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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2017	Feb. 07, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
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		98,167,289
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 7,801,460,276

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 112,446	$ 1,666,574
Restricted cash	0	500
Accounts receivable:
Joint interest and other	73,038	49,476
Oil and natural gas sales	158,575	70,349
Related party	0	297
Inventories	9,108	1,983
Derivative instruments	531	0
Prepaid expenses and other	4,903	2,987
Total current assets	358,601	1,792,166
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($4,105,865 and $1,730,519 excluded from amortization at December 31, 2017 and 2016, respectively)	9,232,694	5,160,261
Midstream assets	191,519	8,362
Other property, equipment and land	80,776	58,290
Accumulated depletion, depreciation, amortization and impairment	(2,161,372)	(1,836,056)
Net property and equipment	7,343,617	3,390,857
Funds held in escrow	6,304	121,391
Derivative instruments	0	709
Other assets	62,463	44,557
Total assets	7,770,985	5,349,680
Current liabilities:
Accounts payable-trade	94,590	47,648
Accounts payable-related party	0	1
Accrued capital expenditures	221,256	60,350
Other accrued liabilities	92,512	55,330
Revenues and royalties payable	68,703	23,405
Derivative instruments	100,367	22,608
Total current liabilities	577,428	209,342
Long-term debt	1,477,347	1,105,912
Derivative instruments	6,303	0
Asset retirement obligations	20,122	16,134
Deferred income taxes	108,048	0
Total liabilities	2,189,248	1,331,388
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 98,167,289 issued and outstanding at December 31, 2017; 90,143,934 issued and outstanding at December 31, 2016	982	901
Additional paid-in capital	5,291,011	4,215,955
Accumulated deficit	(37,133)	(519,394)
Total Diamondback Energy, Inc. stockholders’ equity	5,254,860	3,697,462
Non-controlling interest	326,877	320,830
Total equity	5,581,737	4,018,292
Total liabilities and equity	$ 7,770,985	$ 5,349,680

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Oil and natural gas properties, full cost method of accounting amount excluded from amortization	$ 4,105,865	$ 1,730,519
Common Stock, Par Value (in dollars per share)	$ 0.01	$ 0.01
Common Stock, Shares, Authorized	200,000,000	100,000,000
Common Stock, Shares, Issued	98,167,289	90,143,934
Common Stock, Shares, Outstanding	98,167,289	90,143,934

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Oil sales	$ 1,044,017	$ 470,528	$ 405,715
Natural gas sales	52,210	22,506	19,592
Natural gas liquid sales	90,048	34,073	21,426
Lease bonus	11,764	0	0
Midstream services	7,072	0	0
Total revenues	1,205,111	527,107	446,733
Costs and expenses:
Lease operating expenses	126,524	82,428	82,625
Production and ad valorem taxes	73,505	34,456	32,990
Gathering and transportation	12,834	11,606	6,091
Midstream services	10,409	0	0
Depreciation, depletion and amortization	326,759	178,015	217,697
Impairment of oil and natural gas properties	0	245,536	814,798
General and administrative expenses (including non-cash equity-based compensation, net of capitalized amounts, of $25,537, $26,453 and $18,529 for the year ended December 31, 2017, 2016 and 2015, respectively)	48,669	42,619	31,968
Asset retirement obligation accretion	1,391	1,064	833
Total costs and expenses	600,091	595,724	1,187,002
Income (loss) from operations	605,020	(68,617)	(740,269)
Other income (expense):
Interest expense, net	(40,554)	(40,684)	(41,510)
Other income, net	10,235	3,064	728
Gain (loss) on derivative instruments, net	(77,512)	(25,345)	31,951
Loss on extinguishment of debt	0	(33,134)	0
Total other expense, net	(107,831)	(96,099)	(8,831)
Income (loss) before income taxes	497,189	(164,716)	(749,100)
Provision for (benefit from) income taxes	(19,568)	192	(201,310)
Net income (loss)	516,757	(164,908)	(547,790)
Net income attributable to non-controlling interest	34,496	126	2,838
Net income (loss) attributable to Diamondback Energy, Inc.	$ 482,261	$ (165,034)	$ (550,628)
Earnings per common share:
Basic (in dollars per share)	$ 4.95	$ (2.20)	$ (8.74)
Diluted (in dollars per share)	$ 4.94	$ (2.20)	$ (8.74)
Weighted average common shares outstanding:
Basic (in shares)	97,458	75,077	63,019
Diluted (in shares)	97,688	75,077	63,019

Consolidated Statements of Operations (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
General and Administrative Expense [Member]
Non-cash stock based compensation, net of capitalized amount	$ 25,537	$ 26,453	$ 18,529

Consolidated Statement of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]	Noncontrolling Interest [Member]
Balance at beginning of period at Dec. 31, 2014	$ 1,985,213	$ 569	$ 1,554,174	$ 196,268	$ 234,202
Balance at beginning of period, shares at Dec. 31, 2014		56,888,000
Increase (Decrease) in Stockholders' Equity
Unit-based compensation	3,929	$ 0	0	0	3,929
Distribution to non-controlling interest	(7,968)	0	0	0	(7,968)
Stock-based compensation	20,645	$ 0	20,645	0	0
Common shares issued in public offering, net of offering costs, shares		9,488,000
Common shares issued in public offering, net of offering costs	650,073	$ 94	649,979	0	0
Exercise of stock options and awards of restricted stock	4,871	$ 5	4,866	0	0
Exercise of stock options and awards of restricted stock, shares		421,000
Net income (loss)	(547,790)	$ 0	0	(550,628)	2,838
Balance at end of period at Dec. 31, 2015	2,108,973	$ 668	2,229,664	(354,360)	233,001
Balance at end of period, shares at Dec. 31, 2015		66,797,000
Increase (Decrease) in Stockholders' Equity
Net proceeds from issuance of common units - Viper Energy Partners LP	93,462	$ 0	0	0	93,462
Unit-based compensation	3,815	0	0	0	3,815
Distribution to non-controlling interest	(9,574)	0	0	0	(9,574)
Stock-based compensation	29,717	$ 0	29,717	0	0
Common shares issued in public offering, net of offering costs, shares		23,000,000
Common shares issued in public offering, net of offering costs	1,956,308	$ 229	1,956,079	0	0
Exercise of stock options and awards of restricted stock	499	$ 4	495	0	0
Exercise of stock options and awards of restricted stock, shares		347,000
Net income (loss)	(164,908)	$ 0	0	(165,034)	126
Balance at end of period at Dec. 31, 2016	$ 4,018,292	$ 901	4,215,955	(519,394)	320,830
Balance at end of period, shares at Dec. 31, 2016	90,143,934	90,144,000
Increase (Decrease) in Stockholders' Equity
Net proceeds from issuance of common units - Viper Energy Partners LP	$ 369,896	$ 0	0	0	369,896
Unit-based compensation	2,395	0	0	0	2,395
Common units issued for acquisition	3,050	0	0	0	3,050
Distribution to non-controlling interest	(41,367)	0	0	0	(41,367)
Stock-based compensation	31,783	0	31,783	0	0
Common shares issued in public offering, net of offering costs	14	$ 0	14	0	0
Common shares issued for acquisition, shares		7,685,918
Common shares issued for acquisition	809,173	$ 77	809,096	0	0
Exercise of stock options and awards of restricted stock	359	$ 4	355	0	0
Exercise of stock options and awards of restricted stock, shares		337,000
Change in ownership of consolidated subsidiaries, net	(128,615)	$ 0	233,808	0	(362,423)
Net income (loss)	516,757	0	0	482,261	34,496
Balance at end of period at Dec. 31, 2017	$ 5,581,737	$ 982	$ 5,291,011	$ (37,133)	$ 326,877
Balance at end of period, shares at Dec. 31, 2017	98,167,289	98,167,000

Consolidated Statements of Cash Flows - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss)	$ 516,757	$ (164,908)	$ (547,790)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for deferred income taxes	(20,567)	0	(201,545)
Impairment of oil and natural gas properties	0	245,536	814,798
Asset retirement obligation accretion	1,391	1,064	833
Depreciation, depletion and amortization	326,759	178,015	217,697
Amortization of debt issuance costs	3,943	2,717	2,601
Loss on early extinguishment of debt	0	33,134	0
Change in fair value of derivative instruments	84,240	26,522	112,918
Income from equity investment	(657)	(676)	0
Equity-based compensation expense	25,537	26,453	18,529
Gain (loss) on sale of assets, net	(455)	(61)	668
Changes in operating assets and liabilities:
Accounts receivable	(97,611)	(35,030)	8,998
Accounts receivable-related party	297	1,294	2,149
Restricted cash	500	0	0
Inventories	(2,245)	(255)	224
Prepaid expenses and other	(11,362)	(709)	(1,310)
Accounts payable and accrued liabilities	36,762	15,922	802
Accounts payable and accrued liabilities-related party	(2)	(216)	218
Income tax payable	814	0	0
Accrued interest	(20,774)	(3,161)	(255)
Revenues and royalties payable	45,298	6,439	(13,034)
Net cash provided by operating activities	888,625	332,080	416,501
Cash flows from investing activities:
Additions to oil and natural gas properties	(792,599)	(362,450)	(419,241)
Additions to oil and natural gas properties-related party	0	(637)	(271)
Additions to midstream assets	(68,139)	(1,188)	0
Purchase of other property, equipment and land	(22,779)	(9,891)	(1,213)
Acquisition of leasehold interests	(1,960,591)	(611,280)	(437,455)
Acquisition of mineral interests	(407,450)	(205,721)	(43,907)
Acquisition of midstream assets	(50,279)	0	0
Proceeds from sale of assets	65,656	4,661	9,739
Funds held in escrow	104,087	(121,391)	0
Equity investments	(188)	(2,345)	(2,702)
Net cash used in investing activities	(3,132,282)	(1,310,242)	(895,050)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	753,500	164,000	425,001
Repayment under credit facility	(383,500)	(89,000)	(603,001)
Proceeds from senior notes	0	1,000,000	0
Repayment of senior notes	0	(450,000)	0
Premium on extinguishment of debt	0	(26,561)	0
Debt issuance costs	(9,296)	(15,063)	(526)
Public offering costs	(510)	(1,182)	(586)
Proceeds from public offerings	370,344	2,051,503	650,688
Proceeds from exercise of stock options	358	498	4,873
Distributions to non-controlling interest	(41,367)	(9,574)	(7,968)
Net cash provided by financing activities	689,529	2,624,621	468,481
Net increase (decrease) in cash and cash equivalents	(1,554,128)	1,646,459	(10,068)
Cash and cash equivalents at beginning of period	1,666,574	20,115	30,183
Cash and cash equivalents at end of period	112,446	1,666,574	20,115
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	57,668	38,177	38,758
Cash paid for income taxes	0	192	267
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures	160,906	413	(69,460)
Capitalized stock-based compensation	$ 8,641	$ 7,079	$ 6,043
Common stock issued for oil and natural gas properties	809,173	0	0
Asset retirement obligations acquired	$ 2,432	$ 3,696	$ 3,159

Description of the Business and Basis of Presentation	12 Months Ended
Description of the Business and Basis of Presentation	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of the Business and Basis of Presentation	DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION Organization and Description of the Business Diamondback Energy, Inc. (“Diamondback” or the “Company”) is an independent oil and gas company 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. On June 17, 2014, Diamondback entered into a contribution agreement with Viper Energy Partners LP (the “Partnership”), Viper Energy Partners GP LLC (the “General Partner”) and Viper Energy Partners LLC to transfer Diamondback’s ownership interest in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. Diamondback also owns and controls the General Partner, which holds a non-economic general partner interest in the Partnership. On June 23, 2014, the Partnership completed its initial public offering (the “Viper Offering”) of 5,750,000 common units, and the Company’s common units represented an approximate 92% limited partner interest in the Partnership. On September 19, 2014, the Partnership completed an underwritten public offering of 3,500,000 common units. At the completion of this offering, the Company owned approximately 88% of the common units of the Partnership. See Note 4–Viper Energy Partners LP for additional information regarding the Partnership. The wholly-owned subsidiaries of Diamondback, as of December 31, 2017, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company, and Rattler Midstream LLC (formerly known as White Fang Energy LLC), a Delaware limited liability company. The consolidated subsidiaries include the wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership, and Viper Energy Partners LLC, a Delaware limited liability company. Basis of Presentation The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation. The Partnership is consolidated in the financial statements of the Company. As of December 31, 2017, the Company owned approximately 64% of the common units of the Partnership and the Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the General Partner of the Partnership.

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Company’s 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 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 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, but are not limited to, 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, equity-based compensation, fair value estimates of commodity derivatives and estimates of income 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.

Restricted Cash

In 2014, a subsidiary of the Company entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The subsidiary subsequently terminated the agreement and requested a return of the deposit. The seller challenged the termination and the escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. The parties reached a settlement of this matter in April 2017 and the funds were distributed in accordance with the terms of the settlement. Pending such distribution, these funds were classified as restricted cash.

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 for production 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, 2017 or December 31, 2016.

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 for each period in the consolidated statements of operations.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, restricted cash, receivables, payables, derivatives 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 fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 14–Fair Value Measurements).

Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. 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. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. 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 7–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 $11.11, $11.23 and $17.84 for the years ended December 31, 2017, 2016 and 2015, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $321.9 million, $176.4 million and $216.1 million for the years ended December 31, 2017, 2016 and 2015, respectively.

Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. During the years ended December 31, 2016 and 2015, the Company recorded impairments on proved oil and natural gas properties of $245.5 million and $814.8 million, respectively. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2017.

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, Equipment and Land

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 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 for other property and equipment was $1.4 million for each of the years ended December 31, 2017, 2016 and 2015.

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 or if there is a change in the estimated liability, 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, 2017, 2016 and 2015, respectively.

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 $22.1 million for the year ended December 31, 2017. The Company did not have any capitalized interest for the years ended December 31, 2016 and 2015.

Inventories

Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2017 and 2016. The Company’s tubular goods and equipment are 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, 2017, 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 related to the credit facility of $16.7 million and $8.2 million, net of accumulated amortization of $7.0 million and $4.9 million, as of December 31, 2017 and 2016, respectively. Long-term debt included capitalized costs related to the senior notes of $15.2 million and $14.8 million, net of accumulated amortization of $2.0 million and $0.2 million, as of December 31, 2017 and 2016, respectively. The costs associated with the senior notes are being netted against the senior notes balances and are being amortized over the term of the senior notes using the effective interest method. The costs associated with the Company’s credit facility that are included in other assets are being amortized over the term of the facility.

Other Accrued Liabilities

Other accrued liabilities consist of the following:



	December 31,
	2017		2016
	(In thousands)
Liability for drilling costs prepaid by joint interest partners	$	30,320	$	21,595
Interest payable	6,770		5,445
Lease operating expenses payable	27,850		13,857
Ad valorem taxes payable	3,306		776
Current portion of asset retirement obligations	1,163		1,288
Other	23,103		12,369
Total other accrued liabilities	$	92,512	$	55,330

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 that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying 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, 2017 or December 31, 2016. Revenues from oil and natural gas services are recognized when 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, 2017, 2016 and 2015.

For additional information on the Company’s investments, see Note 7–Equity Method Investments.

Accounting for Equity-Based Compensation

The Company grants various types of stock-based awards including stock options and restricted stock units. The Partnership grants various unit-based awards including unit options and phantom units to employees, officers and directors of the General Partner and the Company who perform services for the Partnership. These plans and related accounting policies are defined and described more fully in Note 10–Equity-Based Compensation. Equity 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, 2017, three purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%); and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). For the year ended December 31, 2015, two purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (59%); and Enterprise Crude Oil LLC (15%). 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 (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) 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 is subject to margin tax in the state of Texas. During the years ended December 31, 2017, 2016 and 2015, the Company had no margin tax expense. The Company’s 2013, 2014, 2015, 2016 and 2017 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2017 and December 31, 2016, the Company had no unrecognized tax benefits that would have a material impact on the effective tax 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, 2017, 2016 and 2015, there was no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements.

Recent Accounting Pronouncements

Recently Issued Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers.

The Company will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Company has reviewed various contracts that represent its material revenue streams and determined that there will be no impact to its financial position, results of operations or liquidity. Upon adoption of this Accounting Standards Update, the Company will not be required to record a cumulative effect adjustment due to the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting Standards Update, the Company will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Company. The Company does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams as compared to existing GAAP.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Unitholders’ Equity and will bring the fair value of its investment to $15.2 million or $15.20 per unit for that investment.

In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company will adopt this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard will change the presentation of its cash flows and did not have a material impact on its consolidated financial statements.

In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Company will adopt this update retrospectively effective January 1, 2018. Adoption of this standard will change the presentation of its cash flows and did not have a material impact on its consolidated financial statements.

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company will adopt this update prospectively effective January 1, 2018. The adoption of this update will not have an impact on its financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses.

Acquisitions

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Acquisitions

ACQUISITIONS

2017 Activity

On February 28, 2017, the Company completed its acquisition of certain oil and natural gas properties, midstream assets and other related assets in the Delaware Basin for an aggregate purchase price consisting of $1.74 billion in cash and 7.69 million shares of the Company’s common stock, of which approximately 1.15 million shares were placed in an indemnity escrow. This transaction included the acquisition of (i) approximately 100,306 gross (80,339 net) acres primarily in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million. The Company used the net proceeds from its December 2016 equity offering, net proceeds from its December 2016 debt offering, cash on hand and other financing sources to fund the cash portion of the purchase price for this acquisition.

The following represents the fair value of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $2.5 billion, resulting in no goodwill or bargain purchase gain.



	(in thousands)
Proved oil and natural gas properties	$	386,308
Unevaluated oil and natural gas properties	2,122,597
Midstream assets	47,432
Prepaid capital costs	3,460
Oil inventory	839
Equipment	163
Revenues and royalties payable	(9,650		)
Asset retirement obligations	(1,550		)
Total fair value of net assets	$	2,549,599

The Company has included in its consolidated statements of operations revenues of $81.4 million and direct operating expenses of $23.5 million for the period from February 28, 2017 to December 31, 2017 due to the acquisition.

Pro Forma Financial Information

The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the year ended December 31, 2017 and 2016 have been prepared to give effect to the February 28, 2017 acquisition as if it had occurred on January 1, 2016. The pro forma data are not necessarily indicative of the financial results that would have been attained had the acquisitions occurred on January 1, 2016.

The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods.



	Year Ended December 31,
	2017		2016
	(in thousands, except per share amounts)
Revenues	$	1,228,040	$	627,301
Income (loss) from operations	619,369		(12,812		)
Net income (loss)	472,649		(109,229		)
Basic earnings per common share	4.85		(1.45		)
Diluted earnings per common share	4.84		(1.45		)

2016 Activity

On September 1, 2016, the Company acquired from an unrelated third party leasehold interests and related assets in the Southern Delaware Basin for an aggregate purchase price of $558.5 million. This transaction included approximately 26,797 gross (19,262 net) acres primarily in Reeves and Ward counties. The Company financed this acquisition with net proceeds from the July 2016 equity offering discussed in Note 9 and cash on hand.

2015 Activity

During 2015, the Company completed acquisitions from unrelated third party sellers of an aggregate of approximately 16,940 gross (12,672 net) acres in the Midland Basin, primarily in northwest Howard County, for an aggregate purchase price of approximately $437.5 million. The acquisitions were accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. These acquisitions were funded with the net proceeds of the May 2015 equity offering discussed in Note 9–Capital Stock and Earnings Per Share and borrowings under the Company’s revolving credit facility discussed in Note 8–Debt.

On July 9, 2015, the Company completed the sale of an approximate average 1.5% overriding royalty interest in certain of its acreage primarily located in Howard County, Texas to the Partnership for $31.1 million. The Partnership primarily funded this acquisition with borrowings under its revolving credit facility discussed in Note 8 – Debt.

Property and Equipment

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property and Equipment

PROPERTY AND EQUIPMENT

Property and equipment includes the following:



	December 31,
	2017			2016
	(in thousands)
Oil and natural gas properties:
Subject to depletion	$	5,126,829		$	3,429,742
Not subject to depletion	4,105,865			1,730,519
Gross oil and natural gas properties	9,232,694			5,160,261
Accumulated depletion	(1,009,893		)	(687,685		)
Accumulated impairment	(1,143,498		)	(1,143,498		)
Oil and natural gas properties, net	7,079,303			3,329,078
Midstream assets	191,519			8,362
Other property, equipment and land	80,776			58,290
Accumulated depreciation	(7,981		)	(4,873		)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	7,343,617		$	3,390,857

Balance of costs not subject to depletion:
Incurred in 2017	$	2,746,936
Incurred in 2016	727,411
Incurred in 2015	301,879
Incurred in 2014	316,455
Incurred in 2013	13,184
Total not subject to depletion	$	4,105,865

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. 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. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized internal costs were approximately $22.0 million $17.2 million and $15.2 million for the years ended December 31, 2017, 2016 and 2015, 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. Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any acreage expire. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.

As a result of the significant decline in prices during 2016, the Company recorded non-cash ceiling test impairments for the years ended December 31, 2016 and 2015 of $245.5 million and $814.8 million, respectively, which are included in accumulated depletion. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2017. For 2016 and 2015, the impairment charges affected the Company’s reported net income but did not reduce its cash flow. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods.

At December 31, 2017, there was $26.0 million in exploration costs and development costs and $22.1 million in capitalized interest that are not subject to depletion. At December 31, 2016, there were no exploration costs, development costs or capitalized interest that are not subject to depletion.

Viper Energy Partners LP	12 Months Ended
Viper Energy Partners LP	Dec. 31, 2017
Noncontrolling Interest [Abstract]
Viper Energy Partners LP	VIPER ENERGY PARTNERS LP The Partnership is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Market under the symbol “VNOM”. The Partnership was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin. Viper Energy Partners GP LLC, a consolidated subsidiary of Diamondback, serves as the general partner of, and holds a non-economic general partner interest in, the Partnership. As of December 31, 2017, the Company owned approximately 64% of the common units of the Partnership. Prior to the completion on June 23, 2014 of the Viper Offering, Diamondback owned all of the general and limited partner interests in the Partnership. The Viper Offering consisted of 5,750,000 common units representing approximately 8% of the limited partner interests in the Partnership at a price to the public of $26.00 per common unit. In connection with the Viper Offering, Diamondback contributed all of the membership interests in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. The contribution of Viper Energy Partners LLC to the Partnership was accounted for 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. During the year ended December 31, 2017, the Partnership distributed $89.5 million to Diamondback in respect of its common units. In August 2016, the Partnership completed an underwritten public offering of 8,050,000 common units, which included 1,050,000 common units issued pursuant to an option to purchase additional common units granted to the underwriter. In this offering, Diamondback purchased 2,000,000 common units from the underwriter at $15.60 per unit, which is the price per common unit paid by the underwriter to the Partnership. Following the August 2016 public offering, Diamondback had an approximate 83% limited partner interest in the Partnership. The Partnership received net proceeds from this offering of approximately $125.0 million, after deducting underwriting discounts and commissions and estimated offering expenses, which it used to fund an acquisition and repaid outstanding borrowings under its revolving credit facility. In January 2017, the Partnership completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. The Partnership received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions. In July 2017, the Partnership completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. In this offering, we purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directors of the Company and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. Following this offering, the Company had an approximate 64% limited partner interest in the Partnership. The Partnership received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $152.8 million to repay all of the then-outstanding borrowings under the Partnership’s revolving credit facility and the balance was used fund a portion of the purchase price for acquisitions and for general partnership purposes. As a result of these public offerings and the Partnership’s issuance of unit-based compensation, the Company’s ownership percentage in the Partnership was reduced. During the year ended December 31, 2017, the Company recorded a $362.4 million decrease to Non-controlling interest in the Partnership with an increase to Additional paid-in capital, which represents the difference between the Company’s share of the underlying net book value in the Partnership before and after the respective Partnership common unit transactions, on the Company’s consolidated balance sheet. Partnership Agreement In connection with the closing of the Viper Offering, the General Partner and Diamondback entered into the first amended and restated agreement of limited partnership, dated as of June 23, 2014 (the “Partnership Agreement”). The Partnership Agreement requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on its behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. Tax Sharing In connection with the closing of the Viper Offering, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period. Other Agreements See Note 11–Related Party Transactions for information regarding the advisory services agreement the Partnership and the General Partner entered into with Wexford Capital LP (“Wexford”). The Partnership has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 8–Debt for a description of this credit facility.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

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



	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Asset retirement obligations, beginning of period	$	17,422		$	12,711		$	8,486
Additional liabilities incurred	1,526			637			594
Liabilities acquired	2,432			3,696			3,159
Liabilities settled	(1,555		)	(711		)	(292		)
Accretion expense	1,391			1,064			833
Revisions in estimated liabilities	69			25			(69		)
Asset retirement obligations, end of period	21,285			17,422			12,711
Less current portion	1,163			1,288			193
Asset retirement obligations - long-term	$	20,122		$	16,134		$	12,518

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, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	EQUITY METHOD INVESTMENTS In October 2014, the Company obtained a 25% interest in HMW Fluid Management LLC, which was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operating in Midland, Martin and Andrews Counties, Texas. The board of this entity may also authorize the entity to offer these services to other counties in the Permian Basin and to pursue other business opportunities. During the year ended December 31, 2017, the Company invested $0.2 million in this entity and recorded income of $0.7 million, which was the Company’s share of HMW Fluid Management LLC’s net income, bringing the Company’s total investment to $7.2 million at December 31, 2017. During the year ended December 31, 2016, the Company invested $2.3 million in this entity and recorded income of $0.7 million, which was the Company’s share of HMW Fluid Management LLC’s net income, bringing its total investment to $6.3 million at December 31, 2016. The Company will retain a minority interest after all commitments are received. The entity was formed as a limited liability company and maintains a specific ownership account for each investor, similar to a partnership capital account structure. The Company accounts for this investment under the equity method of accounting.

