2012 and 2011 is summarized below.



	2012
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Revenues	$	16,351,000	$	16,030,000	$	16,814,000	$	25,767,000
Income from operations	6,737,000		4,307,000		4,086,000		2,177,000
Income tax expense	—		—		—		54,903,000
Net income (loss)	$	1,477,000	$	13,624,000	$	452,000	$	(52,074,000	)

Pro forma information
Income before income taxes	$	1,477,000	$	13,624,000	$	452,000	$	2,829,000
Pro forma provision for income taxes	526,000		4,857,000		161,000		1,009,000
Pro forma net income	$	951,000	$	8,767,000	$	291,000	$	1,820,000
Pro forma earnings per share:
Basic	$	0.06	$	0.60	$	0.02	$	0.05
Diluted	$	0.06	$	0.60	$	0.02	$	0.05

	2011
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Revenues	$	12,087,000	$	11,572,000	$	11,216,000	$	14,491,000
Income from operations	3,328,000		4,067,000		2,928,000		4,824,000
Net income (loss)	$	2,824,000	$	3,453,000	$	2,205,000	$	(8,868,000	)

Organization and Summary of Significant Accounting Policies Organization and Description of Buinsess (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 23, 2012	Oct. 17, 2012	Oct. 11, 2012
Initial Public Offering [Line Items]
First day tax expense to net income from continuing operations recorded to establish a net deferred tax liability for differences between book and tax differences			$ 54,142
Issuance of Equity
Initial Public Offering [Line Items]
Shares issued upon initial public offering	1,875,000	14,375,000	12,500,000
Common stock issued pursuant to underwriters over allotment option		1,875,000
Stock price per share at initial public offerring		$ 17.50	$ 17.50
Company received net proceeds from initial public offerring	$ 234,100	$ 234,100

- Definition

The sum of the current income tax expense or benefit and the deferred income tax expense or benefit pertaining to pretax Income or Loss from continuing operations; income tax expense or benefit may include interest and penalties on tax uncertainties based on the entity's accounting policy.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Number 109
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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 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name FASB Interpretation (FIN)
-Number 48
-Paragraph 15, 16, 19
-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

Organization and Summary of Significant Accounting Policies Reclassifications (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($)
Prepaid Expenses and Other Current Assets
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Prepaid costs related to oil and natural gas properties reclassified	$ 92

Organization and Summary of Significant Accounting Policies Oil and Natural Gas Properties (Details)	12 Months Ended
	Dec. 31, 2012 USD ($) $ / bbl	Dec. 31, 2011 USD ($) $ / bbl	Dec. 31, 2010 USD ($) $ / bbl
Property, Plant and Equipment
Amortization expense per physical unit of production \| $ / bbl	23.90	25.41	17.78
Depreciation, depletion and amortization	$ 25,772,000	$ 15,377,000	$ 7,373,000
Capitalized costs, proved oil and natural gas properties, net, discount percentage	10.00%
Depreciation expense	$ 501,000	727,000	772,000
Interest Costs Capitalized	$ 0	$ 0	$ 150,000
Minimum
Property, Plant and Equipment
Estimated useful life of property and equipment	3 years
Maximum
Property, Plant and Equipment
Estimated useful life of property and equipment	15 years

Organization and Summary of Significant Accounting Policies Inventory (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Inventory, Net	$ 6,195	$ 6,007
Tubular Goods and Equipment
Inventory, Net	5,725	5,631
Tubular Goods
Inventory Held by others	0	1,094
Crude Oil
Inventory, Net	$ 470	$ 376

Organization and Summary of Significant Accounting Policies Debt Issuance Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Line of Credit
Debt Issuance Cost	$ 1,115	$ 1,168

Organization and Summary of Significant Accounting Policies Concentrations (Details) - Sales [Member] - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Plains Marketing, LP
Concentration Risk [Line Items]
Concentration Risk, Percentage	53.00%
Occidental Energy Marketing, Inc.
Concentration Risk [Line Items]
Concentration Risk, Percentage	16.00%
Andrews Oil Buyers, Inc.
Concentration Risk [Line Items]
Concentration Risk, Percentage	10.00%
Windsor Midstream LLC
Concentration Risk [Line Items]
Concentration Risk, Percentage		79.00%	79.00%

Acquisitions Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended
	Oct. 11, 2012	Dec. 31, 2012
Business Combinations [Abstract]
Consideration transferred	$ 220,636
Common stock issued for acquistion	7,914,036
Price per share of common stock issued	$ 17.50
Revenue of acquiree since acquisition date included in consolidated income statement		$ 7,353
Earnings of acquiree since acquisition date included in consolidated income statement		$ 2,260

- Definition

This element represents the acquisition-date fair value of the total consideration transferred which consists of the sum of the acquisition-date fair values of the assets transferred by the acquirer, the liabilities incurred by the acquirer to former owners of the acquiree, and the equity interests issued by the acquirer.

+ References + Details

Acquisitions Acquistion Date Fair Value of Consideration Transferred (Details) $ in Thousands	Oct. 11, 2012 USD ($) shares
Business Combinations [Abstract]
Common Stock (7,914,036 shares)	$ 138,496
Common stock issued for acquistion \| shares	7,914,036
Promissory note paid in full from IPO proceeds	$ 63,590
Closing adjustment payable	18,550
Total	$ 220,636

- Definition

The acquisition-date fair value of the equity interests of the acquirer, including the number of instruments or interests issued or issuable in consideration for the business combination.

+ References + Details

- Definition

Fair Value of the liabilities incurred by the acquirer to former owners of the acquiree, including the fair value of any contingent consideration. If liabilities transferred as consideration remain within the combined entity after the business combination (for example, because the assets or liabilities were transferred to the acquiree rather than to its former owners), and the acquirer therefore retains control of them; in that situation, the acquirer measures those liabilities at their carrying amounts immediately before the acquisition date.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 30
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6911251&loc=d3e6613-128477

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 30
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6911251&loc=d3e6578-128477

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 25
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6911189&loc=d3e6405-128476

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 68
-Subparagraph f(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 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141
-Paragraph 51
-Subparagraph 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 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 141R
-Paragraph 39, 40, 41
-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

+ References + Details

- Definition

Number of shares of stock issued during the period pursuant to acquisitions.

