Diamondback Energy (FANG) 10-K 27 Feb 20 2019 FY Annual report Financial data

Cover

Cover - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2019	Feb. 14, 2020	Jun. 28, 2019
Cover page.
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-35700
Entity Registrant Name	Diamondback Energy, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	45-4502447
Entity Address, Address Line One	500 West Texas
Entity Address, Address Line Two	Suite 1200
Entity Address, City or Town	Midland,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	79701
City Area Code	432
Local Phone Number	221-7400
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	FANG
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 15.9
Entity Common Stock, Shares Outstanding		158,284,486
Documents Incorporated by Reference	Portions of Diamondback Energy, Inc.’s Proxy Statement for the 2020 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Central Index Key	0001539838
Current Fiscal Year End Date	--12-31

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 123	$ 215
Restricted cash	5	0
Accounts receivable:
Joint interest and other, net	186	96
Oil and natural gas sales	429	296
Inventories	37	37
Derivative instruments	46	231
Prepaid expenses and other	43	50
Total current assets	869	925
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($9,207 million and $9,670 million excluded from amortization at December 31, 2019 and 2018, respectively)	25,782	22,299
Midstream assets	931	700
Other property, equipment and land	125	147
Accumulated depletion, depreciation, amortization and impairment	(5,003)	(2,774)
Net property and equipment	21,835	20,372
Equity method investments	479	1
Derivative instruments	7	0
Deferred tax asset	142	97
Investment in real estate, net	109	116
Other assets	90	85
Total assets	23,531	21,596
Current liabilities:
Accounts payable-trade	179	128
Accrued capital expenditures	475	495
Other accrued liabilities	304	253
Revenues and royalties payable	278	143
Derivative instruments	27	0
Total current liabilities	1,263	1,019
Long-term debt	5,371	4,464
Derivative instruments	0	15
Asset retirement obligations	94	136
Deferred income taxes	1,886	1,785
Other long-term liabilities	11	10
Total liabilities	8,625	7,429
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 159,002,338 issued and outstanding at December 31, 2019; 200,000,000 shares authorized, 164,273,447 issued and outstanding at December 31, 2018	2	2
Additional paid-in capital	12,357	12,936
Retained earnings	890	762
Total Diamondback Energy, Inc. stockholders’ equity	13,249	13,700
Non-controlling interest	1,657	467
Total equity	14,906	14,167
Total liabilities and equity	$ 23,531	$ 21,596

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Oil and natural gas properties, amortization excluded	$ 9,207	$ 9,670
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Shares authorized (in Shares)	200,000,000	200,000,000
Shares issued (in Shares)	159,002,338	164,273,447
Shares outstanding (in Shares)	159,002,338	164,273,447

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Lease bonus	$ 4,000,000	$ 3,000,000	$ 12,000,000
Other operating income	9,000,000	9,000,000	0
Total revenues	3,964,000,000	2,176,000,000	1,205,000,000
Costs and expenses:
Lease operating expenses	490,000,000	205,000,000	127,000,000
Production and ad valorem taxes	248,000,000	133,000,000	74,000,000
Depreciation, depletion and amortization	1,447,000,000	623,000,000	327,000,000
Impairment of oil and natural gas properties	790,000,000	0	0
General and administrative expenses	104,000,000	65,000,000	48,000,000
Asset retirement obligation accretion	7,000,000	2,000,000	1,000,000
Merger and integration expense	0	36,000,000	0
Other operating expense	4,000,000	3,000,000	0
Total costs and expenses	3,269,000,000	1,165,000,000	600,000,000
Income from operations	695,000,000	1,011,000,000	605,000,000
Other income (expense):
Interest expense, net	(172,000,000)	(87,000,000)	(41,000,000)
Other (expense) income, net	(2,000,000)	89,000,000	11,000,000
(Loss) gain on derivative instruments, net	(108,000,000)	101,000,000	(78,000,000)
Gain (loss) on revaluation of investment	5,000,000	(1,000,000)	0
Loss on extinguishment of debt	(56,000,000)	0	0
Total other income (expense), net	(333,000,000)	102,000,000	(108,000,000)
Income (loss) before income taxes	362,000,000	1,113,000,000	497,000,000
Provision for (benefit from) income taxes	47,000,000	168,000,000	(20,000,000)
Net income (loss)	315,000,000	945,000,000	517,000,000
Net income attributable to non-controlling interest	75,000,000	99,000,000	35,000,000
Net income (loss) attributable to Diamondback Energy, Inc.	$ 240,000,000	$ 846,000,000	$ 482,000,000
Earnings per common share:
Basic (in dollars per share)	$ 1.47	$ 8.09	$ 4.95
Diluted (in dollars per share)	$ 1.47	$ 8.06	$ 4.94
Weighted average common shares outstanding:
Basic (in shares)	163,493	104,622	97,458
Diluted (in shares)	163,843	104,929	97,688
Dividends declared per share (in dollars per share)	$ 0.9375	$ 0.5000	$ 0
Oil sales
Revenues:
Revenues	$ 3,554,000,000	$ 1,879,000,000	$ 1,044,000,000
Natural gas sales
Revenues:
Revenues	66,000,000	61,000,000	52,000,000
Natural gas liquid sales
Revenues:
Revenues	267,000,000	190,000,000	90,000,000
Gathering and transportation
Costs and expenses:
Cost of goods and services sold	88,000,000	26,000,000	13,000,000
Midstream services
Revenues:
Revenues	64,000,000	34,000,000	7,000,000
Costs and expenses:
Cost of goods and services sold	$ 91,000,000	$ 72,000,000	$ 10,000,000

