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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2013	Feb. 03, 2014	Jun. 30, 2013
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
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	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		47,106,216
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 800,108,000

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 15,555	$ 26,358
Accounts receivable:
Joint interest and other	14,437	5,959
Oil and natural gas sales	23,533	8,081
Related party	1,303	772
Inventories	5,631	6,195
Deferred income taxes	112	1,857
Derivative instruments	213	0
Prepaid expenses and other	1,184	1,053
Total current assets	61,968	50,275
Property and equipment
Oil and natural gas properties, based on the full cost method of accounting ($369,561 and $121,245 excluded from amortization at December 31, 2013 and December 31, 2012, respectively)	1,648,360	697,742
Pipeline and gas gathering assets	6,142	0
Other property and equipment	4,071	2,337
Accumulated depletion, depreciation, amortization and impairment	(212,236)	(145,837)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	1,446,337	554,242
Derivative instruments	218	0
Other assets	13,091	2,184
Total assets	1,521,614	606,701
Current liabilities:
Accounts payable-trade	2,679	12,141
Accounts payable-related party	17	18,813
Accrued capital expenditures	74,649	29,397
Other accrued liabilities	34,750	10,649
Revenues and royalties payable	9,225	3,270
Derivative instruments	0	4,817
Note payable-short term	0	145
Total current liabilities	121,320	79,232
Long-term debt	460,000	193
Derivative instruments	0	388
Asset retirement obligations	2,989	2,125
Deferred income taxes	91,764	62,695
Total liabilities	676,073	144,633
Commitments and contingencies (Note 14)
Stockholders’ equity:
Common stock, $0.01 par value, 100,000,000 shares authorized, 47,106,216 issued and outstanding at December 31, 2013; 36,986,532 issued and outstanding at December 31, 2012	471	370
Additional paid-in capital	842,557	513,772
Retained earnings (accumulated deficit)	2,513	(52,074)
Total stockholders’ equity	845,541	462,068
Total liabilities and stockholders’ equity	$ 1,521,614	$ 606,701

Consolidated Balance Sheets (Parentheticals) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Oil and natural gas properties, amortization excluded	$ 369,561	$ 121,245
Common Stock, Par Value	$ 0.01	$ 0.01
Common Stock, Shares Authorized	100,000,000	100,000,000
Common Stock, Shares, Issued	47,106,216	36,986,532
Common Stock, Shares, Outstanding	47,106,216	36,986,532

Combined Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:
Oil sales	$ 188,753	$ 65,704	$ 2,582
Oil sales - related party	0	0	38,873
Natural gas sales	3,715	1,369	1,061
Natural gas sales - related party	2,534	1,010	586
Natural gas liquid sales	8,304	3,839	3,169
Natural gas liquid sales - related party	4,696	3,040	1,604
Oil and natural gas services - related party	0	0	1,491
Total revenues	208,002	74,962	49,366
Costs and expenses:
Lease operating expenses	19,991	14,231	7,804
Lease operating expenses - related party	1,166	1,016	2,127
Production and ad valorem taxes	12,399	4,950	1,240
Production and ad valorem taxes - related party	500	287	1,792
Gathering and transportation	237	124	53
Gathering and transportation - related party	681	300	149
Oil and natural gas services	0	0	1,207
Oil and natural gas services - related party	0	0	526
Depreciation, depletion and amortization	66,597	26,273	15,601
General and administrative expenses (including non-cash stock based compensation, net of capitalized amounts, of $1,752, $2,477 and $438 for the years ended December 31, 2013, 2012 and 2011, respectively)	9,870	9,178	495
General and administrative expenses - related party	1,166	1,198	3,160
Asset retirement obligation accretion expense	201	98	65
Total costs and expenses	112,808	57,655	34,219
Income from operations	95,194	17,307	15,147
Other income (expense)
Interest income	1	3	11
Interest expense	(8,059)	(3,610)	(2,528)
Other income - related party	1,077	2,132	0
Gain (loss) on derivative instruments, net	(1,872)	2,617	(13,009)
Loss from equity investment	0	(67)	(7)
Total other income (expense), net	(8,853)	1,075	(15,533)
Income (loss) before income taxes	86,341	18,382	(386)
Provision for income taxes
Current	191	0	0
Deferred	31,563	54,903	0
Net income (loss)	$ 54,587	(36,521)	(386)
Earnings per common share
Basic (in dollars per share)	$ 1.30
Diluted (in dollars per share)	$ 1.29
Weighted average common shares outstanding
Basic (in shares)	42,015
Diluted (in shares)	42,255
Pro forma information (unaudited)
Income before income taxes, as reported	$ 86,341	18,382	$ (386)
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)		19,721
Diluted (in shares)		19,724

Combined Consolidated Statements of Operations (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]
Non-cash stock based compensation, capitalized amount	$ 1,752	$ 2,477	$ 438

Consolidated Statement of Stockholders' Equity/Members' Equity - USD ($) $ in Thousands	Total	Member's Equity	Common Stock	Additional Paid-in Capital	Retained Earnings/(Accumulated Deficit)
Balance at beginning 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
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	0	$ (138,967)	$ 147	$ 138,820
Common shares issued upon Merger, shares			14,697,000
Common shares issued upon acquisition of Gulfport properties	138,496		$ 79	138,417
Common shares issued upon acquisition of Gulfport properties, shares			7,914,000
Common shares issued in public offering, net of offering costs	234,144		$ 144	234,000
Common shares issued in public offering, net of offering costs, shares			14,375,000
Stock-based compensation	2,535			2,535
Net loss subsequent to merger	(52,074)				$ (52,074)
Net income (loss)	(36,521)
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		36,986,000
Increase (Decrease) in Stockholders' Equity
Common shares issued in public offering, net of offering costs	$ 321,912		$ 98	321,814
Common shares issued in public offering, net of offering costs, shares			9,775,000
Stock-based compensation	2,724			2,724
Tax benefits related to stock-based compensation	749			749
Exercise of stock options and awards of restricted stock	3,501		$ 3	3,498
Exercise of stock options and awards of restricted stock, shares			345,000
Net income (loss)	54,587				54,587
Balance at end of period at Dec. 31, 2013	$ 845,541		$ 471	$ 842,557	$ 2,513
Balance at end of period, shares at Dec. 31, 2013	47,106,216		47,106,000

Combined Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:
Net income (loss)	$ 54,587	$ (36,521)	$ (386)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for deferred income taxes	31,563	54,903	0
Excess tax benefit from stock-based compensation	(749)	0	0
Asset retirement obligation accretion expense	201	98	65
Depreciation, depletion, and amortization	66,597	26,273	16,104
Amortization of debt issuance costs	1,018	494	250
Change in fair value of derivative instruments	(5,346)	(2,617)	13,009
Loss from equity investment	0	67	0
Equity based compensation expense	1,752	3,482	544
Gain on sale of assets	(39)	(37)	(23)
Changes in operating assets and liabilities:
Accounts receivable	(19,973)	(5,036)	(1,547)
Accounts receivable-related party	(532)	6,096	(4,133)
Inventories	554	(639)	(872)
Prepaid expenses and other	(271)	(606)	(202)
Accounts payable and accrued liabilities	20,588	7,151	2,656
Accounts payable and accrued liabilities-related party	(128)	(1,218)	830
Revenues and royalties payable	5,955	105	2,666
Revenues and royalties payable-related party	0	(2,303)	2,037
Net cash provided by operating activities	155,777	49,692	30,998
Cash flows from investing activities:
Additions to oil and natural gas properties	(278,809)	(90,415)	(58,160)
Additions to oil and natural gas properties-related party	(13,777)	(9,675)	(22,014)
Acquisition of Gulfport properties	(18,550)	(63,590)	0
Acquisition of mineral interests	(444,083)	0	0
Acquisition of leasehold interests	(177,343)	(11,707)	0
Additions to pipeline and gas gathering assets	(5,127)	0	0
Purchase of other property and equipment	(2,234)	(1,102)	(7,065)
Proceeds from sale of property and equipment	72	48	55
Settlement of non-hedge derivative instruments	(289)	(8,963)	(4,127)
Receipt on derivative margins	0	2,326	4,203
Deconsolidation of Bison	0	0	(10)
Proceeds from sale of membership interest in equity investment	0	0	6,010
Net cash used in investing activities	(940,140)	(183,078)	(81,108)
Cash flows from financing activities:
Proceeds from borrowings on credit facility	59,000	15,000	40,233
Repayment on credit facility	(49,000)	(100,000)	0
Proceeds from senior notes	450,000	0	0
Proceeds from note payable - related party	0	30,000	0
Payment of note payable - related party	0	(30,050)	0
Debt issuance costs	(12,361)	(450)	(770)
Public offering costs	(1,009)	(2,887)	(30)
Proceeds from public offering	322,680	237,164	0
Exercise of stock options	3,501	0	0
Excess tax benefits of stock-based compensation	749	0	0
Contributions by members	0	4,008	13,517
Net cash provided by financing activities	773,560	152,785	52,950
Net increase (decrease) in cash and cash equivalents	(10,803)	19,399	2,840
Cash and cash equivalents at beginning of period	26,358	6,959	4,119
Cash and cash equivalents at end of period	15,555	26,358	6,959
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	404	3,017	2,265
Supplemental disclosure of non-cash transactions:
Asset retirement obligation incurred	226	386	297
Asset retirement obligation acquired	471	562	0
Distribution of equity method investments	0	10,504	0
Note payable exchanged for equipment	0	411	0
Common stock issued as a result of the Gulfport transaction	0	138,496	0
Post-closing adjustment payable as a result of the Gulfport transaction	$ 0	$ 18,550	$ 0

Organization	12 Months Ended
Organization	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	ORGANIZATION 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 Diamondback’s common stock and the membership interests in Diamondback O&G LLC (formerly known as Windsor Permian LLC, or “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. The Company refers to the historical results of Windsor Permian and Windsor UT prior to October 11, 2012 as the “Predecessors”. The subsidiaries of Diamondback, as of December 31, 2013, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, and Viper Energy Partners LLC, a Delaware limited liability company. The subsidiaries are all wholly owned. 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 3—Acquisitions for information regarding the acquisition. On October 17, 2012, the Company completed its initial public offering (“IPO”) of 14,375 shares of common stock, which included 1,875 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $17.50 per share and the Company received net proceeds of approximately $234,100 from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. In the first quarter of 2013, Windsor UT merged with and into Windsor Permian and Windsor Permian, the surviving entity in the merger, was renamed Diamondback O&G LLC (“Diamondback O&G”). On May 21, 2013, the Company completed an underwritten primary public offering of 5,175 shares of common stock, which included 675 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $29.25 per share and the Company received net proceeds of approximately $144,439 from the sale of these shares of common stock, after offering expenses and underwriting discounts and commissions. On June 24, 2013, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 6,000 shares of the Company’s common stock and, on July 5, 2013, the underwriters purchased an additional 869 shares of the Company’s common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the public at $34.75 per share and the selling stockholders received all proceeds from this offering. In August 2013, the Company completed an underwritten public offering of 4,600 shares of common stock, which included 600 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold the public at $40.25 per share and the Company received net proceeds of approximately $177,500 from the sale of these shares of common stock, after offering expenses and underwriting discounts and commissions. In September 2013, the Company completed an offering of $450,000 principal amount of our 7.625% Senior Notes due 2021. See Note 7—Debt.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 its operations prior to October 11, 2012, the effective date of the Windsor UT Contribution. The accompanying financial statements and related notes presented herein represent the combined results of operations and cash flows of the 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. The Company has reclassified ad valorem taxes from lease operating expenses to production and ad valorem taxes.

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. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

Accounts Receivable

Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of 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, 2013 or December 31, 2012.

Derivative Instruments

The Company is required to recognize its derivative instruments on the 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 cash and non-cash 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, notes payable and senior notes. 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. The fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 13—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 6—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 $24.63, $23.90 and $25.41 for the years ended December 31, 2013, 2012 and 2011, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $65,821, $25,772 and $15,377 for the years ended December 31, 2013, 2012 and 2011, 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, 2013, 2012 or 2011.

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 $776, $501 and $727 for the years ended December 31, 2013, 2012 and 2011, respectively.

Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability 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.

The Company records a liability relating to the retirement and removal of all assets used in their businesses. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is 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, 2013, 2012 or 2011.

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. The Company capitalized interest of $3,951 for the year ended December 31, 2013. During the years ended December 31, 2012 and 2011, the Company did not capitalize any interest expense.

Inventories

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



	December 31,
	2013		2012
Tubular goods and equipment	$	5,631	$	5,725
Crude oil	—		470
	$	5,631	$	6,195

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, 2013, the Company estimated that all of its tubular goods and equipment will be utilized within one year.

Debt Issuance Costs

Other assets included capitalized costs of $12,458 and $1,115, net of accumulated amortization of $1,798 and $782, as of December 31, 2013 and 2012, respectively. The increase in 2013 related primarily to the $10,376 of costs incurred upon the issuance of the 7.625% Senior Notes due 2021. The costs associated with the Senior Notes are being amortized over the term of the Senior Notes using the effective interest method. The costs associated with our credit facility are being amortized over the term of the facility.