+ References + Details

Acquisitions Estimated Fair Value of Assets Acquired and Liabilities Assummed (Details) $ in Thousands	Oct. 11, 2012 USD ($)
Business Combinations [Abstract]
Proved oil and natural gas properties	$ 115,760
Unevaluated oil and natural gas properties	111,373
Asset retirement obligations	(562)
Deferred income tax liability	(5,935)
Total fair value of net assets	$ 220,636

Acquisitions Summary Pro Forma Combined Statement of Operations (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Business Combinations [Abstract]

Pro forma total revenues

$ 97,455

$ 72,418

Pro forma income from operations

24,064

23,189

Pro forma net income (loss)

$ (29,764)

$ 7,666

^[1]

[1]	For 2011, this amount does not include a pro forma income tax provision relating to becoming subject to income taxes as a result of the Merger.

Property and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment
Subject to depletion	$ 576,497	$ 335,303
Oil and Natural Gas Properties:
Not subject to depletion-acquisition costs	121,245	4,528
Gross oil and natural gas properties	697,742	339,831
Less Accumulated depreciation, depletion, amortization and impairment	(145,102)	(119,366)
Net oil and natural gas properties capitalized	552,640	220,465
Other property and equipment	2,337	1,017
Less accumulated depreciation	(145,837)	(119,699)
Other property and equipment, net	1,602	684
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	554,242	221,149
Capitalized general and administrative costs	4,872	871	$ 0
Other property and equipment
Oil and Natural Gas Properties:
Less accumulated depreciation	(735)	(333)
Incurred in 2012
Oil and Natural Gas Properties:
Not subject to depletion-acquisition costs	117,395	0
Incurred in 2011
Oil and Natural Gas Properties:
Not subject to depletion-acquisition costs	1,670	1,689
Incurred in 2010
Oil and Natural Gas Properties:
Not subject to depletion-acquisition costs	1,647	2,306
Incurred in 2009
Oil and Natural Gas Properties:
Not subject to depletion-acquisition costs	$ 533	$ 533
Minimum
Oil and Natural Gas Properties:
Number of years until unevaluated propertes are included in full cost pool	3 years
Maximum
Oil and Natural Gas Properties:
Number of years until unevaluated propertes are included in full cost pool	5 years

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Changes in ARO liability
Asset retirement obligation, beginning of period	$ 1,104	$ 742	$ 482
Additional liability incurred	201	297	222
Liabilities acquired	562	0	0
Liabilities settled	(5)	0	0
Accretion expense	98	65	38
Revision in estimated liabilities	185	0	0
Asset retirement obligation, end of period	2,145	1,104	742
Less current portion	20	0	0
Asset retirement obligations - long-term	$ 2,125	$ 1,104	$ 742

Equity Method Investments (Details) $ in Thousands			1 Months Ended			12 Months Ended
Equity Method Investments (Details) $ in Thousands	Jun. 15, 2012 USD ($)	May 02, 2011 drilling_rig	Sep. 30, 2011	Apr. 30, 2011 drilling_rig	Dec. 31, 2010 drilling_rig	Dec. 31, 2011 USD ($)	Oct. 07, 2011 USD ($)
Schedule of Equity Method Investments
Payments to acquire land and other capital items						$ 4,200
Bison Drilling
Schedule of Equity Method Investments
Number of drilling rigs \| drilling_rig		4
Number of drilling rigs purchased during the period \| drilling_rig				2	2
Sale of its membership interest to a related party			25.00%
Distribution of equity method investment between entities under common control	$ 6,437
Equity interest in Muskie						27.70%
Muskie Holdings
Schedule of Equity Method Investments
Equity interest in Muskie	33.00%						48.60%
Amount paid for land and the value of property contributed							$ 4,200

Equity Method Investments (Financial Information of Equity Method Investments) (Details) $ in Thousands	Dec. 31, 2011 USD ($)
Bison Drilling
Schedule of Equity Method Investments
Current Assets	$ 4,438
Property and equipment, net	21,708
Other assets	880
Current liabilities	2,419
Equity	24,607
Muskie Holdings
Schedule of Equity Method Investments
Current Assets	994
Property and equipment, net	7,585
Current liabilities	27
Equity	$ 8,552

- Definition

The amount of current assets reported by an equity method investment of the entity.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33918-111571

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33912-111571

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=6957238&loc=d3e14064-108612

Reference 4: 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.(g))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 20
-Subparagraph 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 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph bb
-Article 1

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph w
-Article 1

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph g
-Subparagraph 1, 2
-Article 4

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph f
-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

The amount of current liabilities reported by an equity method investment of the entity.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33918-111571

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6382943&loc=d3e33912-111571

Reference 3: 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.(g))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

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

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 159
-Paragraph 18
-Subparagraph f
-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 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 20
-Subparagraph 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 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph g
-Subparagraph 1, 2
-Article 4