Debt

12 Months Ended

Dec. 31, 2017

Debt Disclosure [Abstract]

Debt

DEBT

Long-term debt consisted of the following as of the dates indicated:



	December 31,
	2017			2016
	(in thousands)
4.750 % Senior Notes due 2024	500,000			500,000
5.375 % Senior Notes due 2025	500,000			500,000
Unamortized debt issuance costs	(13,153		)	(14,588		)
Revolving credit facility	397,000			—
Partnership revolving credit facility	93,500			120,500
Total long-term debt	$	1,477,347		$	1,105,912

2024 Senior Notes

On October 28, 2016, the Company issued $500.0 million in aggregate principal amount of 4.750% Senior Notes due 2024 (the “2024 Senior Notes”). The 2024 Senior Notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and will mature on November 1, 2024. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2024 Senior Notes, provided, however, that the 2024 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries. See also “Note 16. Subsequent Events–New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving Credit Facility.”

The 2024 Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented (the “2024 Indenture”). The 2024 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 capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted 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 natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries.

The Company may on any one or more occasions redeem some or all of the 2024 Senior Notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, the Company may on any one or more occasions redeem all or a portion of the 2024 Senior Notes at a price equal to 100% of the principal amount of the 2024 Senior Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, the Company may on any one or more occasions redeem the 2024 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 Senior Notes issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

2025 Senior Notes

On December 20, 2016, the Company issued $500.0 million in aggregate principal amount of 5.375% Senior Notes due 2025 (the “2025 Senior Notes”). The 2025 Senior Notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year, commencing on May 31, 2017 and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2025 Senior Notes, provided, however, that the 2025 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.

The 2025 Senior Notes were issued under an indenture, dated as of December 20, 2016, among the Company, the guarantors party thereto and Wells Fargo Bank, as the trustee (the “2025 Indenture”). The 2025 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 capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted 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 natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries.

The Company may on any one or more occasions redeem some or all of the 2025 Senior Notes at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, the Company may on any one or more occasions redeem all or a portion of the 2025 Senior Notes at a price equal to 100% of the principal amount of the 2025 Senior Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, the Company may on any one or more occasions redeem the 2025 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 Senior Notes issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

As required under the terms of the registration rights agreements relating to the 2024 Senior Notes and the 2025 Senior Notes, on April 26, 2017, the Company filed with the SEC a Registration Statement on Form S-4 (the “Registration Statement”) relating to the exchange offers of the 2024 Senior Notes and the 2025 Senior Notes for substantially identical notes registered under the Securities Act (the “Exchange Offers”). The Registration Statement was declared effective by the SEC on June 21, 2017 and the Exchange Offers closed on July 27, 2017, in which all of the privately placed 2024 Senior Notes and 2025 Senior Notes were exchanged for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act.

The Company’s Credit Facility

The Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended on June 9, 2014, November 13, 2014, June 21, 2016, December 15, 2016 and November 28, 2017, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. The credit agreement provides for a revolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on the Company’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, the Company may request up to two additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $1.8 billion, the Company had elected a commitment amount of $1.0 billion and the Company had $397.0 million of outstanding borrowings under the revolving credit facility. See “Note 16. Subsequent Events-New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving Credit Facility.”

Diamondback O&G LLC is the borrower under the credit agreement. As of December 31, 2017, the credit agreement is guaranteed by the Company, Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of the Company’s future subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of the assets of the Company, Diamondback O&G LLC and the guarantors.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Company that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5%, and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternate base rate and from 1.25% to 2.25% in the case of LIBOR, each of which applicable margin rates is increased by 0.25% per annum if the total debt to EBITDAX ratio is greater than 3.0 to 1.0. The applicable margin depends on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. 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 commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022.

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 3.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement	Not less than 1.0 to 1.0

The covenant prohibiting additional indebtedness, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance.

As of December 31, 2017 and 2016, 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.

The Partnership’s Credit Agreement

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, and Wells Fargo Securities, as sole book runner and lead arranger. The credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”) of $400.0 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, Viper may request up to three additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $400.0 million, and the Partnership had $93.5 million of outstanding borrowings and $306.5 million available for future borrowings under its revolving credit facility.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Partnership that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the Partnership and its subsidiary’s assets.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, 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

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured 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.

The lenders may accelerate all of the indebtedness under the Partnership’s credit agreement upon the occurrence and during the continuance of any event of default. The Partnership’s 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.

Interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2017, 2016 and 2015:



	Year Ended December 31,
	2017			2016		2015
	(in thousands)
Interest expense	$	60,671		$	39,642	$	40,221
Less capitalized interest	(22,097		)	—		—
Other fees and expenses	2,160			1,426		1,292
Total interest expense	$	40,734		$	41,068	$	41,513

Capital Stock and Earnings Per Share

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Capital Stock and Earnings Per Share

CAPITAL STOCK AND EARNINGS PER SHARE

Diamondback completed the following equity offerings during the years ended December 31, 2017, 2016 and 2015:



Date	Number of Shares of Common Stock Sold	Number of Shares of Common Stock Issued to Underwriters	Price per Share Sold to Underwriters		Proceeds Received by the Company
January 2015	2,012,500	262,500	$	59.34	$	119,422
May 2015	4,600,000	600,000	$	72.53	$	333,638
August 2015	2,875,000	375,000	$	68.74	$	197,628
January 2016	4,600,000	600,000	$	55.33	$	254,518
July 2016	6,325,000	825,000	$	87.24	$	551,777
December 2016	12,075,000	1,575,000	$	95.3025	$	1,150,828

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. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the diluted earnings per share computation, the per share earnings of the Partnership are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiary.

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



	Year Ended December 31,
	2017		2016			2015

Net income (loss) attributable to common stock	$	482,261	$	(165,034	)	$	(550,628	)
Weighted average common shares outstanding
Basic weighted average common units outstanding	97,458		75,077			63,019
Effect of dilutive securities:
Potential common shares issuable	230		—			—
Diluted weighted average common shares outstanding	97,688		75,077			63,019
Basic net income (loss) attributable to common stock	$	4.95	$	(2.20	)	$	(8.74	)
Diluted net income (loss) attributable to common stock	$	4.94	$	(2.20	)	$	(8.74	)

For the years ended December 31, 2017, 2016 and 2015, there were 45,690 shares, 243,654 shares and 100,924 shares, respectively, that were not included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per share in future periods.

Equity-Based Compensation

12 Months Ended

Dec. 31, 2017

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

Stock and Unit Based Compensation

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 2,500,000 shares of the Company’s common stock has been reserved for issuance pursuant to this plan.

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



	2017		2016		2015
	(In thousands)
General and administrative expenses	$	25,537	$	26,453	$	18,529
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	8,641		7,079		6,043

On June 17, 2014, in connection with the Viper Offering, the Board of Directors of the General Partner adopted the Viper Energy Partners LP Long Term Incentive Plan (“Viper LTIP”), effective June 17, 2014, for employees, officers, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. The Viper LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. A total of 9,070,356 common units has been reserved for issuance pursuant to the Viper LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The Viper LTIP is administered by the Board of Directors of the General Partner or a committee thereof.

Stock Options

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

The following table presents the Company’s stock option activity under the Company’s 2012 Equity Incentive Plan (“2012 Plan”) for the year ended December 31, 2017.



			Weighted Average
			Exercise		Remaining	Intrinsic
	Options		Price		Term	Value
					(in years)	(in thousands)
Outstanding at December 31, 2016	15,750		$	22.72
Exercised	(15,750	)	$	22.72
Outstanding at December 31, 2017	—		$	—	0.00	$	—

The aggregate intrinsic value of stock options that were exercised during the years ended December 31, 2016 and 2015 was $1.3 million and $15.7 million, respectively.

Restricted Stock 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 the Company’s restricted stock units activity under the 2012 Plan during the year ended December 31, 2017.



	Restricted Stock Awards & Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2016	206,004		$	70.33
Granted	188,438		$	102.77
Vested	(147,934	)	$	77.44
Forfeited	(2,931	)	$	89.21
Unvested at December 31, 2017	243,577		$	90.88

The aggregate fair value of restricted stock units that vested during the year ended December 31, 2017, 2016 and 2015 was $14.8 million, $12.5 million and $10.1 million, respectively. As of December 31, 2017, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $14.4 million. Such cost is expected to be recognized over a weighted-average period of 1.5 years.

Performance-Based Restricted Stock Units

To provide long-term incentives for the executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a three-year performance period.

In February 2015, eligible employees received performance restricted stock unit awards totaling 90,249 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2014 to December 31, 2016 and vested at December 31, 2016.

In February 2016, eligible employees received performance restricted stock unit awards totaling 174,325 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2016 to December 31, 2017 and vested at December 31, 2017. Eligible employees received additional performance restricted stock unit awards totaling 87,163 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2016 to December 31, 2018 and cliff vest at December 31, 2018.

In February 2017, eligible employees received performance restricted stock unit awards totaling 37,440 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2017 to December 31, 2018 and cliff vest at December 31, 2018. Eligible employees received additional performance restricted stock unit awards totaling 74,880 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2017 to December 31, 2019 and cliff vest at December 31, 2019.

The fair value of each performance restricted stock unit is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of units to be earned during the performance period. The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions.



	2017						2016
	Two-Year Performance Period			Three-Year Performance Period			Two-Year Performance Period			Three-Year Performance Period			2015
Grant-date fair value	$	162.13		$	168.73		$	103.41		$	102.35		$	137.14
Risk-free rate	1.27		%	1.59		%	0.86		%	1.10		%	0.49		%
Company volatility	39.32		%	41.14		%	41.91		%	42.16		%	43.36		%

The following table presents the Company’s performance restricted stock unit activity under the 2012 Plan for the year ended December 31, 2017.



	Performance Restricted Stock Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2016	252,471		$	103.06
Granted	118,169		$	166.53
Vested	(168,314	)	$	103.41
Unvested at December 31, 2017⁽¹⁾	202,326		$	139.83


(1)	A maximum of 404,652 units could be awarded based upon the Company’s final TSR ranking.

As of December 31, 2017, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $15.6 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.

Partnership Unit Options

In accordance with the Viper LTIP, the exercise price of unit options granted may not be less than the market value of the common units at the date of grant. The units issued under the Viper LTIP will consist of new common units of the Partnership. On June 17, 2014, the Board of Directors of the General Partner granted 2,500,000 unit options to the executive officers of the General Partner. The unit options vest approximately 33% ratably on each of the first three anniversaries of the date of grant or earlier upon a change of control (as defined in the Viper LTIP). All outstanding unit options were amended effective November 29, 2016 to provide that vested unit options will become exercisable upon the earlier to occur of (i) the “Exercise Window Period” beginning on the third anniversary of the date of grant and ending on December 31, 2017, or (ii) the “Change of Control Exercise Period” beginning ten days before and ending on the date a change of control occurs (the earlier occurring of such events, the “Exercise Period”). At any time within the Exercise Period, if a participant attempts to exercise a vested unit option and the fair market value per unit as of such date is less than the exercise price per option unit, the vested unit option will not be exercisable. At the end of the Exercise Period, any vested unit option that is not exercisable or that has not been exercised will automatically terminate and become null and void.

The fair value of the unit options on the date of grant is expensed over the applicable vesting period. The Partnership estimates the fair values of unit options granted using a Black-Scholes option valuation model, which requires the Partnership to make several assumptions. At the time of grant the Partnership did not have a 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. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the unit option at the date of grant. The expected dividend yield was based upon projected performance of the Partnership.



	2015
Grant-date fair value	$	4.24
Expected volatility	36.0		%
Expected dividend yield	5.9		%
Expected term (in years)	3.0
Risk-free rate	0.99		%

The following table presents the unit option activity under the Viper LTIP for the year ended December 31, 2017.



			Weighted Average
	Unit Options		Exercise Price		Remaining Term	Intrinsic Value
					(in years)	(in thousands)
Outstanding at December 31, 2016	2,424,266		$	26.00
Forfeited	(2,416,666	)	$	26.00
Outstanding at December 31, 2017	7,600		$	18.49	0.00	$	—

Vested and Expected to vest at December 31, 2017	7,600		$	18.49	0.00	$	—

Phantom Units

Under the Viper LTIP, the Board of Directors of the General Partner is authorized to issue phantom units to eligible employees. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient one common unit of the Partnership for each phantom unit.

The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2017.



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2016	21,048		$	16.23
Granted	116,567		$	17.09
Vested	(32,176	)	$	16.49
Unvested at December 31, 2017	105,439		$	17.10

The aggregate fair value of phantom units that vested during the year ended December 31, 2017 was $0.5 million. As of December 31, 2017, the unrecognized compensation cost related to unvested phantom units was $1.3 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.

Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions

RELATED PARTY TRANSACTIONS

Immediately upon the completion of the Company’s initial public offering on October 17, 2012, Wexford beneficially owned approximately 44% of the Company’s outstanding common stock. As of December 31, 2016, Wexford beneficially owned less than 1% of the Company’s outstanding common stock. The Chairman of the Board of Directors of both the Company and the General Partner was a partner at Wexford until his retirement from Wexford effective December 31, 2016. Another partner at Wexford serves as a member of the Board of Directors of the General Partner. Beginning January 1, 2017, Wexford and entities affiliated with Wexford are no longer considered related parties of the Company and any expenses after December 31, 2016 are no longer classified as related party expenses.

Related Party Revenue and Expenses

During the year ended December 31, 2016, the Company paid $3.3 million in lease operating expenses and $2.2 million in general and administrative expenses to related parties. During the year ended December 31, 2016, the Company received $0.2 million in other income from related parties. During the year ended December 31, 2015, the Company paid $0.2 million in lease operating expenses, $0.2 million in production and ad valorem taxes, $1.0 million in gathering and transportation expenses and $2.3 million in general and administrative expenses to related parties. During the year ended December 31, 2015, the Company received $0.2 million in other income from related parties.

Advisory Services Agreement - The Company

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 $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement had an initial term of two years commencing on October 18, 2012, and continues 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 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 paid $0.5 million during both of the years ended December 31, 2016 and 2015 under the Advisory Services Agreement.

Advisory Services Agreement - The Partnership

In connection with the closing of the Viper Offering, the Partnership and the General Partner entered into an advisory services agreement (the “Viper Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provides the Partnership and the General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Viper Advisory Services Agreement had an initial term of two years commencing on June 23, 2014, 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 Partnership or the General Partner terminates such agreement, the Partnership is obligated to pay all amounts due through the remaining term. In addition, the Partnership and the General Partner have agreed to pay Wexford to-be-negotiated market-based fees approved by the conflict committee of the board of directors of the General Partner for such services as may be provided by Wexford at the Partnership’s or the General Partner’s request in connection with acquisitions and divestitures, financings or other transactions in which the Partnership may be involved. The services provided by Wexford under the Viper Advisory Services Agreement do not extend to the Partnership or the General Partner’s day-to-day business or operations. The Partnership and General Partner have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Viper Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. The Partnership did not pay any amounts during the years ended December 31, 2017 and 2016 under the Viper Advisory Services Agreement. The Partnership paid $0.5 million during the year ended December 31, 2015 under the Viper Advisory Services Agreement.

Coronado Midstream

The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with Coronado Midstream LLC, formerly known as MidMar Gas LLC, an entity that was affiliated with Wexford, that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, Coronado Midstream LLC is obligated to purchase from the Company, and the Company is obligated to sell to Coronado Midstream LLC, all of the gas conforming to certain quality specifications produced from certain of the Company’s Permian Basin acreage. An entity controlled by Wexford had owned approximately 28% equity interest in Coronado Midstream LLC until Coronado Midstream LLC was sold in March 2015. Coronado Midstream LLC is no longer a related party and any revenues, production and ad valorem taxes and gathering and transportation expense after March 2015 are not classified as those attributable to a related party.

Midland Leases

Effective May 15, 2011, the Company occupied corporate office space in the Fasken building in Midland, Texas under a lease with an initial term of five years. On November 10, 2014, the lease was amended to extend the term of the lease for an additional 10-year period and to increase the monthly base rent to $94,000 beginning in June 2016, with an increase of approximately 2% annually. The office space is owned by Fasken, which is an entity controlled by an affiliate of Wexford.

The following table contains amendments made to lease additional office space in the Midland corporate office during the years ended December 31, 2016 and 2015:



Date of Amendments	Rent for Additional Space	Approx. Annual Increase of Monthly Base Rent
2^nd quarter 2014	$27,000	N/A
4^th quarter 2014	$53,000	4%
April 2015	$23,000	N/A
June 2015	$22,000	2%

Field Office Lease

The Company leased field office space in Midland, Texas from an unrelated third party from March 1, 2011. On March 1, 2014, the building was purchased by WT Commercial Portfolio, LLC, which is controlled by an affiliate of Wexford. The term of the lease expires on February 28, 2018. The monthly base rent was $11,000 and increased 3% annually on March 1 of each year. During the third quarter of 2014, the Company entered into a sublease with Bison, in which Bison leased the field office space on the same terms as the Company’s lease for the remainder of the lease term. The Company paid rent of $0.2 million during both of the years ended December 31, 2016 and 2015. The Company received payments of $0.2 million from Bison in respect of this sublease during both of the years ended December 31, 2016 and 2015. During the second quarter of 2017, the sublease between the Company and Bison as well as the original lease between the Company and WT Commercial Portfolio, LLC were terminated.

The Partnership - Lease Bonus

During the year ended December 31, 2017, the Company paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $7,459 per acre. During the year ended December 31, 2016, the Company paid the Partnership $0.3 million in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre.

Income Taxes

12 Months Ended

Dec. 31, 2017

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. The Company is subject to corporate income taxes and the Texas margin tax.

For certain reporting periods prior to the quarter ended December 31, 2017, the Company’s deferred tax assets exceeded its deferred tax liabilities. The resulting net deferred tax asset was subject to a full valuation allowance. The Company continually assesses its deferred tax assets for realizability and, as a result of such reassessment, in the quarter ended December 31, 2017 the Company determined that sufficient evidence existed to indicate that it is probable that its deferred tax assets will be realized primarily through the unfavorable reversal of deferred tax liabilities, which currently exceed the Company’s deferred tax assets. In the quarter ended December 31, 2017, the valuation allowance historically applied against the Company’s gross deferred tax assets was removed. The Company’s gross deferred tax assets were recorded based upon the 35% federal income tax rate that was in effect prior to the enactment of the Tax Cut and Jobs Act. Subsequently, but also in the quarter ended December 31, 2017, the Company’s deferred tax assets and deferred tax liabilities were revalued to reflect the federal income tax rate enacted by the Tax Cut and Jobs Act. The effects of the removal of the valuation allowance and the reduction to the federal income tax rate may both be seen in the reconciliation of our effective tax rate to the statutory rate below.

The Tax Cuts and Jobs Act, a historic reform of the U.S. federal income tax statutes, was enacted on December 22, 2017. Among other significant features, the Tax Cut and Jobs Act reduces the maximum US federal corporate income tax rate from 35% to 21%, preserves long-standing upstream oil and gas tax provisions such as immediate deduction of intangible drilling costs, allows for immediate expensing of capital expenditures for tangible personal property for a period of time, modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporations, and enacts new limitations regarding the deductibility of interest expense.

As of the completion of the Company’s financial statements for its year ended December 31, 2017, the Company has substantially completed its accounting for the effects of the enactment of the Tax Cut and Jobs Act. With respect to those items for which the Company’s accounting is not complete, as described below, the Company has made reasonable estimates of the effects on its existing deferred tax balances. In all cases, the Company will continue to make and refine its calculations as additional analysis is completed.

To account for the effects of the Tax Cut and Jobs Act, the Company remeasured its deferred tax assets and liabilities based on the federal income and state income tax rates at which they are now expected to reverse, which is generally a federal income tax rate of 21%. The enacted rate change resulted in a non-cash decrease of approximately $67.9 million to the Company’s income tax provision for the period ended December 31, 2017 and a corresponding reduction to the Company’s net noncurrent deferred tax liability balance as of December 31, 2017.

The Company is still analyzing certain aspects of the Tax Cuts and Jobs Act, specifically the provisions related to limitations on the deductibility of certain executive compensation, including equity based compensation. The Company is refining its calculations, which could potentially affect the measurement of related deferred tax balances or potentially give rise to new deferred tax amounts. The Company does not expect that a material adjustment to its deferred tax position will result from the completion of its computations, which the Company expects to finalize by the fourth quarter of 2018.

At December 31, 2017, the Company did not have any significant uncertain tax positions requiring recognition in the financial statements. The tax years 2014 through 2017 remain subject to examination by the major tax jurisdictions.

The components of the provision for income taxes for the years ended December 31, 2017, 2016 and 2015 are as follows:



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Current income tax provision (benefit):
Federal	$	—		$	—		$	(33	)
State	999			192			268
Total current income tax provision	999			192			235
Deferred income tax provision (benefit):
Federal	(21,720		)	(579		)	(198,729		)
State	1,153			579			(2,816		)
Total deferred income tax provision (benefit)	(20,567		)	—			(201,545		)
Total provision for (benefit from) income taxes	$	(19,568	)	$	192		$	(201,310	)

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



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Income tax expense (benefit) at the federal statutory rate (35%)	$	174,016		$	(57,694	)	$	(263,179	)
Impact of nontaxable noncontrolling interest	(12,073		)	—			—
Income tax benefit relating to change in statutory tax rate	(67,938		)	—			(1,145		)
State income tax expense (benefit), net of federal tax effect	3,413			770			(2,548		)
Non-deductible compensation	13,492			3,990			1,354
Change in valuation allowance	(127,485		)	53,336			61,056
Other, net	(2,993		)	(210		)	3,152
Provision for (benefit from) income taxes	$	(19,568	)	$	192		$	(201,310	)

The components of the Company’s deferred tax assets and liabilities as of December 31, 2017 and 2016 are as follows:



	December 31,
	2017			2016
	(In thousands)
Current:
Deferred tax assets
Derivative instruments	$	—		$	7,771
Other	—			3,518
Current deferred tax assets	—			11,289
Valuation allowance	—			(11,289		)
Current deferred tax assets, net of valuation allowance	—			—
Deferred tax liabilities
Derivative instruments	—			—
Total current deferred tax liabilities	—			—
Net current deferred tax assets	—			—
Noncurrent:
Deferred tax assets
Net operating loss carryforwards (subject to 20 year expiration)	74,997			139,065
Derivative instruments	22,918			—
Stock based compensation	942			6,234
Other	2,464			—
Noncurrent deferred tax assets	101,321			145,299
Valuation allowance	(104		)	(103,112		)
Noncurrent deferred tax assets, net of valuation allowance	101,217			42,187
Deferred tax liabilities
Oil and natural gas properties and equipment	202,997			42,187
Midstream assets	6,268			—
Total noncurrent deferred tax liabilities	209,265			42,187
Net noncurrent deferred tax liabilities	108,048			—
Net deferred tax liabilities	$	108,048		$	—

The Company incurred a tax net operating loss ("NOL") in the current year due principally to the ability to expense certain intangible drilling and development costs under current law. There is no tax refund available to the Company, nor is there any current income tax payable. At December 31, 2017, the Company had approximately $357.0 million of federal NOLs expiring in 2032 through 2037. The Company principally operates in the state of Texas and is subject to Texas Margin Tax, which currently does not include an NOL carryover provision. The Company believes that Section 382 of the Internal Revenue Code of 1986, as amended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year look back period, will not have an adverse effect on future NOL usage.