Other Accrued Liabilities

Other accrued liabilities consist of the following:



	December 31,
	2013		2012
Prepaid drilling liability	$	16,491	$	4,540
Interest payable	9,918		—
Lease operating expense payable	4,538		4,737
Current portion of asset retirement obligations	40		20
Other	3,763		1,352
	$	34,750	$	10,649

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, 2013 or December 31, 2012. 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, 2013 and 2012. For additional information on the Company’s investments, see Note 6—Equity Method Investments.

Accounting for Stock-Based 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 9—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, 2013 two purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (37%); and Shell Trading (US) Company (37%). For the year ended December 31, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (53%); Occidental Energy Marketing, Inc. (16%); and Andrews Oil Buyers, Inc. (10%). For the year ended December 31, 2011, Windsor Midstream LLC, a related party, accounted for 79% of the Company’s revenue. 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, 2013, 2012 and 2011, there was no margin tax expense. The Company’s 2009, 2010, 2011, 2012 and 2013 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2013 and December 31, 2012, 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, 2013, 2012 and 2011, 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 was formed as a holding company on December 30, 2011, and did not conduct any material business operations prior to the Merger. Diamondback is a C-Corporation 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.

Acquisitions

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Acquisitions

ACQUISITIONS

2013 Activity

In September 2013, the Company completed two separate acquisitions of additional leasehold interests in the Permian Basin from unrelated third party sellers for an aggregate purchase price of $165,000, subject to certain adjustments. The first of these acquisitions closed on September 4, 2013, when the Company acquired certain assets located in northwestern Martin County, Texas, consisting of a 100% working interest (80% net revenue interest) in 4,506 gross and net acres. The second of these acquisitions closed on September 26, 2013, when the Company acquired certain assets located primarily in southwestern Dawson County, Texas, consisting of a 71% working interest (55% net revenue interest) in 9,390 gross (6,638 net) acres. These acquisitions were funded with a portion of the net proceeds from the August 2013 equity offering discussed in Note 1—Organization.

On September 19, 2013, the Company completed the acquisition of the mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas in the Permian Basin. The mineral interests entitle the Company to receive an average 19.5% royalty interest on all production from this acreage with no additional future capital or operating expense required. The acquisition was accounted for as an acquisition of assets. The $440,000 purchase price was funded with the net proceeds of the Company’s offering of Senior Notes discussed in Note 7—Debt.

2012 Activity

On October 11, 2012, the Company completed the acquisition of Gulfport’s oil and natural gas interests in the Permian Basin. The acquisition was accounted for according to the acquisition method, which 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, which consisted of the following:



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

The fair value of the 7,914 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, resulting in no goodwill or bargain purchase gain.



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

The Company has included in its combined consolidated statements of operations revenues of $7,353 and direct operating expenses of $2,260 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 statements of operations data of Diamondback for the years ended December 31, 2012 and 2011 have 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 such financial statements should not be viewed as indicative of operations in future periods.



	Pro Forma
	(Unaudited)
	Year Ended December 31,
	2012			2011
Pro forma total revenues	$	97,455		$	72,418
Pro forma income from operations	24,064			23,189
Pro forma net income	(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.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1490-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
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-Paragraph 2
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 30
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6910749&loc=d3e4845-128472

Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1524-128463

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=7488404&loc=d3e7000-128479

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-Name Accounting Standards Codification
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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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-URI http://asc.fasb.org/extlink&oid=6910749&loc=d3e4926-128472

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=25497992&loc=d3e1383-128463

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
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-URI http://asc.fasb.org/extlink&oid=7488404&loc=d3e6996-128479

+ Details

Property and Equipment

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property and Equipment

PROPERTY AND EQUIPMENT

Property and equipment includes the following:



	December 31,
	2013			2012
Oil and natural gas properties:
Subject to depletion	$	1,278,799		$	576,497
Not subject to depletion-acquisition costs
Incurred in 2013	279,353			—
Incurred in 2012	87,252			117,395
Incurred in 2011	1,598			1,670
Incurred in 2010	1,358			1,647
Incurred in 2009	—			533
Total not subject to depletion	369,561			121,245

Gross oil and natural gas properties	1,648,360			697,742
Less accumulated depreciation, depletion, amortization and impairment	(210,837		)	(145,102		)
Oil and natural gas properties, net	1,437,523			552,640

Pipeline and gas gathering assets	6,142			—

Other property and equipment	4,071			2,337
Less accumulated depreciation	(1,399		)	(735		)
Other property and equipment, net	2,672			1,602

Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	1,446,337		$	554,242

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 $5,348, $4,872 and $871 for the years ended December 31, 2013, 2012 and 2011, 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.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

ASSET RETIREMENT OBLIGATIONS

The following table describes the changes to the Company’s asset retirement obligation liability for the following periods:



	Year Ended December 31,
	2013			2012			2011
Asset retirement obligation, beginning of period	$	2,145		$	1,104		$	742
Additional liability incurred	226			201			297
Liabilities acquired	471			562			—
Liabilities settled	(14		)	(5		)	—
Accretion expense	201			98			65
Revisions in estimated liabilities	—			185			—
Asset retirement obligation, end of period	3,029			2,145			1,104
Less current portion	40			20			—
Asset retirement obligations - long-term	$	2,989		$	2,125		$	1,104

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.

Equity Method Investments	12 Months Ended
Equity Method Investments	Dec. 31, 2013
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 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 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 owns and operates 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. As of June 15, 2012, the Company distributed its remaining 22% interest in Bison to an entity which is controlled and managed by Wexford. As the transaction was between entities under common control, the Company recognized the distribution of $6,437 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 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 (“Muskie”), a Delaware limited liability company now known as Muskie Proppant LLC, 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 from January 1, 2012 through June 15, 2012 and the Company recorded its share of this loss. 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 recognized the distribution of $4,067 as an equity transaction. Muskie continues to be a related party with the Company.

Debt

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt

DEBT

Long-term debt consisted of the following:



	December 31,
	2013		2012
Revolving credit facility	$	10,000	$	—
7.625 % Senior Notes due 2021	450,000		—
Note Payable	—		338
Total long-term debt	460,000		338
Less current portion of long-term debt	—		(145		)
Long-term debt, net of current portion	$	460,000	$	193

Senior Notes

On September 18, 2013, the Company completed an offering of $450,000 in aggregate principal amount of 7.625% senior unsecured notes due 2021 (the “Senior Notes”). The Senior Notes bear interest at the rate of 7.625% per annum, payable semi-annually, in arrears on April 1 and October 1 of each year, commencing on April 1, 2014 and will mature on October 1, 2021. The Senior Notes are fully and unconditionally guaranteed by the Company’s subsidiaries. The net proceeds from the Senior Notes were used to fund the acquisition of mineral interests underlying approximately 15,000 gross (12,500 net) acres in Midland County, Texas in the Permian Basin.

The Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as the trustee (the “Indenture”). The Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on, or redeem or repurchase, capital stock, prepay subordinated indebtedness, sell assets including capital stock of subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries. If the Company experiences certain kinds of changes of control or if it sells certain of its assets, holders of the Senior Notes may have the right to require the Company to repurchase their Senior Notes.

The Company will have the option to redeem the Senior Notes, in whole or in part, at any time on or after October 1, 2016 at the redemption prices (expressed as percentages of principal amount) of 105.719% for the 12-month period beginning on October 1, 2016, 103.813% for the 12-month period beginning on October 1, 2017, 101.906% for the 12-month period beginning on October 1, 2018 and 100.000% beginning on October 1, 2019 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. In addition, prior to October 1, 2016, the Company may redeem all or a part of the Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium at the redemption date. Furthermore, before October 1, 2016, the Company may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of certain equity offerings at a redemption price of 107.625% of the principal amount of the Senior Notes being redeemed plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Senior Notes originally issued under the Indenture remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering.

In connection with the issuance of the Senior Notes, the Company and the subsidiary guarantors entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the initial purchasers on September 18, 2013, pursuant to which the Company and the subsidiary guarantors have agreed to file a registration statement with respect to an offer to exchange the Senior Notes for a new issue of substantially identical debt securities registered under the Securities Act. Under the Registration Rights Agreement, the Company also agreed to use its commercially reasonable efforts to cause the exchange offer registration statement to become effective within 360 days after the issue date of the Senior Notes and to consummate the exchange offer 30 days after effectiveness. The Company may be required to file a shelf registration statement to cover resales of the Senior Notes under certain circumstances. If the Company fails to satisfy certain of its obligations under the Registration Rights Agreement, the Company agreed to pay additional interest to the holders of the Senior Notes as specified in the Registration Rights Agreement.

Credit Facility-Wells Fargo Bank

On October 15, 2010, the Company entered into a secured revolving credit agreement with BNP Paribas, or BNP, as the administrative agent, sole book runner and lead arranger. On May 10, 2012, the revolving credit agreement was amended to provide for the resignation of BNP, and the appointment of Wells Fargo Bank, National Association, as administrative agent for the lenders. The credit agreement was amended and restated as of July 24, 2012 and again as of November 1, 2013. The credit agreement, as so amended and restated, provides for a revolving credit facility in the maximum amount of $600,000, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Company’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 1st. In addition, the Company may request up to three additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2013, the borrowing base was $225,000. As of December 31, 2013, the Company had outstanding borrowings of $10,000 which bore a weighted average interest rate of 1.67%.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Company that is based on the prime rate or LIBOR plus margins ranging from 0.50% for prime-based loans and 1.50% for LIBOR loans to 1.50% for prime-based loans and 2.50% for LIBOR loans, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid (a) if the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of November 1, 2018. The loan is secured by substantially all of the assets of the Company and its subsidiaries.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.



Financial Covenant			Required Ratio
Ratio of total debt to EBITDAX			Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement			Not less than 1.0 to 1.0
EBITDAX will be annualized beginning with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2014.

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $750,000 in the form of senior or senior subordinated notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each 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. As of December 31, 2013, the Company had $450,000 of senior notes outstanding.

As of December 31, 2013 and December 31, 2012, the Company was in compliance with all financial covenants under its revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

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. The Company repaid all outstanding borrowings under this note in 2013 and, as of December 31, 2013, had no amounts outstanding under this note. As of December 31, 2012, the Company had amounts outstanding under this note of $338.

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 $45,000. 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. 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 was 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. Prior to the completion of the IPO, there was $30,050 in aggregate principal and interest outstanding under this note. In connection with the IPO, the Company repaid all outstanding borrowings under the subordinated note and the subordinated note was canceled.

Interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2013, 2012 and 2011:



	Year Ended December 31,
	2013			2012		2011
Cash payments for interest	$	404		$	3,017	$	2,265
Amortization of debt issuance costs	1,018			494		250
Accrued interest related to the Senior Notes	9,913			—		—
Change in accrued interest and other	675			99		13
Interest charges incurred	12,010			3,610		2,528
Less capitalized interest	(3,951		)	—		—
Total interest expense	$	8,059		$	3,610	$	2,528

Earnings Per Share & Pro Forma Earnings Per Share

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Share & Pro Forma Earnings Per Share

EARNINGS PER SHARE & PRO FORMA EARNINGS PER SHARE

Earnings Per Share

The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:



	2013
				Per
	Income		Shares	Share
	(Per share amounts in actual dollars)
Basic:
Net income attributable to common stock	$	54,587	42,015	$	1.30
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	—	240
Diluted:
Net income attributable to common stock	$	54,587	42,255	$	1.29

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. 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
	(Per share amounts in actual dollars)
Basic:
Pro forma net income attributable to common stock	$	11,829	19,721	$	0.60
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	—	3
Diluted:
Pro forma net income attributable to common stock	$	11,829	19,724	$	0.60

Stock and Equity Based Compensation

12 Months Ended

Dec. 31, 2013

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

Stock and Equity Based Compensation

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 2,500 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 was 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 the Company’s IPO was priced at $17.50 per share. Eight employees were affected by this modification. As a result of the modification, incremental compensation cost of $4,588 was recognized on the modification date to recognize the portion of awards that are vested and includes cash payments of $2,813. In addition to the compensation expense recognized on the modification date, $5,866 of compensation expense will be recognized over the remaining service period and a liability of $333 was recognized ratably over one year as the Company’s chief executive officer received a cash payment on the first anniversary date of the IPO. The modification did not change the original vesting or exercise periods. As a result, options vest in four substantially 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:



	2013		2012		2011
General and administrative expenses	$	2,983	$	3,757	$	438
Stock based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	972		2,537		106
Related income tax benefit	704		930		—

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 4 substantially 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.