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph w
-Article 1

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph bb
-Article 1

+ Details

Debt Line of Credit Facility (Details) $ in Thousands	12 Months Ended
Debt Line of Credit Facility (Details) $ in Thousands	Dec. 31, 2012 USD ($) redetermindation	Sep. 30, 2012 USD ($)	Jul. 24, 2012 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 250,000
Quarterly commitment fee percentage based on unused porttion of borrowing base	0.50%
The Company may request additional redeterminations \| redetermindation	3
Line of Credit Facility, Borrowing Base, Period of Redeterminations	12 months
Line of Credit Facility, Current Borrowing Capacity	$ 135,000			$ 100,000	$ 45,000
Outstanding borrowings under credit facility				$ 85,000
Maximum credit amount under the revolving credit agreement			$ 250,000
Reduction of borrowing base			25.00%
Period to Increase Aggregate Limit on Lease Payments	12 months
Minimum
Line of Credit Facility [Line Items]
Increased the aggregate limitation on lease payments		$ 250
Maximum
Line of Credit Facility [Line Items]
Increased the aggregate limitation on lease payments		550
Wells Fargo Bank, NA
Line of Credit Facility [Line Items]
The current lenders and their percentage commitments in the revolving credit facility	45.00%
Amegy Bank NA
Line of Credit Facility [Line Items]
The current lenders and their percentage commitments in the revolving credit facility	25.00%
US Bank NA
Line of Credit Facility [Line Items]
The current lenders and their percentage commitments in the revolving credit facility	25.00%
West Texas National Bank
Line of Credit Facility [Line Items]
The current lenders and their percentage commitments in the revolving credit facility	5.00%
Line of Credit
Line of Credit Facility [Line Items]
Debt Instrument, Description of Variable Rate Basis	prime, LIBOR or federal funds rate
Outstanding borrowings under credit facility bore a weighted average interest rate				3.30%
Line of Credit \| Minimum
Line of Credit Facility [Line Items]
The outstanding borrowings bear interest at a rate elected by the Company that is based on prime, Libor or Federal funds rate plus margins ranging	1.25%
Line of Credit \| Maximum
Line of Credit Facility [Line Items]
The outstanding borrowings bear interest at a rate elected by the Company that is based on prime, Libor or Federal funds rate plus margins ranging	3.50%
Subordinated Debt
Line of Credit Facility [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR
Affiliated Entity \| Subordinated Debt
Line of Credit Facility [Line Items]
The outstanding borrowings bear interest at a rate elected by the Company that is based on prime, Libor or Federal funds rate plus margins ranging	0.28%
Increase in permitted subordinated debt in a maximum principal amount not to exceed		$ 45,000

Debt Financial Covenant Table (Details)	Sep. 30, 2012
Maximum
Line of Credit Facility [Line Items]
Ratio of total debt to EBITDAX	4
Ratio of debt under revolving credit agreement to EBITDAX	3
Minimum
Line of Credit Facility [Line Items]
Ratio of EBITDAX to interest expense, as defined in the credit agreement	2.5
Ratio of current assets to liabilities, as defined in the credit agreementy	1

Debt Subordinated Note (Details) - Subordinated Debt - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012
Debt Instrument [Line Items]
LIBOR	LIBOR
Affiliated Entity
Debt Instrument [Line Items]
Maximum advance allowable on subordinated note		$ 45.0
Debt Instrument, Basis Spread on Variable Rate	0.28%
Debt Instrument, Interest Rate, Stated Percentage	8.00%

Debt Note Payable (Details) $ in Thousands	12 Months Ended
Debt Note Payable (Details) $ in Thousands	Dec. 31, 2012 USD ($)
Debt Disclosure [Abstract]
Debt Instrument, Frequency of Periodic Payment	P36M
Note Payable	$ 338

Stockholders' Equity and Earnings Per Share Common Stock Offering (Details) - USD ($) $ / shares in Units, $ in Millions	Oct. 23, 2012	Oct. 17, 2012	Oct. 11, 2012	Dec. 31, 2012	Dec. 31, 2011
Class of Stock [Line Items]
Common Stock, Shares Authorized				100,000,000	100,000,000
Common Stock, Par Value				$ 0.01	$ 0.01
Preferred Stock, Shares Authorized				10,000,000
Preferred Stock, Par or Stated Value Per Share				$ 0.01
Preferred Stock, Shares Outstanding				0
Issuance of Equity
Class of Stock [Line Items]
Shares issued upon initial public offering	1,875,000	14,375,000	12,500,000
Stock price per share at initial public offerring		$ 17.50	$ 17.50
Company received net proceeds from initial public offerring	$ 234.1	$ 234.1

Stockholders' Equity and Earnings Per Share Reconciliation of the components of Basic and Diluted Net Income (loss) per Common Share (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, 2012
Earnings Per Share, Basic and Diluted
Basic: Pro forma net income attributable to common stock	$ 1,820	$ 291	$ 8,767	$ 951	$ 11,829
Basic: Pro forma net income attributable to common stock, shares					19,720,734
Basic: Pro forma net income attributable to common stock, per share					$ 0.60
Effect of Dilutive Securities: Dilutive effect of potential common shares issuable					$ 0
Effect of Dilutive Securities: Dilutive effect of potential common shares issuable, shares					3,040
Diluted: Pro forma net income attributable to common stock					$ 11,829
Diluted: Pro forma net income attributable to common stock, shares					19,723,774
Diluted: Pro forma net income attributable to common stock, per share					$ 0.60

Stock and Equity Based Compensation Stock and Equity Based Compensation (Details) $ / shares in Units, $ in Thousands, shares in Millions			12 Months Ended
	Oct. 17, 2012 $ / shares	Oct. 11, 2012 employee $ / shares shares	Dec. 31, 2012 USD ($) installment	Dec. 31, 2011 installment
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense recognized on modification date			$ 2,535
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of options in number of annual installments \| installment				4
Exercise period of stock options				5 years
2012 Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares of common stock reserved for issuance \| shares		2.5
2012 Plan \| Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of perople effected by modification of Options \| employee		8
Incremental compensation expense			4,588
Plan modification, cash payment			2,813
Compensation expense recognized on modification date			5,866
Liability from compensation expense			$ 333
Liability to be recognized over this period			1 year
Vesting period of options in number of annual installments \| installment			4
Exercise period of stock options			5 years
Option Excercisable Ratably Over Period			5 years
Issuance of Equity
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock price per share at initial public offerring \| $ / shares	$ 17.50	$ 17.50