As of December 31, 2017, the Company has a remaining valuation allowance of $0.1 million for certain state NOL carryforwards which the Company does not believe are realizable as it does not anticipate future operations in those states. In the fourth quarter of 2017, the Company removed its valuation allowance against deferred tax assets for U.S. NOL carryforwards resulting in income tax benefit of $127.5 million. As discussed above, management’s assessment included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred tax liabilities. Management believes that the balance of the Company’s NOLs are realizable to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. As a result of management’s assessment, in the quarter ended December 31, 2017, the Company has removed its valuation allowance against its federal NOLs and other federal deferred tax assets in order to state its deferred assets and liabilities at the amount more likely than not to be realized.

Derivatives

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

DERIVATIVES

All derivative financial instruments are recorded at fair value in the accompanying balance sheet. 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 consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

The Company has used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its oil and natural gas sales. With respect to the Company’s fixed price swap and fixed price basis 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 has fixed price basis swaps for the spread between the WTI Midland price and the WTI Cushing price. Under the Company’s costless collar contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the put option 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 call option price. If the settlement price is between the put and the call price, there is no payment required. 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 and Crude Oil Brent, and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk.

As of December 31, 2017, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.



	2018			2019
	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)		Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI	9,761,000	$	51.10	1,095,000	$	49.82
Oil Swaps - BRENT	1,830,000	$	54.89	0	$	—
Oil Basis Swaps	5,475,000	$	0.88	0	$	—
Natural Gas Swaps	7,750,000	$	3.14	0	$	—



	Floor			Ceiling
	Volume (Bbls)	Fixed Price (per Bbl)		Volume (Bbls)	Fixed Price (per Bbl)
January 2018 - March 2018
Costless Collars	540,000	$	47.00	270,000	$	56.34

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, 2017 and 2016.



	December 31,
	2017		2016
	(in thousands)
Gross amounts of assets presented in the Consolidated Balance Sheet	$	531	$	709
Net amounts of assets presented in the Consolidated Balance Sheet	531		709

Gross amounts of liabilities presented in the Consolidated Balance Sheet	106,670		22,608
Net amounts of liabilities presented in the Consolidated Balance Sheet	$	106,670	$	22,608

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,
	2017		2016
	(in thousands)
Current assets: derivative instruments	$	531	$	—
Noncurrent assets: derivative instruments	—		709
Total assets	$	531	$	709
Current liabilities: derivative instruments	$	100,367	$	22,608
Noncurrent liabilities: derivative instruments	6,303		—
Total liabilities	$	106,670	$	22,608

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 consolidated statements of operations:



	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Change in fair value of open non-hedge derivative instruments	$	(84,240	)	$	(26,522	)	$	(112,918	)
Gain on settlement of non-hedge derivative instruments	6,728			1,177			144,869
Gain (loss) on derivative instruments	$	(77,512	)	$	(25,345	)	$	31,951

Fair Value Measurements

12 Months Ended

Dec. 31, 2017

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, 2017 and 2016.



	December 31,
	2017			2016
	(in thousands)
Fixed price swaps:
Quoted prices in active markets level 1	$	—		$	—
Significant other observable inputs level 2	(106,139		)	23,317
Significant unobservable inputs level 3	—			—
Total	$	(106,139	)	$	23,317

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 consolidated balance sheets.



	December 31, 2017				December 31, 2016
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
	(in thousands)
Debt:
Revolving credit facility	$	397,000	$	397,000	$	—	$	—
4.750% Senior Notes due 2024	500,000		501,855		500,000		491,250
5.375% Senior Notes due 2025	500,000		515,000		500,000		502,850
Partnership revolving credit facility	93,500		93,500		120,500		120,500

The fair value of the revolving credit facility and the Partnership’s revolving credit facility approximates their 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, 2017 quoted market price, a Level 1 classification 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, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

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

Lease Commitments

The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2017:



Year Ending December 31,	Drilling Rig Commitments		Office and Equipment Leases
	(in thousands)
2018	$	21,882	$	3,581
2019	10,082		3,307
2020	—		2,927
2021	—		2,406
2022	—		2,242
Thereafter	—		7,973
Total	$	31,964	$	22,436

The Company leases office space in Midland, Texas and in Oklahoma City, OK from unrelated third parties. The following table presents rent expense for the years ended December 31, 2017, 2016 and 2015.



	Year ended December 31,
	2017		2016		2015
	(in thousands)
Rent Expense	$	2,412	$	1,961	$	1,449

Drilling contracts

As of December 31, 2017, the Company had entered into drilling rig contracts with various third parties in the ordinary course of business to ensure rig availability to complete the Company’s drilling projects. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments as of December 31, 2017 total approximately $32.0 million.

Oil production purchase agreement

On May 24, 2012, the Company entered into an oil purchase agreement with Shell Trading (US) Company, in which the Company is obligated to commence delivery of specified quantities of oil to Shell Trading (US) Company 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 five years from the completion date. The Company’s maximum delivery obligation under this agreement is 8,000 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 NYMEX 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 (US) Company 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 (US) Company in the event that Shell Trading (US) Company’s contract for transportation on the pipeline is terminated.

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 immediately. For the years ended December 31, 2017, 2016 and 2015 the Company paid $1.8 million, $1.2 million and $1.4 million, respectively, in contributions to the plan.

Subsequent Events

12 Months Ended

Dec. 31, 2017

Subsequent Events [Abstract]

Subsequent Events

SUBSEQUENT EVENTS

Commodity Contracts

Subsequent to December 31, 2017, the Company entered into new fixed price swaps and costless collars with corresponding put and call options. 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.

The following tables present the derivative contracts entered into by the Company subsequent to December 31, 2017. When aggregating multiple contracts, the weighted average contract price is disclosed.



	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
July 2018 - December 2018
Oil Swaps - WTI	184,000	$	60.70
January 2019 - March 2019
Oil Swaps - WTI	90,000	$	58.70

Fasken Building Purchase

On January 31, 2018, the Company completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporate offices are located.

New Senior Notes due 2025 and Repayment of Portion of Outstanding Borrowings under Revolving Credit Facility

On January 29, 2018, the Company closed on the private placement issuance of $300.0 million aggregate principal amount of 5.375% Senior Notes due 2025. In the offering, the Company received approximately $308.4 million in net proceeds, after deducting the initial purchasers’ discount and its estimated offering expenses, but disregarding accrued interest. The Company used all of the net proceeds from the offering to repay a portion of the outstanding borrowings under its revolving credit facility. In connection with the offering, the lenders under the Company’s revolving credit facility waived the borrowing base decrease that would have been triggered in connection with the offering. Immediately following the completion of the offering and the application of the net proceeds thereof, the Company’s borrowing base remained $1.8 billion, the Company’s elected commitment was $1.0 billion, and the Company had $911.4 million of available borrowing capacity under its revolving credit facility.

Guarantor Financial Statements

12 Months Ended

Dec. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Guarantor Financial Statements

GUARANTOR FINANCIAL STATEMENTS

As of December 31, 2017, Diamondback E&P LLC and Diamondback O&G LLC (the “Guarantor Subsidiaries”) are guarantors under the indentures relating to the 2024 Senior Notes and the 2025 Senior Notes. In connection with the issuance of the 2024 Senior Notes and the 2025 Senior Notes, the Partnership, the General Partner, Viper Energy Partners LLC and Rattler Midstream LLC were designated as Non-Guarantor Subsidiaries. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 17 is referred to as the “Parent”), the Guarantor Subsidiaries and the Non–Guarantor Subsidiaries on a consolidated basis. Elimination entries presented are necessary to combine the entities. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantor Subsidiaries because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantor Subsidiaries.



Condensed Consolidated Balance Sheet
December 31, 2017
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	54,074	$	34,175		$	24,197		$	—		$	112,446
Accounts receivable	—		205,859			25,754			—			231,613
Accounts receivable - related party	—		—			5,142			(5,142		)	—
Intercompany receivable	2,624,810		2,267,308			—			(4,892,118		)	—
Inventories	—		9,108			—			—			9,108
Other current assets	618		4,461			355			—			5,434
Total current assets	2,679,502		2,520,911			55,448			(4,897,260		)	358,601
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	—		8,129,211			1,103,897			(414		)	9,232,694
Midstream assets	—		191,519			—			—			191,519
Other property, equipment and land	—		80,776			—			—			80,776
Accumulated depletion, depreciation, amortization and impairment	—		(1,976,248		)	(189,466		)	4,342			(2,161,372		)
Net property and equipment	—		6,425,258			914,431			3,928			7,343,617
Funds held in escrow	—		—			6,304			—			6,304
Derivative instruments	—		—			—			—			—
Investment in subsidiaries	3,809,557		—			—			(3,809,557		)	—
Other assets	—		25,609			36,854			—			62,463
Total assets	$	6,489,059	$	8,971,778		$	1,013,037		$	(8,702,889	)	$	7,770,985
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	1	$	91,629		$	2,960		$	—		$	94,590
Intercompany payable	132,067		4,765,193			—			(4,897,260		)	—
Other current liabilities	7,236		472,933			2,669			—			482,838
Total current liabilities	139,304		5,329,755			5,629			(4,897,260		)	577,428
Long-term debt	986,847		397,000			93,500			—			1,477,347
Derivative instruments	—		6,303			—			—			6,303
Asset retirement obligations	—		20,122			—			—			20,122
Deferred income taxes	108,048		—			—			—			108,048
Total liabilities	1,234,199		5,753,180			99,129			(4,897,260		)	2,189,248
Commitments and contingencies
Stockholders’ equity	5,254,860		3,218,598			913,908			(4,132,506		)	5,254,860
Non-controlling interest	—		—			—			326,877			326,877
Total equity	5,254,860		3,218,598			913,908			(3,805,629		)	5,581,737
Total liabilities and equity	$	6,489,059	$	8,971,778		$	1,013,037		$	(8,702,889	)	$	7,770,985



Condensed Consolidated Balance Sheet
December 31, 2016
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	1,643,226		$	14,135		$	9,213		$	—		$	1,666,574
Restricted cash	—			—			500			—			500
Accounts receivable	—			109,782			10,043			—			119,825
Accounts receivable - related party	—			297			3,470			(3,470		)	297
Intercompany receivable	3,060,566			359,502			—			(3,420,068		)	—
Inventories	—			1,983			—			—			1,983
Other current assets	481			2,319			187			—			2,987
Total current assets	4,704,273			488,018			23,413			(3,423,538		)	1,792,166
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	—			4,400,002			760,818			(559		)	5,160,261
Midstream assets	—			8,362			—			—			8,362
Other property, equipment and land	—			58,290			—			—			58,290
Accumulated depletion, depreciation, amortization and impairment	—			(1,695,701		)	(148,948		)	8,593			(1,836,056		)
Net property and equipment	—			2,770,953			611,870			8,034			3,390,857
Funds held in escrow	—			121,391			—			—			121,391
Derivative instruments	—			709			—			—			709
Investment in subsidiaries	(15,500		)	—			—			15,500			—
Other assets	—			9,291			35,266			—			44,557
Total assets	$	4,688,773		$	3,390,362		$	670,549		$	(3,400,004	)	$	5,349,680
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	30		$	45,838		$	1,780		$	—		$	47,648
Accounts payable-related party	1			—			—			—			1
Intercompany payable	—			3,423,538			—			(3,423,538		)	—
Other current liabilities	5,868			155,454			371			—			161,693
Total current liabilities	5,899			3,624,830			2,151			(3,423,538		)	209,342
Long-term debt	985,412			—			120,500			—			1,105,912
Asset retirement obligations	—			16,134			—			—			16,134
Total liabilities	991,311			3,640,964			122,651			(3,423,538		)	1,331,388
Commitments and contingencies
Stockholders’ equity	3,697,462			(250,602		)	547,898			(297,296		)	3,697,462
Non-controlling interest	—			—			—			320,830			320,830
Total equity	3,697,462			(250,602		)	547,898			23,534			4,018,292
Total liabilities and equity	$	4,688,773		$	3,390,362		$	670,549		$	(3,400,004	)	$	5,349,680



Condensed Consolidated Statement of Operations
Year Ended December 31, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	903,842		$	—		$	140,175		$	1,044,017
Natural gas sales	—			42,899			—			9,311			52,210
Natural gas liquid sales	—			79,371			—			10,677			90,048
Royalty income	—			—			160,163			(160,163		)	—
Lease bonus income	—			—			11,870			(106		)	11,764
Midstream services	—			7,072			—			—			7,072
Total revenues	—			1,033,184			172,033			(106		)	1,205,111
Costs and expenses:
Lease operating expenses	—			126,524			—			—			126,524
Production and ad valorem taxes	—			62,897			10,608			—			73,505
Gathering and transportation	—			12,045			789			—			12,834
Midstream services	—			10,409			—			—			10,409
Depreciation, depletion and amortization	—			281,989			40,519			4,251			326,759
General and administrative expenses	26,776			18,057			6,296			(2,460		)	48,669
Asset retirement obligation accretion	—			1,391			—			—			1,391
Total costs and expenses	26,776			513,312			58,212			1,791			600,091
Income (loss) from operations	(26,776		)	519,872			113,821			(1,897		)	605,020
Other income (expense)
Interest expense, net	(29,925		)	(7,465		)	(3,164		)	—			(40,554		)
Other income, net	1,142			10,732			821			(2,460		)	10,235
Loss on derivative instruments, net	—			(77,512		)	—			—			(77,512		)
Total other expense, net	(28,783		)	(74,245		)	(2,343		)	(2,460		)	(107,831		)
Income (loss) before income taxes	(55,559		)	445,627			111,478			(4,357		)	497,189
Benefit from income taxes	(19,568		)	—			—			—			(19,568		)
Net income (loss)	(35,991		)	445,627			111,478			(4,357		)	516,757
Net income attributable to non-controlling interest	—			—			—			34,496			34,496
Net income (loss) attributable to Diamondback Energy, Inc.	$	(35,991	)	$	445,627		$	111,478		$	(38,853	)	$	482,261



Condensed Consolidated Statement of Operations
Year Ended December 31, 2016
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	399,007		$	—		$	71,521		$	470,528
Natural gas sales	—			19,399			—			3,107			22,506
Natural gas liquid sales	—			29,864			—			4,209			34,073
Royalty income	—			—			78,837			(78,837		)	—
Lease bonus income	—			—			309			(309		)	—
Total revenues	—			448,270			79,146			(309		)	527,107
Costs and expenses:
Lease operating expenses	—			82,428			—			—			82,428
Production and ad valorem taxes	—			28,912			5,544			—			34,456
Gathering and transportation	—			11,189			415			2			11,606
Depreciation, depletion and amortization	—			151,376			29,820			(3,181		)	178,015
Impairment of oil and natural gas properties	—			198,067			47,469			—			245,536
General and administrative expenses	25,959			11,451			5,209			—			42,619
Asset retirement obligation accretion	—			1,064			—			—			1,064
Total costs and expenses	25,959			484,487			88,457			(3,179		)	595,724
Income (loss) from operations	(25,959		)	(36,217		)	(9,311		)	2,870			(68,617		)
Other income (expense)
Interest expense, net	(35,318		)	(2,911		)	(2,455		)	—			(40,684		)
Other income, net	437			2,010			867			(250		)	3,064
Loss on derivative instruments, net	—			(25,345		)	—			—			(25,345		)
Loss on extinguishment of debt	(33,134		)	—			—			—			(33,134		)
Total other expense, net	(68,015		)	(26,246		)	(1,588		)	(250		)	(96,099		)
Income (loss) before income taxes	(93,974		)	(62,463		)	(10,899		)	2,620			(164,716		)
Provision for income taxes	192			—			—			—			192
Net income (loss)	(94,166		)	(62,463		)	(10,899		)	2,620			(164,908		)
Net income attributable to non-controlling interest	—			—			—			126			126
Net income (loss) attributable to Diamondback Energy, Inc.	$	(94,166	)	$	(62,463	)	$	(10,899	)	$	2,494		$	(165,034	)



Condensed Consolidated Statement of Operations
Year Ended December 31, 2015
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	336,106		$	—		$	69,609		$	405,715
Natural gas sales	—			16,932			—			2,660			19,592
Natural gas liquid sales	—			18,836			—			2,590			21,426
Royalty income	—			—			74,859			(74,859		)	—
Total revenues	—			371,874			74,859			—			446,733
Costs and expenses:
Lease operating expenses	—			82,625			—			—			82,625
Production and ad valorem taxes	—			27,459			5,531			—			32,990
Gathering and transportation	—			5,832			259			—			6,091
Depreciation, depletion and amortization	—			182,395			35,436			(134		)	217,697
Impairment of oil and natural gas properties	—			814,798			3,423			(3,423		)	814,798
General and administrative expenses	17,077			9,056			5,835			—			31,968
Asset retirement obligation accretion expense	—			833			—			—			833
Total costs and expenses	17,077			1,122,998			50,484			(3,557		)	1,187,002
Income (loss) from operations	(17,077		)	(751,124		)	24,375			3,557			(740,269		)
Other income (expense)
Interest expense, net	(35,651		)	(4,749		)	(1,110		)	—			(41,510		)
Other income, net	1			(427		)	1,154			—			728
Gain on derivative instruments, net	—			31,951			—			—			31,951
Total other expense, net	(35,650		)	26,775			44			—			(8,831		)
Income (loss) before income taxes	(52,727		)	(724,349		)	24,419			3,557			(749,100		)
Benefit from income taxes	(201,310		)	—			—			—			(201,310		)
Net income (loss)	$	148,583		$	(724,349	)	$	24,419		$	3,557		$	(547,790	)
Net income attributable to non-controlling interest	$	—		$	—		$	—		$	2,838		$	2,838
Net income (loss) attributable to Diamondback Energy, Inc.	$	148,583		$	(724,349	)	$	24,419		$	719		$	(550,628	)



Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(29,470	)	$	778,876		$	139,219		$	—		$	888,625
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(792,599		)	—			—			(792,599		)
Additions to midstream assets	—			(68,139		)	—			—			(68,139		)
Purchase of other property, equipment and land	—			(22,779		)	—			—			(22,779		)
Acquisition of leasehold interests	—			(1,960,591		)	—			—			(1,960,591		)
Acquisition of mineral interests	—			(63,371		)	(344,079		)	—			(407,450		)
Acquisition of midstream assets	—			(50,279		)	—			—			(50,279		)
Proceeds from sale of assets	—			65,656			—			—			65,656
Funds held in escrow	—			104,087			—			—			104,087
Equity investments	—			(188		)	—			—			(188		)
Intercompany transfers	(1,631,078		)	1,631,078			—			—			—
Net cash used in investing activities	(1,631,078		)	(1,157,125		)	(344,079		)	—			(3,132,282		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			475,000			278,500			—			753,500
Repayment on credit facility	—			(78,000		)	(305,500		)	—			(383,500		)
Purchase of subsidiary units by parent	(10,068		)	—			—			10,068			—
Debt issuance costs	(8,326		)	1,289			(2,259		)	—			(9,296		)
Public offering costs	(77		)	—			(433		)	—			(510		)
Proceeds from public offerings	—			—			380,412			(10,068		)	370,344
Distribution from subsidiary	89,509			—			—			(89,509		)	—
Exercise of stock options	358			—			—			—			358
Distribution to non-controlling interest	—			—			(130,876		)	89,509			(41,367		)
Net cash provided by financing activities	71,396			398,289			219,844			—			689,529
Net increase (decrease) in cash and cash equivalents	(1,589,152		)	20,040			14,984			—			(1,554,128		)
Cash and cash equivalents at beginning of period	1,643,226			14,135			9,213			—			1,666,574
Cash and cash equivalents at end of period	$	54,074		$	34,175		$	24,197		$	—		$	112,446



Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2016
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(39,894	)	$	303,347		$	68,627		$	—		$	332,080
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(363,087		)	—			—			(363,087		)
Additions to midstream assets	—			(1,188		)	—			—			(1,188		)
Purchase of other property, equipment and land	—			(9,891		)	—			—			(9,891		)
Acquisition of leasehold interests	—			(611,280		)	—			—			(611,280		)
Acquisition of mineral interests	—			—			(205,721		)	—			(205,721		)
Proceeds from sale of assets	—			4,661			—			—			4,661
Funds held in escrow	—			(121,391		)	—			—			(121,391		)
Equity investments	—			(2,345		)	—			—			(2,345		)
Intercompany transfers	(796,053		)	796,053			—			—			—
Net cash used in investing activities	(796,053		)	(308,468		)	(205,721		)	—			(1,310,242		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			—			164,000			—			164,000
Repayment on credit facility	—			(11,000		)	(78,000		)	—			(89,000		)
Proceeds from senior notes	1,000,000			—			—			—			1,000,000
Repayment of senior notes	(450,000		)	—			—			—			(450,000		)
Premium on extinguishment of debt	(26,561		)	—			—			—			(26,561		)
Debt issuance costs	(14,449		)	(172		)	(442		)	—			(15,063		)
Public offering costs	(636		)	—			(546		)	—			(1,182		)
Proceeds from public offerings	1,925,923			—			125,580			—			2,051,503
Distribution from subsidiary	55,250			—			—			(55,250		)	—
Exercise of stock options	498			—			—			—			498
Distribution to non-controlling interest	—			—			(64,824		)	55,250			(9,574		)
Intercompany transfers	(11,000		)	11,000			—			—			—
Net cash provided by (used in) financing activities	2,479,025			(172		)	145,768			—			2,624,621
Net increase (decrease) in cash and cash equivalents	1,643,078			(5,293		)	8,674			—			1,646,459
Cash and cash equivalents at beginning of period	148			19,428			539			—			20,115
Cash and cash equivalents at end of period	$	1,643,226		$	14,135		$	9,213		$	—		$	1,666,574



Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2015
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(37,597	)	$	390,266		$	63,832		$	—		$	416,501
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(419,512		)	—			—			(419,512		)
Purchase of other property, equipment and land	—			(1,213		)	—			—			(1,213		)
Acquisition of leasehold interests	—			(437,455		)	—			—			(437,455		)
Acquisition of royalty interests	—			—			(43,907		)	—			(43,907		)
Proceeds from sale of assets	—			9,739			—			—			9,739
Equity investments	—			(2,702		)	—			—			(2,702		)
Intercompany transfers	(145,023		)	145,023			—			—			—
Net cash used in investing activities	(145,023		)	(706,120		)	(43,907		)	—			(895,050		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			390,501			34,500			—			425,001
Repayment on credit facility	—			(603,001		)	—			—			(603,001		)
Debt issuance costs	—			(85		)	(441		)	—			(526		)
Public offering costs	(586		)	—			—			—			(586		)
Proceeds from public offerings	650,688			—			—			—			650,688
Distribution from subsidiary	60,587			—			—			(60,587		)	—
Exercise of stock options	4,873			—			—			—			4,873
Distribution to non-controlling interest	—			—			(68,555		)	60,587			(7,968		)
Intercompany transfers	(532,800		)	532,800			—			—			—
Net cash provided by (used in) financing activities	182,762			320,215			(34,496		)	—			468,481
Net increase (decrease) in cash and cash equivalents	142			4,361			(14,571		)	—			(10,068		)
Cash and cash equivalents at beginning of period	6			15,067			15,110			—			30,183
Cash and cash equivalents at end of period	$	148		$	19,428		$	539		$	—		$	20,115

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

12 Months Ended

Dec. 31, 2017

Oil and Gas Exploration and Production Industries Disclosures [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,
	2017			2016
	(In thousands)
Oil and Natural Gas Properties:
Proved properties	$	5,126,829		$	3,429,742
Unproved properties	4,105,865			1,730,519
Total oil and natural gas properties	9,232,694			5,160,261
Accumulated depreciation, depletion, amortization	(1,009,893		)	(687,685		)
Accumulated impairment	(1,143,498		)	(1,143,498		)
Net oil and natural gas properties capitalized	$	7,079,303		$	3,329,078

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,
	2017		2016		2015
	(In thousands)
Acquisition costs
Proved properties	$	452,661	$	72,044	$	64,340
Unproved properties	2,692,000		752,117		448,638
Development costs	145,362		47,575		42,749
Exploration costs	779,728		329,122		319,102
Capitalized asset retirement costs	2,682		4,030		3,458
Total	$	4,072,433	$	1,204,888	$	878,287

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,
	2017			2016			2015
	(In thousands)
Oil, natural gas and natural gas liquid sales	$	1,186,275		$	527,107		$	446,733
Lease operating expenses	(126,524		)	(82,428		)	(82,625		)
Production and ad valorem taxes	(73,505		)	(34,456		)	(32,990		)
Gathering and transportation	(12,834		)	(11,606		)	(6,091		)
Depreciation, depletion, and amortization	(321,870		)	(176,369		)	(216,056		)
Impairment	—			(245,536		)	(814,798		)
Asset retirement obligation accretion expense	(1,391		)	(1,064		)	(833		)
Income tax benefit (expense)	19,568			(192		)	201,310
Results of operations	$	669,719		$	(24,544	)	$	(505,350	)

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2017, 2016 and 2015 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:



	Oil (MBbls)		Natural Gas Liquids (MBbls)		Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves:
As of January 1, 2015	75,690		18,542		111,605
Extensions and discoveries	48,725		12,056		53,453
Revisions of previous estimates	(12,130	)	(4,081	)	(14,726	)
Purchase of reserves in place	2,775		1,165		7,102
Production	(9,081	)	(1,678	)	(7,931	)
As of December 31, 2015	105,979		26,004		149,503
Extensions and discoveries	55,069		13,962		64,758
Revisions of previous estimates	(12,483	)	(1,888	)	(34,519	)
Purchase of reserves in place	2,537		1,455		7,567
Divestitures	(366	)	—		(1,985	)
Production	(11,562	)	(2,399	)	(10,428	)
As of December 31, 2016	139,174		37,134		174,896
Extensions and discoveries	99,980		20,825		109,032
Revisions of previous estimates	(7,715	)	(1,466	)	(10,065	)
Purchase of reserves in place	24,322		2,633		34,640
Divestitures	(1,163	)	(461	)	(2,474	)
Production	(21,417	)	(4,056	)	(20,660	)
As of December 31, 2017	233,181		54,609		285,369

Proved Developed Reserves:
January 1, 2015	43,886		11,221		68,264
December 31, 2015	60,569		15,418		96,871
December 31, 2016	79,457		22,080		105,399
December 31, 2017	141,246		35,412		190,740

Proved Undeveloped Reserves:
January 1, 2015	31,804		7,321		43,341
December 31, 2015	45,409		10,586		52,632
December 31, 2016	59,717		15,054		69,497
December 31, 2017	91,935		19,198		94,629

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.