	2013			2012
Grant-date fair value	$	6.51		$	4.41
Expected volatility	36.9		%	40.0		%
Expected dividend yield	0.0		%	0.0		%
Expected term (in years)	3.8			3.8
Risk-free rate	0.57		%	0.33		%

The following table presents the Company’s stock option activity under the 2012 Plan for the year ended December 31, 2013:



			Weighted Average
			Exercise		Remaining	Intrinsic
	Options		Price		Term	Value
					(In years)
Outstanding at December 31, 2012	850		$	17.50
Granted	63		$	22.72
Exercised	(200	)	$	17.50
Expired/Forfeited	—		$	—
Outstanding at December 31, 2013	713		$	17.96	2.69	$	24,895

Vested and Expected to vest at December 31, 2013	713		$	17.96	2.69	$	24,895
Exercisable at December 31, 2013	250		$	17.50	2.11	$	8,843

The aggregate intrinsic value of stock options that were exercised during 2013 was $5,717. As of December 31, 2013, the unrecognized compensation cost related to unvested stock options was $1,718. Such cost is expected to be recognized over a weighted-average period of 1.7 years.

Restricted Stock Awards and Units

Under the 2012 Plan, approved by the Board of Directors, the Company is authorized to issue restricted stock and restricted stock units to 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.

The following table presents the Company’s restricted stock awards and units activity under the 2012 Plan for the year ended December 31, 2013:



			Weighted Average
	Restricted Stock		Grant-Date
	Awards & Units		Fair Value
Unvested at December 31, 2012	206		$	17.50
Granted	11		$	41.66
Vested	(81	)	$	18.03
Forfeited	(4	)	$	17.50
Unvested at December 31, 2013	132		$	19.20

The aggregate fair value of restricted stock units that vested in 2013 and 2012 was $3,310 and $1,269, respectively. As of December 31, 2013, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $2,053. Such cost is expected to be recognized over a weighted-average period of 1.4 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 five 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	$	1,453
August 2011	1.20%	6,000		1,384
September 2011	1.25%	5,900		1,533
November 2011	0.25%	1,250		288
	3.70%	$	16,750	$	4,658

At December 31, 2011, the intrinsic value for all outstanding options was $113 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.

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2013
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. The initial term of this shared service agreement was two years. Since the expiration of such two-year period on March 1, 2010, the agreement by its terms, continued on a month-to-month basis. For the years ended December 31, 2013, 2012 and 2011, the Company incurred total costs of $207, $4,419 and $10,110, 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 and $1,954 for the years ended December 31, 2012 and 2011, respectively. As of December 31, 2013 and December 31, 2012, the Company owed the administrative services affiliate $17 and $13, respectively. These amounts are included in accounts payable-related party in the accompanying 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 years ended December 31, 2013 and 2012, the affiliate reimbursed the Company $1,077 and $2,132, respectively for services under the shared services agreement. As of December 31, 2013 and December 31, 2012, the affiliate owed the Company no amounts and $1, respectively. These amounts are included in accounts receivable-related party in the accompanying 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, 2013 and December 31, 2012, amounts due from an affiliate (a greater than 5% stockholder) related to joint interest billings and included in accounts receivable-related party in the accompanying consolidated balance sheets were no amounts and $742, respectively. Drilling Services Bison has performed drilling and field services for the Company under master drilling and field service agreements. Under the Company’s most recent master drilling agreement with Bison, effective as of January 1, 2013, Bison committed to accept orders from the Company for the use of at least two of its rigs. At December 31, 2013, Bison was providing drilling services to the Company using one 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. For the years ended December 31, 2013, 2012 and 2011 the Company incurred total costs of $13,921, $16,040 and $16,357, respectively, payable to Bison. The Company owed Bison no amounts as of December 31, 2013 and $120 as of December 31, 2012. Effective September 9, 2013, the Company entered into a master service agreement with Panther Drilling Systems LLC (“Panther Drilling”), an entity controlled by Wexford. Panther Drilling provides directional drilling and other services. This master service agreement is terminable by either party on 30 days prior written notice, although neither party will be relieved of its respective obligations arising from work performed prior to the termination of the master service agreement. In the third quarter 2013, the Company began using Panther Drilling’s directional drilling services. For the year ended December 31, 2013, the Company incurred $176 for services performed by Panther Drilling. The Company owed Panther Drilling no amounts as of December 31, 2013. 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 for the year ended December 31, 2011, and such amounts are included in oil sales–related party in the accompanying combined consolidated statements of operations. Coronado Midstream The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with Coronado Midstream LLC (“Coronado Midstream”), formerly known as MidMar Gas LLC, an entity affiliated with Wexford that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, Coronado Midstream is obligated to purchase from the Company, and the Company is obligated to sell to Coronado Midstream, 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, Coronado Midstream is obligated to pay the Company 87% of the net revenue received by Coronado Midstream 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 Coronado Midstream’s gas processing plant, and 94.56% of the net revenue received by Coronado Midstream from the sale of such gas components and residue gas, extracted, recovered or otherwise processed at Chevron’s Headlee plant. The Company recognized revenues from Coronado Midstream of $7,230, $4,050 and $2,190 for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013 and December 31, 2012, Coronado Midstream owed the Company $1,303 and $6, respectively, for the Company’s portion of the net proceeds from the sale of gas, gas products and residue gas. Sand Supply Muskie, an entity affiliated with Wexford, processes and sells fracking grade sand for oil and natural gas operations. The Company began purchasing sand from Muskie in March 2013. On May 16, 2013, the Company entered into a master services agreement with Muskie, pursuant to which Muskie agreed to sell custom natural sand proppant to the Company based on the Company’s requirements. The Company is not obligated to place any orders with, or accept any offers from, Muskie for sand proppant. The agreement may be terminated at the option of either party on 30 days’ notice. The Company incurred costs of $743 for the year ended December 31, 2013. As of December 31, 2013, the Company did not owe Muskie any amounts. 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 $214, $155 and $40 for the years ended December 31, 2013, 2012 and 2011, respectively, under this lease. In the second and third quarters of 2013, the Company amended this agreement to increase the size of the leased premises. The monthly rent under the lease increased from $13 to $15 beginning on August 1, 2013 and increased further to $25 beginning on October 1, 2013. The monthly rent will continue to increase approximately 4% annually on June 1 of each year during the remainder of 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 $244 and $329 for the years ended December 31, 2013 and 2012, respectively, under this lease. Effective April 1, 2013, this lease was amended to increase the size of the leased premises, at which time our monthly base rent increased to $19 for the remainder of the lease term. The Company is also responsible for paying a portion of specified costs, fees and expenses associated with the operation of the premises. 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, 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 $500 and $191 for the years ended December 31, 2013 and 2012, respectively, under the Advisory Services Agreement. Wexford provides certain professional services to the Company, for which the Company incurred total costs of $119 for the year ended December 31, 2012. As of December 31, 2013 and December 31, 2012, the Company owed Wexford no amounts and $113, respectively. These amounts are included in accounts payable-related party in the accompanying consolidated balance sheets. The Company did not incur any costs for professional services from Wexford during the year ended December 31, 2011. Secondary Offering Costs On June 24, 2013, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 6,000 shares of the Company’s common stock and, on July 5, 2013, the underwriters purchased an additional 869 shares of the Company’s common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the public at $34.75 per share and the selling stockholders received all proceeds from this offering. The Company incurred costs of approximately $185 related to the secondary public offering. On November 13, 2013, Gulfport completed an underwritten secondary public offering of 2,000 shares of the Company’s common stock that were owned by Gulfport. The shares were sold to the public at $53.46 per share and the selling stockholder received all proceeds from this offering. The Company incurred costs of approximately $53 related to the secondary public offering.

- 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 + Details

Income Taxes

12 Months Ended

Dec. 31, 2013

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 2—Summary of Significant Accounting Policies, Diamondback Energy LLC merged with and into Diamondback on October 11, 2012 and, accordingly, Diamondback has filed 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 Company is subject to corporate income taxes and the Texas margin tax.

The components of the provision for income taxes for the years ended December 31, 2013 and 2012 are as follows:



	Year Ended December 31,
	2013		2012
Current income tax provision:
Federal	$	191	$	—
State	—		—
Total current income tax provision	191		—
Deferred income tax provision:
Federal	30,768		53,319
State	795		1,584
Total deferred income tax provision	31,563		54,903
Total provision for income taxes	$	31,754	$	54,903

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

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



	Year Ended December 31,
	2013		2012
Income tax expense at the federal statutory rate (35%)	$	30,231	$	6,434
Deduction for pre-merger LLC earnings	—		(5,717		)
Income tax expense relating to change in tax status	—		54,142
State income tax expense, net of federal tax benefit	517		42
Non-deductible expenses	1,006		2
Provision for income taxes	$	31,754	$	54,903

The components of the Company’s deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows:



	December 31,
	2013		2012
Current:
Deferred tax assets
Derivative instruments	$	—	$	1,857
Other	265		—
Total current deferred tax assets	265		1,857
Deferred tax liabilities
Derivative instruments	153		—
Total current deferred tax liabilities	153		—
Net current deferred tax assets	112		1,857
Noncurrent:
Deferred tax assets
Net operating loss carryforwards (subject to 20 year expiration)	—		1,577
Stock based compensation	346		930
Alternative minimum tax credit carryforward	191		—
Other	20		—
Total noncurrent deferred tax assets	557		2,507
Deferred tax liabilities
Oil and natural gas properties and equipment	92,321		64,636
Other	—		566
Total noncurrent deferred tax liabilities	92,321		65,202
Net noncurrent deferred tax liabilities	91,764		62,695
Net deferred tax liabilities	$	91,652	$	60,838

As of December 31, 2013, the Company had a federal net operating loss carryforward of $5,833. However, a related deferred tax asset is not reflected as the excess tax benefit has not been recognized for certain stock-based compensation deductions which have not reduced current taxes payable. As of December 31, 2013, the Company also had recognized a $191 deferred tax asset related to alternative minimum tax credits which have no expiration date and will be available or use against tax on future taxable income.

Derivatives

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

DERIVATIVES

All derivative financial instruments are recorded at fair value. 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 cash and non-cash changes in fair value in the combined consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

The Company has used price swap contracts to reduce price volatility associated with certain of its oil sales. With respect to the Company’s fixed price swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing, Argus Louisiana light sweet pricing or Inter–Continental Exchange (“ICE”) pricing for Brent crude oil. The counterparty to the Company’s derivative contracts is Wells Fargo Bank, N.A., who the Company believes is an acceptable credit risk.

As of December 31, 2013, the Company had open crude oil derivative positions with respect to future production as set forth in the tables below. When aggregating multiple contracts, the weighted average contract price is disclosed.



Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap

Production Period	Volume (Bbls)	Fixed Swap Price
January - December 2014	944,000	$	98.78
January 2015	31,000	101.00

Crude Oil—ICE Brent Fixed Price Swap

Production Period	Volume (Bbls)	Fixed Swap Price
January–April 2014	120,000	$	109.70

Balance sheet offsetting of derivative assets and liabilities

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. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement.

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2013 and December 31, 2012.



	December 31, 2013
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Assets Presented in the Consolidated Balance Sheet
Derivative assets	$	998	$	(567	)	$	431

	December 31, 2012
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
Derivative liabilities	$	5,205	$	—		$	5,205

The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:



	December 31,		December 31,
	2013		2012
Current Assets: Derivative instruments	$	213	$	—
Noncurrent Assets: Derivative instruments	218		—
Total Assets	$	431	$	—

Current Liabilities: Derivative instruments	$	—	$	4,817
Noncurrent Liabilities: Derivative instruments	—		388
Total Liabilities	$	—	$	5,205

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 table summarizes the gains and losses on derivative instruments included in the combined consolidated statements of operations:



	Year Ended December 31,
	2013			2012			2011
Non-cash gain (loss) on open non-hedge derivative instruments	$	5,346		$	8,057		$	(12,972	)
Loss on settlement of non-hedge derivative instruments	(7,218		)	(5,440		)	(37		)
Gain (loss) on derivative instruments	$	(1,872	)	$	2,617		$	(13,009	)

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

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-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5618551-113959

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5580258-113959

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4E
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624181-113959

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41638-113959

Reference 20: 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.(n))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

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.

The fair value hierarchy is 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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s fixed price 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.

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, 2013 and December 31, 2012.



	Fair value measurements at December 31, 2013 using:
	Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Total
Assets:
Fixed price swaps	$	—	$	431	$	—	$	431

	Fair value measurements at December 31, 2012 using:
	Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Total
Liabilities:
Fixed price swaps	$	—	$	5,205	$	—	$	5,205

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the combined consolidated financial statements.



	December 31, 2013				December 31, 2012
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Debt:
Revolving credit facility	$	10,000	$	10,000	$	—	$	—
7.625% Senior Notes due 2021	450,000		460,406		—		—
Note payable	—		—		338		305

The fair value of the revolving credit facility approximates its carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the December 31, 2013 quoted market price, a Level 1 classification in the fair value hierarchy. The fair value of the note payable is determined using internal discounted cash flow calculations based on the interest rate and payment terms of the note payable. The fair value of the note payable is classified as Level 3 in the fair value hierarchy.