Stock and Equity Based Compensation Schedule of Stock-Based Compensation Plans and Related Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Effects of equity and stock-based compensation plans and related costs
Share-based compensation	$ 3,482	$ 544	$ 0
General and administrative expenses
Effects of equity and stock-based compensation plans and related costs
Share-based compensation	3,757	438
Stock-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties
Effects of equity and stock-based compensation plans and related costs
Share-based compensation	2,537	106
Related income tax benefit
Effects of equity and stock-based compensation plans and related costs
Share-based compensation	$ 930	$ 0

Stock and Equity Based Compensation Fair Value Assumptions of Stock Options (Details) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility		45.50%
Expected dividend yield		0.00%
Expected term (in years)		5 years
Risk-free rate		0.96%
2012 Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value	$ 4.41
Expected volatility	40.00%
Expected dividend yield	0.00%
Expected term (in years)	3 years 9 months 18 days		0 years
Risk-free rate	0.33%

Stock and Equity Based Compensation Summary of Company's Outstanding Stock Options (Details) - Stock Options - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options, Outstanding at beginning of period	0
Options granted	850,000
Option exercised	0
Options, Outstanding at end of period	850,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward]
Outstanding Options at beginning of period, weighted average exercise price	$ 0.00
Options Granted, Weighted Average Exercise Price	17.50
Options Exercised, Weighted Average Exercise Price	0.00
Outstanding Options at end of period, weighted average exercise price	$ 17.50
Options outstanding, weighted average remaining contractual term at end of period	3 years 6 months 29 days
Options outstanding at the end of period, Intrinsic Value	$ 1,377	$ 113
Number of Options, Vested and Expected to Vest, Outstanding at period end	850,000
Weighted average exercise price of Options, Vested and Expected to Vest, Outstanding at period end	$ 17.50
Remaining Term of Options Outstanding, Vested and Expected to Vest at period end	3 years 6 months 29 days
Intrinsic Value of Options Outstanding at end of period, Vested and Expected to Vest	$ 1,377
Options Exercisable at end of period	212,500
Options exercisable at end of period, Weighted Average Exercise Price	$ 17.50
Stock options are excericasble from the date of grant	3 years 6 months 18 days
Options Exercisable at end of period, Intrinsic Value	$ 344
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized [Abstract]
Unrecognized compensation cost related to unvested stock options	$ 2,462
Unrecognized compensation cost, period of recognition	2 years 7 months 6 days

Stock and Equity Based Compensation Restricted Stock Awards and Units (Details) - 2012 Plan - Restricted Stock Units (RSUs) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2012 USD ($) $ / shares shares
Restricted Stock Awards & Units
Unvested at Beginning of period \| shares	0
Granted \| shares	279,046
Vested \| shares	(72,539)
Forfeited \| shares	0
Unvested at end of period \| shares	206,507
Weighted Average Grant-Date Fair Value
Unvested at beginning of period \| $ / shares	$ 0.00
Granted \| $ / shares	17.50
Vested \| $ / shares	17.50
Forfeited \| $ / shares	0.00
Unvested at end of period \| $ / shares	$ 17.50
Aggregate fair value of restricted stock that vested during 2012 \| $	$ 1,269
Unrecognized compensation cost related to unvested restricted stock awards and units \| $	$ 3,228
Unrecognized compensation cost, period of recognition	2 years 6 months

Stock and Equity Based Compensation Equity-Based Compensation (Details) - Stock Options $ in Thousands	1 Months Ended				12 Months Ended
	Nov. 30, 2011 USD ($)	Sep. 30, 2011 USD ($)	Aug. 31, 2011 USD ($)	Apr. 30, 2011 USD ($)	Dec. 31, 2011 USD ($) installment	Dec. 31, 2012 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise period of stock options					5 years
Vesting period of options in number of annual installments \| installment					4
Membership Interest Granted	0.30%	1.30%	1.20%	1.00%	3.70%
Exercise Price	$ 1,250	$ 5,900	$ 6,000	$ 3,600	$ 16,750
Fair Value at Date of Grant	$ 288	$ 1,533	$ 1,384	$ 1,453	4,658
Intrinsic value of outstanding options					$ 113	$ 1,377
Weighted-average remaining contractual term					4 years 7 months 6 days
Fair value assumptions
Expected term (in years)					5 years
Risk-free rate					0.96%
Expected volatility					45.50%
Expected dividend yield					0.00%

Related Party Transactions Administrative Services (Details) - USD ($) $ in Thousands		12 Months Ended
	Jan. 02, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction
Accounts payable-related party		$ 18,813	$ 3,230
Subsidiary of Common Parent
Related Party Transaction
The Company incurred total costs under administrative serices agreement		4,419	10,110	$ 7,996
Expense costs partially offset in general administraticve expenses by overhead reimbursements		2,548	1,954	$ 1,389
Accounts payable-related party		13	$ 773
Affiliated Entity
Related Party Transaction
The initial term of the additional shared services agreement	2 years
Agreement termination, written notice period	30 days
Affiliate reimbursed the Company		2,132
The affiliate owed the Company and it is included in accounts receivable-related party in the consolidated balance sheet		$ 1

Related Party Transactions Operating Services (Details) - Affiliated Entity - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction
Amounts due to affiliated parties relating to revenue distributions payable		$ 2,303
Amounts due from affiliates related to joint interest billings and included in accounts receivable-related party	$ 742	$ 8,590

Related Party Transactions Drilling Services (Details) $ in Thousands		12 Months Ended
	Jan. 02, 2012	Dec. 31, 2012 USD ($) drilling_rig	Dec. 31, 2011 USD ($)
Affiliated Entity
Related Party Transaction
Number of drilling rigs committed to use during the period		2
Agreement termination, written notice period	30 days
Affiliated Entity, Bison
Related Party Transaction
Number of drilling rigs		4
Agreement termination, written notice period	30 days
The company owed Bison \| $		$ 120	$ 154

- Definition

Amount for accounts payable to related parties.