During the year ended December 31, 2017, the Company’s extensions and discoveries of 138,977 MBOE resulted primarily from the drilling of 102 new wells and from 87 new proved undeveloped locations added. Partnership royalty interests accounted for 8% of the extension volumes. The Company’s revisions of previous estimates were primarily the result of 2,550 MBOE from reclassifying PUD locations due to anticipated timing, with the remaining 8,308 MBOE being technical revisions. Delaware Basin working interest purchases accounted for 87% of the total purchases and Partnership royalty interest purchases accounted for 10%, with working interest purchases contributing the remainder.

During the year ended December 31, 2016, the Company’s extensions and discoveries of 69,042 MBOE resulted primarily from the drilling of 59 new wells and from 51 new proved undeveloped locations added. The Company owns the mineral interests associated with 30 of the 59 new wells and 30 of the 51 proved undeveloped locations through the Partnership. The Company’s negative revisions of previous estimates were primarily the result of 5,978 MBOE of pricing revisions and 7,253 MBOE from reclassifying 17 locations from proved undeveloped due to pricing. Purchases of reserves in place of 3,993 MBOE were primarily the result of the purchase of producing wells included with the Reeves and Ward county acreage purchase and reserves associated with multiple purchases made by the Partnership.

During the year ended December 31, 2015, the Company made one large acquisition of oil and natural gas interests in 2015 located in western Howard and eastern Martin counties. Several small acquisitions were also made in various counties including Andrews, Midland, Martin, and Glasscock counties. The reserves from these acquisitions were primarily proved producing reserves from 136 vertical wells and four horizontal wells and three vertical wells where additional interest was acquired. All of the properties were acquired for horizontal exploitation. Although there were four producing horizontal wells on the properties no PUD’s were included in the acquired properties because of very limited production from the wells at the time of acquisition. Significant extensions occurred in 2015 as a result of continued horizontal development of the Lower Spraberry and Wolfcamp B horizons. There was also initial development of the Wolfcamp A and Middle Spraberry horizons in some locations. The extensions resulted from two vertical wells and 119 horizontal wells in which the Company has a working interest and from 16 horizontal wells in which the Company has a mineral interest through its ownership in Viper. Of the two vertical wells and 135 horizontal wells, one of the vertical wells and 89 of the horizontal wells are in the proved undeveloped category. The revisions are primarily the result of lower product pricing. As a result of lower pricing, 80 vertical wells and 22 horizontal wells in which the Company has a working interest and 22 vertical wells in which the Company has a mineral interest were downgraded from the proved undeveloped category to probable or possible reserves. Additional downward revisions resulted from shorter producing lives on existing wells as a result of the wells reaching their economic limit sooner due to lower revenues.

At December 31, 2017, the Company’s estimated PUD reserves were approximately 126,904 MBOE, a 40,550 MBOE increase over the reserve estimate at December 31, 2016 of 86,354 MBOE. The following table includes the changes in PUD reserves for 2017:



	(MBOE)
Beginning proved undeveloped reserves at December 31, 2016	86,354
Undeveloped reserves transferred to developed	(31,666	)
Revisions	(4,710	)
Net purchases	6,246
Extensions and discoveries	70,680
Ending proved undeveloped reserves at December 31, 2017	126,904

The increase in proved undeveloped reserves was primarily attributable to extensions of 67,676 MBOE from 87 gross (75 net) wells in which the Company has a working interest and 3,004 MBOE from 40 gross wells in which the Partnership owns royalty interests. Of the 87 gross wells, 26 were in the Delaware Basin. Transfers of 31,666 MBOE were the result of drilling or participating in 44 gross (37 net) horizontal wells in which the Company has a working interest and 27 gross wells in which the Company has a royalty interest or mineral interest through the Partnership. The Company owns a working interest in 23 of the 27 gross Partnership wells. Net purchases of 6,246 MBOE were primarily from the Company’s purchase in Pecos and Reeves counties. Downward revisions of 4,710 MBOE resulted from reclassification of seven locations and technical revisions.

As of December 31, 2017, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2017, approximately $145.4 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is 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, 2017, 2016 and 2015.



	December 31,
	2017			2016			2015
	(In thousands)
Future cash inflows	$	12,921,897		$	6,275,705		$	5,377,783
Future development costs	(1,123,979		)	(617,636		)	(548,239		)
Future production costs	(2,994,877		)	(1,392,852		)	(1,279,101		)
Future production taxes	(928,891		)	(459,244		)	(363,129		)
Future income tax expenses	(83,961		)	(75,595		)	(28,233		)
Future net cash flows	7,790,189			3,730,378			3,159,081
10% discount to reflect timing of cash flows	(4,033,130		)	(2,018,965		)	(1,740,948		)
Standardized measure of discounted future net cash flows	$	3,757,059		$	1,711,413		$	1,418,133

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,
	2017		2016		2015
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	48.03	$	39.94	$	45.07
Natural gas (per Mcf)	$	2.06	$	1.36	$	1.83
Natural gas liquids (per Bbl)	$	20.79	$	12.91	$	12.56

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,
	2017			2016			2015
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	1,711,413		$	1,418,133		$	2,045,224
Sales of oil and natural gas, net of production costs	(986,246		)	(411,558		)	(331,119		)
Acquisition of reserves	439,396			43,142			58,849
Divestiture of reserves	(11,072		)	(5,481		)	(1,490		)
Extensions and discoveries, net of future development costs	1,791,686			779,359			629,149
Previously estimated development costs incurred during the period	190,121			85,696			129,901
Net changes in prices and production costs	577,781			(150,509		)	(1,383,698		)
Changes in estimated future development costs	(52,908		)	20,647			38,638
Revisions of previous quantity estimates	(98,857		)	(123,795		)	(377,160		)
Accretion of discount	174,185			143,134			236,716
Net change in income taxes	(9,074		)	(30,530		)	268,963
Net changes in timing of production and other	30,634			(56,825		)	104,160
Standardized measure of discounted future net cash flows at the end of the period	$	3,757,059		$	1,711,413		$	1,418,133

Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2017

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Data (Unaudited)

QUARTERLY FINANCIAL DATA (Unaudited)

The Company’s unaudited quarterly financial data for 2017 and 2016 is summarized below.



	2017
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	235,230		$	269,434		$	301,253		$	399,194
Income from operations	116,410			132,308			142,639			213,663
Income tax expense (benefit)	1,957			1,579			857			(23,961		)
Net income	141,074			164,128			81,948			129,607
Net income attributable to non-controlling interest	4,801			5,723			8,924			15,048
Net income attributable to Diamondback Energy, Inc.	$	136,273		$	158,405		$	73,024		$	114,559
Earnings per common share
Basic	$	1.46		$	1.61		$	0.74		$	1.17
Diluted	$	1.46		$	1.61		$	0.74		$	1.16

	2016
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	87,481		$	112,483		$	142,131		$	185,012
Income (loss) from operations	(27,603		)	(134,786		)	6,693			87,079
Income tax expense (benefit)	—			368			—			(176		)
Net income (loss)	(35,627		)	(157,121		)	(600		)	28,440
Net income (loss) attributable to non-controlling interest	(2,715		)	(1,631		)	1,630			2,842
Net income (loss) attributable to Diamondback Energy, Inc.	$	(32,912	)	$	(155,490	)	$	(2,230	)	$	25,598
Earnings per common share
Basic	$	(0.46	)	$	(2.17	)	$	(0.03	)	$	0.32
Diluted	$	(0.46	)	$	(2.17	)	$	(0.03	)	$	0.32

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.
Use of Estimates	Use of Estimates Certain amounts included in or affecting the Company’s 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 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 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, but are not limited to, 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, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.
Cash and Cash Equivalents and Restricted Cash	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. Restricted Cash In 2014, a subsidiary of the Company entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The subsidiary subsequently terminated the agreement and requested a return of the deposit. The seller challenged the termination and the escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds.
Accounts Receivable	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 for production 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.
Derivative Instruments	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 for each period in the consolidated statements of operations.
Fair Value of Financial Instruments	Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, restricted cash, receivables, payables, derivatives 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 fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 14–Fair Value Measurements).
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. 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. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. 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 7–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 Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. 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, Equipment and Land 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 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.
Asset Retirement Obligations	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 or if there is a change in the estimated liability, the difference is recorded in oil and natural gas properties.
Impairment or Long-Lived Assets	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.
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 $22.1 million for the year ended December 31, 2017. The Company did not have any capitalized interest for the years ended December 31, 2016 and 2015.
Inventories	The Company’s tubular goods and equipment are 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.
Debt Issuance Costs	The costs associated with the senior notes are being netted against the senior notes balances and are being amortized over the term of the senior notes using the effective interest method. The costs associated with the Company’s credit facility that are included in other assets are being amortized over the term of the facility.
Revenue and Royalties Payable	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 that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.
Revenue Recognition	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. Revenues from oil and natural gas services are recognized when services are provided.
Investments	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.
Accounting for Stock-based Compensation	Accounting for Equity-Based Compensation The Company grants various types of stock-based awards including stock options and restricted stock units. The Partnership grants various unit-based awards including unit options and phantom units to employees, officers and directors of the General Partner and the Company who perform services for the Partnership. These plans and related accounting policies are defined and described more fully in Note 10–Equity-Based Compensation. Equity 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	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. 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 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	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 (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) 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.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Recently Issued Pronouncements In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The Company will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Company has reviewed various contracts that represent its material revenue streams and determined that there will be no impact to its financial position, results of operations or liquidity. Upon adoption of this Accounting Standards Update, the Company will not be required to record a cumulative effect adjustment due to the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting Standards Update, the Company will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Company. The Company does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams as compared to existing GAAP. In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Unitholders’ Equity and will bring the fair value of its investment to $15.2 million or $15.20 per unit for that investment. In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company will adopt this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard will change the presentation of its cash flows and did not have a material impact on its consolidated financial statements. In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Company will adopt this update retrospectively effective January 1, 2018. Adoption of this standard will change the presentation of its cash flows and did not have a material impact on its consolidated financial statements. In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company will adopt this update prospectively effective January 1, 2018. The adoption of this update will not have an impact on its financial position, results of operations or liquidity. Accounting Pronouncements Not Yet Adopted In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard. In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses.
Fair Value Measurement	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.

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Schedule of other accrued liabilities

Other accrued liabilities consist of the following:



	December 31,
	2017		2016
	(In thousands)
Liability for drilling costs prepaid by joint interest partners	$	30,320	$	21,595
Interest payable	6,770		5,445
Lease operating expenses payable	27,850		13,857
Ad valorem taxes payable	3,306		776
Current portion of asset retirement obligations	1,163		1,288
Other	23,103		12,369
Total other accrued liabilities	$	92,512	$	55,330

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2017

Business Acquisition [Line Items]

Schedule of estimated fair values of assets acquired and liabilities assumed



	(in thousands)
Proved oil and natural gas properties	$	386,308
Unevaluated oil and natural gas properties	2,122,597
Midstream assets	47,432
Prepaid capital costs	3,460
Oil inventory	839
Equipment	163
Revenues and royalties payable	(9,650		)
Asset retirement obligations	(1,550		)
Total fair value of net assets	$	2,549,599

Schedule of business acquisition pro forma

The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods.



	Year Ended December 31,
	2017		2016
	(in thousands, except per share amounts)
Revenues	$	1,228,040	$	627,301
Income (loss) from operations	619,369		(12,812		)
Net income (loss)	472,649		(109,229		)
Basic earnings per common share	4.85		(1.45		)
Diluted earnings per common share	4.84		(1.45		)

Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2017

Property, Plant and Equipment [Abstract]

Property and Equipment

Property and equipment includes the following:



	December 31,
	2017			2016
	(in thousands)
Oil and natural gas properties:
Subject to depletion	$	5,126,829		$	3,429,742
Not subject to depletion	4,105,865			1,730,519
Gross oil and natural gas properties	9,232,694			5,160,261
Accumulated depletion	(1,009,893		)	(687,685		)
Accumulated impairment	(1,143,498		)	(1,143,498		)
Oil and natural gas properties, net	7,079,303			3,329,078
Midstream assets	191,519			8,362
Other property, equipment and land	80,776			58,290
Accumulated depreciation	(7,981		)	(4,873		)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	7,343,617		$	3,390,857

Balance of costs not subject to depletion:
Incurred in 2017	$	2,746,936
Incurred in 2016	727,411
Incurred in 2015	301,879
Incurred in 2014	316,455
Incurred in 2013	13,184
Total not subject to depletion	$	4,105,865

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

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



	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Asset retirement obligations, beginning of period	$	17,422		$	12,711		$	8,486
Additional liabilities incurred	1,526			637			594
Liabilities acquired	2,432			3,696			3,159
Liabilities settled	(1,555		)	(711		)	(292		)
Accretion expense	1,391			1,064			833
Revisions in estimated liabilities	69			25			(69		)
Asset retirement obligations, end of period	21,285			17,422			12,711
Less current portion	1,163			1,288			193
Asset retirement obligations - long-term	$	20,122		$	16,134		$	12,518

Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt Instrument [Line Items]

Schedule of long-term debt

Long-term debt consisted of the following as of the dates indicated:



	December 31,
	2017			2016
	(in thousands)
4.750 % Senior Notes due 2024	500,000			500,000
5.375 % Senior Notes due 2025	500,000			500,000
Unamortized debt issuance costs	(13,153		)	(14,588		)
Revolving credit facility	397,000			—
Partnership revolving credit facility	93,500			120,500
Total long-term debt	$	1,477,347		$	1,105,912

Schedule of interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2017, 2016 and 2015:



	Year Ended December 31,
	2017			2016		2015
	(in thousands)
Interest expense	$	60,671		$	39,642	$	40,221
Less capitalized interest	(22,097		)	—		—
Other fees and expenses	2,160			1,426		1,292
Total interest expense	$	40,734		$	41,068	$	41,513

Company Credit Facility [Member]

Debt Instrument [Line Items]

Financial Covenants



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

Partnership Credit Facility [Member]

Debt Instrument [Line Items]

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

- 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=84159872&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=75038535&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=64930739&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=84159872&loc=d3e21538-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
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-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=84159872&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
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-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=64930785&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=64930785&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=84159872&loc=d3e21521-112644

+ Details

Capital Stock and Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2017

Class of Stock [Line Items]

Schedule of sale of stock [Table Text Block]

Diamondback completed the following equity offerings during the years ended December 31, 2017, 2016 and 2015:



Date	Number of Shares of Common Stock Sold	Number of Shares of Common Stock Issued to Underwriters	Price per Share Sold to Underwriters		Proceeds Received by the Company
January 2015	2,012,500	262,500	$	59.34	$	119,422
May 2015	4,600,000	600,000	$	72.53	$	333,638
August 2015	2,875,000	375,000	$	68.74	$	197,628
January 2016	4,600,000	600,000	$	55.33	$	254,518
July 2016	6,325,000	825,000	$	87.24	$	551,777
December 2016	12,075,000	1,575,000	$	95.3025	$	1,150,828

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:



	Year Ended December 31,
	2017		2016			2015

Net income (loss) attributable to common stock	$	482,261	$	(165,034	)	$	(550,628	)
Weighted average common shares outstanding
Basic weighted average common units outstanding	97,458		75,077			63,019
Effect of dilutive securities:
Potential common shares issuable	230		—			—
Diluted weighted average common shares outstanding	97,688		75,077			63,019
Basic net income (loss) attributable to common stock	$	4.95	$	(2.20	)	$	(8.74	)
Diluted net income (loss) attributable to common stock	$	4.94	$	(2.20	)	$	(8.74	)

Equity-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2017

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

The effects of stock-based compensation plans and related costs

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



	2017		2016		2015
	(In thousands)
General and administrative expenses	$	25,537	$	26,453	$	18,529
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	8,641		7,079		6,043

Schedule of stock/unit option activity

The following table presents the Company’s stock option activity under the Company’s 2012 Equity Incentive Plan (“2012 Plan”) for the year ended December 31, 2017.



			Weighted Average
			Exercise		Remaining	Intrinsic
	Options		Price		Term	Value
					(in years)	(in thousands)
Outstanding at December 31, 2016	15,750		$	22.72
Exercised	(15,750	)	$	22.72
Outstanding at December 31, 2017	—		$	—	0.00	$	—

Summary of restricted stock awards and units

The following table presents the Company’s restricted stock units activity under the 2012 Plan during the year ended December 31, 2017.



	Restricted Stock Awards & Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2016	206,004		$	70.33
Granted	188,438		$	102.77
Vested	(147,934	)	$	77.44
Forfeited	(2,931	)	$	89.21
Unvested at December 31, 2017	243,577		$	90.88

Summary of grant-date fair values of performance restricted stock units granted and related assumptions

The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions.



	2017						2016
	Two-Year Performance Period			Three-Year Performance Period			Two-Year Performance Period			Three-Year Performance Period			2015
Grant-date fair value	$	162.13		$	168.73		$	103.41		$	102.35		$	137.14
Risk-free rate	1.27		%	1.59		%	0.86		%	1.10		%	0.49		%
Company volatility	39.32		%	41.14		%	41.91		%	42.16		%	43.36		%

Schedule of performance restricted stock units activity

The following table presents the Company’s performance restricted stock unit activity under the 2012 Plan for the year ended December 31, 2017.



	Performance Restricted Stock Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2016	252,471		$	103.06
Granted	118,169		$	166.53
Vested	(168,314	)	$	103.41
Unvested at December 31, 2017⁽¹⁾	202,326		$	139.83


(1)	A maximum of 404,652 units could be awarded based upon the Company’s final TSR ranking.

Viper LTIP [Member]

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

Schedule of stock/unit option activity

The following table presents the unit option activity under the Viper LTIP for the year ended December 31, 2017.



			Weighted Average
	Unit Options		Exercise Price		Remaining Term	Intrinsic Value
					(in years)	(in thousands)
Outstanding at December 31, 2016	2,424,266		$	26.00
Forfeited	(2,416,666	)	$	26.00
Outstanding at December 31, 2017	7,600		$	18.49	0.00	$	—

Vested and Expected to vest at December 31, 2017	7,600		$	18.49	0.00	$	—

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]



	2015
Grant-date fair value	$	4.24
Expected volatility	36.0		%
Expected dividend yield	5.9		%
Expected term (in years)	3.0
Risk-free rate	0.99		%

Schedule of phantom units activity

The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2017.



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2016	21,048		$	16.23
Granted	116,567		$	17.09
Vested	(32,176	)	$	16.49
Unvested at December 31, 2017	105,439		$	17.10

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of Amendments to Corporate Office Leases [Table Text Block]

The following table contains amendments made to lease additional office space in the Midland corporate office during the years ended December 31, 2016 and 2015:



Date of Amendments	Rent for Additional Space	Approx. Annual Increase of Monthly Base Rent
2^nd quarter 2014	$27,000	N/A
4^th quarter 2014	$53,000	4%
April 2015	$23,000	N/A
June 2015	$22,000	2%

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

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, 2017, 2016 and 2015 are as follows:



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Current income tax provision (benefit):
Federal	$	—		$	—		$	(33	)
State	999			192			268
Total current income tax provision	999			192			235
Deferred income tax provision (benefit):
Federal	(21,720		)	(579		)	(198,729		)
State	1,153			579			(2,816		)
Total deferred income tax provision (benefit)	(20,567		)	—			(201,545		)
Total provision for (benefit from) income taxes	$	(19,568	)	$	192		$	(201,310	)

Reconciliation of Statutory Federal Income Tax Amount to Recorded Expense

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



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Income tax expense (benefit) at the federal statutory rate (35%)	$	174,016		$	(57,694	)	$	(263,179	)
Impact of nontaxable noncontrolling interest	(12,073		)	—			—
Income tax benefit relating to change in statutory tax rate	(67,938		)	—			(1,145		)
State income tax expense (benefit), net of federal tax effect	3,413			770			(2,548		)
Non-deductible compensation	13,492			3,990			1,354
Change in valuation allowance	(127,485		)	53,336			61,056
Other, net	(2,993		)	(210		)	3,152
Provision for (benefit from) income taxes	$	(19,568	)	$	192		$	(201,310	)

Schedule of Deferred Tax Assets and Liabilities

The components of the Company’s deferred tax assets and liabilities as of December 31, 2017 and 2016 are as follows:



	December 31,
	2017			2016
	(In thousands)
Current:
Deferred tax assets
Derivative instruments	$	—		$	7,771
Other	—			3,518
Current deferred tax assets	—			11,289
Valuation allowance	—			(11,289		)
Current deferred tax assets, net of valuation allowance	—			—
Deferred tax liabilities
Derivative instruments	—			—
Total current deferred tax liabilities	—			—
Net current deferred tax assets	—			—
Noncurrent:
Deferred tax assets
Net operating loss carryforwards (subject to 20 year expiration)	74,997			139,065
Derivative instruments	22,918			—
Stock based compensation	942			6,234
Other	2,464			—
Noncurrent deferred tax assets	101,321			145,299
Valuation allowance	(104		)	(103,112		)
Noncurrent deferred tax assets, net of valuation allowance	101,217			42,187
Deferred tax liabilities
Oil and natural gas properties and equipment	202,997			42,187
Midstream assets	6,268			—
Total noncurrent deferred tax liabilities	209,265			42,187
Net noncurrent deferred tax liabilities	108,048			—
Net deferred tax liabilities	$	108,048		$	—

Derivatives (Tables)

12 Months Ended

Dec. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivative instruments



	2018			2019
	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)		Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI	9,761,000	$	51.10	1,095,000	$	49.82
Oil Swaps - BRENT	1,830,000	$	54.89	0	$	—
Oil Basis Swaps	5,475,000	$	0.88	0	$	—
Natural Gas Swaps	7,750,000	$	3.14	0	$	—



	Floor			Ceiling
	Volume (Bbls)	Fixed Price (per Bbl)		Volume (Bbls)	Fixed Price (per Bbl)
January 2018 - March 2018
Costless Collars	540,000	$	47.00	270,000	$	56.34



	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
July 2018 - December 2018
Oil Swaps - WTI	184,000	$	60.70
January 2019 - March 2019
Oil Swaps - WTI	90,000	$	58.70

Schedule of netting offsets of derivative assets and liabilities



	December 31,
	2017		2016
	(in thousands)
Gross amounts of assets presented in the Consolidated Balance Sheet	$	531	$	709
Net amounts of assets presented in the Consolidated Balance Sheet	531		709

Gross amounts of liabilities presented in the Consolidated Balance Sheet	106,670		22,608
Net amounts of liabilities presented in the Consolidated Balance Sheet	$	106,670	$	22,608

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,
	2017		2016
	(in thousands)
Current assets: derivative instruments	$	531	$	—
Noncurrent assets: derivative instruments	—		709
Total assets	$	531	$	709
Current liabilities: derivative instruments	$	100,367	$	22,608
Noncurrent liabilities: derivative instruments	6,303		—
Total liabilities	$	106,670	$	22,608

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 consolidated statements of operations:



	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Change in fair value of open non-hedge derivative instruments	$	(84,240	)	$	(26,522	)	$	(112,918	)
Gain on settlement of non-hedge derivative instruments	6,728			1,177			144,869
Gain (loss) on derivative instruments	$	(77,512	)	$	(25,345	)	$	31,951

- 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=84234895&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=84234895&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=84234895&loc=d3e41620-113959

Reference 10: 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, 2017

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, 2017 and 2016.