- 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 + Details

Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

In September 2010, Windsor Permian (now known as Diamondback O&G LLC) purchased certain property in Goodhue County, Minnesota, that was prospective for hydraulic fracturing grade sand. Prior to the purchase, the prior owners of the property had entered into a Mineral Development Agreement with the plaintiff and the Company purchased the property subject to that agreement. Windsor Permian subsequently contributed the property to Muskie. In an amended complaint filed in November 2012 by the plaintiff against the prior owners of the property, Windsor Permian and certain affiliates of Windsor Permian in the first judicial district court in Goodhue County, Minnesota, the plaintiff seeks damages from the Company and the other defendants alleging, among other things, interference with contractual relationship, interference with prospective advantage and unjust enrichment. In an order filed on May 24, 2013, the judge denied certain motions made by the defendants and set a trial date to determine liability, with a damage phase of the matter to commence on a later date if there is a determination of liability. Following a trial on the liability phase on June 21, 2013, the jury determined that the defendants intentionally interfered with plaintiff’s contract but that the interference did not cause the plaintiff to be unable to acquire mining permits prior to the enactment of the moratorium by Goodhue County. In an order filed on July 10, 2013, the judge ordered the damage phase to be set for trial following a pretrial and scheduling conference, and the parties have agreed upon a schedule for pretrial activities. Subsequently, the plaintiff disclosed a new damage theory, and the defendants filed motions with the court to dismiss plaintiff’s claims on the grounds that the damage claim is speculative and that plaintiff cannot prove damages as a matter of law. Plaintiff also filed a motion for leave to amend its complaint to assert a punitive damage claim. The motions were argued in December 2013 and the Company currently anticipate a ruling before the end of March 2014. The Company believes these claims are without merit and will continue to vigorously defend this action. While management has determined that the possibility of loss is remote, litigation is inherently uncertain and management cannot determine the amount of loss, if any, that may result.

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, 2013.



Year Ending December 31,	Office and Equipment Leases

2014	$	667
2015	682
2016	505
2017	301
2018	25
Thereafter	—
Total	$	2,180

The Company leases office space in Midland, Texas from a third party and leases office space in Midland, Texas and Oklahoma City, Oklahoma from related parties. Refer to Note 10—Related Party Transactions for further information on the related party lease agreements. In March 2011, the Company began leasing field office space in Midland, Texas from a third party. The lease term is 84 months with equal monthly installments that escalate 3% annually on March 1st of each year. The following table presents rent expense for the years ended December 31, 2013, 2012 and 2011.



	For the years ended
	December 31,
	2013		2012		2011
Rent Expense	$	571	$	547	$	74

Drilling contracts

As of December 31, 2013, the Company had entered into drilling rig contracts with one related party and various third parties in the ordinary course of business to ensure rig availability to complete the Company’s drilling projects. Refer to Note 10—Related Party Transactions for further information on the related party drilling agreement. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments as of December 31, 2013 total approximately $4,729.

Oil production purchase agreement

On May 24, 2012, the Company entered into an oil purchase agreement with Shell Trading, in which the Company is obligated to commence delivery of specified quantities of oil to Shell Trading upon completion of the reversal of the Magellan Longhorn pipeline and its conversion for oil shipment, which occurred on October 1, 2013. The Company’s agreement with Shell Trading has an initial term of 5 years from the completion date. The Company’s maximum delivery obligation under this agreement is 8 gross barrels per day. The Company has a one-time right to elect to decrease the contract quantity by not more than 20% of the then-current quantity, which decreased contract quantity will be effective for the remainder of the term of the agreement. The Company will receive the price per barrel of oil based on the arithmetic average of the daily settlement price for “Light Sweet Crude Oil” Prompt Month future contracts reported by the New York Mercantile Exchange over the one-month period, as adjusted based on adjustment formulas specified in the agreement. If the Company fails to deliver the required quantities of oil under the agreement during any three-month period following the service commencement date, the Company has agreed to pay Shell Trading a deficiency payment, which is calculated by multiplying (i) the volume of oil that the Company failed to deliver as required under the agreement during such period by (ii) Magellan’s Longhorn Spot tariff rate in effect for transportation from Crane, Texas to the Houston Ship Channel for the period of time for which such deficiency volume is calculated. The agreement may be terminated by Shell Trading in the event that Shell Trading’s contract for transportation on the pipeline is terminated.

Fracturing and well stimulation agreement

The Company has a contractual obligation with a third-party service provider for fracturing and well stimulation services. The agreement has a term through March 31, 2014. As of December 31, 2013, the future minimum commitment was approximately $3,600.

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. For the year ended December 31, 2013 and 2012 the Company paid $262 and $86, respectively, in contributions to the plan. Prior to 2012, the previous plan was sponsored under the shared service agreements discussed in Note 10—Related Party Transactions and the Company did not directly contribute to the previous plan.

Subsequent Events

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTS

On January 2, 2014 the Company granted 79 performance awards with a combination of market and service vesting criteria and 79 restricted stock awards with service vesting criteria under the 2012 Plan. For the performance awards the Company will use an appropriate fair value model to determine the fair value on the date of grant of the performance stock awards, which is expensed over the applicable two year vesting period of these awards. For the restricted stock awards the Company will estimate the fair values of restricted stock awards as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable two year vesting period of these awards.

On January 28, 2014, the Company entered into a new commodity contract with JP Morgan Chase Bank, National Association. The derivative is a fixed price oil swap that will settle against the weighted average price per barrel of Argus Louisiana light sweet during the calculation period. The following table presents the terms of the contract:



		Fixed Swap
	Volumes (Bbls)	Price		Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap	365,000	$	96.75	February 2014	-	January 2015

On February 19, 2014, the Company entered into a new commodity contract with Wells Fargo Bank, N. A. The derivative is a fixed price oil swap that will settle against the calendar month average price per barrel of Argus Louisiana light sweet during the calculation period. The following table presents the terms of the contract:



		Fixed Swap
	Volumes (Bbls)	Price		Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap	365,000	$	100.60	March 2014	-	February 2015

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

12 Months Ended

Dec. 31, 2013

Extractive Industries [Abstract]

Supplemental information on oil and natural gas operations

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (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,
	2013			2012
Oil and Natural Gas Properties:
Proved properties	$	1,278,799		$	576,497
Unproved properties	369,561			121,245
Total Oil and Natural Gas Properties	1,648,360			697,742
Less Accumulated depreciation, depletion, amortization and impairment	(210,837		)	(145,102		)
Net oil and natural gas properties capitalized	$	1,437,523		$	552,640

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,
	2013		2012		2011
Acquisition costs
Proved properties	$	339,130	$	115,760	$	—
Unproved properties	279,402		117,395		3,704
Development costs	88,460		106,261		75,374
Exploration costs	242,929		17,547		11,226
Capitalized asset retirement costs	697		948		297
Total	$	950,618	$	357,911	$	90,601

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,
	2013			2012			2011
Oil, natural gas and natural gas liquid sales	$	208,002		$	74,962		$	47,875
Lease operating expenses	(21,157		)	(15,247		)	(9,931		)
Production and ad valorem taxes	(12,899		)	(5,237		)	(3,032		)
Gathering and transportation	(918		)	(424		)	(202		)
Depreciation, depletion, and amortization	(65,821		)	(25,772		)	(15,377		)
Asset retirement obligation accretion expense	(201		)	(98		)	(65		)
Income tax expense	(31,754		)	(54,903		)	—
Results of operations	$	75,252		$	(26,719	)	$	19,268

Pro forma information
Pro forma results of operations before income taxes				$	28,184
Pro forma income tax⁽¹⁾				(10,083		)
Pro forma results of operations				$	18,101



(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, 2013, 2012 and 2011 were prepared by Ryder Scott Company, L.P., 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, 2011	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	)
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	)
As of December 31, 2012	26,196,859		8,251,429		34,570,148

Extensions and discoveries	17,041,744		4,597,856		24,184,540
Revisions of previous estimates	(5,943,164	)	(3,455,306	)	(5,786,180	)
Purchase of reserves in place	7,328,162		1,672,824		10,441,485
Production	(2,022,749	)	(361,079	)	(1,730,497	)
As of December 31, 2013	42,600,852		10,705,724		61,679,496

Proved Developed Reserves:
January 1, 2011	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
December 31, 2013	19,789,965		4,973,493		31,428,756

Proved Undeveloped Reserves:
January 1, 2011	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
December 31, 2013	22,810,887		5,732,231		30,250,740

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, natural gas and natural gas liquid reserves in 2013. The downward revisions were primarily a result of downgrading 92 vertical locations that were booked as PUDs to probable in accordance with the SEC five year PUD rule.

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.

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, 2013, 2012 and 2011.



	December 31,
	2013			2012			2011
Future cash inflows	$	4,604,241		$	2,769,485		$	2,049,520
Future development costs	(517,075		)	(541,445		)	(410,350		)
Future production costs	(806,895		)	(773,611		)	(497,808		)
Future production taxes	(318,396		)	(140,758		)	(104,856		)
Future income tax expenses	(674,260		)	(334,903		)	—
Future net cash flows	2,287,615			978,768			1,036,506
10% discount to reflect timing of cash flows	(1,311,976		)	(611,548		)	(671,894		)
Standardized measure of discounted future net cash flows	$	975,639		$	367,220		$	364,612

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,
	2013		2012		2011
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	92.59	$	88.13	$	93.09
Natural gas (per Mcf)	$	4.13	$	2.86	$	3.91
Natural gas liquids (per Bbl)	$	37.82	$	43.88	$	56.33

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,
	2013			2012			2011
Standardized measure of discounted future net cash flows at the beginning of the period	$	367,220		$	364,612		$	339,001
Sales of oil and natural gas, net of production costs	(173,946		)	(54,208		)	(34,711		)
Purchase of minerals in place	305,109			107,897			—
Extensions and discoveries, net of future development costs	552,450			79,293			73,571
Previously estimated development costs incurred during the period	76,631			88,849			87,530
Net changes in prices and production costs	51,828			(76,515		)	82,364
Changes in estimated future development costs	(5,822		)	8,309			(82,855		)
Revisions of previous quantity estimates	(126,993		)	(22,882		)	(98,533		)
Accretion of discount	57,988			36,461			33,900
Net change in income taxes	(168,570		)	(125,542		)	—
Net changes in timing of production and other	39,744			(39,054		)	(35,655		)
Standardized measure of discounted future net cash flows at the end of the period	$	975,639		$	367,220		$	364,612

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

QUARTERLY FINANCIAL DATA (Unaudited)

The Company’s unaudited quarterly financial data for 2013 and 2012 is summarized below.



	2013
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Revenues	$	28,909	$	45,394	$	57,791	$	75,908
Income from operations	8,662		19,383		29,423		37,726
Income tax expense	3,162		7,802		9,099		11,691
Net income (loss)	$	5,396	$	14,471	$	14,596	$	20,124
Earnings per common share
Basic	$	0.15	$	0.37	$	0.33	$	0.43
Diluted	$	0.15	$	0.36	$	0.33	$	0.42

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

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

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.

Pro Forma Earnings per Share

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Basis of Presentation

Use of Estimates

Reclassifications

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

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.

Oil and Natural Gas Properties

Other Property and Equipment

Asset Retirement Obligations

Impairment or Long-Lived Assets

Impairment of Long-Lived Assets

Capitalized Interest

Inventory

Inventories

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



	December 31,
	2013		2012
Tubular goods and equipment	$	5,631	$	5,725
Crude oil	—		470
	$	5,631	$	6,195

Debt Issuance Costs

Revenue Recognition

Revenue and Royalties Payable

Revenue Recognition

Investments

Accounting for Stock-based Compensation

Accounting for Stock-Based Compensation

Concentrations

Environmental Compliance and Remediation

Income Taxes

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Schedule of inventories

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



	December 31,
	2013		2012
Tubular goods and equipment	$	5,631	$	5,725
Crude oil	—		470
	$	5,631	$	6,195

Schedule of other accrued liabilities

Other accrued liabilities consist of the following:



	December 31,
	2013		2012
Prepaid drilling liability	$	16,491	$	4,540
Interest payable	9,918		—
Lease operating expense payable	4,538		4,737
Current portion of asset retirement obligations	40		20
Other	3,763		1,352
	$	34,750	$	10,649

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Schedule of business acquisitions

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



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

Schedule of assets acquired and liabilities assumed at acquisition date



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

Schedule of business acquisition pro forma

The following unaudited summary pro forma combined consolidated statements of operations data of Diamondback for the years ended December 31, 2012 and 2011 have 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 such financial statements should not be viewed as indicative of operations in future periods.