Consolidated Statement of Stock

Consolidated Statement of Stockholders' Equity - USD ($) $ in Millions	Total	Brigham	Energen	Ajax	Viper Energy Partners LP	Rattler MIdstream LP	Common Stock	Common StockBrigham	Common StockEnergen	Common StockAjax	Additional Paid-in Capital	Additional Paid-in CapitalBrigham	Additional Paid-in CapitalEnergen	Additional Paid-in CapitalAjax	Retained Earnings (Accumulated Deficit)	Non-Controlling Interest	Non-Controlling InterestViper Energy Partners LP	Non-Controlling InterestRattler MIdstream LP
Balance at beginning of period (in shares) at Dec. 31, 2016							90,144,000
Balance at beginning of period at Dec. 31, 2016	$ 4,018						$ 1				$ 4,216				$ (520)	$ 321
Increase (Decrease) in Stockholders' Equity
Net proceeds from issuance of common units					$ 370												$ 370
Unit-based compensation	2															2
Common units issued for acquisition	3															3
Stock-based compensation	32										32
Distribution to non-controlling interest	(41)															(41)
Common shares issued for acquisition, shares								7,686,000
Common shares issued for business combination		$ 809										$ 809
Exercise of stock options and awards of restricted stock, shares							337,000
Exercise of stock options and vesting of restricted stock units	0
Change in ownership of consolidated subsidiaries, net	(129)										234					(363)
Net income	517														482	35
Balance at end of period (in shares) at Dec. 31, 2017							98,167,000
Balance at end of period at Dec. 31, 2017	5,581						$ 1				5,291				(38)	327
Increase (Decrease) in Stockholders' Equity
Net proceeds from issuance of common units					303												303
Unit-based compensation	3															3
Stock-based compensation	34										34
Distribution to non-controlling interest	(98)															(98)
Common shares issued for acquisition, shares									63,126,000	2,584,000
Common shares issued for business combination			$ 7,070	$ 340					$ 1				$ 7,069	$ 340
Restricted stock units assumed in business combination	52		52										52
Repurchased shares for tax withholding (in shares)							(140,000)
Repurchased shares for tax withholding	(14)										(14)
Stock options assumed in business combination	14		$ 14										$ 14
Dividend paid	(37)														(37)
Exercise of stock options and awards of restricted stock, shares							536,000
Exercise of stock options and vesting of restricted stock units	0
Change in ownership of consolidated subsidiaries, net	(10)										150					(160)
Net income	$ 945														846	99
Balance at end of period (in shares) at Dec. 31, 2018	164,273,447						164,273,000
Balance at end of period at Dec. 31, 2018	$ 14,167						$ 2				12,936				762	467
Increase (Decrease) in Stockholders' Equity
Net proceeds from issuance of common units					$ 341	$ 720											$ 341	$ 720
Unit-based compensation	7															7
Common units issued for acquisition	124															124
Stock-based compensation	57										57
Distribution to non-controlling interest	(122)															(122)
Repurchased shares for tax withholding (in shares)							(125,000)
Repurchased shares for tax withholding	(13)										(13)
Repurchased shares for share buyback program (in shares)							(6,385,000)
Repurchased shares for share buyback program	(598)										(598)
Dividend paid	(112)														(112)
Exercise of stock options and awards of restricted stock, shares							1,239,000
Exercise of stock options and vesting of restricted stock units	8										8
Change in ownership of consolidated subsidiaries, net	12										(33)					45
Net income	$ 315														240	75
Balance at end of period (in shares) at Dec. 31, 2019	159,002,338						159,002,000
Balance at end of period at Dec. 31, 2019	$ 14,906						$ 2				$ 12,357				$ 890	$ 1,657