	December 31,
	2017			2016
	(in thousands)
Fixed price swaps:
Quoted prices in active markets level 1	$	—		$	—
Significant other observable inputs level 2	(106,139		)	23,317
Significant unobservable inputs level 3	—			—
Total	$	(106,139	)	$	23,317

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 consolidated balance sheets.



	December 31, 2017				December 31, 2016
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
	(in thousands)
Debt:
Revolving credit facility	$	397,000	$	397,000	$	—	$	—
4.750% Senior Notes due 2024	500,000		501,855		500,000		491,250
5.375% Senior Notes due 2025	500,000		515,000		500,000		502,850
Partnership revolving credit facility	93,500		93,500		120,500		120,500

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

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, 2017:



Year Ending December 31,	Drilling Rig Commitments		Office and Equipment Leases
	(in thousands)
2018	$	21,882	$	3,581
2019	10,082		3,307
2020	—		2,927
2021	—		2,406
2022	—		2,242
Thereafter	—		7,973
Total	$	31,964	$	22,436

Schedule of rent expense

The following table presents rent expense for the years ended December 31, 2017, 2016 and 2015.



	Year ended December 31,
	2017		2016		2015
	(in thousands)
Rent Expense	$	2,412	$	1,961	$	1,449

Subsequent Events Subsequent Events (Tables)

12 Months Ended

Dec. 31, 2017

Subsequent Events [Abstract]

Schedule of derivative instruments



	2018			2019
	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)		Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI	9,761,000	$	51.10	1,095,000	$	49.82
Oil Swaps - BRENT	1,830,000	$	54.89	0	$	—
Oil Basis Swaps	5,475,000	$	0.88	0	$	—
Natural Gas Swaps	7,750,000	$	3.14	0	$	—



	Floor			Ceiling
	Volume (Bbls)	Fixed Price (per Bbl)		Volume (Bbls)	Fixed Price (per Bbl)
January 2018 - March 2018
Costless Collars	540,000	$	47.00	270,000	$	56.34



	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
July 2018 - December 2018
Oil Swaps - WTI	184,000	$	60.70
January 2019 - March 2019
Oil Swaps - WTI	90,000	$	58.70

- Definition

+ References

+ Details

Guarantor Financial Statements (Tables)

12 Months Ended

Dec. 31, 2017

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Condensed Consolidated Balance Sheet



Condensed Consolidated Balance Sheet
December 31, 2017
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	54,074	$	34,175		$	24,197		$	—		$	112,446
Accounts receivable	—		205,859			25,754			—			231,613
Accounts receivable - related party	—		—			5,142			(5,142		)	—
Intercompany receivable	2,624,810		2,267,308			—			(4,892,118		)	—
Inventories	—		9,108			—			—			9,108
Other current assets	618		4,461			355			—			5,434
Total current assets	2,679,502		2,520,911			55,448			(4,897,260		)	358,601
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	—		8,129,211			1,103,897			(414		)	9,232,694
Midstream assets	—		191,519			—			—			191,519
Other property, equipment and land	—		80,776			—			—			80,776
Accumulated depletion, depreciation, amortization and impairment	—		(1,976,248		)	(189,466		)	4,342			(2,161,372		)
Net property and equipment	—		6,425,258			914,431			3,928			7,343,617
Funds held in escrow	—		—			6,304			—			6,304
Derivative instruments	—		—			—			—			—
Investment in subsidiaries	3,809,557		—			—			(3,809,557		)	—
Other assets	—		25,609			36,854			—			62,463
Total assets	$	6,489,059	$	8,971,778		$	1,013,037		$	(8,702,889	)	$	7,770,985
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	1	$	91,629		$	2,960		$	—		$	94,590
Intercompany payable	132,067		4,765,193			—			(4,897,260		)	—
Other current liabilities	7,236		472,933			2,669			—			482,838
Total current liabilities	139,304		5,329,755			5,629			(4,897,260		)	577,428
Long-term debt	986,847		397,000			93,500			—			1,477,347
Derivative instruments	—		6,303			—			—			6,303
Asset retirement obligations	—		20,122			—			—			20,122
Deferred income taxes	108,048		—			—			—			108,048
Total liabilities	1,234,199		5,753,180			99,129			(4,897,260		)	2,189,248
Commitments and contingencies
Stockholders’ equity	5,254,860		3,218,598			913,908			(4,132,506		)	5,254,860
Non-controlling interest	—		—			—			326,877			326,877
Total equity	5,254,860		3,218,598			913,908			(3,805,629		)	5,581,737
Total liabilities and equity	$	6,489,059	$	8,971,778		$	1,013,037		$	(8,702,889	)	$	7,770,985



Condensed Consolidated Balance Sheet
December 31, 2016
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	1,643,226		$	14,135		$	9,213		$	—		$	1,666,574
Restricted cash	—			—			500			—			500
Accounts receivable	—			109,782			10,043			—			119,825
Accounts receivable - related party	—			297			3,470			(3,470		)	297
Intercompany receivable	3,060,566			359,502			—			(3,420,068		)	—
Inventories	—			1,983			—			—			1,983
Other current assets	481			2,319			187			—			2,987
Total current assets	4,704,273			488,018			23,413			(3,423,538		)	1,792,166
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	—			4,400,002			760,818			(559		)	5,160,261
Midstream assets	—			8,362			—			—			8,362
Other property, equipment and land	—			58,290			—			—			58,290
Accumulated depletion, depreciation, amortization and impairment	—			(1,695,701		)	(148,948		)	8,593			(1,836,056		)
Net property and equipment	—			2,770,953			611,870			8,034			3,390,857
Funds held in escrow	—			121,391			—			—			121,391
Derivative instruments	—			709			—			—			709
Investment in subsidiaries	(15,500		)	—			—			15,500			—
Other assets	—			9,291			35,266			—			44,557
Total assets	$	4,688,773		$	3,390,362		$	670,549		$	(3,400,004	)	$	5,349,680
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	30		$	45,838		$	1,780		$	—		$	47,648
Accounts payable-related party	1			—			—			—			1
Intercompany payable	—			3,423,538			—			(3,423,538		)	—
Other current liabilities	5,868			155,454			371			—			161,693
Total current liabilities	5,899			3,624,830			2,151			(3,423,538		)	209,342
Long-term debt	985,412			—			120,500			—			1,105,912
Asset retirement obligations	—			16,134			—			—			16,134
Total liabilities	991,311			3,640,964			122,651			(3,423,538		)	1,331,388
Commitments and contingencies
Stockholders’ equity	3,697,462			(250,602		)	547,898			(297,296		)	3,697,462
Non-controlling interest	—			—			—			320,830			320,830
Total equity	3,697,462			(250,602		)	547,898			23,534			4,018,292
Total liabilities and equity	$	4,688,773		$	3,390,362		$	670,549		$	(3,400,004	)	$	5,349,680

Condensed Consolidated Statement of Operations



Condensed Consolidated Statement of Operations
Year Ended December 31, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	903,842		$	—		$	140,175		$	1,044,017
Natural gas sales	—			42,899			—			9,311			52,210
Natural gas liquid sales	—			79,371			—			10,677			90,048
Royalty income	—			—			160,163			(160,163		)	—
Lease bonus income	—			—			11,870			(106		)	11,764
Midstream services	—			7,072			—			—			7,072
Total revenues	—			1,033,184			172,033			(106		)	1,205,111
Costs and expenses:
Lease operating expenses	—			126,524			—			—			126,524
Production and ad valorem taxes	—			62,897			10,608			—			73,505
Gathering and transportation	—			12,045			789			—			12,834
Midstream services	—			10,409			—			—			10,409
Depreciation, depletion and amortization	—			281,989			40,519			4,251			326,759
General and administrative expenses	26,776			18,057			6,296			(2,460		)	48,669
Asset retirement obligation accretion	—			1,391			—			—			1,391
Total costs and expenses	26,776			513,312			58,212			1,791			600,091
Income (loss) from operations	(26,776		)	519,872			113,821			(1,897		)	605,020
Other income (expense)
Interest expense, net	(29,925		)	(7,465		)	(3,164		)	—			(40,554		)
Other income, net	1,142			10,732			821			(2,460		)	10,235
Loss on derivative instruments, net	—			(77,512		)	—			—			(77,512		)
Total other expense, net	(28,783		)	(74,245		)	(2,343		)	(2,460		)	(107,831		)
Income (loss) before income taxes	(55,559		)	445,627			111,478			(4,357		)	497,189
Benefit from income taxes	(19,568		)	—			—			—			(19,568		)
Net income (loss)	(35,991		)	445,627			111,478			(4,357		)	516,757
Net income attributable to non-controlling interest	—			—			—			34,496			34,496
Net income (loss) attributable to Diamondback Energy, Inc.	$	(35,991	)	$	445,627		$	111,478		$	(38,853	)	$	482,261



Condensed Consolidated Statement of Operations
Year Ended December 31, 2016
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	399,007		$	—		$	71,521		$	470,528
Natural gas sales	—			19,399			—			3,107			22,506
Natural gas liquid sales	—			29,864			—			4,209			34,073
Royalty income	—			—			78,837			(78,837		)	—
Lease bonus income	—			—			309			(309		)	—
Total revenues	—			448,270			79,146			(309		)	527,107
Costs and expenses:
Lease operating expenses	—			82,428			—			—			82,428
Production and ad valorem taxes	—			28,912			5,544			—			34,456
Gathering and transportation	—			11,189			415			2			11,606
Depreciation, depletion and amortization	—			151,376			29,820			(3,181		)	178,015
Impairment of oil and natural gas properties	—			198,067			47,469			—			245,536
General and administrative expenses	25,959			11,451			5,209			—			42,619
Asset retirement obligation accretion	—			1,064			—			—			1,064
Total costs and expenses	25,959			484,487			88,457			(3,179		)	595,724
Income (loss) from operations	(25,959		)	(36,217		)	(9,311		)	2,870			(68,617		)
Other income (expense)
Interest expense, net	(35,318		)	(2,911		)	(2,455		)	—			(40,684		)
Other income, net	437			2,010			867			(250		)	3,064
Loss on derivative instruments, net	—			(25,345		)	—			—			(25,345		)
Loss on extinguishment of debt	(33,134		)	—			—			—			(33,134		)
Total other expense, net	(68,015		)	(26,246		)	(1,588		)	(250		)	(96,099		)
Income (loss) before income taxes	(93,974		)	(62,463		)	(10,899		)	2,620			(164,716		)
Provision for income taxes	192			—			—			—			192
Net income (loss)	(94,166		)	(62,463		)	(10,899		)	2,620			(164,908		)
Net income attributable to non-controlling interest	—			—			—			126			126
Net income (loss) attributable to Diamondback Energy, Inc.	$	(94,166	)	$	(62,463	)	$	(10,899	)	$	2,494		$	(165,034	)



Condensed Consolidated Statement of Operations
Year Ended December 31, 2015
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	336,106		$	—		$	69,609		$	405,715
Natural gas sales	—			16,932			—			2,660			19,592
Natural gas liquid sales	—			18,836			—			2,590			21,426
Royalty income	—			—			74,859			(74,859		)	—
Total revenues	—			371,874			74,859			—			446,733
Costs and expenses:
Lease operating expenses	—			82,625			—			—			82,625
Production and ad valorem taxes	—			27,459			5,531			—			32,990
Gathering and transportation	—			5,832			259			—			6,091
Depreciation, depletion and amortization	—			182,395			35,436			(134		)	217,697
Impairment of oil and natural gas properties	—			814,798			3,423			(3,423		)	814,798
General and administrative expenses	17,077			9,056			5,835			—			31,968
Asset retirement obligation accretion expense	—			833			—			—			833
Total costs and expenses	17,077			1,122,998			50,484			(3,557		)	1,187,002
Income (loss) from operations	(17,077		)	(751,124		)	24,375			3,557			(740,269		)
Other income (expense)
Interest expense, net	(35,651		)	(4,749		)	(1,110		)	—			(41,510		)
Other income, net	1			(427		)	1,154			—			728
Gain on derivative instruments, net	—			31,951			—			—			31,951
Total other expense, net	(35,650		)	26,775			44			—			(8,831		)
Income (loss) before income taxes	(52,727		)	(724,349		)	24,419			3,557			(749,100		)
Benefit from income taxes	(201,310		)	—			—			—			(201,310		)
Net income (loss)	$	148,583		$	(724,349	)	$	24,419		$	3,557		$	(547,790	)
Net income attributable to non-controlling interest	$	—		$	—		$	—		$	2,838		$	2,838
Net income (loss) attributable to Diamondback Energy, Inc.	$	148,583		$	(724,349	)	$	24,419		$	719		$	(550,628	)

Condensed Consolidated Statement of Cash Flows



Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(29,470	)	$	778,876		$	139,219		$	—		$	888,625
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(792,599		)	—			—			(792,599		)
Additions to midstream assets	—			(68,139		)	—			—			(68,139		)
Purchase of other property, equipment and land	—			(22,779		)	—			—			(22,779		)
Acquisition of leasehold interests	—			(1,960,591		)	—			—			(1,960,591		)
Acquisition of mineral interests	—			(63,371		)	(344,079		)	—			(407,450		)
Acquisition of midstream assets	—			(50,279		)	—			—			(50,279		)
Proceeds from sale of assets	—			65,656			—			—			65,656
Funds held in escrow	—			104,087			—			—			104,087
Equity investments	—			(188		)	—			—			(188		)
Intercompany transfers	(1,631,078		)	1,631,078			—			—			—
Net cash used in investing activities	(1,631,078		)	(1,157,125		)	(344,079		)	—			(3,132,282		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			475,000			278,500			—			753,500
Repayment on credit facility	—			(78,000		)	(305,500		)	—			(383,500		)
Purchase of subsidiary units by parent	(10,068		)	—			—			10,068			—
Debt issuance costs	(8,326		)	1,289			(2,259		)	—			(9,296		)
Public offering costs	(77		)	—			(433		)	—			(510		)
Proceeds from public offerings	—			—			380,412			(10,068		)	370,344
Distribution from subsidiary	89,509			—			—			(89,509		)	—
Exercise of stock options	358			—			—			—			358
Distribution to non-controlling interest	—			—			(130,876		)	89,509			(41,367		)
Net cash provided by financing activities	71,396			398,289			219,844			—			689,529
Net increase (decrease) in cash and cash equivalents	(1,589,152		)	20,040			14,984			—			(1,554,128		)
Cash and cash equivalents at beginning of period	1,643,226			14,135			9,213			—			1,666,574
Cash and cash equivalents at end of period	$	54,074		$	34,175		$	24,197		$	—		$	112,446



Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2016
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(39,894	)	$	303,347		$	68,627		$	—		$	332,080
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(363,087		)	—			—			(363,087		)
Additions to midstream assets	—			(1,188		)	—			—			(1,188		)
Purchase of other property, equipment and land	—			(9,891		)	—			—			(9,891		)
Acquisition of leasehold interests	—			(611,280		)	—			—			(611,280		)
Acquisition of mineral interests	—			—			(205,721		)	—			(205,721		)
Proceeds from sale of assets	—			4,661			—			—			4,661
Funds held in escrow	—			(121,391		)	—			—			(121,391		)
Equity investments	—			(2,345		)	—			—			(2,345		)
Intercompany transfers	(796,053		)	796,053			—			—			—
Net cash used in investing activities	(796,053		)	(308,468		)	(205,721		)	—			(1,310,242		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			—			164,000			—			164,000
Repayment on credit facility	—			(11,000		)	(78,000		)	—			(89,000		)
Proceeds from senior notes	1,000,000			—			—			—			1,000,000
Repayment of senior notes	(450,000		)	—			—			—			(450,000		)
Premium on extinguishment of debt	(26,561		)	—			—			—			(26,561		)
Debt issuance costs	(14,449		)	(172		)	(442		)	—			(15,063		)
Public offering costs	(636		)	—			(546		)	—			(1,182		)
Proceeds from public offerings	1,925,923			—			125,580			—			2,051,503
Distribution from subsidiary	55,250			—			—			(55,250		)	—
Exercise of stock options	498			—			—			—			498
Distribution to non-controlling interest	—			—			(64,824		)	55,250			(9,574		)
Intercompany transfers	(11,000		)	11,000			—			—			—
Net cash provided by (used in) financing activities	2,479,025			(172		)	145,768			—			2,624,621
Net increase (decrease) in cash and cash equivalents	1,643,078			(5,293		)	8,674			—			1,646,459
Cash and cash equivalents at beginning of period	148			19,428			539			—			20,115
Cash and cash equivalents at end of period	$	1,643,226		$	14,135		$	9,213		$	—		$	1,666,574



Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2015
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(37,597	)	$	390,266		$	63,832		$	—		$	416,501
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(419,512		)	—			—			(419,512		)
Purchase of other property, equipment and land	—			(1,213		)	—			—			(1,213		)
Acquisition of leasehold interests	—			(437,455		)	—			—			(437,455		)
Acquisition of royalty interests	—			—			(43,907		)	—			(43,907		)
Proceeds from sale of assets	—			9,739			—			—			9,739
Equity investments	—			(2,702		)	—			—			(2,702		)
Intercompany transfers	(145,023		)	145,023			—			—			—
Net cash used in investing activities	(145,023		)	(706,120		)	(43,907		)	—			(895,050		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			390,501			34,500			—			425,001
Repayment on credit facility	—			(603,001		)	—			—			(603,001		)
Debt issuance costs	—			(85		)	(441		)	—			(526		)
Public offering costs	(586		)	—			—			—			(586		)
Proceeds from public offerings	650,688			—			—			—			650,688
Distribution from subsidiary	60,587			—			—			(60,587		)	—
Exercise of stock options	4,873			—			—			—			4,873
Distribution to non-controlling interest	—			—			(68,555		)	60,587			(7,968		)
Intercompany transfers	(532,800		)	532,800			—			—			—
Net cash provided by (used in) financing activities	182,762			320,215			(34,496		)	—			468,481
Net increase (decrease) in cash and cash equivalents	142			4,361			(14,571		)	—			(10,068		)
Cash and cash equivalents at beginning of period	6			15,067			15,110			—			30,183
Cash and cash equivalents at end of period	$	148		$	19,428		$	539		$	—		$	20,115

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

12 Months Ended

Dec. 31, 2017

Oil and Gas Exploration and Production Industries Disclosures [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,
	2017			2016
	(In thousands)
Oil and Natural Gas Properties:
Proved properties	$	5,126,829		$	3,429,742
Unproved properties	4,105,865			1,730,519
Total oil and natural gas properties	9,232,694			5,160,261
Accumulated depreciation, depletion, amortization	(1,009,893		)	(687,685		)
Accumulated impairment	(1,143,498		)	(1,143,498		)
Net oil and natural gas properties capitalized	$	7,079,303		$	3,329,078

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,
	2017		2016		2015
	(In thousands)
Acquisition costs
Proved properties	$	452,661	$	72,044	$	64,340
Unproved properties	2,692,000		752,117		448,638
Development costs	145,362		47,575		42,749
Exploration costs	779,728		329,122		319,102
Capitalized asset retirement costs	2,682		4,030		3,458
Total	$	4,072,433	$	1,204,888	$	878,287

Results of operations from oil and natural gas producing activities



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Oil, natural gas and natural gas liquid sales	$	1,186,275		$	527,107		$	446,733
Lease operating expenses	(126,524		)	(82,428		)	(82,625		)
Production and ad valorem taxes	(73,505		)	(34,456		)	(32,990		)
Gathering and transportation	(12,834		)	(11,606		)	(6,091		)
Depreciation, depletion, and amortization	(321,870		)	(176,369		)	(216,056		)
Impairment	—			(245,536		)	(814,798		)
Asset retirement obligation accretion expense	(1,391		)	(1,064		)	(833		)
Income tax benefit (expense)	19,568			(192		)	201,310
Results of operations	$	669,719		$	(24,544	)	$	(505,350	)

Schedule of changes in estimated proved reserves

The changes in estimated proved reserves are as follows:



	Oil (MBbls)		Natural Gas Liquids (MBbls)		Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves:
As of January 1, 2015	75,690		18,542		111,605
Extensions and discoveries	48,725		12,056		53,453
Revisions of previous estimates	(12,130	)	(4,081	)	(14,726	)
Purchase of reserves in place	2,775		1,165		7,102
Production	(9,081	)	(1,678	)	(7,931	)
As of December 31, 2015	105,979		26,004		149,503
Extensions and discoveries	55,069		13,962		64,758
Revisions of previous estimates	(12,483	)	(1,888	)	(34,519	)
Purchase of reserves in place	2,537		1,455		7,567
Divestitures	(366	)	—		(1,985	)
Production	(11,562	)	(2,399	)	(10,428	)
As of December 31, 2016	139,174		37,134		174,896
Extensions and discoveries	99,980		20,825		109,032
Revisions of previous estimates	(7,715	)	(1,466	)	(10,065	)
Purchase of reserves in place	24,322		2,633		34,640
Divestitures	(1,163	)	(461	)	(2,474	)
Production	(21,417	)	(4,056	)	(20,660	)
As of December 31, 2017	233,181		54,609		285,369

Proved Developed Reserves:
January 1, 2015	43,886		11,221		68,264
December 31, 2015	60,569		15,418		96,871
December 31, 2016	79,457		22,080		105,399
December 31, 2017	141,246		35,412		190,740

Proved Undeveloped Reserves:
January 1, 2015	31,804		7,321		43,341
December 31, 2015	45,409		10,586		52,632
December 31, 2016	59,717		15,054		69,497
December 31, 2017	91,935		19,198		94,629

The following table includes the changes in PUD reserves for 2017:



	(MBOE)
Beginning proved undeveloped reserves at December 31, 2016	86,354
Undeveloped reserves transferred to developed	(31,666	)
Revisions	(4,710	)
Net purchases	6,246
Extensions and discoveries	70,680
Ending proved undeveloped reserves at December 31, 2017	126,904

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, 2017, 2016 and 2015.



	December 31,
	2017			2016			2015
	(In thousands)
Future cash inflows	$	12,921,897		$	6,275,705		$	5,377,783
Future development costs	(1,123,979		)	(617,636		)	(548,239		)
Future production costs	(2,994,877		)	(1,392,852		)	(1,279,101		)
Future production taxes	(928,891		)	(459,244		)	(363,129		)
Future income tax expenses	(83,961		)	(75,595		)	(28,233		)
Future net cash flows	7,790,189			3,730,378			3,159,081
10% discount to reflect timing of cash flows	(4,033,130		)	(2,018,965		)	(1,740,948		)
Standardized measure of discounted future net cash flows	$	3,757,059		$	1,711,413		$	1,418,133

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,
	2017		2016		2015
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	48.03	$	39.94	$	45.07
Natural gas (per Mcf)	$	2.06	$	1.36	$	1.83
Natural gas liquids (per Bbl)	$	20.79	$	12.91	$	12.56

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,
	2017			2016			2015
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	1,711,413		$	1,418,133		$	2,045,224
Sales of oil and natural gas, net of production costs	(986,246		)	(411,558		)	(331,119		)
Acquisition of reserves	439,396			43,142			58,849
Divestiture of reserves	(11,072		)	(5,481		)	(1,490		)
Extensions and discoveries, net of future development costs	1,791,686			779,359			629,149
Previously estimated development costs incurred during the period	190,121			85,696			129,901
Net changes in prices and production costs	577,781			(150,509		)	(1,383,698		)
Changes in estimated future development costs	(52,908		)	20,647			38,638
Revisions of previous quantity estimates	(98,857		)	(123,795		)	(377,160		)
Accretion of discount	174,185			143,134			236,716
Net change in income taxes	(9,074		)	(30,530		)	268,963
Net changes in timing of production and other	30,634			(56,825		)	104,160
Standardized measure of discounted future net cash flows at the end of the period	$	3,757,059		$	1,711,413		$	1,418,133

- 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=68064819&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=68064819&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=68064819&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=82851474&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=68064819&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=68064819&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=68064819&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=68064819&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=34713648&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, 2017

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Data

The Company’s unaudited quarterly financial data for 2017 and 2016 is summarized below.