	Pro Forma
	(Unaudited)
	Year Ended December 31,
	2012			2011
Pro forma total revenues	$	97,455		$	72,418
Pro forma income from operations	24,064			23,189
Pro forma net income	(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 (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property and Equipment

Property and equipment includes the following:



	December 31,
	2013			2012
Oil and natural gas properties:
Subject to depletion	$	1,278,799		$	576,497
Not subject to depletion-acquisition costs
Incurred in 2013	279,353			—
Incurred in 2012	87,252			117,395
Incurred in 2011	1,598			1,670
Incurred in 2010	1,358			1,647
Incurred in 2009	—			533
Total not subject to depletion	369,561			121,245

Gross oil and natural gas properties	1,648,360			697,742
Less accumulated depreciation, depletion, amortization and impairment	(210,837		)	(145,102		)
Oil and natural gas properties, net	1,437,523			552,640

Pipeline and gas gathering assets	6,142			—

Other property and equipment	4,071			2,337
Less accumulated depreciation	(1,399		)	(735		)
Other property and equipment, net	2,672			1,602

Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	1,446,337		$	554,242

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

The following table describes the changes to the Company’s asset retirement obligation liability for the following periods:



	Year Ended December 31,
	2013			2012			2011
Asset retirement obligation, beginning of period	$	2,145		$	1,104		$	742
Additional liability incurred	226			201			297
Liabilities acquired	471			562			—
Liabilities settled	(14		)	(5		)	—
Accretion expense	201			98			65
Revisions in estimated liabilities	—			185			—
Asset retirement obligation, end of period	3,029			2,145			1,104
Less current portion	40			20			—
Asset retirement obligations - long-term	$	2,989		$	2,125		$	1,104

Debt (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Schedule of long-term debt

Long-term debt consisted of the following:



	December 31,
	2013		2012
Revolving credit facility	$	10,000	$	—
7.625 % Senior Notes due 2021	450,000		—
Note Payable	—		338
Total long-term debt	460,000		338
Less current portion of long-term debt	—		(145		)
Long-term debt, net of current portion	$	460,000	$	193

Financial Covenants



Financial Covenant			Required Ratio
Ratio of total debt to EBITDAX			Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement			Not less than 1.0 to 1.0
EBITDAX will be annualized beginning with the quarter ended September 30, 2013 and ending with the quarter ending March 31, 2014.

Schedule of interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2013, 2012 and 2011:



	Year Ended December 31,
	2013			2012		2011
Cash payments for interest	$	404		$	3,017	$	2,265
Amortization of debt issuance costs	1,018			494		250
Accrued interest related to the Senior Notes	9,913			—		—
Change in accrued interest and other	675			99		13
Interest charges incurred	12,010			3,610		2,528
Less capitalized interest	(3,951		)	—		—
Total interest expense	$	8,059		$	3,610	$	2,528

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, 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 210.5-02.22)
-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 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

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.(e),(f))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

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 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

+ Details

Earnings Per Share & Pro Forma Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Schedule of reconciliation of basic and diluted net income per share

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



	2013
				Per
	Income		Shares	Share
	(Per share amounts in actual dollars)
Basic:
Net income attributable to common stock	$	54,587	42,015	$	1.30
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	—	240
Diluted:
Net income attributable to common stock	$	54,587	42,255	$	1.29

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
	(Per share amounts in actual dollars)
Basic:
Pro forma net income attributable to common stock	$	11,829	19,721	$	0.60
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	—	3
Diluted:
Pro forma net income attributable to common stock	$	11,829	19,724	$	0.60

Stock and Equity Based Compensation (Tables)

12 Months Ended

Dec. 31, 2013

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:



	2013		2012		2011
General and administrative expenses	$	2,983	$	3,757	$	438
Stock based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	972		2,537		106
Related income tax benefit	704		930		—

Significant assumptions used to estimate fair value of the options

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%



	2013			2012
Grant-date fair value	$	6.51		$	4.41
Expected volatility	36.9		%	40.0		%
Expected dividend yield	0.0		%	0.0		%
Expected term (in years)	3.8			3.8
Risk-free rate	0.57		%	0.33		%

Schedule of stock option activity

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	$	1,453
August 2011	1.20%	6,000		1,384
September 2011	1.25%	5,900		1,533
November 2011	0.25%	1,250		288
	3.70%	$	16,750	$	4,658

The following table presents the Company’s stock option activity under the 2012 Plan for the year ended December 31, 2013:



			Weighted Average
			Exercise		Remaining	Intrinsic
	Options		Price		Term	Value
					(In years)
Outstanding at December 31, 2012	850		$	17.50
Granted	63		$	22.72
Exercised	(200	)	$	17.50
Expired/Forfeited	—		$	—
Outstanding at December 31, 2013	713		$	17.96	2.69	$	24,895

Vested and Expected to vest at December 31, 2013	713		$	17.96	2.69	$	24,895
Exercisable at December 31, 2013	250		$	17.50	2.11	$	8,843

Summary of restricted stock awards and units

The following table presents the Company’s restricted stock awards and units activity under the 2012 Plan for the year ended December 31, 2013:



			Weighted Average
	Restricted Stock		Grant-Date
	Awards & Units		Fair Value
Unvested at December 31, 2012	206		$	17.50
Granted	11		$	41.66
Vested	(81	)	$	18.03
Forfeited	(4	)	$	17.50
Unvested at December 31, 2013	132		$	19.20

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The components of the provision for income taxes for the years ended December 31, 2013 and 2012 are as follows:



	Year Ended December 31,
	2013		2012
Current income tax provision:
Federal	$	191	$	—
State	—		—
Total current income tax provision	191		—
Deferred income tax provision:
Federal	30,768		53,319
State	795		1,584
Total deferred income tax provision	31,563		54,903
Total provision for income taxes	$	31,754	$	54,903

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

Schedule of Effective Income Tax Rate Reconciliation

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



	Year Ended December 31,
	2013		2012
Income tax expense at the federal statutory rate (35%)	$	30,231	$	6,434
Deduction for pre-merger LLC earnings	—		(5,717		)
Income tax expense relating to change in tax status	—		54,142
State income tax expense, net of federal tax benefit	517		42
Non-deductible expenses	1,006		2
Provision for income taxes	$	31,754	$	54,903

Schedule of Deferred Tax Assets and Liabilities

The components of the Company’s deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows:



	December 31,
	2013		2012
Current:
Deferred tax assets
Derivative instruments	$	—	$	1,857
Other	265		—
Total current deferred tax assets	265		1,857
Deferred tax liabilities
Derivative instruments	153		—
Total current deferred tax liabilities	153		—
Net current deferred tax assets	112		1,857
Noncurrent:
Deferred tax assets
Net operating loss carryforwards (subject to 20 year expiration)	—		1,577
Stock based compensation	346		930
Alternative minimum tax credit carryforward	191		—
Other	20		—
Total noncurrent deferred tax assets	557		2,507
Deferred tax liabilities
Oil and natural gas properties and equipment	92,321		64,636
Other	—		566
Total noncurrent deferred tax liabilities	92,321		65,202
Net noncurrent deferred tax liabilities	91,764		62,695
Net deferred tax liabilities	$	91,652	$	60,838

Derivatives (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivative instruments



Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap

Production Period	Volume (Bbls)	Fixed Swap Price
January - December 2014	944,000	$	98.78
January 2015	31,000	101.00

Crude Oil—ICE Brent Fixed Price Swap

Production Period	Volume (Bbls)	Fixed Swap Price
January–April 2014	120,000	$	109.70

The following table presents the terms of the contract:



		Fixed Swap
	Volumes (Bbls)	Price		Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap	365,000	$	100.60	March 2014	-	February 2015

The following table presents the terms of the contract:



		Fixed Swap
	Volumes (Bbls)	Price		Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap	365,000	$	96.75	February 2014	-	January 2015

Schedule of netting offsets of derivative assets and liabilities



	December 31, 2013
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Assets Presented in the Consolidated Balance Sheet
Derivative assets	$	998	$	(567	)	$	431

	December 31, 2012
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
Derivative liabilities	$	5,205	$	—		$	5,205

Schedule of derivative instruments included in the consolidated balance sheet

The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:



	December 31,		December 31,
	2013		2012
Current Assets: Derivative instruments	$	213	$	—
Noncurrent Assets: Derivative instruments	218		—
Total Assets	$	431	$	—

Current Liabilities: Derivative instruments	$	—	$	4,817
Noncurrent Liabilities: Derivative instruments	—		388
Total Liabilities	$	—	$	5,205

Summary of derivative contract gains and losses included in the consolidated statements of operations

The following table summarizes the gains and losses on derivative instruments included in the combined consolidated statements of operations:



	Year Ended December 31,
	2013			2012			2011
Non-cash gain (loss) on open non-hedge derivative instruments	$	5,346		$	8,057		$	(12,972	)
Loss on settlement of non-hedge derivative instruments	(7,218		)	(5,440		)	(37		)
Gain (loss) on derivative instruments	$	(1,872	)	$	2,617		$	(13,009	)

- 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 5
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41641-113959

Reference 2: 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 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
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-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=7476318&loc=SL5579240-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=7476318&loc=d3e41620-113959

Reference 11: 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.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair value measurement information for financial instruments measured 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, 2013 and December 31, 2012.



	Fair value measurements at December 31, 2013 using:
	Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Total
Assets:
Fixed price swaps	$	—	$	431	$	—	$	431

	Fair value measurements at December 31, 2012 using:
	Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Total
Liabilities:
Fixed price swaps	$	—	$	5,205	$	—	$	5,205

Fair value measurement information for financial instruments measured on a nonrecurring basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the combined consolidated financial statements.



	December 31, 2013				December 31, 2012
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Debt:
Revolving credit facility	$	10,000	$	10,000	$	—	$	—
7.625% Senior Notes due 2021	450,000		460,406		—		—
Note payable	—		—		338		305

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2013

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, 2013.



Year Ending December 31,	Office and Equipment Leases

2014	$	667
2015	682
2016	505
2017	301
2018	25
Thereafter	—
Total	$	2,180

Schedule of rent expense

The following table presents rent expense for the years ended December 31, 2013, 2012 and 2011.



	For the years ended
	December 31,
	2013		2012		2011
Rent Expense	$	571	$	547	$	74

Subsequent Events (Tables)

12 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

Schedule of derivative instruments



Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap

Production Period	Volume (Bbls)	Fixed Swap Price
January - December 2014	944,000	$	98.78
January 2015	31,000	101.00

Crude Oil—ICE Brent Fixed Price Swap

Production Period	Volume (Bbls)	Fixed Swap Price
January–April 2014	120,000	$	109.70

The following table presents the terms of the contract:



		Fixed Swap
	Volumes (Bbls)	Price		Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap	365,000	$	100.60	March 2014	-	February 2015

The following table presents the terms of the contract:



		Fixed Swap
	Volumes (Bbls)	Price		Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap	365,000	$	96.75	February 2014	-	January 2015

- Definition

+ References

+ Details

Supplemental Information on Oil and Natural Gas Operations (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

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,
	2013			2012
Oil and Natural Gas Properties:
Proved properties	$	1,278,799		$	576,497
Unproved properties	369,561			121,245
Total Oil and Natural Gas Properties	1,648,360			697,742
Less Accumulated depreciation, depletion, amortization and impairment	(210,837		)	(145,102		)
Net oil and natural gas properties capitalized	$	1,437,523		$	552,640

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,
	2013		2012		2011
Acquisition costs
Proved properties	$	339,130	$	115,760	$	—
Unproved properties	279,402		117,395		3,704
Development costs	88,460		106,261		75,374
Exploration costs	242,929		17,547		11,226
Capitalized asset retirement costs	697		948		297
Total	$	950,618	$	357,911	$	90,601

Results of operations from oil and natural gas producing activities



	Year Ended December 31,
	2013			2012			2011
Oil, natural gas and natural gas liquid sales	$	208,002		$	74,962		$	47,875
Lease operating expenses	(21,157		)	(15,247		)	(9,931		)
Production and ad valorem taxes	(12,899		)	(5,237		)	(3,032		)
Gathering and transportation	(918		)	(424		)	(202		)
Depreciation, depletion, and amortization	(65,821		)	(25,772		)	(15,377		)
Asset retirement obligation accretion expense	(201		)	(98		)	(65		)
Income tax expense	(31,754		)	(54,903		)	—
Results of operations	$	75,252		$	(26,719	)	$	19,268

Pro forma information
Pro forma results of operations before income taxes				$	28,184
Pro forma income tax⁽¹⁾				(10,083		)
Pro forma results of operations				$	18,101



(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, 2011	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	)
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	)
As of December 31, 2012	26,196,859		8,251,429		34,570,148

Extensions and discoveries	17,041,744		4,597,856		24,184,540
Revisions of previous estimates	(5,943,164	)	(3,455,306	)	(5,786,180	)
Purchase of reserves in place	7,328,162		1,672,824		10,441,485
Production	(2,022,749	)	(361,079	)	(1,730,497	)
As of December 31, 2013	42,600,852		10,705,724		61,679,496

Proved Developed Reserves:
January 1, 2011	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
December 31, 2013	19,789,965		4,973,493		31,428,756

Proved Undeveloped Reserves:
January 1, 2011	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
December 31, 2013	22,810,887		5,732,231		30,250,740

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, 2013, 2012 and 2011.