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) shares in Millions		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income		$ 315,000,000	$ 945,000,000	$ 517,000,000
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes		47,000,000	168,000,000	(20,000,000)
Impairment of oil and natural gas properties		790,000,000	0	0
Asset retirement obligation accretion		7,000,000	2,000,000	1,000,000
Depreciation, depletion and amortization		1,447,000,000	623,000,000	327,000,000
Amortization of debt issuance costs		9,000,000	12,000,000	4,000,000
Loss on early extinguishment of debt		56,000,000	0	0
Change in fair value of derivative instruments		188,000,000	(222,000,000)	84,000,000
Loss (income) from equity investment		6,000,000	0	(1,000,000)
(Gain) loss on revaluation of investment		(5,000,000)	1,000,000	0
Equity-based compensation expense		48,000,000	27,000,000	26,000,000
(Gain) loss on sale of assets, net		(1,000,000)	3,000,000	(1,000,000)
Gain on sale of inventory		(1,000,000)	0	0
Restricted cash		(5,000,000)	0	0
Changes in operating assets and liabilities:
Accounts receivable		(187,000,000)	13,000,000	(97,000,000)
Inventories		(10,000,000)	(14,000,000)	(2,000,000)
Prepaid expenses and other		29,000,000	25,000,000	(11,000,000)
Accounts payable and accrued liabilities		(129,000,000)	(7,000,000)	37,000,000
Income tax payable		0	(1,000,000)	1,000,000
Accrued interest		(5,000,000)	(22,000,000)	(21,000,000)
Revenues and royalties payable		135,000,000	12,000,000	45,000,000
Net cash provided by operating activities		2,734,000,000	1,565,000,000	889,000,000
Cash flows from investing activities:
Drilling, completions and non-operated additions to oil and natural gas properties		(2,557,000,000)	(1,359,000,000)	(737,000,000)
Infrastructure additions to oil and natural gas properties		(120,000,000)	(102,000,000)	(56,000,000)
Additions to midstream assets		(244,000,000)	(204,000,000)	(68,000,000)
Purchase of other property, equipment and land		(5,000,000)	(7,000,000)	(23,000,000)
Acquisition of leasehold interests		(443,000,000)	(1,371,000,000)	(1,961,000,000)
Acquisition of mineral interests		(333,000,000)	(440,000,000)	(407,000,000)
Acquisition of midstream assets		0	0	(50,000,000)
Proceeds from sale of assets		300,000,000	80,000,000	66,000,000
Investment in real estate		(1,000,000)	(111,000,000)	0
Funds held in escrow		0	11,000,000	104,000,000
Equity investments		(485,000,000)	0	0
Net cash used in investing activities		(3,888,000,000)	(3,503,000,000)	(3,132,000,000)
Cash flows from financing activities:
Proceeds from borrowings under credit facility		2,350,000,000	2,652,000,000	754,000,000
Repayment under credit facility		(3,718,000,000)	(1,242,000,000)	(384,000,000)
Repayment on Energen's credit facility		0	(559,000,000)	0
Proceeds from senior notes		3,469,000,000	1,062,000,000	0
Repayment of senior notes		(1,250,000,000)	0	0
Proceeds from joint venture		39,000,000	0	0
Premium on extinguishment of debt		(44,000,000)	0	0
Debt issuance costs		(18,000,000)	(25,000,000)	(9,000,000)
Public offering costs		(41,000,000)	(3,000,000)	(1,000,000)
Proceeds from public offerings		1,106,000,000	305,000,000	370,000,000
Proceeds from exercise of stock options		9,000,000	0	0
Repurchased shares for tax withholdings		(13,000,000)	(14,000,000)	0
Repurchased as part of share buyback		(593,000,000)	0	0
Dividends to stockholders		(112,000,000)	(37,000,000)	0
Distributions to non-controlling interest		(122,000,000)	(98,000,000)	(41,000,000)
Net cash (used in) provided by financing activities		1,062,000,000	2,041,000,000	689,000,000
Net increase (decrease) in cash and cash equivalents		(92,000,000)	103,000,000	(1,554,000,000)
Cash and cash equivalents at beginning of period		215,000,000	112,000,000	1,666,000,000
Cash and cash equivalents at end of period		123,000,000	215,000,000	112,000,000
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest		237,000,000	114,000,000	58,000,000
Cash paid for income taxes		0	1,000,000	0
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures		(20,000,000)	274,000,000	161,000,000
Capitalized stock-based compensation		$ 17,000,000	$ 10,000,000	$ 9,000,000
Common stock issued	[1]	0	7,136	0
Asset retirement obligations acquired		$ 4,000,000	$ 111,000,000	$ 2,000,000
Ajax Acquisition
Supplemental disclosure of non-cash transactions:
Common stock issued		0	340	0
Brigham
Supplemental disclosure of non-cash transactions:
Common stock issued		0	0	809
[1]	Includes $7 billion of Common stock issued for business combination, $14 million for stock options assumed and $52 million for restricted stock units assumed.

Consolidated Statements of Ca_2

Consolidated Statements of Cash Flows (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Stock options assumed in business combination	$ 14
Restricted stock units assumed in business combinations	52
Energen
Common shares issued for business combination	$ 7,000

DESCRIPTION OF THE BUSINESS AND

DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2019
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. The wholly-owned subsidiaries of Diamondback, as of December 31, 2019 , 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 (“Viper’s General Partner”), Rattler Midstream GP LLC, a Delaware limited liability company (Rattler’s General Partner), and Energen Corporation, an Alabama corporation (“Energen”). The consolidated subsidiaries include these wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (“Viper”), Viper’s subsidiary Viper Energy Partners LLC, a Delaware limited liability company (“Viper LLC”), Rattler Midstream LP (formerly known as Rattler Midstream Partners LP), a Delaware limited partnership (“Rattler”), Rattler Midstream Operating LLC (formerly known as Rattler Midstream LLC), a Delaware limited liability company (“Rattler LLC”), Rattler LLC’s wholly-owned subsidiary Tall City Towers LLC, a Delaware limited liability company (“Tall City”), and Energen’s wholly-owned subsidiaries Energen Resources Corporation, an Alabama corporation (“Energen Resources”), and EGN Services, Inc., an Alabama corporation. 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. Viper is consolidated in the financial statements of the Company. As of December 31, 2019 , the Company owned approximately 58% of the total units outstanding of Viper and the Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is Viper’s General Partner. Rattler is consolidated in the financial statements of the Company. As of December 31, 2019 , the Company owned approximately 71%