	2017
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	235,230		$	269,434		$	301,253		$	399,194
Income from operations	116,410			132,308			142,639			213,663
Income tax expense (benefit)	1,957			1,579			857			(23,961		)
Net income	141,074			164,128			81,948			129,607
Net income attributable to non-controlling interest	4,801			5,723			8,924			15,048
Net income attributable to Diamondback Energy, Inc.	$	136,273		$	158,405		$	73,024		$	114,559
Earnings per common share
Basic	$	1.46		$	1.61		$	0.74		$	1.17
Diluted	$	1.46		$	1.61		$	0.74		$	1.16

	2016
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
Revenues	$	87,481		$	112,483		$	142,131		$	185,012
Income (loss) from operations	(27,603		)	(134,786		)	6,693			87,079
Income tax expense (benefit)	—			368			—			(176		)
Net income (loss)	(35,627		)	(157,121		)	(600		)	28,440
Net income (loss) attributable to non-controlling interest	(2,715		)	(1,631		)	1,630			2,842
Net income (loss) attributable to Diamondback Energy, Inc.	$	(32,912	)	$	(155,490	)	$	(2,230	)	$	25,598
Earnings per common share
Basic	$	(0.46	)	$	(2.17	)	$	(0.03	)	$	0.32
Diluted	$	(0.46	)	$	(2.17	)	$	(0.03	)	$	0.32

Description of the Business and Basis of Presentation (Details) - shares			1 Months Ended
	Sep. 19, 2014	Jun. 23, 2014	Jul. 31, 2017	Jan. 31, 2017	Aug. 31, 2016	Dec. 31, 2017	Aug. 01, 2016
Noncontrolling Interest [Line Items]
Interest in Viper Energy Partners LP			64.00%
Viper Energy Partners LP [Member]
Noncontrolling Interest [Line Items]
Interest in Viper Energy Partners LP	88.00%	92.00%				64.00%
Viper Energy Partners LP [Member] \| IPO [Member]
Noncontrolling Interest [Line Items]
Units issued by Viper Energy Partners LP		5,750,000
Viper Energy Partners LP [Member] \| Follow-on Public Offering [Member]
Noncontrolling Interest [Line Items]
Units issued by Viper Energy Partners LP	3,500,000		16,100,000	9,775,000	8,050,000
Interest in Viper Energy Partners LP							83.00%
Viper Energy Partners LP [Member] \| Diamondback Energy, Inc. [Member]
Noncontrolling Interest [Line Items]
Exchange of membership interests for common units		70,450,000

Summary of Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 31, 2018	Dec. 31, 2014
Debt Instrument [Line Items]
Interest Costs Capitalized Adjustment	$ 22,097	$ 0	$ 0
Gas Balancing Asset (Liability)	0	0
Depreciation, Depletion and Amortization Excluding Amortization of Financing Costs	326,759	178,015	217,697
Escrow deposit	0	500			$ 500
Allowance for doubtful accounts	0	0
Impairment losses of long-lived assets	0	0	0
Interest costs capitalized		0
Equity method investment impairment	0	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
Senior Notes [Member]
Debt Instrument [Line Items]
Debt issuance costs	15,200	14,800
Debt issuance costs, accumulated amortization	2,000	200
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt issuance costs	16,700	8,200
Debt issuance costs, accumulated amortization	$ 7,000	$ 4,900
Subsequent Event [Member] \| Viper Energy Partners LP [Member]
Debt Instrument [Line Items]
Cost Method Investments				$ 15,200
Cost Method Investment, Value per Unit				$ 15.20

Summary of Significant Accounting Policies - Property and Equipment (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) $ / Boe	Dec. 31, 2016 USD ($) $ / Boe	Dec. 31, 2015 USD ($) $ / Boe
Property, Plant and Equipment [Line Items]
Depreciation, Depletion and Amortization Excluding Amortization of Financing Costs	$ 326,759	$ 178,015	$ 217,697
Impairment of oil and natural gas properties	$ 0	$ 245,536	$ 814,798
Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Average depletion rate per barrel equivalent unit of production \| $ / Boe	11.11	11.23	17.84
Depreciation, Depletion and Amortization Excluding Amortization of Financing Costs	$ 321,900	$ 176,400	$ 216,100
Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Depreciation, Depletion and Amortization Excluding Amortization of Financing Costs	$ 1,438	$ 1,394	$ 1,402
Oil and Gas Properties [Member] \| Minimum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life of property and equipment	3 years
Oil and Gas Properties [Member] \| Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful life of property and equipment	15 years

Summary of Significant Accounting Policies - Other Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Liability for drilling costs prepaid by joint interest partners	$ 30,320	$ 21,595
Interest payable	6,770	5,445
Lease operating expenses payable	27,850	13,857
Ad valorem taxes payable	3,306	776
Current portion of asset retirement obligations	1,163	1,288	$ 193
Other	23,103	12,369
Total other accrued liabilities	$ 92,512	$ 55,330

Summary of Significant Accounting Policies - Concentrations (Details) - Customer Concentration Risk [Member] - Sales Revenue, Net [Member]	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Shell Trading US Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	31.00%	45.00%	59.00%
Koch Supply & Trading LP [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	19.00%	15.00%
Enterprise Crude Oil LLC [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	11.00%	13.00%	15.00%

Acquisitions - 2017 Activity (Details) shares in Thousands, $ in Thousands		12 Months Ended
	Feb. 28, 2017 USD ($) a shares	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 01, 2016 a
Business Acquisition [Line Items]
Acquisition of leasehold interests		$ 1,960,591	$ 611,280	$ 437,455
Additions to midstream assets		$ 68,139	$ 1,188	$ 0
Delaware Basin Interests [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross	$ 1,740,000
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable \| shares	7,690
Shares Held in Escrow \| shares	1,150
Oil and Gas Area, Gross \| a	100,306				26,797
Oil and Gas Area, Net \| a	80,339				19,262
Acquisition of leasehold interests	$ 2,500,000
Additions to midstream assets	$ 47,600

Acquisitions - Estimated Fair Values of Assets Acquired and Liabilities Assumed (Details) - Delaware Basin Interests [Member] $ in Thousands	10 Months Ended
	Dec. 31, 2017 USD ($)
Business Acquisition [Line Items]
Proved oil and gas properties	$ 386,308
Unevaluated oil and natural gas properties	2,122,597
Midstream assets	47,432
Prepaid capital costs	3,460
Oil inventory	839
Equipment	163
Revenues and royalties payable	(9,650)
Asset retirement obligations	(1,550)
Total fair value of net assets	2,549,599
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	81,400
Business Combination, Pro Forma Information, Direct Operating Expenses since Acquisition Date, Actual	$ 23,500

Acquisitions - Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Revenues	$ 1,228,040	$ 627,301
Income (loss) from operations	619,369	(12,812)
Net income (loss)	$ 472,649	$ (109,229)
Basic earnings per common share	$ 4.85	$ (1.45)
Diluted earnings per common share	$ 4.84	$ (1.45)

Acquisitions - 2016 Activity (Details) - Delaware Basin Interests [Member] $ in Millions	Sep. 01, 2016 USD ($) a	Feb. 28, 2017 a
Business Acquisition [Line Items]
Business Combination, Consideration Transferred \| $	$ 558.5
Oil and Gas Area, Gross	26,797	100,306
Oil and Gas Area, Net	19,262	80,339

Acquisitions - 2015 Activity (Details) - Howard County, Texas [Member] $ in Millions		12 Months Ended
	Jul. 09, 2015 USD ($)	Dec. 31, 2015 USD ($) a
Business Acquisition [Line Items]
Gas and Oil Area, Developed, Gross \| a		16,940
Gas and Oil Area, Developed, Net \| a		12,672
Business Combination, Consideration Transferred \| $		$ 437.5
Viper Energy Partners LP [Member]
Business Acquisition [Line Items]
Oil and Gas Property, Percent of Royalty Interest Sold	1.50%
Proceeds from Sale of Oil and Gas Property and Equipment \| $	$ 31.1

Viper Energy Partners LP (Details) - USD ($) $ / shares in Units, $ in Thousands			1 Months Ended									12 Months Ended
	Sep. 19, 2014	Jun. 23, 2014	Jul. 31, 2017	Jan. 31, 2017	Dec. 31, 2016	Aug. 31, 2016	Jul. 31, 2016	Jan. 31, 2016	Aug. 31, 2015	May 31, 2015	Jan. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Aug. 01, 2016
Noncontrolling Interest [Line Items]
Interest in Viper Energy Partners LP			64.00%
Repayment under credit facility												$ 383,500	$ 89,000	$ 603,001
Follow-on Public Offering [Member]
Noncontrolling Interest [Line Items]
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions					$ 1,150,828		$ 551,777	$ 254,518	$ 197,628	$ 333,638	$ 119,422
Viper Energy Partners LP [Member]
Noncontrolling Interest [Line Items]
Interest in Viper Energy Partners LP	88.00%	92.00%										64.00%
Viper Energy Partners LP [Member] \| IPO [Member]
Noncontrolling Interest [Line Items]
Units issued by Viper Energy Partners LP		5,750,000
Noncontrolling owners' interest in Viper Energy Partners LP		8.00%
Price per common unit (in dollars per unit)		$ 26.00
Viper Energy Partners LP [Member] \| Follow-on Public Offering [Member]
Noncontrolling Interest [Line Items]
Interest in Viper Energy Partners LP															83.00%
Units issued by Viper Energy Partners LP	3,500,000		16,100,000	9,775,000		8,050,000
Price per common unit (in dollars per unit)															$ 15.6
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions			$ 232,500	$ 147,500		$ 125,000
Viper Energy Partners LP [Member] \| Over-Allotment Option [Member]
Noncontrolling Interest [Line Items]
Units issued by Viper Energy Partners LP			2,100,000	1,275,000		1,050,000
Viper Energy Partners LP [Member] \| Diamondback Energy, Inc. [Member]
Noncontrolling Interest [Line Items]
Exchange of membership interests for common units		70,450,000
Distribution Made to Limited Partner, Cash Distributions Paid												$ 89,500
Limited Partner [Member] \| Viper Energy Partners LP [Member] \| Diamondback Energy, Inc. [Member]
Noncontrolling Interest [Line Items]
Units issued by Viper Energy Partners LP						2,000,000
Partnership Credit Facility [Member]
Noncontrolling Interest [Line Items]
Repayment under credit facility			$ 152,800	$ 120,500
Diamondback Energy, Inc. [Member] \| Viper Energy Partners LP [Member] \| Over-Allotment Option [Member]
Noncontrolling Interest [Line Items]
Units issued by Viper Energy Partners LP			700,000
Affiliated Entity [Member] \| Viper Energy Partners LP [Member] \| Over-Allotment Option [Member]
Noncontrolling Interest [Line Items]
Units issued by Viper Energy Partners LP			3,000,000
Executive Officer [Member] \| Viper Energy Partners LP [Member] \| Over-Allotment Option [Member]
Noncontrolling Interest [Line Items]
Units issued by Viper Energy Partners LP			114,000

Property and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
Property and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Natural Gas Properties:
Subject to depletion	$ 5,126,829	$ 3,429,742
Not subject to depletion	4,105,865	1,730,519
Gross oil and natural gas properties	9,232,694	5,160,261
Accumulated impairment	(1,143,498)	(1,143,498)
Oil and natural gas properties, net	7,079,303	3,329,078
Midstream Assets	191,519	8,362
Other property, equipment and land	80,776	58,290
Accumulated depreciation	(2,161,372)	(1,836,056)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	7,343,617	3,390,857
Capitalized internal costs	21,978	17,183	$ 15,200
Impairment of oil and natural gas properties	0	245,536	814,798
Exploration costs or development costs not subject to depletion	26,040	0
Capitalized interest not subject to depletion	$ 22,097	0
Minimum [Member]
Oil and Natural Gas Properties:
Anticipated Timing of Inclusion of Costs in Amortization Calculation	3 years
Maximum [Member]
Oil and Natural Gas Properties:
Anticipated Timing of Inclusion of Costs in Amortization Calculation	5 years
Oil and Gas Properties [Member]
Oil and Natural Gas Properties:
Subject to depletion	$ 5,126,829	3,429,742
Not subject to depletion	4,105,865	1,730,519
Gross oil and natural gas properties	9,232,694	5,160,261
Accumulated impairment	(1,143,498)	(1,143,498)
Oil and natural gas properties, net	7,079,303	3,329,078
Accumulated depreciation	(1,009,893)	(687,685)
Balance of costs not subject to depletion:	2,746,936	727,411	$ 301,879	$ 316,455	$ 13,184
Other Property and Equipment, Net [Member]
Oil and Natural Gas Properties:
Other property, equipment and land	80,776	58,290
Accumulated depreciation	$ (7,981)	$ (4,873)

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes in ARO liability
Asset retirement obligations, beginning of period	$ 17,422	$ 12,711	$ 8,486
Additional liabilities incurred	1,526	637	594
Liabilities acquired	2,432	3,696	3,159
Liabilities settled	(1,555)	(711)	(292)
Accretion expense	1,391	1,064	833
Revisions in estimated liabilities	69	25	(69)
Asset retirement obligations, end of period	21,285	17,422	12,711
Less current portion	1,163	1,288	193
Asset retirement obligations - long-term	$ 20,122	$ 16,134	$ 12,518

Equity Method Investments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Oct. 31, 2014
Schedule of Equity Method Investments
Payment to acquire equity method investment	$ 188	$ 2,345	$ 2,702
Income (Loss) from Equity Method Investments	657	676	$ 0
HMW Fluid Management LLC [Member]
Schedule of Equity Method Investments
Ownership interest				25.00%
Payment to acquire equity method investment	188	2,345
Income (Loss) from Equity Method Investments	657	676
Equity Method Investments	$ 7,195	$ 6,349

Debt - Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Unamortized debt issuance costs	$ (13,153)	$ (14,588)
Total long-term debt	1,477,347	1,105,912
Senior Unsecured Notes due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	500,000	500,000
Senior Unsecured Notes due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	500,000	500,000
Company Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	397,000	0
Partnership Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 93,500	$ 120,500

Debt - Senior Notes (Details) - USD ($) $ in Millions	12 Months Ended
Debt - Senior Notes (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 20, 2016	Oct. 28, 2016
Senior Unsecured Notes due 2024 [Member]
Debt Instrument [Line Items]
Aggregate principal amount				$ 500.0
Stated interest rate	4.75%	4.75%		4.75%
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Unsecured Notes due 2024 [Member] \| Debt Instrument, Redemption, Period One [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	103.563%
Debt Instrument, Redemption Period, Start Date	Nov. 01, 2019
Debt Instrument, Redemption Period, End Date	Oct. 31, 2020
Senior Unsecured Notes due 2024 [Member] \| Debt Instrument, Redemption, Period Two [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	102.375%
Debt Instrument, Redemption Period, Start Date	Nov. 01, 2020
Debt Instrument, Redemption Period, End Date	Oct. 31, 2021
Senior Unsecured Notes due 2024 [Member] \| Debt Instrument, Redemption, Period Three [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	101.188%
Debt Instrument, Redemption Period, Start Date	Nov. 01, 2021
Debt Instrument, Redemption Period, End Date	Oct. 31, 2022
Senior Unsecured Notes due 2024 [Member] \| Debt Instrument, Redemption, Period Four [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%
Debt Instrument, Redemption Period, Start Date	Nov. 01, 2022
Senior Unsecured Notes due 2024 [Member] \| Debt Instrument, Redemption, Period Five [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	104.75%
Debt Instrument, Redemption Period, Start Date	Oct. 28, 2016
Debt Instrument, Redemption Period, End Date	Oct. 31, 2019
Senior Unsecured Notes due 2024 [Member] \| Debt Instrument, Redemption, Period Five [Member] \| Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	35.00%
Senior Unsecured Notes due 2025 [Member]
Debt Instrument [Line Items]
Aggregate principal amount			$ 500.0
Stated interest rate	5.375%	5.375%	5.375%
Debt Instrument, Redemption Price, Percentage	100.00%
Senior Unsecured Notes due 2025 [Member] \| Debt Instrument, Redemption, Period One [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	104.031%
Debt Instrument, Redemption Period, Start Date	May 31, 2020
Debt Instrument, Redemption Period, End Date	May 30, 2021
Senior Unsecured Notes due 2025 [Member] \| Debt Instrument, Redemption, Period Two [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	102.688%
Debt Instrument, Redemption Period, Start Date	May 31, 2021
Debt Instrument, Redemption Period, End Date	May 30, 2022
Senior Unsecured Notes due 2025 [Member] \| Debt Instrument, Redemption, Period Three [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	101.344%
Debt Instrument, Redemption Period, Start Date	May 31, 2022
Debt Instrument, Redemption Period, End Date	May 30, 2023
Senior Unsecured Notes due 2025 [Member] \| Debt Instrument, Redemption, Period Four [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	100.00%
Debt Instrument, Redemption Period, Start Date	May 31, 2023
Senior Unsecured Notes due 2025 [Member] \| Debt Instrument, Redemption, Period Five [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage	105.375%
Debt Instrument, Redemption Period, Start Date	Dec. 20, 2016
Debt Instrument, Redemption Period, End Date	May 30, 2020
Senior Unsecured Notes due 2025 [Member] \| Debt Instrument, Redemption, Period Five [Member] \| Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	35.00%

Debt - The Company's Credit Facility (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) redetermindation	Dec. 31, 2016 USD ($)
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Increase (Decrease)	0.25%
Company Credit Facility [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 5,000,000
Number of additional redeterminations that may be requested \| redetermindation	2
Period of Redeterminations	12 months
Current borrowing base	$ 1,800,000
Elected borrowing base	1,000,000
Outstanding borrowings	$ 397,000	$ 0
Financial covenant, reduction of borrowing base	25.00%
Company Credit Facility [Member] \| Minimum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.375%
Company Credit Facility [Member] \| Maximum [Member]
Line of Credit Facility [Line Items]
Ratio of total debt to EBITDAX	3
Quarterly commitment fee percentage based on unused portion of borrowing base	0.50%
Company Credit Facility [Member] \| Base Rate [Member] \| Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.25%
Company Credit Facility [Member] \| Base Rate [Member] \| Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.25%
Company Credit Facility [Member] \| Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
Company Credit Facility [Member] \| LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Company Credit Facility [Member] \| LIBOR [Member] \| Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.25%
Company Credit Facility [Member] \| LIBOR [Member] \| Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.25%

Debt - The Partnership's Credit Facility (Details) - Partnership Credit Facility [Member] $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2017 redetermindation	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Line of Credit Facility [Line Items]
Maximum borrowing capacity		$ 2,000,000
Number of additional redeterminations that may be requested \| redetermindation	3
Period of Redeterminations	12 months
Current borrowing base		400,000
Outstanding borrowings		93,500	$ 120,500
Remaining borrowing capacity		306,500
Financial covenant, maximum issuance of unsecured debt		$ 400,000
Financial covenant, reduction of borrowing base		25.00%
Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate		0.50%
LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.00%
Minimum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base		0.375%
Minimum [Member] \| Base Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate		0.75%
Minimum [Member] \| LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.75%
Maximum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base		0.50%
Maximum [Member] \| Base Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.75%
Maximum [Member] \| LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate		2.75%

Debt - Financial Covenant Table (Details)	Dec. 31, 2017
Maximum [Member] \| Company Credit Facility [Member]
Line of Credit Facility [Line Items]
Ratio of total debt to EBITDAX	3
Maximum [Member] \| Partnership Credit Facility [Member]
Line of Credit Facility [Line Items]
Ratio of total debt to EBITDAX	4
Minimum [Member] \| Company Credit Facility [Member]
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement	1.0
Minimum [Member] \| Partnership Credit Facility [Member]
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement	1.0

Debt - Interest Expense (Details) - USD ($) $ in Thousands	12 Months Ended
Debt - Interest Expense (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Disclosure [Abstract]
Interest expense	$ 60,671	$ 39,642	$ 40,221
Interest Costs Capitalized Adjustment	(22,097)	0	0
Other fees and expenses	2,160	1,426	1,292
Total interest expense	$ 40,734	$ 41,068	$ 41,513

Capital Stock and Earnings Per Share - Capital Stock (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended
	Dec. 31, 2016	Jul. 31, 2016	Jan. 31, 2016	Aug. 31, 2015	May 31, 2015	Jan. 31, 2015
Follow-on Public Offering [Member]
Class of Stock [Line Items]
Shares issued upon public offering	12,075,000	6,325,000	4,600,000	2,875,000	4,600,000	2,012,500
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions	$ 1,150,828	$ 551,777	$ 254,518	$ 197,628	$ 333,638	$ 119,422
Stock price per share at public offering (in dollars per share)	$ 95.3025	$ 87.24	$ 55.33	$ 68.74	$ 72.53	$ 59.34
Over-Allotment Option [Member]
Class of Stock [Line Items]
Shares issued upon public offering	1,575,000	825,000	600,000	375,000	600,000	262,500

Capital Stock and Earnings Per Share - Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Basic:
Net Income (loss) attributable to common stock	$ 114,559	$ 73,024	$ 158,405	$ 136,273	$ 25,598	$ (2,230)	$ (155,490)	$ (32,912)	$ 482,261	$ (165,034)	$ (550,628)
Weighted Average Number of Shares Outstanding, Basic									97,458,000	75,077,000	63,019,000
Net income attributable to common stock, basic, (in dollars per share)	$ 1.17	$ 0.74	$ 1.61	$ 1.46	$ 0.32	$ (0.03)	$ (2.17)	$ (0.46)	$ 4.95	$ (2.20)	$ (8.74)
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable (in shares)									230,000	0	0
Diluted:
Net income attributable to common stock, diluted (in shares)									97,688,000	75,077,000	63,019,000
Net income attributable to common stock, diluted (in dollars per share)	$ 1.16	$ 0.74	$ 1.61	$ 1.46	$ 0.32	$ (0.03)	$ (2.17)	$ (0.46)	$ 4.94	$ (2.20)	$ (8.74)
Antidilutive securities excluded from earnings per share (in shares)									45,690	243,654	100,924

Equity-Based Compensation - Schedule of Stock-Based Compensation Plans and Related Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$ 8,641	$ 7,079	$ 6,043
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Stock and equity based compensation	$ 25,537	$ 26,453	$ 18,529
Equity Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	2,500,000
Viper LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	9,070,356

Equity-Based Compensation - Stock/Unit Option Activity (Details) - Stock/Unit Options [Member] - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
	Jun. 17, 2014	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Equity Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period		5 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period		4 years
Number of Options (in shares)
Outstanding, beginning of period		15,750
Exercised		(15,750)
Outstanding, end of period		0	15,750
Weighted Average Exercise Price (in dollars per share)
Outstanding, beginning of period		$ 22.72
Exercised		22.72
Outstanding, end of period		$ 0.00	$ 22.72
Outstanding, period end, remaining term		0 years
Outstanding, period end, intrinsic value		$ 0
Options exercised, intrinsic value			$ 1,300	$ 15,700
Expected dividend yield		0.00%
Viper LTIP [Member]
Number of Options (in shares)
Outstanding, beginning of period		2,424,266
Forfeitures		(2,416,666)
Outstanding, end of period		7,600	2,424,266
Vested and expected to vest, at period end		7,600
Weighted Average Exercise Price (in dollars per share)
Outstanding, beginning of period		$ 26.00
Forfeitures		26.00
Outstanding, end of period		18.49	$ 26.00
Vested and expected to vest, period end		$ 18.49
Outstanding, period end, remaining term		0 years
Vested and expected to vest, period end, remaining term		0 years
Outstanding, period end, intrinsic value		$ 0
Vested and expected to vest, period end, intrinsic value		$ 0
Expected dividend yield				5.90%
Viper LTIP [Member] \| Executive Officers of General Partner [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross	2,500,000
Weighted Average Exercise Price (in dollars per share)
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	33.00%

Equity-Based Compensation - Restricted Stock (Details) - Equity Plan [Member] - USD ($) $ / shares in Units, $ in Millions	1 Months Ended			12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock Units (RSUs) [Member]
Awards & Units (in shares)
Unvested at beginning of period				206,004
Granted				188,438
Vested				(147,934)
Forfeited				(2,931)
Unvested at end of period				243,577	206,004
Weighted Average Grant-Date Fair Value (in dollars per share)
Unvested at beginning of period				$ 70.33
Granted				102.77
Vested				77.44
Forfeited				89.21
Unvested at end of period				$ 90.88	$ 70.33
Aggregate fair value of share-based awards that vested				$ 14.8	$ 12.5	$ 10.1
Unrecognized compensation cost related to unvested awards				$ 14.4
Unrecognized compensation cost, period of recognition				1 year 5 months 21 days
Performance Shares [Member]
Awards & Units (in shares)
Unvested at beginning of period				252,471
Granted			90,249	118,169
Vested				(168,314)
Unvested at end of period				202,326	252,471
Weighted Average Grant-Date Fair Value (in dollars per share)
Unvested at beginning of period				$ 103.06
Granted			$ 137.14	166.53
Vested				103.41
Unvested at end of period				$ 139.83	$ 103.06
Share Based Compensation Arrangement by Share Based Payment Maximum Award Potential				404,652
Unrecognized compensation cost related to unvested awards				$ 15.6
Unrecognized compensation cost, period of recognition				1 year 4 months 19 days
Minimum [Member] \| Performance Shares [Member]
Weighted Average Grant-Date Fair Value (in dollars per share)
Number of shares authorized to be awarded, percent of initial awards received	0.00%	0.00%	0.00%
Maximum [Member] \| Performance Shares [Member]
Weighted Average Grant-Date Fair Value (in dollars per share)
Number of shares authorized to be awarded, percent of initial awards received	200.00%	200.00%	200.00%
Share-based Compensation Award, Tranche One [Member] \| Performance Shares [Member]
Awards & Units (in shares)
Granted	37,440	174,325
Weighted Average Grant-Date Fair Value (in dollars per share)
Granted	$ 162.13	$ 103.41
Share-based Compensation Award, Tranche Two [Member] \| Performance Shares [Member]
Awards & Units (in shares)
Granted	74,880	87,163
Weighted Average Grant-Date Fair Value (in dollars per share)
Granted	$ 168.73	$ 102.35
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years