+ References + Details

Related Party Transactions Completion and Well Servicing Services (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction
Costs Incurred, Development Costs	$ 106,261	$ 75,374	$ 48,817
Affiliated Entity
Related Party Transaction
Costs Incurred, Development Costs		$ 12,511	$ 7,709

Related Party Transactions Marketing Services (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction
The Company's revenue from oil sales from affiliate	$ 0	$ 38,873	$ 21,403
The company had an accounts receivable-related party balance with an affiliate	$ 772	12,937
Subsidiary of Common Parent
Related Party Transaction
The Company's revenue from oil sales from affiliate		38,873	$ 21,403
The company had an accounts receivable-related party balance with an affiliate		$ 4,347

- Definition

Amount of receivables arising from transactions with related parties due within one year or the normal operating cycle, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.3(a)(2))
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: 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 3: 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)(1))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 850
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=6457730&loc=d3e39549-107864

Reference 5: 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 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph k
-Subparagraph 1
-Article 4

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 57
-Paragraph 2
-Subparagraph 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 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 3
-Subparagraph a
-Article 5

+ Details

Related Party Transactions MidMar (Details) - USD ($) $ in Thousands		12 Months Ended
	May 01, 2009	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction
Revenue from Related Parties, Natural Gas Sales		$ 3,040	$ 1,604	$ 0
Affiliated Entity, MidMar
Related Party Transaction
The initial term of the additional shared services agreement	10 years
Agreement termination, written notice period	30 days
Revenue from Related Parties, Natural Gas Sales		2,958	3,128	$ 1,066
MidMar owed the company for its portion from the sale of gas, gas products and residue gas		$ 6	$ 462
Affiliated Entity, MidMar \| MidMar Plant
Related Party Transaction
Sales Revenue, Goods, Net, Percentage		87.00%
Affiliated Entity, MidMar \| Chevron Headlee Plant
Related Party Transaction
Sales Revenue, Goods, Net, Percentage		94.56%

Related Party Transactions Midland Lease (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Jun. 01, 2012	Jun. 02, 2011	May 15, 2011	Mar. 02, 2011
Related Party Transaction
The current monthly rent under the lease will increase annually			4.00%	4.00%		3.00%
Affiliated Entity, Midland Lease
Related Party Transaction
Term of lease from related party					5 years
Office rent to affilate	$ 155	$ 40

Related Party Transactions Oklahoma City Lease (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Aug. 02, 2012	Jan. 02, 2012
Related Party Transaction
Monthly rent increase		9.00%
Affiliated Entity, Oklahoma City Lease
Related Party Transaction
Term of lease from related party			67 months
Office rent to affilate	$ 329
Monthly rent increase		9.00%

Related Party Transactions Advisory Services Agreement & Professional Services from Wexford (Details) - USD ($) $ in Thousands		12 Months Ended
	Oct. 11, 2012	Dec. 31, 2012
Related Party Transaction
Advisory Services Agreement, Annual Fee	$ 500
Term of advisory services agreement	2 years
Affiliated Entity, Wexford
Related Party Transaction
Agreement termination, written notice period	30 days
Controlling Entity
Related Party Transaction
The company incurred costs from Wexford relating from professional services		$ 191
Accounts Payable due to Wexford		$ 113

- Definition

Amount for accounts payable to related parties.

+ References + Details

Income Taxes Components of Federal Income Tax (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Deferred tax provision:
Deferred recognized at date of Merger - change in tax status of Predecessors	$ 54,142
Deferred as a result of operations from October 11, 2012 through December 31, 2012	761
Total provision for income taxes	$ 54,903	$ 54,903	$ 0	$ 0

- Definition

The component of income tax expense for the period representing the increase (decrease) in the entity's deferred tax assets and liabilities pertaining to continuing operations.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Deferred Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6510177

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 4: 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.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 289
-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 109
-Paragraph 45
-Subparagraph 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 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 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.

+ Details

Income Taxes Reconciliation of Statutory Federal Income Tax (Details) - USD ($)	3 Months Ended					9 Months Ended
	Dec. 31, 2012	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Oct. 11, 2012
Income Tax Disclosure [Abstract]
Federal statutory tax rate		35.00%				35.00%
Income tax expense at the federal statutory rate		$ 717,000				$ 6,434,000
Deduction for pre-merger LLC earnings						$ (5,717,000)
Income tax expense relating to change in tax status		54,142,000
State income tax		42,000
Non-deductible expenses		2,000
Provision for income taxes	$ 54,903,000	$ 54,903,000	$ 0	$ 0	$ 0

Income Taxes Components of Deferred Tax Assets and Liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Current deferred tax assets
Derivative instruments	$ 1,857,000
Total current deferred tax assets	1,857,000	$ 0
Noncurrent deferred tax assets
Net operating loss carryforwards (subject to 20 year expiration)	1,577,000
Stock based compensation	930,000
Total noncurrent deferred tax assets	2,507,000
Deferred tax liabilities
Oil and natural gas properties and equipment	64,636,000
Other	566,000
Total noncurrent deferred tax liabilities	65,202,000
Net noncurrent deferred tax liabilities	62,695,000	$ 0
Net deferred tax liabilities	60,838,000
Net operating loss carryforward	$ 4,506,000
Operating loss carryforward expiration period	20 years