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2019
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 As of December 31, 2019, the Company had restricted cash of $5 million related to the Company’s obligations under its participation and development agreement with Obsidian Resources, L.L.C. 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. At December 31, 2019 and 2018 , the Company recorded an allowance for doubtful accounts of $2 million related to joint interest receivables. 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 16 —Fair Value Measurements). Prepaid Expenses and Other Prepaid expenses and other consist of the following: Year Ended December 31, 2019 2018 (In millions) Prepaid insurance $ 6 $ 4 Prepaid fees and licenses 4 3 Income tax receivable 19 38 Other 14 5 Total prepaid expenses and other $ 43 $ 50 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 9 –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 $13.54 , $12.62 and $11.11 for the years ended December 31, 2019 , 2018 and 2017 , respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $1.4 billion , $595 million and $321 million for the years ended December 31, 2019 , 2018 and 2017 , 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. An impairment on proved oil and natural gas properties of $790 million was recorded for the year ended December 31, 2019 . No impairments on proved oil and natural gas properties were recorded for the years ended December 31, 2018 and 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. Real Estate Assets Real estate assets are stated at cost, less accumulated depreciation and amortization. The Company considers the period of future benefit of each respective asset to determine the appropriate useful life and depreciation and amortization is calculated using the straight-line method over the assigned useful life. Upon acquisition of real estate properties, the purchase price is allocated to tangible assets, consisting of land and building, and to identified intangible assets and liabilities, which may include the value of above market and below market leases and the value of in-place leases. The allocation of the purchase price is based upon the fair value of each component of the property. Although independent appraisals may be used to assist in the determination of fair value, in many cases these values will be based upon management’s assessment of each property, the selling prices of comparable properties and the discounted value of cash flows from the asset. The fair values of above market and below market in-place leases will be recorded based on the present value (using an interest rate which reflects the risks associated with the leases acquired) of the difference between (i) the contractual amounts to be paid pursuant to the in-place leases and (ii) an estimate of fair market lease rates for the corresponding in-place leases measured over a period equal to the non-cancelable term of the lease including any bargain renewal periods. The above market and below market lease values will be capitalized as intangible lease assets or liabilities. Above market lease values will be amortized as an adjustment of rental income over the remaining term of the respective leases. Below market lease values will be amortized as an adjustment of rental income over the remaining term of the respective leases, including any bargain renewal periods. If a lease were to be terminated prior to its stated expiration, all unamortized amounts of above market and below market in-place lease values relating to that lease would be recorded as an adjustment to rental income. The fair values of in-place leases will include estimated direct costs associated with obtaining a new tenant, and opportunity costs associated with lost rentals which are avoided by acquiring an in-place lease. Direct costs associated with obtaining a new tenant may include commissions, tenant improvements, and other direct costs and are estimated, in part, by management’s consideration of current market costs to execute a similar lease. These direct costs will be included in intangible lease assets on the balance sheet and will be amortized to expense over the remaining term of the respective leases. The value of opportunity costs will be calculated using the contractual amounts to be paid pursuant to the in-place leases over a market absorption period for a similar lease. These intangibles will be included in intangible lease assets on the balance sheet and will be amortized to expense over the remaining term of the respective leases. If a lease were to be terminated prior to its stated expiration, all unamortized amounts of in-place lease assets relating to that lease would be expensed. 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 15 years . Depreciation expense for other property and equipment was $16 million , $9 million and $1 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. Asset Retirement Obligations The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The Company records a liability relating to the retirement and removal of all assets used in their businesses. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount 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, 2019 , 2018 and 2017 , 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 unevaluated properties to their intended use. Capitalized interest cannot exceed gross interest expense. The Company capitalized interest of $66 million , $32 million and $22 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. Inventories Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2019 and 2018 . 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, 2019 , 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 $36 million and $28 million , net of accumulated amortization of $15 million and $9 million , as of December 31, 2019 and 2018 , respectively. Long-term debt included capitalized costs related to the senior notes of $24 million and $32 million , net of accumulated amortization of $14 million and $15 million , as of December 31, 2019 and 2018 , 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, 2019 2018 (In millions) Liability for drilling costs prepaid by joint interest partners $ 12 $ 16 Interest payable 27 26 Lease operating expenses payable 119 59 Ad valorem taxes payable 68 49 Other 78 103 Total other accrued liabilities $ 304 $ 253 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 from Contracts with Customers Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies. Oil sales The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations. Natural gas and natural gas liquids sales Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations. Midstream Revenue Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler provides to exploration and production operations. The portion of such fees shown in the Company’s consolidated financial statements represent amounts charged to interest owners in the Company’s operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement. Transaction price allocated to remaining performance obligations The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligations under any of our product sales contracts. The majority of the Company’s midstream revenue agreements have a term greater than one year, and as such the Company has utilized the practical expedient in ASC 606, which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The remainder of the Company’s midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. The Company has utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less. Contract balances Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2019 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded. 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, 2019 , 2018 and 2017 . For additional information on the Company’s investments, see Note 9 —Equity Method Investments. Accounting for Equity-Based Compensation The Company has granted various types of stock-based awards including stock options and restricted stock units. Viper has granted various unit-based awards including unit options and phantom units to employees, officers and directors of Viper’s General Partner and the Company who perform services for Viper. Rattler has granted unit-based awards consisting of phantom units to employees, officers and directors of Rattler’s General Partner and the Company who perform services for Rattler. These plans and related accounting policies are defined and described more fully in Note 12 —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, 2019 , three purchasers each accounted for more than 10% of our revenue: Shell ( 27% ); Plains ( 23% ); and Vitol ( 15% ). For the year ended December 31, 2018 , three purchasers each accounted for more than 10% of the Company’s revenue: Shell ( 26% ); Koch ( 15% ); and Occidental Energy Marketing Inc. ( 11% ). For the year ended December 31, 2017 , three purchasers each accounted for more than 10% of the Company’s revenue: Shell ( 31% ); Koch ( 19% ); and Enterprise Crude Oil LLC ( 11% ). 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, 2019 , 2018 and 2017 , the Company had no margin tax expense. The Company’s 2015 , 2016 , 2017 , 2018 and 2019 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2019 and 2018 , we had $2 million unrecognized tax benefits. 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, 2019 , 2018 and 2017 , there was no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements. Recent Accounting Pronouncements The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Company’s analysis of the effects on its financial statements: Standard Description Date of Adoption Effect on Financial Statements or Other Significant Matters Recently Adopted Pronouncements ASU 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. Q1 2020 The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses. ASU 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement” This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. Q1 2020 The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels. ASU 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract” This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is requi