Equity-Based Compensation - Valuation Assumptions (Details) - $ / shares	1 Months Ended			12 Months Ended
	Feb. 28, 2017	Feb. 29, 2016	Feb. 28, 2015	Dec. 31, 2017	Dec. 31, 2015
Equity Plan [Member] \| Stock/Unit Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected dividend yield				0.00%
Equity Plan [Member] \| Performance Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value, performance restricted stock units (in dollars per share)			$ 137.14	$ 166.53
Expected volatility			43.36%
Risk-free rate			0.49%
Viper LTIP [Member] \| Stock/Unit Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value, stock/unit options (in dollars per share)					$ 4.24
Expected volatility					36.00%
Expected dividend yield					5.90%
Expected term (in years)					3 years
Risk-free rate					0.99%
Share-based Compensation Award, Tranche One [Member] \| Equity Plan [Member] \| Performance Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value, performance restricted stock units (in dollars per share)	$ 162.13	$ 103.41
Expected volatility	39.32%	41.91%
Risk-free rate	1.27%	0.86%
Share-based Compensation Award, Tranche Two [Member] \| Equity Plan [Member] \| Performance Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant-date fair value, performance restricted stock units (in dollars per share)	$ 168.73	$ 102.35
Expected volatility	41.14%	42.16%
Risk-free rate	1.59%	1.10%

Equity-Based Compensation - Phantom Units (Details) - Viper LTIP [Member] - Phantom Units [Member] $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) $ / shares shares
Awards & Units (in shares)
Unvested at beginning of period \| shares	21,048
Granted \| shares	116,567
Vested \| shares	(32,176)
Unvested at end of period \| shares	105,439
Weighted Average Grant-Date Fair Value (in dollars per share)
Unvested at beginning of period \| $ / shares	$ 16.23
Granted \| $ / shares	17.09
Vested \| $ / shares	16.49
Unvested at end of period \| $ / shares	$ 17.10
Aggregate fair value of share-based awards that vested \| $	$ 0.5
Unrecognized compensation cost related to unvested awards \| $	$ 1.3
Unrecognized compensation cost, period of recognition	1 year 4 months 17 days

Related Party Transactions (Details) - USD ($)	12 Months Ended
Related Party Transactions (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Oct. 17, 2012
Related Party Transaction
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		$ 2,198,000	$ 2,300,000
Related Party Transaction, Other Revenues from Transactions with Related Party		170,000	200,000
Wexford [Member]
Related Party Transaction
Affiliate Beneficial Ownership Percentage				44.00%
WT Commercial Portfolio, LLC [Member]
Related Party Transaction
Payments for Operating Activities		164,000	163,000
Viper Energy Partners LP [Member]
Related Party Transaction
Payments for Operating Activities	$ 100,000	300,000
Operating Leases [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party		3,300,000	200,000
Production and Ad Valorem Taxes [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party			200,000
Gathering and Transportation [Member]
Related Party Transaction
Related Party Transaction, Expenses from Transactions with Related Party			1,000,000
Advisory Services Agreement [Member] \| Wexford [Member]
Related Party Transaction
Payments for Operating Activities		500,000	500,000
Advisory Services Agreement [Member] \| Viper Energy Partners LP [Member] \| Wexford [Member]
Related Party Transaction
Payments for Operating Activities	$ 0	0	500,000
Bison Drilling and Field Services LLC [Member]
Related Party Transaction
Revenue from Related Parties		$ 182,000	$ 161,000
Maximum [Member] \| Wexford [Member]
Related Party Transaction
Affiliate Beneficial Ownership Percentage		1.00%

Related Party Transactions - Advisory Services Agreements (Details) - Advisory Services Agreement [Member] - Wexford [Member] - USD ($)			12 Months Ended
	Jun. 23, 2014	Oct. 11, 2012	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction
Advisory services agreement, annual fee		$ 500,000
Term of advisory services agreement		2 years
Renewal term of advisory services agreement		1 year
Minimum period for cancellation of additional one-year periods		10 days
Agreement termination, written notice period		30 days
Payments for Operating Activities				$ 500,000	$ 500,000
Viper Energy Partners LP [Member]
Related Party Transaction
Advisory services agreement, annual fee	$ 500,000
Term of advisory services agreement	2 years
Renewal term of advisory services agreement	1 year
Minimum period for cancellation of additional one-year periods	10 days
Agreement termination, written notice period	30 days
Payments for Operating Activities			$ 0	$ 0	$ 500,000

Related Party Transactions - Coronado Midstream (Details)	Feb. 28, 2015
Coronado Midstream [Member]
Related Party Transaction
Ownership interest	28.00%

Related Party Transactions - Midland Leases (Details) - USD ($)		1 Months Ended				3 Months Ended			12 Months Ended
	May 15, 2011	Jun. 30, 2016	Jun. 30, 2015	Apr. 30, 2015	Nov. 30, 2014	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017
WT Commercial Portfolio, LLC [Member]
Related Party Transaction
Payments for Operating Activities									$ 164,000	$ 163,000
Bison Drilling and Field Services LLC [Member]
Related Party Transaction
Revenue from Related Parties									$ 182,000	$ 161,000
Corporate Office Space [Member] \| Fasken [Member]
Related Party Transaction
Term of lease from related party	5 years				10 years
Operating Leases, Rent Expense, Minimum Rentals Monthly Base		$ 94,000				$ 53,000		$ 27,000
Operating Leases, Rent Expense, Minimum Rentals Monthly Additional Space				$ 23,000
Monthly rent for additional space			$ 22,000
Annual monthly rent increase		2.00%	2.00%			4.00%
Field Office Space [Member] \| Bison Drilling and Field Services LLC [Member]
Related Party Transaction
Annual monthly rent increase											3.00%
Operating Lease, Rent Expense, Sublease Rentals Monthly Base							$ 11,000

Related Party Transactions - Lease Bonus (Details) - Viper Energy Partners LP [Member]	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Related Party Transaction
Payments for Operating Activities	$ 100,000	$ 300,000
Number of leases extended	2	6
Average price per acre	$ 7,459	$ 1,371

Income Taxes - Components of Federal Income Tax (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Change in valuation allowance									$ (127,485)	$ 53,336	$ 61,056
Income tax benefit relating to change in statutory tax rate									(67,938)	0	(1,145)
Current income tax provision (benefit):
Federal									0	0	(33)
State									999	192	268
Total current income tax provision									999	192	235
Deferred income tax provision (benefit):
Federal									(21,720)	(579)	(198,729)
State									1,153	579	(2,816)
Total deferred income tax provision (benefit)									(20,567)	0	(201,545)
Total provision for (benefit from) income taxes	$ (23,961)	$ 857	$ 1,579	$ 1,957	$ (176)	$ 0	$ 368	$ 0	$ (19,568)	$ 192	$ (201,310)

Income Taxes - Reconciliation of Statutory Federal Income Tax (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent									35.00%	35.00%	35.00%
Income tax expense (benefit) at the federal statutory rate (35%)									$ 174,016	$ (57,694)	$ (263,179)
Impact of nontaxable noncontrolling interest									12,073	0	0
Income tax benefit relating to change in statutory tax rate									(67,938)	0	(1,145)
State income tax expense (benefit), net of federal tax effect									3,413	770	(2,548)
Non-deductible compensation									13,492	3,990	1,354
Change in valuation allowance									(127,485)	53,336	61,056
Other, net									(2,993)	(210)	3,152
Total provision for (benefit from) income taxes	$ (23,961)	$ 857	$ 1,579	$ 1,957	$ (176)	$ 0	$ 368	$ 0	$ (19,568)	$ 192	$ (201,310)

Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current deferred tax assets
Derivative instruments	$ 0	$ 7,771
Other	0	3,518
Current deferred tax assets	0	11,289
Valuation allowance	0	(11,289)
Current deferred tax assets, net of valuation allowance	0	0
Current deferred tax liabilities
Derivative instruments	0	0
Total current deferred tax liabilities	0	0
Net current deferred tax assets	0	0
Noncurrent deferred tax assets
Net operating loss carryforwards (subject to 20 year expiration)	74,997	139,065
Derivative instruments	22,918	0
Stock based compensation	942	6,234
Other	2,464	0
Noncurrent deferred tax assets	101,321	145,299
Valuation allowance	(104)	(103,112)
Noncurrent deferred tax assets, net of valuation allowance	101,217	42,187
Noncurrent deferred tax liabilities
Oil and natural gas properties and equipment	202,997	42,187
Amount of deferred tax liability attributable to taxable temporary differences from midstream assets	6,268	0
Total noncurrent deferred tax liabilities	209,265	42,187
Net noncurrent deferred tax liabilities	108,048	0
Net deferred tax liabilities	108,048	$ 0
Deferred Tax Assets, Valuation Allowance, Noncurrent	$ 100

Income Taxes Net Operating Loss (Details) $ in Millions	12 Months Ended
Income Taxes Net Operating Loss (Details) $ in Millions	Dec. 31, 2017 USD ($)
Deferred Tax Assets, Operating Loss Carryforwards, Subject to Expiration	$ 357.0
Minimum [Member]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2032
Maximum [Member]
Operating Loss Carryforwards, Expiration Date	Dec. 31, 2037

Derivatives - Open Derivative Positions (Details)	12 Months Ended
Derivatives - Open Derivative Positions (Details)	Dec. 31, 2017 MMBTU $ / MMBTU $ / bbl bbl
Costless Collars 2018 [Member]
Derivative [Line Items]
Derivative, Floor Price \| $ / bbl	47.00
Derivative, Cap Price \| $ / bbl	56.34
Oil Swaps 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl	9,761,000
Fixed Swap Price \| $ / bbl	51.10
Oil Swaps 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl	1,095,000
Fixed Swap Price \| $ / bbl	49.82
BRENT Oil Swaps 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl	1,830,000
Fixed Swap Price \| $ / bbl	54.89
BRENT Oil Swaps 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl	0
Fixed Swap Price \| $ / bbl	0.00
Oil Basis Swaps 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl	5,475,000
Fixed Swap Price \| $ / bbl	0.88
Oil Basis Swaps 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl	0
Fixed Swap Price \| $ / bbl	0.00
Natural Gas Swaps 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure \| MMBTU	7,750,000
Fixed Swap Price \| $ / MMBTU	3.14
Natural Gas Swaps 2019 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure \| MMBTU	0
Fixed Swap Price \| $ / MMBTU	0.00
Minimum [Member] \| Costless Collars 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl	540,000
Maximum [Member] \| Costless Collars 2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl	270,000

Derivatives - Offsetting Derivative Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross amounts of assets presented in the Consolidated Balance Sheet	$ 531	$ 709
Net amounts of assets presented in the Consolidated Balance Sheet	531	709
Gross amounts of liabilities presented in the Consolidated Balance Sheet	106,670	22,608
Net amounts of liabilities presented in the Consolidated Balance Sheet	$ 106,670	$ 22,608

Derivatives - Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current assets: derivative instruments	$ 531	$ 0
Noncurrent assets: derivative instruments	0	709
Total assets	531	709
Current liabilities: derivative instruments	100,367	22,608
Noncurrent liabilities: derivative instruments	6,303	0
Total liabilities	$ 106,670	$ 22,608

Derivatives - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Change in fair value of open non-hedge derivative instruments	$ (84,240)	$ (26,522)	$ (112,918)
Gain on settlement of non-hedge derivative instruments	6,728	1,177	144,869
Gain (loss) on derivative instruments	$ (77,512)	$ (25,345)	$ 31,951

Fair Value Measurements - Recurring Measurements (Details) - Recurring [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets:
Derivative Assets (Liabilities), at Fair Value, Net	$ (106,139)	$ 23,317
Fair Value, Inputs, Level 1 [Member]
Assets:
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Fair Value, Inputs, Level 2 [Member]
Assets:
Derivative Assets (Liabilities), at Fair Value, Net	(106,139)	23,317
Significant Unobservable Inputs Level 3 [Member]
Assets:
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0

Fair Value Measurements - Nonrecurring Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 20, 2016	Oct. 28, 2016
Senior Unsecured Notes due 2024 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	4.75%	4.75%		4.75%
Senior Unsecured Notes due 2025 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	5.375%	5.375%	5.375%
Reported Value Measurement [Member] \| Company Credit Facility [Member] \| Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	$ 397,000	$ 0
Reported Value Measurement [Member] \| Senior Unsecured Notes due 2024 [Member] \| Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	500,000	500,000
Reported Value Measurement [Member] \| Senior Unsecured Notes due 2025 [Member] \| Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	500,000	500,000
Reported Value Measurement [Member] \| Partnership Credit Facility [Member] \| Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	93,500	120,500
Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 1 [Member] \| Senior Unsecured Notes due 2024 [Member] \| Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	501,855	491,250
Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 1 [Member] \| Senior Unsecured Notes due 2025 [Member] \| Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	515,000	502,850
Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 2 [Member] \| Company Credit Facility [Member] \| Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	397,000	0
Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 2 [Member] \| Partnership Credit Facility [Member] \| Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	$ 93,500	$ 120,500

Commitments and Contingencies - Lease Commitments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Future minimum lease payments
Rent Expense	$ 2,412	$ 1,961	$ 1,449
Drilling Rig [Member]
Future minimum lease payments
2018	21,882
2019	10,082
2020	0
2021	0
2022	0
Thereafter	0
Total	31,964
Office and Equipment [Member]
Future minimum lease payments
2018	3,581
2019	3,307
2020	2,927
2021	2,406
2022	2,242
Thereafter	7,973
Total	$ 22,436

Commitments and Contingencies - Commitments and Obligations (Details) - Shell Trading US Company [Member]	May 24, 2012 bbl
Supply Commitment [Line Items]
Delivery contract, term	5 years
One-time right to decrease contract quantity, percent, not more than 20%	20.00%
Maximum [Member]
Supply Commitment [Line Items]
Maximum delivery obligation, barrels per day	8,000

Commitments and Contingencies - Defined Contribution Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined contribution plan
Employee maximum annual contribution as percentage of annual compensation	100.00%
Employer matching contribution percentage, up to 6%	6.00%
Contributions by employer	$ 1.8	$ 1.2	$ 1.4

Subsequent Events (Details) $ in Thousands		1 Months Ended	12 Months Ended
Subsequent Events (Details) $ in Thousands	Jan. 29, 2018 USD ($)	Feb. 12, 2018 $ / bbl bbl	Dec. 31, 2017 USD ($) $ / bbl bbl	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Subsequent Event [Line Items]
Proceeds from senior notes			$ 0	$ 1,000,000	$ 0
Oil Swaps 2018 [Member]
Subsequent Event [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl			9,761,000
Fixed Swap Price \| $ / bbl			51.10
Oil Swaps 2019 [Member]
Subsequent Event [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl			1,095,000
Fixed Swap Price \| $ / bbl			49.82
Subsequent Event [Member] \| Oil Swaps 2018 [Member]
Subsequent Event [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl		184,000
Fixed Swap Price \| $ / bbl		60.70
Subsequent Event [Member] \| Oil Swaps 2019 [Member]
Subsequent Event [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| bbl		90,000
Fixed Swap Price \| $ / bbl		58.70
Senior Unsecured Additional Notes due 2025 [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Aggregate principal amount	$ 300,000
Stated interest rate	5.375%
Proceeds from senior notes	$ 308,400
Company Credit Facility [Member]
Subsequent Event [Line Items]
Current borrowing base			$ 1,800,000
Elected borrowing base			$ 1,000,000
Company Credit Facility [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Remaining borrowing capacity	911,400
Current borrowing base	1,800,000
Elected borrowing base	$ 1,000,000

Guarantor Financial Statements - Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 112,446	$ 1,666,574	$ 20,115	$ 30,183
Restricted cash	0	500		500
Accounts receivable	231,613	119,825
Accounts receivable - related party	0	297
Intercompany receivable	0	0
Inventories	9,108	1,983
Other current assets	5,434	2,987
Total current assets	358,601	1,792,166
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	9,232,694	5,160,261
Midstream assets	191,519	8,362
Other property, equipment and land	80,776	58,290
Accumulated depletion, depreciation, amortization and impairment	(2,161,372)	(1,836,056)
Net property and equipment	7,343,617	3,390,857
Funds held in escrow	6,304	121,391
Derivative instruments	0	709
Investment in subsidiaries	0	0
Other assets	62,463	44,557
Total assets	7,770,985	5,349,680
Current liabilities:
Accounts payable-trade	94,590	47,648
Accounts payable-related party	0	1
Intercompany payable	0	0
Other current liabilities	482,838	161,693
Total current liabilities	577,428	209,342
Long-term debt	1,477,347	1,105,912
Derivative instruments	6,303	0
Asset retirement obligations	20,122	16,134	12,518
Deferred income taxes	108,048	0
Total liabilities	2,189,248	1,331,388
Commitments and contingencies
Stockholders’ equity:
Stockholders’ equity	5,254,860	3,697,462
Non-controlling interest	326,877	320,830
Total equity	5,581,737	4,018,292	2,108,973	1,985,213
Total liabilities and equity	7,770,985	5,349,680
Eliminations [Member]
Current assets:
Cash and cash equivalents	0	0	0	0
Restricted cash		0
Accounts receivable	0	0
Accounts receivable - related party	(5,142)	(3,470)
Intercompany receivable	(4,892,118)	(3,420,068)
Inventories	0	0
Other current assets	0	0
Total current assets	(4,897,260)	(3,423,538)
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	(414)	(559)
Midstream assets	0	0
Other property, equipment and land	0	0
Accumulated depletion, depreciation, amortization and impairment	4,342	8,593
Net property and equipment	3,928	8,034
Funds held in escrow	0	0
Derivative instruments	0	0
Investment in subsidiaries	(3,809,557)	15,500
Other assets	0	0
Total assets	(8,702,889)	(3,400,004)
Current liabilities:
Accounts payable-trade	0	0
Accounts payable-related party		0
Intercompany payable	(4,897,260)	(3,423,538)
Other current liabilities	0	0
Total current liabilities	(4,897,260)	(3,423,538)
Long-term debt	0	0
Derivative instruments	0
Asset retirement obligations	0	0
Deferred income taxes	0
Total liabilities	(4,897,260)	(3,423,538)
Stockholders’ equity:
Stockholders’ equity	(4,132,506)	(297,296)
Non-controlling interest	326,877	320,830
Total equity	(3,805,629)	23,534
Total liabilities and equity	(8,702,889)	(3,400,004)
Parent Company [Member] \| Reportable Legal Entities [Member]
Current assets:
Cash and cash equivalents	54,074	1,643,226	148	6
Restricted cash		0
Accounts receivable	0	0
Accounts receivable - related party	0	0
Intercompany receivable	2,624,810	3,060,566
Inventories	0	0
Other current assets	618	481
Total current assets	2,679,502	4,704,273
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	0	0
Midstream assets	0	0
Other property, equipment and land	0	0
Accumulated depletion, depreciation, amortization and impairment	0	0
Net property and equipment	0	0
Funds held in escrow	0	0
Derivative instruments	0	0
Investment in subsidiaries	3,809,557	(15,500)
Other assets	0	0
Total assets	6,489,059	4,688,773
Current liabilities:
Accounts payable-trade	1	30
Accounts payable-related party		1
Intercompany payable	132,067	0
Other current liabilities	7,236	5,868
Total current liabilities	139,304	5,899
Long-term debt	986,847	985,412
Derivative instruments	0
Asset retirement obligations	0	0
Deferred income taxes	108,048
Total liabilities	1,234,199	991,311
Stockholders’ equity:
Stockholders’ equity	5,254,860	3,697,462
Non-controlling interest	0	0
Total equity	5,254,860	3,697,462
Total liabilities and equity	6,489,059	4,688,773
Guarantor Subsidiaries [Member] \| Reportable Legal Entities [Member]
Current assets:
Cash and cash equivalents	34,175	14,135	19,428	15,067
Restricted cash		0
Accounts receivable	205,859	109,782
Accounts receivable - related party	0	297
Intercompany receivable	2,267,308	359,502
Inventories	9,108	1,983
Other current assets	4,461	2,319
Total current assets	2,520,911	488,018
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	8,129,211	4,400,002
Midstream assets	191,519	8,362
Other property, equipment and land	80,776	58,290
Accumulated depletion, depreciation, amortization and impairment	(1,976,248)	(1,695,701)
Net property and equipment	6,425,258	2,770,953
Funds held in escrow	0	121,391
Derivative instruments	0	709
Investment in subsidiaries	0	0
Other assets	25,609	9,291
Total assets	8,971,778	3,390,362
Current liabilities:
Accounts payable-trade	91,629	45,838
Accounts payable-related party		0
Intercompany payable	4,765,193	3,423,538
Other current liabilities	472,933	155,454
Total current liabilities	5,329,755	3,624,830
Long-term debt	397,000	0
Derivative instruments	6,303
Asset retirement obligations	20,122	16,134
Deferred income taxes	0
Total liabilities	5,753,180	3,640,964
Stockholders’ equity:
Stockholders’ equity	3,218,598	(250,602)
Non-controlling interest	0	0
Total equity	3,218,598	(250,602)
Total liabilities and equity	8,971,778	3,390,362
Viper Energy Partners LP [Member] \| Reportable Legal Entities [Member]
Current assets:
Cash and cash equivalents	24,197	9,213	$ 539	$ 15,110
Restricted cash		500
Accounts receivable	25,754	10,043
Accounts receivable - related party	5,142	3,470
Intercompany receivable	0	0
Inventories	0	0
Other current assets	355	187
Total current assets	55,448	23,413
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	1,103,897	760,818
Midstream assets	0	0
Other property, equipment and land	0	0
Accumulated depletion, depreciation, amortization and impairment	(189,466)	(148,948)
Net property and equipment	914,431	611,870
Funds held in escrow	6,304	0
Derivative instruments	0	0
Investment in subsidiaries	0	0
Other assets	36,854	35,266
Total assets	1,013,037	670,549
Current liabilities:
Accounts payable-trade	2,960	1,780
Accounts payable-related party		0
Intercompany payable	0	0
Other current liabilities	2,669	371
Total current liabilities	5,629	2,151
Long-term debt	93,500	120,500
Derivative instruments	0
Asset retirement obligations	0	0
Deferred income taxes	0
Total liabilities	99,129	122,651
Stockholders’ equity:
Stockholders’ equity	913,908	547,898
Non-controlling interest	0	0
Total equity	913,908	547,898
Total liabilities and equity	$ 1,013,037	$ 670,549