Derivatives Terms and Fair Values of Outstanding Derivative Instruments (Details) - Crude Oil bbl / d in Thousands, bbl in Thousands, $ in Thousands	Dec. 31, 2012 USD ($) bbl $ / bbl	Dec. 31, 2011 USD ($)	Oct. 04, 2011 bbl / d $ / bbl	Jun. 30, 2009 bbl	Apr. 30, 2008 bbl	Dec. 31, 2007 bbl
Swap
Crude Oil Swaps:
Volume (Bbls) \| bbl						1,680
Swap \| Derivative, Crude Oil Swap, 2012
Crude Oil Swaps:
Original Strike Price (per Bbl) \| $ / bbl			78.50
Swap \| January - November 2012
Crude Oil Swaps:
Volume (Bbls) \| bbl	335
Original Strike Price (per Bbl) \| $ / bbl	78.50
Fair Value Liability \| $	$ 0	$ 6,833
Swap \| December 2012
Crude Oil Swaps:
Volume (Bbls) \| bbl	31
Original Strike Price (per Bbl) \| $ / bbl	78.50
Fair Value Liability \| $	$ 302	594
Swap \| January - December 2013
Crude Oil Swaps:
Volume (Bbls)	365		1
Original Strike Price (per Bbl) \| $ / bbl	80.55		80.55
Fair Value Liability \| $	$ 4,614	$ 5,545
Counter Swap
Crude Oil Swaps:
Volume (Bbls) \| bbl				324	1,188

Derivatives Locked-in Swaps Settled In April 2008 (Details) - Crude Oil $ in Thousands	Dec. 31, 2012 USD ($) bbl $ / bbl	Dec. 31, 2011 USD ($)	Jun. 30, 2009 bbl	Apr. 30, 2008 bbl	Dec. 31, 2007 bbl
Swap
Crude Oil Swaps:
Volume (Bbls) \| bbl					1,680,000
Counter Swap
Crude Oil Swaps:
Volume (Bbls) \| bbl			324,000	1,188,000
December 2011 \| Swap \| Summarized amounts, terms, and fair values of the locked-in swaps from April 2008 settlments \| December 2011
Crude Oil Swaps:
Volume (Bbls) \| bbl	22,500
Original Strike Price (per Bbl)	82.90
Fair Value Liability \| $	$ 0	$ 379
December 2011 \| Swap \| Summarized amounts, terms, and fair values of the locked-in swaps from April 2008 settlments \| Minimum
Crude Oil Swaps:
Lock-in Price (per Bbl)	98.50
December 2011 \| Swap \| Summarized amounts, terms, and fair values of the locked-in swaps from April 2008 settlments \| Maximum
Crude Oil Swaps:
Lock-in Price (per Bbl)	102.20
January - November 2012 \| Swap
Crude Oil Swaps:
Volume (Bbls) \| bbl	335,000
Original Strike Price (per Bbl)	78.50
Fair Value Liability \| $	$ 0	6,833
January - November 2012 \| Swap \| Summarized amounts, terms, and fair values of the locked-in swaps from April 2008 settlments \| January - November 2012
Crude Oil Swaps:
Volume (Bbls) \| bbl	247,500
Original Strike Price (per Bbl)	85.07
Fair Value Liability \| $	$ 0	3,554
January - November 2012 \| Swap \| Summarized amounts, terms, and fair values of the locked-in swaps from April 2008 settlments \| Minimum
Crude Oil Swaps:
Lock-in Price (per Bbl)	98.25
January - November 2012 \| Swap \| Summarized amounts, terms, and fair values of the locked-in swaps from April 2008 settlments \| Maximum
Crude Oil Swaps:
Lock-in Price (per Bbl)	101.80
December 2012 \| Swap
Crude Oil Swaps:
Volume (Bbls) \| bbl	31,000
Original Strike Price (per Bbl)	78.50
Fair Value Liability \| $	$ 302	594
December 2012 \| Swap \| Summarized amounts, terms, and fair values of the locked-in swaps from April 2008 settlments \| December 2012
Crude Oil Swaps:
Volume (Bbls) \| bbl	22,500
Original Strike Price (per Bbl)	85.07
Fair Value Liability \| $	$ 323	$ 323
December 2012 \| Swap \| Summarized amounts, terms, and fair values of the locked-in swaps from April 2008 settlments \| Minimum
Crude Oil Swaps:
Lock-in Price (per Bbl)	98.25
December 2012 \| Swap \| Summarized amounts, terms, and fair values of the locked-in swaps from April 2008 settlments \| Maximum
Crude Oil Swaps:
Lock-in Price (per Bbl)	101.80

Derivatives Locked-in Swaps Settled in June 2009 (Details) - Crude Oil $ in Thousands	Dec. 31, 2012 USD ($) bbl $ / bbl	Dec. 31, 2011 USD ($)	Jun. 30, 2009 bbl	Apr. 30, 2008 bbl	Dec. 31, 2007 bbl
Swap
Crude Oil Swaps:
Volume (Bbls) \| bbl					1,680,000
Counter Swap
Crude Oil Swaps:
Volume (Bbls) \| bbl			324,000	1,188,000
December 2011 \| Swap \| Summarized amounts, terms and fair values of locked-in swaps from June 2009 settlements \| December 2011
Crude Oil Swaps:
Volume (Bbls) \| bbl	7,500
Original Strike Price (per Bbl)	82.90
Lock-in Price (per Bbl)	78.42
Fair Value Liability \| $	$ 0	$ 34
January - November 2012 \| Swap
Crude Oil Swaps:
Volume (Bbls) \| bbl	335,000
Original Strike Price (per Bbl)	78.50
January - November 2012 \| Swap \| Summarized amounts, terms and fair values of locked-in swaps from June 2009 settlements \| January - November 2012
Crude Oil Swaps:
Volume (Bbls) \| bbl	82,500
Original Strike Price (per Bbl)	85.07
Lock-in Price (per Bbl)	80.52
Fair Value Liability \| $	$ 0	375
December 2012 \| Swap
Crude Oil Swaps:
Volume (Bbls) \| bbl	31,000
Original Strike Price (per Bbl)	78.50
December 2012 \| Swap \| Summarized amounts, terms and fair values of locked-in swaps from June 2009 settlements \| December 2012
Crude Oil Swaps:
Volume (Bbls) \| bbl	7,500
Original Strike Price (per Bbl)	85.07
Lock-in Price (per Bbl)	80.52
Fair Value Liability \| $	$ 34	$ 34

Derivatives Loss on Derivative Contracts Included in Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Unrealized gain (loss) on open non-hedge derivative instruments	$ 8,057	$ (12,972)	$ 0
Loss on settlement of non-hedge derivative instruments	(5,440)	(37)	(148)
Gain (loss) on derivative instruments	2,617	(13,009)	$ (148)
Margin deposit assets	$ 0	$ 2,326

- Definition

The amount of net gains and losses recognized in income during the period on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges, on derivative instruments designated and qualifying as hedging instruments in cash flow hedges, and on derivative instruments not designated as hedging instruments.