	December 31,
	2013			2012			2011
Future cash inflows	$	4,604,241		$	2,769,485		$	2,049,520
Future development costs	(517,075		)	(541,445		)	(410,350		)
Future production costs	(806,895		)	(773,611		)	(497,808		)
Future production taxes	(318,396		)	(140,758		)	(104,856		)
Future income tax expenses	(674,260		)	(334,903		)	—
Future net cash flows	2,287,615			978,768			1,036,506
10% discount to reflect timing of cash flows	(1,311,976		)	(611,548		)	(671,894		)
Standardized measure of discounted future net cash flows	$	975,639		$	367,220		$	364,612

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,
	2013		2012		2011
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	92.59	$	88.13	$	93.09
Natural gas (per Mcf)	$	4.13	$	2.86	$	3.91
Natural gas liquids (per Bbl)	$	37.82	$	43.88	$	56.33

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,
	2013			2012			2011
Standardized measure of discounted future net cash flows at the beginning of the period	$	367,220		$	364,612		$	339,001
Sales of oil and natural gas, net of production costs	(173,946		)	(54,208		)	(34,711		)
Purchase of minerals in place	305,109			107,897			—
Extensions and discoveries, net of future development costs	552,450			79,293			73,571
Previously estimated development costs incurred during the period	76,631			88,849			87,530
Net changes in prices and production costs	51,828			(76,515		)	82,364
Changes in estimated future development costs	(5,822		)	8,309			(82,855		)
Revisions of previous quantity estimates	(126,993		)	(22,882		)	(98,533		)
Accretion of discount	57,988			36,461			33,900
Net change in income taxes	(168,570		)	(125,542		)	—
Net changes in timing of production and other	39,744			(39,054		)	(35,655		)
Standardized measure of discounted future net cash flows at the end of the period	$	975,639		$	367,220		$	364,612

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 27
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62352-109447

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 24
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62246-109447

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 23
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62136-109447

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
-URI http://asc.fasb.org/extlink&oid=27015464&loc=d3e511914-122862

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

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62299-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62094-109447

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=8451039&loc=d3e62395-109447

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

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 55
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=8451751&loc=d3e63071-109448

+ 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, 2013

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Data

The Company’s unaudited quarterly financial data for 2013 and 2012 is summarized below.



	2013
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
Revenues	$	28,909	$	45,394	$	57,791	$	75,908
Income from operations	8,662		19,383		29,423		37,726
Income tax expense	3,162		7,802		9,099		11,691
Net income (loss)	$	5,396	$	14,471	$	14,596	$	20,124
Earnings per common share
Basic	$	0.15	$	0.37	$	0.33	$	0.43
Diluted	$	0.15	$	0.36	$	0.33	$	0.42

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

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

Organization (Details) - USD ($) $ / shares in Units, shares in Thousands							1 Months Ended	7 Months Ended	12 Months Ended
	Nov. 13, 2013	Jul. 05, 2013	Jul. 05, 2013	Jun. 24, 2013	Oct. 17, 2012	Oct. 11, 2012	Aug. 31, 2013	Jul. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Sep. 18, 2013
Initial Public Offering [Line Items]
Deferred recognized at date of Merger - change in tax status of Predecessors									$ 54,142,000
Stock price per share at public offering						$ 17.50
Common Stock [Member]
Initial Public Offering [Line Items]
Shares issued upon public offering					14,375		4,600	5,175
Common stock issued pursuant to underwriters over allotment option					1,875		600	675
Stock price per share at public offering					$ 17.50		$ 40.25	$ 29.25
Net proceeds received from public offering					$ 234,100,000		$ 177,500,000	$ 144,439,000
Shares sold in secondary public offering	2,000			6,000
Shares sold by existing stockholders		869
Stock price per share, selling stockholders	$ 53.46		$ 34.75
Senior Unsecured Notes due 2021 [Member] \| Senior Notes [Member]
Initial Public Offering [Line Items]
Aggregate principal amount											$ 450,000,000
Stated interest rate										7.625%	7.625%

Summary of Significant Accounting Policies (Details)	12 Months Ended
Summary of Significant Accounting Policies (Details)	Dec. 31, 2013 USD ($) $ / Boe	Dec. 31, 2012 USD ($) $ / Boe	Dec. 31, 2011 USD ($) $ / Boe
Accounting Policies [Abstract]
Amortization expense per physical unit of production \| $ / Boe	24.63	23.90	25.41
Depreciation, depletion and amortization	$ 65,821,000	$ 25,772,000	$ 15,377,000
Capitalized costs, proved oil and natural gas properties, net, discount percentage	10.00%
Impairment on proved oil and gas properties	$ 0	0	0
Interest costs capitalized	3,951,000	0	0
Unrecognized tax benefits that would have a material impact on the effective rate	0	0
Interest or penalties associated with uncertain tax positions	$ 0	$ 0	$ 0

Summary of Significant Accounting Policies - Other Property and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Depreciation expense	$ 776	$ 501	$ 727
Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life of property and equipment	3 years
Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life of property and equipment	15 years

Summary of Significant Accounting Policies - Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Inventory [Line Items]
Inventories	$ 5,631	$ 6,195
Tubular Goods and Equipment [Member]
Inventory [Line Items]
Inventories	5,631	5,725
Crude Oil [Member]
Inventory [Line Items]
Inventories	$ 0	$ 470

Summary of Significant Accounting Policies - Debt Issuance Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Sep. 18, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Debt issuance costs, net	$ 12,458		$ 1,115
Debt issuance costs, accumulated amortization	1,798		$ 782
Senior Unsecured Notes due 2021 [Member] \| Senior Notes [Member]
Debt Instrument [Line Items]
Debt issuance costs, net	$ 10,376
Stated interest rate	7.625%	7.625%

Summary of Significant Accounting Policies - Other Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]
Prepaid drilling liability	$ 16,491	$ 4,540
Interest payable	9,918	0
Lease operating expense payable	4,538	4,737
Current portion of asset retirement obligation	40	20	$ 0
Other	3,763	1,352
Total other accrued liabilities	$ 34,750	$ 10,649

Summary of Significant Accounting Policies - Concentrations (Details) - Customer Concentration Risk [Member] - Sales Revenue, Net [Member]	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Plains Marketing, L.P. [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	37.00%	53.00%
Shell Trading US Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	37.00%
Occidental Energy Marketing, Inc [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		16.00%
Andrews Oil Buyers, Inc [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%
Windsor Midstream LLC [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage			79.00%

Acquisitions - 2013 Activity (Details) $ in Thousands				1 Months Ended	12 Months Ended
Acquisitions - 2013 Activity (Details) $ in Thousands	Sep. 26, 2013 a	Sep. 19, 2013 USD ($) a	Sep. 04, 2013 a	Sep. 30, 2013 USD ($) leasehold_interest	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Sep. 18, 2013 a
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Payments to acquire leasehold interests \| $					$ 177,343	$ 11,707	$ 0
FANG mineral interest area, developed, gross								15,000
FANG mineral interest, area, developed, net								12,500
Payments to acquire mineral interests \| $					$ 444,083	$ 0	$ 0
Permian Basin [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Number of leasehold interest acquisitions \| leasehold_interest				2
Payments to acquire leasehold interests \| $				$ 165,000
Martin County, Texas [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Percent of working interest			100.00%
Percent of net revenue interest			80.00%
Acres of oil and gas property, gross			4,506
Acres of oil and gas property, net			4,506
Dawson County, Texas [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Percent of working interest	71.00%
Percent of net revenue interest	55.00%
Acres of oil and gas property, gross	9,390
Acres of oil and gas property, net	6,638
Midland County, Texas [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
FANG mineral interest area, developed, gross		15,000
FANG mineral interest, area, developed, net		12,500
Percent of royalty interest		19.50%
Payments to acquire mineral interests \| $		$ 440,000

Acquisitions - 2012 Activity (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		3 Months Ended
	Oct. 11, 2012	Dec. 31, 2012
Business Combinations [Abstract]
Consideration transferred	$ 220,636
Common stock issued for acquisition	7,914
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

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

Acquisitions - Estimated Fair Value of Assets Acquired and Liabilities Assumed (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

^[1]

$ (29,764)

$ 7,666

[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, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Subject to depletion	$ 1,278,799	$ 576,497
Oil and Natural Gas Properties:
Not subject to depletion-acquisition costs	369,561	121,245
Gross oil and natural gas properties	1,648,360	697,742
Less accumulated depreciation, depletion, amortization and impairment	(210,837)	(145,102)
Net oil and natural gas properties capitalized	1,437,523	552,640
Pipeline and gas gathering assets	6,142	0
Other property and equipment	4,071	2,337
Less accumulated depreciation	(212,236)	(145,837)
Other property and equipment, net	2,672	1,602
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	1,446,337	554,242
Capitalized general and administrative costs	5,348	4,872	$ 871
Other property and equipment
Oil and Natural Gas Properties:
Less accumulated depreciation	(1,399)	(735)
Incurred in 2013
Oil and Natural Gas Properties:
Not subject to depletion-acquisition costs	279,353	0
Incurred in 2012
Oil and Natural Gas Properties:
Not subject to depletion-acquisition costs	87,252	117,395
Incurred in 2011
Oil and Natural Gas Properties:
Not subject to depletion-acquisition costs	1,598	1,670
Incurred in 2010
Oil and Natural Gas Properties:
Not subject to depletion-acquisition costs	1,358	1,647
Incurred in 2009
Oil and Natural Gas Properties:
Not subject to depletion-acquisition costs	$ 0	$ 533
Minimum [Member]
Oil and Natural Gas Properties:
Number of years until unevaluated properties are included in full cost pool	3 years
Maximum [Member]
Oil and Natural Gas Properties:
Number of years until unevaluated properties are included in full cost pool	5 years

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in ARO liability
Asset retirement obligation, beginning of period	$ 2,145	$ 1,104	$ 742
Additional liability incurred	226	201	297
Liabilities acquired	471	562	0
Liabilities settled	(14)	(5)	0
Accretion expense	201	98	65
Revisions in estimated liabilities	0	185	0
Asset retirement obligation, end of period	3,029	2,145	1,104
Less current portion	40	20	0
Asset retirement obligations - long-term	$ 2,989	$ 2,125	$ 1,104

Equity Method Investments (Details) - USD ($) $ in Thousands	Jun. 15, 2012	Oct. 07, 2011
Bison Drilling
Schedule of Equity Method Investments
Ownership interest	22.00%
Distribution of equity method investment between entities under common control	$ 6,437
Muskie Holdings
Schedule of Equity Method Investments
Ownership interest	33.00%	48.60%
Distribution of equity method investment between entities under common control	$ 4,067
Amount paid for land and the value of property contributed		$ 4,200

Debt - Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Sep. 18, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Long-term debt	$ 460,000		$ 338
Less current portion of long-term debt	0		(145)
Long-term debt, net of current portion	460,000		193
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term debt	10,000		0
Senior Notes [Member] \| Senior Unsecured Notes due 2021 [Member]
Debt Instrument [Line Items]
Long-term debt	$ 450,000		0
Stated interest rate	7.625%	7.625%
Note Payable
Debt Instrument [Line Items]
Long-term debt	$ 0		$ 338

Debt - Senior Notes (Details)	12 Months Ended
Debt - Senior Notes (Details)	Dec. 31, 2013	Sep. 18, 2013 USD ($) a
Debt Instrument [Line Items]
FANG mineral interest area, developed, gross		15,000
FANG mineral interest, area, developed, net		12,500
Senior Notes [Member] \| Senior Unsecured Notes due 2021 [Member]
Debt Instrument [Line Items]
Aggregate principal amount \| $		$ 450,000,000
Stated interest rate	7.625%	7.625%
Number of days registration statement becomes effective after issue date of Senior Notes	360 days
Number of days to consummate the exchange after effectiveness	30 days
Senior Notes [Member] \| Senior Unsecured Notes due 2021 [Member] \| 12-month period beginning October 1, 2016
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount	105.719%
Senior Notes [Member] \| Senior Unsecured Notes due 2021 [Member] \| 12-month period beginning October 1, 2017
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount	103.813%
Senior Notes [Member] \| Senior Unsecured Notes due 2021 [Member] \| 12-month period beginning October 1, 2018
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount	101.906%
Senior Notes [Member] \| Senior Unsecured Notes due 2021 [Member] \| 12-month period beginning October 1, 2019 and thereafter
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount	100.00%
Make-whole premium option [Member] \| Senior Notes [Member] \| Senior Unsecured Notes due 2021 [Member] \| Period prior to October 1, 2016
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount	100.00%
Net cash proceeds of certain equity offerings [Member] \| Senior Notes [Member] \| Senior Unsecured Notes due 2021 [Member] \| Period prior to October 1, 2016
Debt Instrument [Line Items]
Redemption price, expressed as percentage of principal amount	107.625%
Maximum percent of aggregate principal amount redeemable	35.00%
Minimum required principal amount to remain outstanding subsequent to redemption	65.00%
Number of days within closing date redemption can occur	120 days

Debt - Line of Credit Facility (Details)	12 Months Ended
Debt - Line of Credit Facility (Details)	Dec. 31, 2013 USD ($) redetermindation	Dec. 31, 2012 USD ($)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 600,000,000
The Company may request additional redeterminations \| redetermindation	3
Period of Redeterminations	12 months
Current borrowing base	$ 225,000,000
Maximum amount of unsecured debt	$ 750,000,000
Reduction of borrowing base	25.00%
Debt outstanding	$ 460,000,000	$ 338,000
Minimum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.375%
Maximum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.50%
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Weighted average interest rate	1.67%
Description of variable rate basis	prime rate or LIBOR
Debt outstanding	$ 10,000,000	$ 0
Prime rate [Member] \| Revolving Credit Facility [Member] \| Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
Prime rate [Member] \| Revolving Credit Facility [Member] \| Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.50%
LIBOR [Member] \| Revolving Credit Facility [Member] \| Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.50%
LIBOR [Member] \| Revolving Credit Facility [Member] \| Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.50%