ACQUISITIONS AND DIVESTITURES

ACQUISITIONS AND DIVESTITURES	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
ACQUISITIONS AND DIVESTITURES	ACQUISITIONS AND DIVESTITURES 2019 Activity Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen On May 23, 2019, the Company completed its divestiture of 6,589 net acres of certain non-core Permian assets, which were acquired by the Company in its merger with Energen (as described below), for an aggregate sale price of $37 million . This divestiture did no t result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate. On July 1, 2019, the Company completed its divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in the merger with Energen (as described below), for an aggregate sale price of $285 million . This divestiture did no t result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate. 2019 Drop-Down Transaction On July 29, 2019, the Company entered into a definitive purchase agreement to divest certain mineral and royalty interests to Viper for approximately 18.3 million of Viper’s newly-issued Class B units, approximately 18.3 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits (the “Drop-Down”). The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by the Company, and have an average net royalty interest of approximately 3.2% (the “Drop-Down Assets”). The Drop-Down closed on October 1, 2019 and was effective as of July 1, 2019. Viper funded the cash portion of the purchase price of the Drop-Down Assets through a combination of cash on hand and borrowings under Viper LLC’s revolving credit facility. 2018 Activity Tall City Towers LLC On January 31, 2018, Tall City Towers LLC, a subsidiary of the Company, completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporate offices are located for a net purchase price of $110 million . Ajax Resources, LLC On October 31, 2018, the Company completed its acquisition of leasehold interests and related assets of Ajax Resources, LLC, which included approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900 million in cash and approximately 2.6 million shares of the Company’s common stock (the “Ajax acquisition”). This transaction was effective as of July 1, 2018. The cash portion of this transaction was funded through a combination of cash on hand, proceeds from the sale of mineral interests to Viper (described below under the caption “2018 Drop-Down Transaction”), borrowing under the Company’s revolving credit facility and a portion of the proceeds from the Company’s September 2018 senior note offering. See Note 10 —Debt for information relating to this offering. 2018 Drop-down Transaction On August 15, 2018, the Company completed a transaction to sell to Viper mineral interests underlying 32,424 gross ( 1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by the Company, for $175 million . ExL Petroleum Management, LLC and EnergyQuest II LLC On October 31, 2018, the Company completed its acquisitions of leasehold interests and related assets, one with ExL Petroleum Management, LLC and ExL Petroleum Operating, Inc. and one with EnergyQuest II LLC, for an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin for a total of $313 million in cash. These transactions were effective as of August 1, 2018 and were funded through a combination of cash on hand, proceeds from the sale of assets to Viper (described immediately above) and borrowing under the Company’s revolving credit facility. Energen Corporation Merger On November 29, 2018, the Company completed its acquisition of Energen in an all-stock transaction (the “ Merger”), which was accounted for as a business combination. Upon completion of the Merger, the addition of Energen’s assets increased the Company’s assets to: (i) over 273,000 net Tier One acres in the Permian Basin, (ii) approximately 7,200 estimated total net horizontal Permian locations, and (iii) approximately 394,000 net acres across the Midland and Delaware Basins. Under the terms of the Merger, each share of Energen common stock was converted into 0.6442 of a share of the Company’s common stock. The Company issued approximately 62.8 million shares of its common stock valued at a price of $112.00 per share on the closing date, resulting in total consideration paid by the Company to the former Energen shareholders of approximately $7.1 billion . In connection with the closing of the Merger, the Company repaid outstanding principal under Energen’s revolving credit facility and assumed all of Energen’s long-term debt. See Note 10 —Debt for additional information. Purchase Price Allocation The Merger has been accounted for as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price of Energen to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date resulting in no goodwill or bargain purchase gain. The following table sets forth the Company’s purchase price allocation: (In millions) Consideration: Fair value of the Company's common stock issued $ 7,136 Total consideration $ 7,136 Fair value of liabilities assumed: Current liabilities $ 388 Asset retirement obligation 105 Long-term debt 1,099 Noncurrent derivative instruments 17 Deferred income taxes 1,425 Other long-term liabilities 7 Amount attributable to liabilities assumed $ 3,041 Fair value of assets acquired: Total current assets $ 298 Oil and natural gas properties 9,361 Midstream assets 253 Investment in real estate 11 Other property, equipment and land 58 Asset retirement obligation 105 Other postretirement assets 3 Noncurrent income tax receivable, net 76 Other long term assets 12 Amount attributable to assets acquired $ 10,177 The Company has included in its consolidated statements of operations revenues of $102 million and direct operating expenses of $17 million for the period from December 1, 2018 to December 31, 2018 due to the acquisition. Pro Forma Financial Information The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the years ended December 31, 2018 and 2017 have been prepared to give effect to the Merger as if it had occurred on January 1, 2017. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Energen’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Energen’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Energen’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $37 million for the year ended December 31, 2018 and acquisition-related costs incurred by Energen of $59 million . The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Energen assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material. The pro forma consolidated statement of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2017 and is not intended to be a projection of future results. Year Ended December 31, 2018 2017 (in millions, except per share amounts) Revenues $ 3,532 $ 2,196 Income from operations 1,559 900 Net income 1,320 875 Basic earnings per common share $ 7.54 $ 5.26 Diluted earnings per common share $ 7.53 $ 5.24 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 $1.7 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 $48 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 millions) Proved oil and natural gas properties $ 386 Unevaluated oil and natural gas properties 2,123 Midstream assets 47 Prepaid capital costs 4 Oil inventory 1 Revenues and royalties payable (10 ) Asset retirement obligations (2 ) Total fair value of net assets $ 2,549 The Company has included in its consolidated statements of operations revenues of $81 million and direct operating expenses of $24 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 years 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 millions, except per share amounts) Revenues $ 1,228 $ 627 Income (loss) from operations 619 (13 ) Net income (loss) 473 (109 ) Basic earnings per common share $ 4.85 $ (1.45 ) Diluted earnings per common share $ 4.84 $ (1.45 )