+ References + Details

Fair Value Measurements (Details) - USD ($)
$ in Thousands

Dec. 31, 2012

Dec. 31, 2011

Quoted Prices in Active Markets Level 1

Financial Liabilities

Derivative contracts

$ 0

Significant Other Observable Inputs Level 2

Financial Liabilities

Derivative contracts

5,205

16,785

Significant Unobservable Inputs Level 3

Financial Liabilities

Derivative contracts

Cash Collateral

Financial Liabilities

Derivative contracts

^[1]

(2,326)

Net Fair Value

Financial Liabilities

Derivative contracts

$ 5,205

$ 14,459

[1]	Represents the impact of netting cash collateral with a counterparty with which the right of offset exists.

Commitments and Contingencies Lease Commitments (Details) - USD ($) $ in Thousands		1 Months Ended		12 Months Ended
	Jan. 02, 2012	May 31, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Aug. 02, 2012	Jun. 01, 2012	Jun. 02, 2011	Mar. 02, 2011
Commitments and Contingencies Disclosure [Abstract]
Lease term	67 months	5 years	84 months
The current monthly rent under the lease will increase annually								4.00%	4.00%	3.00%
Monthly rent increase							9.00%
Rent Expense				$ 547	$ 74	$ 0
Future minimum lease payments
2013				485
2014				491
2015				501
2106				412
2017				281
Thereafter				25
Total				$ 2,195

Commitments and Contingencies Contractual Obligation (Details) $ in Thousands	Dec. 31, 2012 USD ($)
Minimum future expenditures for fracturing and well stimulation services
2013	$ 14,400
2014	3,600
Total	$ 18,000

Commitments and Contingencies Drilling Contracts (Details)	Jan. 02, 2012
Affiliated Entity, Bison
Related Party Transaction
Agreement termination, written notice period	30 days

Commitments and Contingencies Defined Contribution Plan (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2012 USD ($)
Defined contribution plan
Employee maximum annual contribution as percentage of annual compensation	100.00%
Employer matching contribution percentage	6.00%
Employer contribution vesting period	4 years
Contributions by employer	$ 86

Subsequent Events (Details) bbl in Thousands	Jan. 28, 2013 drilling_rig	Jan. 02, 2012	Feb. 01, 2013 bbl $ / bbl	Dec. 31, 2007 bbl
Affiliated Entity, Bison
Subsequent Event [Line Items]
Agreement termination, written notice period		30 days
Swap \| Crude Oil
Subsequent Event [Line Items]
Aggregate volumes				1,680
Subsequent Event \| Affiliated Entity, Bison \| Drilling Rights
Subsequent Event [Line Items]
Agreement termination, written notice period	30 days
Subsequent Event \| Affiliated Entity, Bison \| Drilling Rights \| Minimum
Subsequent Event [Line Items]
Number of drilling rigs committed to use during the period \| drilling_rig	2
Subsequent Event \| Affiliated Entity, Bison \| Service Agreements
Subsequent Event [Line Items]
Agreement termination, written notice period	30 days
Subsequent Event \| Swap \| Crude Oil \| Derivative, Crude Oil Swap, May 2013-April 2014
Subsequent Event [Line Items]
Aggregate volumes			365
Swap Price \| $ / bbl			109.70

Supplemental Information on Oil and Gas Exploration and Production Activities Capitalized Oil and Natural Gas Costs(Details) - USD ($) $ in Thousands	Dec. 31, 2012	Dec. 31, 2011
Oil and Natural Gas Properties:
Proved properties	$ 576,497	$ 335,303
Unproved properties	121,245	4,528
Total Oil and Natural Gas Properties	697,742	339,831
Less Accumulated depreciation, depletion, amortization and impairment	(145,102)	(119,366)
Net oil and natural gas properties capitalized	$ 552,640	$ 220,465

Supplemental Information on Oil and Gas Exploration and Production Activities Costs Incurred in Crude Oil and Natural Gas Activities(Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Acquisition costs
Proved properties	$ 115,760	$ 0	$ 0
Unproved properties	117,395	3,704	9,930
Development costs	106,261	75,374	48,817
Exploration costs	17,547	11,226	3,920
Capitalized asset retirement costs	948	297	222
Total	$ 357,911	$ 90,601	$ 62,889

- 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 Information on Oil and Gas Exploration and Production Activities Results of Operations for Oil and Natural Gas Producing Activities (Details) - USD ($)

12 Months Ended

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Extractive Industries [Abstract]

Oil, natural gas and natural gas liquid sales

$ 74,962,000

$ 47,875,000

$ 26,442,000

Lease operating expenses

(16,793,000)

(10,597,000)

(4,589,000)

Production taxes

(3,691,000)

(2,366,000)

(1,347,000)

Gathering and transportation

(424,000)

(202,000)

(106,000)

Depreciation, depletion, and amortization

(25,772,000)

(15,377,000)

(7,373,000)

Results of operations from oil, natural gas and natural gas liquids before income taxes

28,282,000

$ 19,333,000

$ 13,027,000

Pro forma information

Pro forma income tax

^[1]

10,083,000

Pro forma results of operations

^[1]