Debt - Financial Covenant Table (Details)	Dec. 31, 2013
Maximum [Member]
Line of Credit Facility [Line Items]
Ratio of total debt to EBITDAX	4.0
Minimum [Member]
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement	1.0

Debt - Note Payable (Details) - USD ($) $ in Thousands	12 Months Ended
Debt - Note Payable (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Debt outstanding	$ 460,000	$ 338
Note Payable
Debt Instrument [Line Items]
Installment payment contract period	36 months
Debt outstanding	$ 0	$ 338

Debt - Subordinated Note (Details) - Affiliated Entity - Subordinated Debt - USD ($)	May 14, 2012	Oct. 15, 2012
Debt Instrument [Line Items]
Maximum principal amount of debt	$ 45,000,000
Description of variable rate basis	LIBOR
Basis spread on variable rate	0.28%
Stated interest rate	8.00%
Aggregate principal amount outstanding		$ 30,050,000

Debt - Interest Expense (Details) - USD ($) $ in Thousands	12 Months Ended
Debt - Interest Expense (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Cash payments for interest	$ 404	$ 3,017	$ 2,265
Amortization of debt issuance costs	1,018	494	250
Interest Costs Incurred	12,010	3,610	2,528
Less capitalized interest	(3,951)	0	0
Total interest expense	8,059	3,610	2,528
Senior Notes [Member]
Debt Instrument [Line Items]
Accrued interest	9,913	0	0
Other Debt [Member]
Debt Instrument [Line Items]
Accrued interest	$ 675	$ 99	$ 13

Earnings Per Share & Pro Forma Earnings Per Share - Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
Basic:
Net income attributable to common stock, basic					$ 54,587
Net income attributable to common stock, basic (in shares)					42,015
Net income attributable to common stock, basic, (in dollars per share)	$ 0.43	$ 0.33	$ 0.37	$ 0.15	$ 1.30
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable					$ 0	$ 0
Dilutive effect of potential common shares issuable (in shares)					240	3
Diluted:
Net income attributable to common stock, diluted					$ 54,587
Net income attributable to common stock, diluted (in shares)					42,255
Net income attributable to common stock, diluted (in dollars per share)	$ 0.42	$ 0.33	$ 0.36	$ 0.15	$ 1.29

Earnings Per Share & Pro Forma Earnings Per Share - Pro Forma Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
Basic:
Pro forma net income attributable to common stock, basic	$ 1,820	$ 291	$ 8,767	$ 951		$ 11,829
Pro forma net income attributable to common stock (in shares)						19,721
Pro forma net income attributable to common stock (in dollars per share)	$ 0.05	$ 0.02	$ 0.60	$ 0.06		$ 0.60
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable					$ 0	$ 0
Dilutive effect of potential common shares issuable (in shares)					240	3
Diluted:
Pro forma net income attributable to common stock, diluted						$ 11,829
Pro forma net income attributable to common stock, diluted (in shares)						19,724
Pro forma net income attributable to common stock, diluted (in dollars per share)	$ 0.05	$ 0.02	$ 0.60	$ 0.06		$ 0.60

Stock and Equity Based Compensation (Details) $ / shares in Units, shares in Thousands, $ in Thousands		12 Months Ended
	Oct. 11, 2012 USD ($) employee $ / shares shares	Dec. 31, 2013 USD ($) installment	Dec. 31, 2012 USD ($)	Dec. 31, 2011 installment
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock price per share at public offering \| $ / shares	$ 17.50
Compensation expense recognized on modification date		$ 2,724	$ 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	2,500
2012 Plan \| Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of people 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

Stock and Equity Based Compensation - Schedule of Stock-Based Compensation Plans and Related Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Effects of equity and stock-based compensation plans and related costs
Share-based compensation	$ 1,752	$ 3,482	$ 544
General and administrative expenses
Effects of equity and stock-based compensation plans and related costs
Share-based compensation	2,983	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	972	2,537	106
Related income tax benefit
Effects of equity and stock-based compensation plans and related costs
Share-based compensation	$ 704	$ 930	$ 0

Stock and Equity Based Compensation - Fair Value Assumptions of Stock Options (Details) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value	$ 6.51	$ 4.41
Expected volatility	36.90%	40.00%	45.50%
Expected dividend yield	0.00%	0.00%	0.00%
Expected term (in years)	3 years 9 months 18 days	3 years 9 months 18 days	5 years
Risk-free rate	0.57%	0.33%	0.96%

Stock and Equity Based Compensation - Summary of Outstanding Stock Options (Details) - Stock Options - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Options, outstanding at beginning of period	850
Options granted	63
Option exercised	(200)
Options expired/forfeited	0
Options, outstanding at end of period	713
Options, vested and expected to vest, outstanding at period end	713
Options exercisable at end of period	250
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	$ 17.50
Options granted, weighted average exercise price	22.72
Options exercised, weighted average exercise price	17.50
Options expired/forfeited, weighted average exercise price	0.00
Outstanding options at end of period, weighted average exercise price	17.96
Weighted average exercise price of options, Vested and Expected to vest, outstanding at period end	17.96
Options exercisable at end of period, weighted average exercise price	$ 17.50
Options outstanding, weighted average remaining contractual term at end of period	2 years 8 months 8 days
Remaining term of options outstanding, vested and expected to vest at period end	2 years 8 months 8 days
Stock options are exercisable from the date of grant	2 years 1 month 10 days
Options outstanding at the end of period, Intrinsic Value	$ 24,895	$ 113
Intrinsic value of options outstanding at end of period, vested and expected to vest	24,895
Options exercisable at end of period, intrinsic value	8,843
Aggregate intrinsic value of stock options exercised	5,717
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized [Abstract]
Unrecognized compensation cost	$ 1,718
Unrecognized compensation cost, period of recognition	1 year 8 months 20 days

Stock and Equity Based Compensation - Summary of Restricted Stock Awards and Units (Details) - 2012 Plan - Restricted Stock Units (RSUs) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock Awards & Units
Unvested at Beginning of period	206
Granted	11
Vested	(81)
Forfeited	(4)
Unvested at end of period	132	206
Weighted Average Grant-Date Fair Value
Unvested at beginning of period	$ 17.50
Granted	41.66
Vested	18.03
Forfeited	17.50
Unvested at end of period	$ 19.20	$ 17.50
Aggregate fair value of restricted stock that vested	$ 3,310	$ 1,269
Unrecognized compensation cost	$ 2,053
Unrecognized compensation cost, period of recognition	1 year 4 months 25 days

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, 2013 USD ($)	Dec. 31, 2012	Dec. 31, 2011 USD ($) installment
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
Membership Interest Granted	0.25%	1.25%	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					$ 24,895		$ 113
Weighted-average remaining contractual term							4 years 7 months 6 days
Fair value assumptions
Expected term (in years)					3 years 9 months 18 days	3 years 9 months 18 days	5 years
Risk-free rate					0.57%	0.33%	0.96%
Expected volatility					36.90%	40.00%	45.50%
Expected dividend yield					0.00%	0.00%	0.00%

Related Party Transactions - Administrative Services (Details) - USD ($) $ in Thousands			12 Months Ended
	Jan. 02, 2012	Mar. 01, 2008	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction
Accounts payable-related party			$ 17	$ 18,813
Subsidiary of Common Parent
Related Party Transaction
Initial term of the additional shared services agreement		2 years
Related party incurred costs			207	4,419	$ 10,110
Expense costs partially offset in general administrative expenses by overhead reimbursements				2,548	$ 1,954
Accounts payable-related party			17	13
Affiliated Entity
Related Party Transaction
Initial term of the additional shared services agreement	2 years
Agreement termination, written notice period	30 days
Reimbursement from affiliate			1,077	2,132
Amount owed by affiliate			$ 0	$ 1

Related Party Transactions - Operating Services (Details) - USD ($)	Dec. 31, 2013	Dec. 31, 2012
Affiliated Entity
Related Party Transaction
Amounts due from affiliates related to joint interest billings and included in accounts receivable-related party	$ 0	$ 742,000

Related Party Transactions - Drilling Services (Details)		12 Months Ended
	Sep. 09, 2013	Dec. 31, 2013 USD ($) drilling_rig	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)
Bison
Related Party Transaction
Number of drilling rigs committed to use during the period \| drilling_rig		2
Number of drilling rigs \| drilling_rig		1
Agreement termination, written notice period		30 days
Related party incurred costs		$ 13,921,000	$ 16,040,000	$ 16,357,000
Amount owed to related party		0	$ 120,000
Panther Drilling [Member]
Related Party Transaction
Agreement termination, written notice period	30 days
Related party incurred costs		176,000
Amount owed to related party		$ 0

Related Party Transactions - Marketing Services (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($)
Marketing Services [Member] \| Affiliated Entity
Related Party Transaction
Revenue from related party	$ 38,873

Related Party Transactions - Coronado Midstream (Details) - USD ($) $ in Thousands		12 Months Ended
	May 01, 2009	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction
Natural gas revenue from related party		$ 4,696	$ 3,040	$ 1,604
Coronado Midstream
Related Party Transaction
Initial term of the additional shared services agreement	10 years
Agreement termination, written notice period	30 days
Natural gas revenue from related party		7,230	4,050	$ 2,190
Amount owed from related party from the sale of gas, gas products and residue gas		$ 1,303	$ 6
Coronado Midstream \| Coronado Midstream Plant
Related Party Transaction
Percent of natural gas revenue from related party		87.00%
Coronado Midstream \| Chevron Headlee Plant
Related Party Transaction
Percent of natural gas revenue from related party		94.56%

Related Party Transactions - Sand Supply (Details) - Muskie [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2013 USD ($)
Related Party Transaction
Agreement termination, written notice period	30 days
Related party incurred costs	$ 743

Related Party Transactions - Midland Lease (Details) - USD ($) $ in Thousands		2 Months Ended	3 Months Ended	7 Months Ended	12 Months Ended
	May 15, 2011	Sep. 30, 2013	Dec. 31, 2013	Jul. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction
Annual monthly rent increase			3.00%		3.00%
Midland Lease
Related Party Transaction
Term of lease from related party	5 years
Office rent to affiliate					$ 214	$ 155	$ 40
Monthly rent		$ 15	$ 25	$ 13
Annual monthly rent increase			4.00%		4.00%

Related Party Transactions - Oklahoma City Lease (Details) - Oklahoma City Lease - USD ($) $ in Thousands		12 Months Ended
	Jan. 02, 2012	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction
Term of lease from related party	67 months
Office rent to affiliate		$ 244	$ 329
Monthly base rent		$ 19

Related Party Transactions - Advisory Services Agreement & Professional Services from Wexford (Details) - Wexford - USD ($)		12 Months Ended
	Oct. 11, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction
Amount owed to related party		$ 0	$ 113,000
Advisory Services Agreement [Member]
Related Party Transaction
Advisory Services Agreement, Annual Fee	$ 500,000
Term of advisory services agreement	2 years
Agreement termination, written notice period	30 days
Related party incurred costs		$ 500,000	191,000	$ 0
Professional Services [Member]
Related Party Transaction
Related party incurred costs			$ 119,000

Related Party Transactions - Secondary Offering Costs (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Nov. 13, 2013	Jul. 05, 2013	Jul. 05, 2013	Jun. 24, 2013
Wexford and Gulfport Affiliates [Member]
Related Party Transaction
Related party incurred costs	$ 53		$ 185
Common Stock [Member]
Related Party Transaction
Shares sold in secondary public offering	2,000			6,000
Shares sold by existing stockholders		869
Stock price per share, selling stockholders	$ 53.46		$ 34.75

Income Taxes - Components of Federal Income Tax (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current income tax provision:
Federal									$ 191	$ 0
State									0	0
Total current income tax provision									191	0	$ 0
Deferred income tax provision:
Federal									30,768	53,319
State									795	1,584
Total deferred income tax provision									31,563	54,903	$ 0
Total provision for income taxes	$ 11,691	$ 9,099	$ 7,802	$ 3,162	$ 54,903	$ 0	$ 0	$ 0	$ 31,754	54,903
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

Income Taxes - Reconciliation of Statutory Federal Income Tax (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Federal statutory tax rate									35.00%	35.00%
Income tax expense at the federal statutory rate									$ 30,231	$ 6,434
Deduction for pre-merger LLC earnings									0	(5,717)
Income tax expense relating to change in tax status									0	54,142
State income tax expense, net of federal tax benefit									517	42
Non-deductible expenses									1,006	2
Total provision for income taxes	$ 11,691	$ 9,099	$ 7,802	$ 3,162	$ 54,903	$ 0	$ 0	$ 0	$ 31,754	$ 54,903

Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Current deferred tax assets
Derivative instruments	$ 0	$ 1,857,000
Other	265,000	0
Total current deferred tax assets	265,000	1,857,000
Current deferred tax liabilities
Derivative instruments	153,000	0
Total current deferred tax liabilities	153,000	0
Total current deferred tax assets	112,000	1,857,000
Noncurrent deferred tax assets
Net operating loss carryforwards (subject to 20 year expiration)	0	1,577,000
Stock based compensation	346,000	930,000
Alternative minimum tax credit carryforward	191,000	0
Other	20,000	0
Total noncurrent deferred tax assets	557,000	2,507,000
Noncurrent deferred tax liabilities
Oil and natural gas properties and equipment	92,321,000	64,636,000
Other	0	566,000
Total noncurrent deferred tax liabilities	92,321,000	65,202,000
Net noncurrent deferred tax liabilities	91,764,000	62,695,000
Net deferred tax liabilities	91,652,000	$ 60,838,000
Operating loss carryforwards	$ 5,833
Operating loss carryforward expiration period	20 years

Derivatives - Open Derivative Positions (Details) - Crude Oil [Member] - Swap [Member] bbl in Thousands	Dec. 31, 2013 bbl $ / bbl
Argus Louisiana Light Sweet [Member] \| January - December 2014
Derivative [Line Items]
Volume (Bbls) \| bbl	944
Fixed Swap Price \| $ / bbl	98.78
Argus Louisiana Light Sweet [Member] \| January 2015 [Member]
Derivative [Line Items]
Volume (Bbls) \| bbl	31
Fixed Swap Price \| $ / bbl	101.00
ICE Brent [Member] \| January–April 2014
Derivative [Line Items]
Volume (Bbls) \| bbl	120
Fixed Swap Price \| $ / bbl	109.70

Derivatives - Offsetting Derivative Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross Amounts of Recognized Assets	$ 998
Gross Amounts Offset in the Consolidated Balance Sheet	(567)
Net Amounts of Assets Presented in the Consolidated Balance Sheet	$ 431
Gross Amounts of Recognized Liabilities		$ 5,205
Gross Amounts Offset in the Consolidated Balance Sheet		0
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		$ 5,205

Derivatives - Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current Assets: Derivative instruments	$ 213	$ 0
Noncurrent Assets: Derivative instruments	218	0
Total Assets	431	0
Current Liabilities: Derivative instruments	0	4,817
Noncurrent Liabilities: Derivative instruments	0	388
Total Liabilities	$ 0	$ 5,205

- Definition

Fair value, after the effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset, expected to be settled within one year or normal operating cycle, if longer. Includes assets not subject to a master netting arrangement and not elected to be offset.

+ References + Details

Derivatives - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Non-cash gain (loss) on open non-hedge derivative instruments	$ 5,346	$ 8,057	$ (12,972)
Loss on settlement of non-hedge derivative instruments	(7,218)	(5,440)	(37)
Gain (loss) on derivative instruments	$ (1,872)	$ 2,617	$ (13,009)

Fair Value Measurements - Recurring Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Assets:
Derivative Assets	$ 431	$ 0
Liabilities:
Derivative liabilities	0	5,205
Recurring [Member] \| Quoted Prices in Active Markets Level 1
Assets:
Derivative Assets	0
Liabilities:
Derivative liabilities		0
Recurring [Member] \| Significant Other Observable Inputs Level 2
Assets:
Derivative Assets	431
Liabilities:
Derivative liabilities		5,205
Recurring [Member] \| Significant Unobservable Inputs Level 3
Assets:
Derivative Assets	0
Liabilities:
Derivative liabilities		0
Recurring [Member] \| Total
Assets:
Derivative Assets	$ 431
Liabilities:
Derivative liabilities		$ 5,205

Fair Value Measurements - Nonrecurring Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Sep. 18, 2013	Dec. 31, 2012
Carrying Amount \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	$ 10,000		$ 0
7.625% Senior Notes due 2021	450,000		0
Note payable	0		338
Fair Value \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	10,000		0
7.625% Senior Notes due 2021	460,406		0
Note payable	$ 0		$ 305
Senior Notes [Member] \| Senior Unsecured Notes due 2021 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	7.625%	7.625%

Commitments and Contingencies - Lease Commitments (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Mar. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commitments and Contingencies Disclosure [Abstract]
Lease term	84 months
Annual monthly rent increase		3.00%
Rent Expense		$ 571	$ 547	$ 74
Future minimum lease payments
2014		667
2015		682
2016		505
2017		301
2018		25
Thereafter		0
Total		$ 2,180

Commitments and Contingencies - Commitments and Obligations (Details) bbl in Thousands, $ in Thousands	May 24, 2012 bbl	Dec. 31, 2013 USD ($)
Other Commitments [Line Items]
Future commitments for drilling contracts		$ 4,729
Delivery contract, term	5 years
Future minimum contractual obligation		$ 3,600
Maximum [Member]
Other Commitments [Line Items]
Maximum delivery obligation, barrels per day \| bbl	8
One-time right to decrease contract quantity, percent	20.00%

Commitments and Contingencies - Defined Contribution Plan (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
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	$ 262	$ 86

Subsequent Events (Details) - Subsequent Event [Member] shares in Thousands, bbl in Thousands	Jan. 02, 2014 shares	Feb. 19, 2014 bbl $ / bbl	Jan. 28, 2014 bbl $ / bbl
2012 Plan \| Performance Shares [Member]
Subsequent Event [Line Items]
Awards granted \| shares	79
Vesting period	2 years
2012 Plan \| Restricted Stock [Member]
Subsequent Event [Line Items]
Awards granted \| shares	79
Vesting period	2 years
Argus Louisiana Light Sweet [Member] \| Swap [Member] \| February 2014 - January 2015 [Member] \| Crude Oil [Member]
Subsequent Event [Line Items]
Volume (Bbls) \| bbl			365
Fixed Swap Price \| $ / bbl			96.75
Argus Louisiana Light Sweet [Member] \| Swap [Member] \| March 2014 - February 2015 [Member] \| Crude Oil [Member]
Subsequent Event [Line Items]
Volume (Bbls) \| bbl		365
Fixed Swap Price \| $ / bbl		100.60

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Capitalized Oil and Natural Gas Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2013	Dec. 31, 2012
Oil and Natural Gas Properties:
Proved properties	$ 1,278,799	$ 576,497
Unproved properties	369,561	121,245
Total Oil and Natural Gas Properties	1,648,360	697,742
Less accumulated depreciation, depletion, amortization and impairment	(210,837)	(145,102)
Net oil and natural gas properties capitalized	$ 1,437,523	$ 552,640

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Costs Incurred in Crude Oil and Natural Gas Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Acquisition costs
Proved properties	$ 339,130	$ 115,760	$ 0
Unproved properties	279,402	117,395	3,704
Development costs	88,460	106,261	75,374
Exploration costs	242,929	17,547	11,226
Capitalized asset retirement costs	697	948	297
Total	$ 950,618	$ 357,911	$ 90,601

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Results of Operations for Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]
Oil, natural gas and natural gas liquid sales	$ 208,002	$ 74,962	$ 47,875
Lease operating expenses	(21,157)	(15,247)	(9,931)
Production and ad valorem taxes	(12,899)	(5,237)	(3,032)
Gathering and transportation	(918)	(424)	(202)
Depreciation, depletion, and amortization	(65,821)	(25,772)	(15,377)
Asset retirement obligation accretion expense	(201)	(98)	(65)
Income tax expense	(31,754)	(54,903)	0
Results of operations	$ 75,252	(26,719)	$ 19,268
Pro forma information
Pro forma results of operations before income taxes		28,184
Pro forma income tax		(10,083)
Pro forma results of operations		$ 18,101

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Oil and Natural Gas Reserves (Details)	12 Months Ended
	Dec. 31, 2013 well bbl Mcf	Dec. 31, 2012 bbl Mcf	Dec. 31, 2011 bbl Mcf	Dec. 31, 2010 bbl Mcf
Reserve Quantities [Roll Forward]
Number of vertical locations downgraded \| well	92
Oil [Member]
Reserve Quantities [Roll Forward]
Beginning of the period	26,196,859	18,100,473	19,630,160
Extensions and discoveries	17,041,744	3,106,433	1,799,175
Revisions of previous estimates	(5,943,164)	(1,464,243)	(2,879,429)
Purchase of reserves in place	7,328,162	7,210,482	0
Production	(2,022,749)	(756,286)	(449,433)
End of the period	42,600,852	26,196,859	18,100,473
Proved Developed Reserves	19,789,965	7,189,367	3,949,099	3,371,460
Proved Undeveloped Reserves	22,810,887	19,007,492	14,151,375	16,258,700
Natural Gas Liquids [Member]
Reserve Quantities [Roll Forward]
Beginning of the period	8,251,429	5,049,560	5,832,967
Extensions and discoveries	4,597,856	869,741	466,538
Revisions of previous estimates	(3,455,306)	(5,811)	(1,163,130)
Purchase of reserves in place	1,672,824	2,521,053	0
Production	(361,079)	(183,114)	(86,815)
End of the period	10,705,724	8,251,429	5,049,560
Proved Developed Reserves	4,973,493	2,999,440	1,263,711	1,126,431
Proved Undeveloped Reserves	5,732,231	5,251,989	3,785,850	4,706,536
Natural Gas [Member]
Reserve Quantities [Roll Forward]
Beginning of the period \| Mcf	34,570,148	20,551,465	22,695,080
Extensions and discoveries \| Mcf	24,184,540	3,759,684	1,884,192
Revisions of previous estimates \| Mcf	(5,786,180)	383,335	(3,614,167)
Purchase of reserves in place \| Mcf	10,441,485	10,709,180	0
Production \| Mcf	(1,730,497)	(833,516)	(413,640)
End of the period \| Mcf	61,679,496	34,570,148	20,551,465
Proved Developed Reserves \| Mcf	31,428,756	12,864,941	5,285,945	4,336,720
Proved Undeveloped Reserves \| Mcf	30,250,740	21,705,207	15,265,520	18,358,360

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Standardized measure of Discounted Future Net Cash Flows - Proved Crude Oil and Natural Gas Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Future cash inflows	$ 4,604,241	$ 2,769,485	$ 2,049,520
Future development costs	(517,075)	(541,445)	(410,350)
Future production costs	(806,895)	(773,611)	(497,808)
Future production taxes	(318,396)	(140,758)	(104,856)
Future income tax expenses	(674,260)	(334,903)	0
Future net cash flows	2,287,615	978,768	1,036,506
10% discount to reflect timing of cash flows	(1,311,976)	(611,548)	(671,894)
Standardized measure of discounted future net cash flows	$ 975,639	$ 367,220	$ 364,612

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Average First Day of the Month Price for Oil, Natural Gas & Natural Gas Liquids (Details)	12 Months Ended
	Dec. 31, 2013 $ / bbl $ / Mcf	Dec. 31, 2012 $ / bbl $ / Mcf	Dec. 31, 2011 $ / bbl $ / Mcf
Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales prices (dollars per unit)	92.59	88.13	93.09
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales prices (dollars per unit) \| $ / Mcf	4.13	2.86	3.91
Natural Gas Liquids [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales prices (dollars per unit)	37.82	43.88	56.33

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$ 367,220	$ 364,612	$ 339,001
Sales of oil and natural gas, net of production costs	(173,946)	(54,208)	(34,711)
Purchase of minerals in place	305,109	107,897	0
Extensions and discoveries, net of future development costs	552,450	79,293	73,571
Previously estimated development costs incurred during the period	76,631	88,849	87,530
Net changes in prices and production costs	51,828	(76,515)	82,364
Changes in estimated future development costs	(5,822)	8,309	(82,855)
Revisions of previous quantity estimates	(126,993)	(22,882)	(98,533)
Accretion of discount	57,988	36,461	33,900
Net change in income taxes	(168,570)	(125,542)	0
Net changes in timing of production and other	39,744	(39,054)	(35,655)
Standardized measure of discounted future net cash flows at the end of the period	$ 975,639	$ 367,220	$ 364,612

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 75,908	$ 57,791	$ 45,394	$ 28,909	$ 25,767	$ 16,814	$ 16,030	$ 16,351	$ 208,002	$ 74,962	$ 49,366
Income from operations	37,726	29,423	19,383	8,662	2,177	4,086	4,307	6,737	95,194	17,307	15,147
Income tax expense	11,691	9,099	7,802	3,162	54,903	0	0	0	31,754	54,903
Net income (loss)	$ 20,124	$ 14,596	$ 14,471	$ 5,396	(52,074)	452	13,624	1,477	$ 54,587	(36,521)	(386)
Earnings per common share
Basic (in dollars per share)	$ 0.43	$ 0.33	$ 0.37	$ 0.15					$ 1.30
Diluted (in dollars per share)	$ 0.42	$ 0.33	$ 0.36	$ 0.15					$ 1.29
Pro forma information
Income before income taxes, as reported					2,829	452	13,624	1,477	$ 86,341	18,382	$ (386)
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
Pro forma earnings per common share
Basic (in dollars per share)					$ 0.05	$ 0.02	$ 0.60	$ 0.06		$ 0.60
Diluted (in dollars per share)					$ 0.05	$ 0.02	$ 0.60	$ 0.06		$ 0.60