VIPER ENERGY PARTNERS LP

VIPER ENERGY PARTNERS LP	12 Months Ended
	Dec. 31, 2019
Noncontrolling Interest [Abstract]
VIPER ENERGY PARTNERS LP	VIPER ENERGY PARTNERS LP Viper is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. Viper was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. Viper 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 general partner interest in, Viper. As of December 31, 2019 , the Company owned approximately 58% of Viper’s total units outstanding. During the year ended December 31, 2019 , Diamondback received distributions of $133 million in respect of its interests in Viper and Viper LLC. Viper completed the following equity offerings during the years ended December 31, 2019 , 2018 and 2017 : Date Number of Units of Common Units Sold Number of Units of Common Units Issued to Underwriters Proceeds Received by Viper Amount Repaid on Viper LLC’s Credit Facility (in millions) January 2017 9,775,000 1,275,000 $ 148 $ 121 July 2017 (1) 16,100,000 2,100,000 $ 232 $ 153 July 2018 10,080,000 1,080,000 $ 303 $ 362 March 2019 10,925,000 1,425,000 $ 341 $ 314 (1) In this offering, Diamondback 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. As a result of Viper’s public offerings, Viper’s issuance of units for acquisitions and Viper’s issuance of unit-based compensation, the Company’s ownership percentage in Viper was reduced. During the year ended December 31, 2019 , the Company recorded a $45 million decrease to non-controlling interest in Viper with an increase to additional paid-in capital, which represents the difference between the Company’s share of the underlying net book value in Viper before and after the respective Partnership common unit transactions, on the Company’s consolidated balance sheet. Recapitalization, Tax Status Election and Related Transactions by Viper In March 2018, Viper announced that the Board of Directors of the General Partner had unanimously approved a change of Viper’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 Viper (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of the Operating Company, (iii) amended and restated its existing registration rights agreement with the Company and (iv) entered into an exchange agreement with the Company, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, the Company delivered and assigned to Viper the 73,150,000 common units the Company owned in exchange for (i) 73,150,000 of Viper’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, Viper continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and the Company owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of Viper’s July 2018 offering of units, it owned approximately 41% of the outstanding units issued by the Operating Company and the Company owned the remaining approximately 59% . The Operating Company units and Viper’s Class B units owned by the Company are exchangeable from time to time for Viper’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit). On May 10, 2018, the change in Viper’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1 million to Viper in respect of its general partner interest and (ii) the Company made a cash capital contribution of $1 million to Viper in respect of the Class B units. The Company, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, the Company also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of Viper and a cash amount of $10,000 representing a proportionate return of the $1 million invested capital in respect of the Class B units. The General Partner continues to serve as Viper’s general partner and the Company continues to control Viper. After the effectiveness of the tax status election and the completion of related transactions, Viper’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to Viper’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to Viper’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and Viper’s Current Report on Form 8-K filed with the SEC on May 15, 2018. Partnership Agreement The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Viper Partnership Agreement”), requires Viper to reimburse Viper’s General Partner for all direct and indirect expenses incurred or paid on Viper’s behalf and all other expenses allocable to Viper or otherwise incurred by Viper’s General Partner in connection with operating Viper’s business. The Viper Partnership Agreement does not set a limit on the amount of expenses for which Viper’s 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 Viper or on its behalf and expenses allocated to Viper’s General Partner by its affiliates. Viper’s General Partner is entitled to determine the expenses that are allocable to Viper. For each of the year ended December 31, 2019 and 2018 , Viper’s General Partner allocated $3 million and $2 million , respectively, to Viper. Tax Sharing In connection with the closing of the Viper Offering, Viper entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which Viper agreed to reimburse Diamondback for its share of state and local income and other taxes for which Viper’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 Viper 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 Viper may be a member for this purpose, to owe less or no tax. In such a situation, Viper agreed to reimburse Diamondback for the tax Viper would have owed had the tax attributes not been available or used for Viper’s benefit, even though Diamondback had no cash tax expense for that period. For the year ended December 31, 2019 , Viper did no t accrue any state income tax expense. For the year ended December 31, 2018 , Viper accrued a minimal amount for its share of Texas margin tax for which Viper’s results are included in a combined tax return filed by Diamondback. Viper LLC’s Revolving Credit Facility Viper 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 10 —Debt for a description of this credit facility. Rattler is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR”. Rattler was formed by Diamondback in July 2018 to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Rattler’s General Partner, a wholly-owned subsidiary of Diamondback, serves as the general partner of Rattler. As of December 31, 2019 , Diamondback owned approximately 71% of Rattler’s total units outstanding. Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May of 2019, Diamondback owned all of the general and limited partner interests in Rattler. The Rattler Offering consisted of 43,700,000 common units representing approximately 29% of the limited partner interests in Rattler at a price to the public of $17.50 per common unit, which included 5,700,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms which closed on May 30, 2019. Rattler received net proceeds of approximately $720 million from the sale of these common units, after deducting offering expenses and underwriting discounts and commissions. In connection with the completion of the Rattler Offering, Rattler (i) issued 107,815,152 Class B Units representing an aggregate 71% voting limited partner interest in Rattler in exchange for a $1 million cash contribution from Diamondback, (ii) issued a general partner interest in Rattler to Rattler’s General Partner, in exchange for a $1 million cash contribution from Rattler’s General Partner, and (iii) caused Rattler LLC to make a distribution of approximately $727 million to Diamondback. Diamondback, as the holder of the Class B units, and Rattler’s General Partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1 million capital contributions, payable quarterly. Diamondback has also entered into the following agreements with Rattler: Rattler’s Partnership Agreement In connection with the closing of the Rattler Offering, Rattler’s General Partner and Energen Resources entered into the first amended and restated agreement of limited partnership of Rattler, dated May 28, 2019 (the “Rattler Partnership Agreement”). The Rattler Partnership Agreement requires Rattler to reimburse Rattler’s General Partner for all direct and indirect expenses incurred or paid on Rattler’s behalf and all other expenses allocable to Rattler or otherwise incurred by Rattler’s General Partner in connection with operating Rattler’s business. The Rattler Partnership Agreement does not set a limit on the amount of expenses for which its 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 Rattler or on its behalf and expenses allocated to Rattler’s General Partner by its affiliates. Rattler’s General Partner is entitled to determine the expenses that are allocable to Rattler. For the year ended December 31, 2019 , Rattler’s General Partner allocated $364,342 of such expenses to Rattler. Rattler’s Services and Secondment Agreement In connection with the closing of the Rattler Offering, Rattler entered into a services and secondment agreement with Diamondback, Diamondback E&P LLC, Rattler’s General Partner and Rattler LLC, dated as of May 28, 2019 (the “Services and Secondment Agreement”). Pursuant to the Services and Secondment Agreement, Diamondback and its subsidiaries second certain operational, construction, design and management employees and contractors of Diamondback to Rattler’s General Partner, Rattler and its subsidiaries, providing management, maintenance and operational functions with respect to Rattler’s assets. The Services and Secondment Agreement requires Rattler’s General Partner and Rattler to reimburse Diamondback for the cost of the seconded employees and contractors, including their wages and benefits. For the year ended December 31, 2019 , Rattler’s General Partner and Rattler paid Diamondback $5 million under the Services and Secondment Agreement. Rattler’s Tax Sharing Agreement In connection with the closing of the Rattler Offering, Rattler LLC entered into a tax sharing agreement with Diamondback pursuant to which Rattler LLC will reimburse Diamondback for its share of state and local income and other taxes borne by Diamondback as a result of Rattler LLC’s results being included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on May 28, 2019. The amount of any such reimbursement is limited to the tax that Rattler LLC would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which Rattler LLC may be a member for this purpose, to owe less or no tax. In such a situation, Rattler LLC agreed to reimburse Diamondback for the tax Rattler LLC would have owed had the attributes not been available or used for Rattler LLC’s benefit, even though Diamondback had no cash expense for that period. For the year ended December 31, 2019 , Rattler accrued state income tax expense of $188,808 for its share of Texas margin tax for which Rattler’s share of Rattler LLC’s results are included in a combined tax return filed by Diamondback. Rattler LLC’s Revolving Credit Facility Rattler LLC has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, sole book runner and lead arranger. See Note 10 — Debt for a description of this credit facility.