$ 18,199,000

[1]

Supplemental Information on Oil and Gas Exploration and Production Activities Oil and Natural Gas Reserves (Details)	12 Months Ended
	Dec. 31, 2012 bbl Mcf	Dec. 31, 2011 bbl Mcf	Dec. 31, 2010 bbl Mcf	Dec. 31, 2009 bbl Mcf
Oil [Member]
Reserve Quantities [Roll Forward]
Beginning of the period	18,100,473	19,630,160	29,230,940
Extensions and discoveries	3,106,433	1,799,175	2,402,204
Revisions of previous estimates	(1,464,243)	(2,879,429)	(11,722,263)
Purchase of reserves in place	7,210,482	0	0
Production	(756,286)	(449,433)	(280,721)
Sales of reserves in place	0	0	0
End of the period	26,196,859	18,100,473	19,630,160
Proved Developed Reserves	7,189,367	3,949,099	3,371,460	1,954,060
Proved Undeveloped Reserves	19,007,492	14,151,375	16,258,700	27,276,880
Natural Gas Liquids [Member]
Reserve Quantities [Roll Forward]
Beginning of the period	5,049,560	5,832,967	7,522,225
Extensions and discoveries	869,741	466,538	1,463,206
Revisions of previous estimates	(5,811)	(1,163,130)	(3,072,486)
Purchase of reserves in place	2,521,053	0	0
Production	(183,114)	(86,815)	(79,978)
Sales of reserves in place	0	0	0
End of the period	8,251,429	5,049,560	5,832,967
Proved Developed Reserves	2,999,440	1,263,711	1,126,431	591,532
Proved Undeveloped Reserves	5,251,989	3,785,850	4,706,536	6,930,693
Natural Gas [Member]
Reserve Quantities [Roll Forward]
Beginning of the period \| Mcf	20,551,465	22,695,080	27,481,820
Extensions and discoveries \| Mcf	3,759,684	1,884,192	14,043,737
Revisions of previous estimates \| Mcf	383,335	(3,614,167)	(18,506,630)
Purchase of reserves in place \| Mcf	10,709,180	0	0
Production \| Mcf	(833,516)	(413,640)	(323,847)
Sales of reserves in place \| Mcf	0	0	0
End of the period \| Mcf	34,570,148	20,551,465	22,695,080
Proved Developed Reserves \| Mcf	12,864,941	5,285,945	4,336,720	2,453,750
Proved Undeveloped Reserves \| Mcf	21,705,207	15,265,520	18,358,360	25,028,070

Supplemental Information on Oil and Gas Exploration and Production Activities Standardized measure of Discounted Future Net Cash Flows - Proved Crude Oil and Natural Gas Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Future cash inflows	$ 2,769,485	$ 2,049,520	$ 1,856,294
Future development costs	(541,445)	(410,350)	(398,305)
Future production costs	(773,611)	(497,808)	(384,916)
Future production taxes	(140,758)	(104,856)	(126,090)
Future income tax expenses	(334,903)	0	0
Future net cash flows	978,768	1,036,506	946,983
10% discount to reflect timing of cash flows	(611,548)	(671,894)	(607,982)
Standardized measure of discounted future net cash flows	$ 367,220	$ 364,612	$ 339,001

Supplemental Information on Oil and Gas Exploration and Production Activities Average First Day of the Month Price for Oil, Natural Gas & Natural Gas Liquids (Details)	12 Months Ended
	Dec. 31, 2012 $ / bbl $ / Mcf	Dec. 31, 2011 $ / bbl $ / Mcf	Dec. 31, 2010 $ / bbl $ / Mcf
Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales prices (dollars per unit)	88.13	93.09	77.61
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales prices (dollars per unit) \| $ / Mcf	2.86	3.91	4.14
Natural Gas Liquids [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales prices (dollars per unit)	43.88	56.33	40.74

Supplemental Information on Oil and Gas Exploration and Production Activities Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows at the beginning of the period	$ 364,612	$ 339,001	$ 392,919
Sales of oil and natural gas, net of production costs	(54,208)	(34,711)	(20,401)
Purchase of minerals in place	107,897	0	0
Extensions and discoveries, net of future development costs	79,293	73,571	59,414
Previously estimated development costs incurred during the period	88,849	87,530	52,932
Net changes in prices and production costs	(76,515)	82,364	178,198
Changes in estimated future development costs	8,309	(82,855)	(23,992)
Revisions of previous quantity estimates	(22,882)	(98,533)	(292,306)
Sales of reserves in place, net of future development costs	0	0	0
Accretion of discount	36,461	33,900	39,292
Net change in income taxes	(125,542)	0	0
Net changes in timing of production and other	(39,054)	(35,655)	(47,055)
Standardized measure of discounted future net cash flows at the end of the period	$ 367,220	$ 364,612	$ 339,001

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2012	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
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 25,767		$ 16,814	$ 16,030	$ 16,351	$ 14,491	$ 11,216	$ 11,572	$ 12,087	$ 74,962	$ 49,366	$ 27,253
Income from operations	2,177		4,086	4,307	6,737	4,824	2,928	4,067	3,328	17,307	15,147	9,181
Income tax expense	54,903	$ 54,903	0	0	0
Net income (loss)	(52,074)		452	13,624	1,477	$ (8,868)	$ 2,205	$ 3,453	$ 2,824	(36,521)	(386)	8,231
Pro forma information
Income before income taxes	2,829		452	13,624	1,477					18,382	$ (386)	$ 8,231
Pro forma provision for income taxes	1,009		161	4,857	526					6,553
Pro forma net income	$ 1,820		$ 291	$ 8,767	$ 951					$ 11,829
Income per share:
Earnings Per Share, Basic	$ 0.05		$ 0.02	$ 0.60	$ 0.06
Earnings Per Share, Diluted	$ 0.05		$ 0.02	$ 0.60	$ 0.06