Guarantor Financial Statements - Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Oil sales									$ 1,044,017	$ 470,528	$ 405,715
Natural gas sales									52,210	22,506	19,592
Natural gas liquid sales									90,048	34,073	21,426
Royalty income									0	0	0
Lease bonus									11,764	0	0
Midstream services									7,072	0	0
Total revenues	$ 399,194	$ 301,253	$ 269,434	$ 235,230	$ 185,012	$ 142,131	$ 112,483	$ 87,481	1,205,111	527,107	446,733
Costs and expenses:
Lease operating expenses									126,524	82,428	82,625
Production and ad valorem taxes									73,505	34,456	32,990
Gathering and transportation									12,834	11,606	6,091
Midstream services									10,409	0	0
Depreciation, depletion and amortization									326,759	178,015	217,697
Impairment of oil and natural gas properties									0	245,536	814,798
General and administrative expenses									48,669	42,619	31,968
Asset retirement obligation accretion									1,391	1,064	833
Total costs and expenses									600,091	595,724	1,187,002
Income (loss) from operations	213,663	142,639	132,308	116,410	87,079	6,693	(134,786)	(27,603)	605,020	(68,617)	(740,269)
Other income (expense):
Interest expense, net									(40,554)	(40,684)	(41,510)
Other income, net									10,235	3,064	728
Loss on derivative instruments, net									(77,512)	(25,345)	31,951
Loss on extinguishment of debt									0	(33,134)	0
Total other expense, net									(107,831)	(96,099)	(8,831)
Income (loss) before income taxes									497,189	(164,716)	(749,100)
Provision for (benefit from) income taxes	(23,961)	857	1,579	1,957	(176)	0	368	0	(19,568)	192	(201,310)
Net income (loss)	129,607	81,948	164,128	141,074	28,440	(600)	(157,121)	(35,627)	516,757	(164,908)	(547,790)
Net income attributable to non-controlling interest	15,048	8,924	5,723	4,801	2,842	1,630	(1,631)	(2,715)	34,496	126	2,838
Net income (loss) attributable to Diamondback Energy, Inc.	$ 114,559	$ 73,024	$ 158,405	$ 136,273	$ 25,598	$ (2,230)	$ (155,490)	$ (32,912)	482,261	(165,034)	(550,628)
Eliminations [Member]
Revenues:
Oil sales									140,175	71,521	69,609
Natural gas sales									9,311	3,107	2,660
Natural gas liquid sales									10,677	4,209	2,590
Royalty income									(160,163)	(78,837)	(74,859)
Lease bonus									(106)	(309)
Midstream services									0
Total revenues									(106)	(309)	0
Costs and expenses:
Lease operating expenses									0	0	0
Production and ad valorem taxes									0	0	0
Gathering and transportation									0	2	0
Midstream services									0
Depreciation, depletion and amortization									4,251	(3,181)	(134)
Impairment of oil and natural gas properties										0	(3,423)
General and administrative expenses									(2,460)	0	0
Asset retirement obligation accretion									0	0	0
Total costs and expenses									1,791	(3,179)	(3,557)
Income (loss) from operations									(1,897)	2,870	3,557
Other income (expense):
Interest expense, net									0	0	0
Other income, net									(2,460)	(250)	0
Loss on derivative instruments, net									0	0	0
Loss on extinguishment of debt										0
Total other expense, net									(2,460)	(250)	0
Income (loss) before income taxes									(4,357)	2,620	3,557
Provision for (benefit from) income taxes									0	0	0
Net income (loss)									(4,357)	2,620	3,557
Net income attributable to non-controlling interest									34,496	126	2,838
Net income (loss) attributable to Diamondback Energy, Inc.									(38,853)	2,494	719
Parent Company [Member] \| Reportable Legal Entities [Member]
Revenues:
Oil sales									0	0	0
Natural gas sales									0	0	0
Natural gas liquid sales									0	0	0
Royalty income									0	0	0
Lease bonus									0	0
Midstream services									0
Total revenues									0	0	0
Costs and expenses:
Lease operating expenses									0	0	0
Production and ad valorem taxes									0	0	0
Gathering and transportation									0	0	0
Midstream services									0
Depreciation, depletion and amortization									0	0	0
Impairment of oil and natural gas properties										0	0
General and administrative expenses									26,776	25,959	17,077
Asset retirement obligation accretion									0	0	0
Total costs and expenses									26,776	25,959	17,077
Income (loss) from operations									(26,776)	(25,959)	(17,077)
Other income (expense):
Interest expense, net									(29,925)	(35,318)	(35,651)
Other income, net									1,142	437	1
Loss on derivative instruments, net									0	0	0
Loss on extinguishment of debt										(33,134)
Total other expense, net									(28,783)	(68,015)	(35,650)
Income (loss) before income taxes									(55,559)	(93,974)	(52,727)
Provision for (benefit from) income taxes									(19,568)	192	(201,310)
Net income (loss)									(35,991)	(94,166)	148,583
Net income attributable to non-controlling interest									0	0	0
Net income (loss) attributable to Diamondback Energy, Inc.									(35,991)	(94,166)	148,583
Guarantor Subsidiaries [Member] \| Reportable Legal Entities [Member]
Revenues:
Oil sales									903,842	399,007	336,106
Natural gas sales									42,899	19,399	16,932
Natural gas liquid sales									79,371	29,864	18,836
Royalty income									0	0	0
Lease bonus									0	0
Midstream services									7,072
Total revenues									1,033,184	448,270	371,874
Costs and expenses:
Lease operating expenses									126,524	82,428	82,625
Production and ad valorem taxes									62,897	28,912	27,459
Gathering and transportation									12,045	11,189	5,832
Midstream services									10,409
Depreciation, depletion and amortization									281,989	151,376	182,395
Impairment of oil and natural gas properties										198,067	814,798
General and administrative expenses									18,057	11,451	9,056
Asset retirement obligation accretion									1,391	1,064	833
Total costs and expenses									513,312	484,487	1,122,998
Income (loss) from operations									519,872	(36,217)	(751,124)
Other income (expense):
Interest expense, net									(7,465)	(2,911)	(4,749)
Other income, net									10,732	2,010	(427)
Loss on derivative instruments, net									(77,512)	(25,345)	31,951
Loss on extinguishment of debt										0
Total other expense, net									(74,245)	(26,246)	26,775
Income (loss) before income taxes									445,627	(62,463)	(724,349)
Provision for (benefit from) income taxes									0	0	0
Net income (loss)									445,627	(62,463)	(724,349)
Net income attributable to non-controlling interest									0	0	0
Net income (loss) attributable to Diamondback Energy, Inc.									445,627	(62,463)	(724,349)
Non-Guarantor Subsidiaries [Member] \| Reportable Legal Entities [Member]
Revenues:
Oil sales									0	0	0
Natural gas sales									0	0	0
Natural gas liquid sales									0	0	0
Royalty income									160,163	78,837	74,859
Lease bonus									11,870	309
Midstream services									0
Total revenues									172,033	79,146	74,859
Costs and expenses:
Lease operating expenses									0	0	0
Production and ad valorem taxes									10,608	5,544	5,531
Gathering and transportation									789	415	259
Midstream services									0
Depreciation, depletion and amortization									40,519	29,820	35,436
Impairment of oil and natural gas properties										47,469	3,423
General and administrative expenses									6,296	5,209	5,835
Asset retirement obligation accretion									0	0	0
Total costs and expenses									58,212	88,457	50,484
Income (loss) from operations									113,821	(9,311)	24,375
Other income (expense):
Interest expense, net									(3,164)	(2,455)	(1,110)
Other income, net									821	867	1,154
Loss on derivative instruments, net									0	0	0
Loss on extinguishment of debt										0
Total other expense, net									(2,343)	(1,588)	44
Income (loss) before income taxes									111,478	(10,899)	24,419
Provision for (benefit from) income taxes									0	0	0
Net income (loss)									111,478	(10,899)	24,419
Net income attributable to non-controlling interest									0	0	0
Net income (loss) attributable to Diamondback Energy, Inc.									$ 111,478	$ (10,899)	$ 24,419

Guarantor Financial Statements - Cash Flow Statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	$ 888,625	$ 332,080	$ 416,501
Cash flows from investing activities:
Additions to oil and natural gas properties	(792,599)	(363,087)	(419,512)
Additions to midstream assets	(68,139)	(1,188)	0
Purchase of other property, equipment and land	(22,779)	(9,891)	(1,213)
Acquisition of leasehold interests	(1,960,591)	(611,280)	(437,455)
Acquisition of mineral interests	(407,450)	(205,721)	(43,907)
Acquisition of midstream assets	(50,279)	0	0
Proceeds from sale of assets	65,656	4,661	9,739
Funds held in escrow	104,087	(121,391)	0
Equity investments	(188)	(2,345)	(2,702)
Intercompany transfers	0	0	0
Net cash used in investing activities	(3,132,282)	(1,310,242)	(895,050)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	753,500	164,000	425,001
Repayment on credit facility	(383,500)	(89,000)	(603,001)
Proceeds from senior notes	0	(1,000,000)	0
Repayment of senior notes	0	(450,000)	0
Premium on extinguishment of debt	0	(26,561)	0
Purchase of subsidiary units by parent	0
Debt issuance costs	(9,296)	(15,063)	(526)
Public offering costs	(510)	(1,182)	(586)
Proceeds from public offerings	370,344	2,051,503	650,688
Distribution from subsidiary	0	0	0
Proceeds from exercise of stock options	358	498	4,873
Distributions to non-controlling interest	(41,367)	(9,574)	(7,968)
Intercompany transfers		0	0
Net cash provided by financing activities	689,529	2,624,621	468,481
Net increase (decrease) in cash and cash equivalents	(1,554,128)	1,646,459	(10,068)
Cash and cash equivalents at beginning of period	1,666,574	20,115	30,183
Cash and cash equivalents at end of period	112,446	1,666,574	20,115
Eliminations [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	0	0	0
Cash flows from investing activities:
Additions to oil and natural gas properties	0	0	0
Additions to midstream assets	0	0
Purchase of other property, equipment and land	0	0	0
Acquisition of leasehold interests	0	0	0
Acquisition of mineral interests	0	0	0
Acquisition of midstream assets	0
Proceeds from sale of assets	0	0	0
Funds held in escrow	0	0
Equity investments	0	0	0
Intercompany transfers	0	0	0
Net cash used in investing activities	0	0	0
Cash flows from financing activities:
Proceeds from borrowings under credit facility	0	0	0
Repayment on credit facility	0	0	0
Proceeds from senior notes		0
Repayment of senior notes		0
Premium on extinguishment of debt		0
Purchase of subsidiary units by parent	10,068
Debt issuance costs	0	0	0
Public offering costs	0	0	0
Proceeds from public offerings	(10,068)	0	0
Distribution from subsidiary	(89,509)	(55,250)	(60,587)
Proceeds from exercise of stock options	0	0	0
Distributions to non-controlling interest	89,509	55,250	60,587
Intercompany transfers		0	0
Net cash provided by financing activities	0	0	0
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	0	0	0
Parent Company [Member] \| Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(29,470)	(39,894)	(37,597)
Cash flows from investing activities:
Additions to oil and natural gas properties	0	0	0
Additions to midstream assets	0	0
Purchase of other property, equipment and land	0	0	0
Acquisition of leasehold interests	0	0	0
Acquisition of mineral interests	0	0	0
Acquisition of midstream assets	0
Proceeds from sale of assets	0	0	0
Funds held in escrow	0	0
Equity investments	0	0	0
Intercompany transfers	(1,631,078)	(796,053)	(145,023)
Net cash used in investing activities	(1,631,078)	(796,053)	(145,023)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	0	0	0
Repayment on credit facility	0	0	0
Proceeds from senior notes		(1,000,000)
Repayment of senior notes		(450,000)
Premium on extinguishment of debt		(26,561)
Purchase of subsidiary units by parent	(10,068)
Debt issuance costs	(8,326)	(14,449)	0
Public offering costs	(77)	(636)	(586)
Proceeds from public offerings	0	1,925,923	650,688
Distribution from subsidiary	89,509	55,250	60,587
Proceeds from exercise of stock options	358	498	4,873
Distributions to non-controlling interest	0	0	0
Intercompany transfers		(11,000)	(532,800)
Net cash provided by financing activities	71,396	2,479,025	182,762
Net increase (decrease) in cash and cash equivalents	(1,589,152)	1,643,078	142
Cash and cash equivalents at beginning of period	1,643,226	148	6
Cash and cash equivalents at end of period	54,074	1,643,226	148
Guarantor Subsidiaries [Member] \| Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	778,876	303,347	390,266
Cash flows from investing activities:
Additions to oil and natural gas properties	(792,599)	(363,087)	(419,512)
Additions to midstream assets	(68,139)	(1,188)
Purchase of other property, equipment and land	(22,779)	(9,891)	(1,213)
Acquisition of leasehold interests	(1,960,591)	(611,280)	(437,455)
Acquisition of mineral interests	(63,371)	0	0
Acquisition of midstream assets	(50,279)
Proceeds from sale of assets	65,656	4,661	9,739
Funds held in escrow	104,087	(121,391)
Equity investments	(188)	(2,345)	(2,702)
Intercompany transfers	1,631,078	796,053	145,023
Net cash used in investing activities	(1,157,125)	(308,468)	(706,120)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	475,000	0	390,501
Repayment on credit facility	(78,000)	(11,000)	(603,001)
Proceeds from senior notes		0
Repayment of senior notes		0
Premium on extinguishment of debt		0
Purchase of subsidiary units by parent	0
Debt issuance costs	1,289	(172)	(85)
Public offering costs	0	0	0
Proceeds from public offerings	0	0	0
Distribution from subsidiary	0	0	0
Proceeds from exercise of stock options	0	0	0
Distributions to non-controlling interest	0	0	0
Intercompany transfers		11,000	532,800
Net cash provided by financing activities	398,289	(172)	320,215
Net increase (decrease) in cash and cash equivalents	20,040	(5,293)	4,361
Cash and cash equivalents at beginning of period	14,135	19,428	15,067
Cash and cash equivalents at end of period	34,175	14,135	19,428
Non-Guarantor Subsidiaries [Member] \| Reportable Legal Entities [Member]
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	139,219	68,627	63,832
Cash flows from investing activities:
Additions to oil and natural gas properties	0	0	0
Additions to midstream assets	0	0
Purchase of other property, equipment and land	0	0	0
Acquisition of leasehold interests	0	0	0
Acquisition of mineral interests	(344,079)	(205,721)	(43,907)
Acquisition of midstream assets	0
Proceeds from sale of assets	0	0	0
Funds held in escrow	0	0
Equity investments	0	0	0
Intercompany transfers	0	0	0
Net cash used in investing activities	(344,079)	(205,721)	(43,907)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	278,500	164,000	34,500
Repayment on credit facility	(305,500)	(78,000)	0
Proceeds from senior notes		0
Repayment of senior notes		0
Premium on extinguishment of debt		0
Purchase of subsidiary units by parent	0
Debt issuance costs	(2,259)	(442)	(441)
Public offering costs	(433)	(546)	0
Proceeds from public offerings	380,412	125,580	0
Distribution from subsidiary	0	0	0
Proceeds from exercise of stock options	0	0	0
Distributions to non-controlling interest	(130,876)	(64,824)	(68,555)
Intercompany transfers		0	0
Net cash provided by financing activities	219,844	145,768	(34,496)
Net increase (decrease) in cash and cash equivalents	14,984	8,674	(14,571)
Cash and cash equivalents at beginning of period	9,213	539	15,110
Cash and cash equivalents at end of period	$ 24,197	$ 9,213	$ 539

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Capitalized Oil and Natural Gas Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Oil and Natural Gas Properties:
Proved properties	$ 5,126,829	$ 3,429,742
Unproved properties	4,105,865	1,730,519
Total oil and natural gas properties	9,232,694	5,160,261
Accumulated depreciation, depletion, amortization	(1,009,893)	(687,685)
Accumulated impairment	(1,143,498)	(1,143,498)
Oil and natural gas properties, net	$ 7,079,303	$ 3,329,078

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Acquisition costs
Proved properties	$ 452,661	$ 72,044	$ 64,340
Unproved properties	2,692,000	752,117	448,638
Development costs	145,362	47,575	42,749
Exploration costs	779,728	329,122	319,102
Capitalized asset retirement costs	2,682	4,030	3,458
Total	$ 4,072,433	$ 1,204,888	$ 878,287

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil, natural gas and natural gas liquid sales	$ 1,186,275	$ 527,107	$ 446,733
Lease operating expenses	(126,524)	(82,428)	(82,625)
Production and ad valorem taxes	(73,505)	(34,456)	(32,990)
Gathering and transportation	(12,834)	(11,606)	(6,091)
Depreciation, depletion, and amortization	(321,870)	(176,369)	(216,056)
Impairment	0	(245,536)	(814,798)
Asset retirement obligation accretion expense	(1,391)	(1,064)	(833)
Income tax benefit (expense)	19,568	(192)	201,310
Results of operations	$ 669,719	$ (24,544)	$ (505,350)

Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Oil and Natural Gas Reserves (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017 USD ($) Boe MBoe well bbl Mcf	Dec. 31, 2016 USD ($) Boe bbl Mcf	Dec. 31, 2015 USD ($) well acquisition bbl Mcf	Dec. 31, 2014 bbl Mcf
Proved Developed and Undeveloped Reserves (Volume)
Extensions and discoveries	138,977	69,042
Revisions of previous estimates	8,308
Purchase of reserves in place		3,993
Development Wells Drilled, Net Productive	102	59
Proved Undeveloped Reserves Number of Wells Added	87	51
Percentage of extension volumes attributable to subsidiary	8.00%
Number of New Wells Developed, Mineral Interest		30
Number of Wells Developed, Mineral Interest		30
Proved Developed And Undeveloped Reserves Revisions Of Previous Estimates Increase (Decrease) Due to Reclassification of Proved Undeveloped Locations	2,550	(7,253)
Proved Developed And Undeveloped Reserves Revisions Of Previous Estimates Increase(Decrease) Due to Pricing		(5,978)
Number of major acquisitions \| acquisition			1
Number of existing vertical wells \| well			136
Number of existing horizontal wells \| well			4
Number of vertical wells acquired \| well			3
Number of horizontal PUDs included in the acquired reserves \| well			0
Number of vertical wells developed, working interest \| well			2
Number of horizontal wells developed, working interest \| well	26		119
Proved Undeveloped Reserves, Extensions and Discoveries, Mineral Interest \| MBoe	3,004
Number of horizontal wells developed, mineral interest \| well	40		16
Number of Vertical Wells Developed \| well			2
Number of Horizontal Wells Developed \| well			135
Number of vertical wells developed, proved undeveloped category \| well			1
Number of vertical locations downgraded \| well			89
Proved Undeveloped Reserves, Vertical Wells Downgraded, Working Interest \| well			80
Proved Undeveloped Reserves, Horizontal Wells Downgraded, Working Interest \| well			22
Proved Undeveloped Reserves, Vertical Wells Downgraded, Mineral Interest \| well			22
Proved undeveloped reserves, increase (Energy) \| Boe	40,550
Proved Undeveloped Reserves (Energy)
Beginning proved undeveloped reserves at December 31, 2016 \| Boe	86,354
Undeveloped reserves transferred to developed \| Boe	(31,666)
Revisions \| Boe	(4,710)
Proved Undeveloped Reserves, Purchases \| Boe	6,246
Extensions and discoveries \| MBoe	67,676
Ending proved undeveloped reserves at December 31, 2017 \| Boe	126,904	86,354
Number of locations downgraded due to reclassifications and technical revisions	7	17
Number of Horizontal Wells Drilled, Working Interest, Gross \| well	44
Number of Horizontal Wells Drilled, Working Interest, Net \| well	37
Number of Horizontal Wells Drilled, Mineral Interest, Gross \| well	27
Number of Horizontal Wells Drilled, Working and Mineral Interest, Gross \| well	23
Number of Horizontal Wells Developed, Working Interest, Gross \| well	87
Number of Horizontal Wells Developed, Working Interest, Net \| well	75
Proved undeveloped reserves, planned development period	5 years
Capital expenditures towards development of proved undeveloped reserves \| $	$ 145,362	$ 47,575	$ 42,749
Proved Undeveloped Reserves, Extensions and Discoveries \| Boe	70,680
Oil [Member]
Proved Developed and Undeveloped Reserves (Volume)
Beginning of the period	139,174	105,979	75,690
Extensions and discoveries	99,980	55,069	48,725
Revisions of previous estimates	(7,715)	(12,483)	(12,130)
Purchase of reserves in place	24,322	2,537	2,775
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	(1,163)	(366)
Production	(21,417)	(11,562)	(9,081)
End of the period	233,181	139,174	105,979
Proved Developed Reserves (Volume)	141,246	79,457	60,569	43,886
Proved Undeveloped Reserve (Volume)	91,935	59,717	45,409	31,804
Natural Gas Liquids [Member]
Proved Developed and Undeveloped Reserves (Volume)
Beginning of the period	37,134	26,004	18,542
Extensions and discoveries	20,825	13,962	12,056
Revisions of previous estimates	(1,466)	(1,888)	(4,081)
Purchase of reserves in place	2,633	1,455	1,165
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	(461)	0
Production	(4,056)	(2,399)	(1,678)
End of the period	54,609	37,134	26,004
Proved Developed Reserves (Volume)	35,412	22,080	15,418	11,221
Proved Undeveloped Reserve (Volume)	19,198	15,054	10,586	7,321
Natural Gas [Member]
Proved Developed and Undeveloped Reserves (Volume)
Beginning of the period \| Mcf	174,896	149,503	111,605
Extensions and discoveries \| Mcf	109,032	64,758	53,453
Revisions of previous estimates \| Mcf	(10,065)	(34,519)	(14,726)
Purchase of reserves in place \| Mcf	34,640	7,567	7,102
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place \| Mcf	(2,474)	(1,985)
Production \| Mcf	(20,660)	(10,428)	(7,931)
End of the period \| Mcf	285,369	174,896	149,503
Proved Developed Reserves (Volume) \| Mcf	190,740	105,399	96,871	68,264
Proved Undeveloped Reserve (Volume) \| Mcf	94,629	69,497	52,632	43,341
Delaware Basin [Member]
Proved Developed and Undeveloped Reserves (Volume)
Percentage of total purchase volumes	87.00%
Viper Energy Partners LP [Member]
Proved Developed and Undeveloped Reserves (Volume)
Percentage of total purchase volumes	10.00%

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	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Future cash inflows	$ 12,921,897	$ 6,275,705	$ 5,377,783
Future development costs	(1,123,979)	(617,636)	(548,239)
Future production costs	(2,994,877)	(1,392,852)	(1,279,101)
Future production taxes	(928,891)	(459,244)	(363,129)
Future income tax expenses	(83,961)	(75,595)	(28,233)
Future net cash flows	7,790,189	3,730,378	3,159,081
10% discount to reflect timing of cash flows	(4,033,130)	(2,018,965)	(1,740,948)
Standardized measure of discounted future net cash flows	$ 3,757,059	$ 1,711,413	$ 1,418,133	$ 2,045,224

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, 2017 $ / bbl $ / Mcf	Dec. 31, 2016 $ / bbl $ / Mcf	Dec. 31, 2015 $ / bbl $ / Mcf
Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales prices (dollars per unit)	48.03	39.94	45.07
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales prices (dollars per unit) \| $ / Mcf	2.06	1.36	1.83
Natural Gas Liquids [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average sales prices (dollars per unit)	20.79	12.91	12.56

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, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ 1,711,413	$ 1,418,133	$ 2,045,224
Sales of oil and natural gas, net of production costs	(986,246)	(411,558)	(331,119)
Acquisition of reserves	439,396	43,142	58,849
Divestiture of reserves	(11,072)	(5,481)	(1,490)
Extensions and discoveries, net of future development costs	1,791,686	779,359	629,149
Previously estimated development costs incurred during the period	190,121	85,696	129,901
Net changes in prices and production costs	577,781	(150,509)	(1,383,698)
Changes in estimated future development costs	(52,908)	20,647	38,638
Revisions of previous quantity estimates	(98,857)	(123,795)	(377,160)
Accretion of discount	174,185	143,134	236,716
Net change in income taxes	(9,074)	(30,530)	268,963
Net changes in timing of production and other	30,634	(56,825)	104,160
Standardized measure of discounted future net cash flows at the end of the period	$ 3,757,059	$ 1,711,413	$ 1,418,133

Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 399,194	$ 301,253	$ 269,434	$ 235,230	$ 185,012	$ 142,131	$ 112,483	$ 87,481	$ 1,205,111	$ 527,107	$ 446,733
Income (loss) from operations	213,663	142,639	132,308	116,410	87,079	6,693	(134,786)	(27,603)	605,020	(68,617)	(740,269)
Income tax expense (benefit)	(23,961)	857	1,579	1,957	(176)	0	368	0	(19,568)	192	(201,310)
Net income (loss)	129,607	81,948	164,128	141,074	28,440	(600)	(157,121)	(35,627)	516,757	(164,908)	(547,790)
Net income (loss) attributable to non-controlling interest	15,048	8,924	5,723	4,801	2,842	1,630	(1,631)	(2,715)	34,496	126	2,838
Net income (loss) attributable to Diamondback Energy, Inc.	$ 114,559	$ 73,024	$ 158,405	$ 136,273	$ 25,598	$ (2,230)	$ (155,490)	$ (32,912)	$ 482,261	$ (165,034)	$ (550,628)
Earnings per common share:
Basic (in dollars per share)	$ 1.17	$ 0.74	$ 1.61	$ 1.46	$ 0.32	$ (0.03)	$ (2.17)	$ (0.46)	$ 4.95	$ (2.20)	$ (8.74)
Diluted (in dollars per share)	$ 1.16	$ 0.74	$ 1.61	$ 1.46	$ 0.32	$ (0.03)	$ (2.17)	$ (0.46)	$ 4.94	$ (2.20)	$ (8.74)