RATTLER MIDSTREAM LP

RATTLER MIDSTREAM LP	12 Months Ended
	Dec. 31, 2019
Noncontrolling Interest [Abstract]
RATTLER MIDSTREAM LP	VIPER ENERGY PARTNERS LP Viper is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. Viper was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. Viper 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 general partner interest in, Viper. As of December 31, 2019 , the Company owned approximately 58% of Viper’s total units outstanding. During the year ended December 31, 2019 , Diamondback received distributions of $133 million in respect of its interests in Viper and Viper LLC. Viper completed the following equity offerings during the years ended December 31, 2019 , 2018 and 2017 : Date Number of Units of Common Units Sold Number of Units of Common Units Issued to Underwriters Proceeds Received by Viper Amount Repaid on Viper LLC’s Credit Facility (in millions) January 2017 9,775,000 1,275,000 $ 148 $ 121 July 2017 (1) 16,100,000 2,100,000 $ 232 $ 153 July 2018 10,080,000 1,080,000 $ 303 $ 362 March 2019 10,925,000 1,425,000 $ 341 $ 314 (1) In this offering, Diamondback 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. As a result of Viper’s public offerings, Viper’s issuance of units for acquisitions and Viper’s issuance of unit-based compensation, the Company’s ownership percentage in Viper was reduced. During the year ended December 31, 2019 , the Company recorded a $45 million decrease to non-controlling interest in Viper with an increase to additional paid-in capital, which represents the difference between the Company’s share of the underlying net book value in Viper before and after the respective Partnership common unit transactions, on the Company’s consolidated balance sheet. Recapitalization, Tax Status Election and Related Transactions by Viper In March 2018, Viper announced that the Board of Directors of the General Partner had unanimously approved a change of Viper’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 Viper (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of the Operating Company, (iii) amended and restated its existing registration rights agreement with the Company and (iv) entered into an exchange agreement with the Company, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, the Company delivered and assigned to Viper the 73,150,000 common units the Company owned in exchange for (i) 73,150,000 of Viper’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, Viper continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and the Company owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of Viper’s July 2018 offering of units, it owned approximately 41% of the outstanding units issued by the Operating Company and the Company owned the remaining approximately 59% . The Operating Company units and Viper’s Class B units owned by the Company are exchangeable from time to time for Viper’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit). On May 10, 2018, the change in Viper’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1 million to Viper in respect of its general partner interest and (ii) the Company made a cash capital contribution of $1 million to Viper in respect of the Class B units. The Company, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, the Company also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of Viper and a cash amount of $10,000 representing a proportionate return of the $1 million invested capital in respect of the Class B units. The General Partner continues to serve as Viper’s general partner and the Company continues to control Viper. After the effectiveness of the tax status election and the completion of related transactions, Viper’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to Viper’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to Viper’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and Viper’s Current Report on Form 8-K filed with the SEC on May 15, 2018. Partnership Agreement The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Viper Partnership Agreement”), requires Viper to reimburse Viper’s General Partner for all direct and indirect expenses incurred or paid on Viper’s behalf and all other expenses allocable to Viper or otherwise incurred by Viper’s General Partner in connection with operating Viper’s business. The Viper Partnership Agreement does not set a limit on the amount of expenses for which Viper’s 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 Viper or on its behalf and expenses allocated to Viper’s General Partner by its affiliates. Viper’s General Partner is entitled to determine the expenses that are allocable to Viper. For each of the year ended December 31, 2019 and 2018 , Viper’s General Partner allocated $3 million and $2 million , respectively, to Viper. Tax Sharing In connection with the closing of the Viper Offering, Viper entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which Viper agreed to reimburse Diamondback for its share of state and local income and other taxes for which Viper’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 Viper 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 Viper may be a member for this purpose, to owe less or no tax. In such a situation, Viper agreed to reimburse Diamondback for the tax Viper would have owed had the tax attributes not been available or used for Viper’s benefit, even though Diamondback had no cash tax expense for that period. For the year ended December 31, 2019 , Viper did no t accrue any state income tax expense. For the year ended December 31, 2018 , Viper accrued a minimal amount for its share of Texas margin tax for which Viper’s results are included in a combined tax return filed by Diamondback. Viper LLC’s Revolving Credit Facility Viper 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 10 —Debt for a description of this credit facility. Rattler is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR”. Rattler was formed by Diamondback in July 2018 to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Rattler’s General Partner, a wholly-owned subsidiary of Diamondback, serves as the general partner of Rattler. As of December 31, 2019 , Diamondback owned approximately 71% of Rattler’s total units outstanding. Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May of 2019, Diamondback owned all of the general and limited partner interests in Rattler. The Rattler Offering consisted of 43,700,000 common units representing approximately 29% of the limited partner interests in Rattler at a price to the public of $17.50 per common unit, which included 5,700,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms which closed on May 30, 2019. Rattler received net proceeds of approximately $720 million from the sale of these common units, after deducting offering expenses and underwriting discounts and commissions. In connection with the completion of the Rattler Offering, Rattler (i) issued 107,815,152 Class B Units representing an aggregate 71% voting limited partner interest in Rattler in exchange for a $1 million cash contribution from Diamondback, (ii) issued a general partner interest in Rattler to Rattler’s General Partner, in exchange for a $1 million cash contribution from Rattler’s General Partner, and (iii) caused Rattler LLC to make a distribution of approximately $727 million to Diamondback. Diamondback, as the holder of the Class B units, and Rattler’s General Partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1 million capital contributions, payable quarterly. Diamondback has also entered into the following agreements with Rattler: Rattler’s Partnership Agreement In connection with the closing of the Rattler Offering, Rattler’s General Partner and Energen Resources entered into the first amended and restated agreement of limited partnership of Rattler, dated May 28, 2019 (the “Rattler Partnership Agreement”). The Rattler Partnership Agreement requires Rattler to reimburse Rattler’s General Partner for all direct and indirect expenses incurred or paid on Rattler’s behalf and all other expenses allocable to Rattler or otherwise incurred by Rattler’s General Partner in connection with operating Rattler’s business. The Rattler Partnership Agreement does not set a limit on the amount of expenses for which its 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 Rattler or on its behalf and expenses allocated to Rattler’s General Partner by its affiliates. Rattler’s General Partner is entitled to determine the expenses that are allocable to Rattler. For the year ended December 31, 2019 , Rattler’s General Partner allocated $364,342 of such expenses to Rattler. Rattler’s Services and Secondment Agreement In connection with the closing of the Rattler Offering, Rattler entered into a services and secondment agreement with Diamondback, Diamondback E&P LLC, Rattler’s General Partner and Rattler LLC, dated as of May 28, 2019 (the “Services and Secondment Agreement”). Pursuant to the Services and Secondment Agreement, Diamondback and its subsidiaries second certain operational, construction, design and management employees and contractors of Diamondback to Rattler’s General Partner, Rattler and its subsidiaries, providing management, maintenance and operational functions with respect to Rattler’s assets. The Services and Secondment Agreement requires Rattler’s General Partner and Rattler to reimburse Diamondback for the cost of the seconded employees and contractors, including their wages and benefits. For the year ended December 31, 2019 , Rattler’s General Partner and Rattler paid Diamondback $5 million under the Services and Secondment Agreement. Rattler’s Tax Sharing Agreement In connection with the closing of the Rattler Offering, Rattler LLC entered into a tax sharing agreement with Diamondback pursuant to which Rattler LLC will reimburse Diamondback for its share of state and local income and other taxes borne by Diamondback as a result of Rattler LLC’s results being included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on May 28, 2019. The amount of any such reimbursement is limited to the tax that Rattler LLC would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which Rattler LLC may be a member for this purpose, to owe less or no tax. In such a situation, Rattler LLC agreed to reimburse Diamondback for the tax Rattler LLC would have owed had the attributes not been available or used for Rattler LLC’s benefit, even though Diamondback had no cash expense for that period. For the year ended December 31, 2019 , Rattler accrued state income tax expense of $188,808 for its share of Texas margin tax for which Rattler’s share of Rattler LLC’s results are included in a combined tax return filed by Diamondback. Rattler LLC’s Revolving Credit Facility Rattler LLC has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, sole book runner and lead arranger. See Note 10 — Debt for a description of this credit facility.

REAL ESTATE ASSETS

REAL ESTATE ASSETS	12 Months Ended
	Dec. 31, 2019
Real Estate [Abstract]
REAL ESTATE ASSETS	REAL ESTATE ASSETS In conjunction with Diamondback’s acquisition of Fasken Towers Tall Towers, the Company allocated the $110 million purchase price between real estate assets and intangible lease assets related to in-place and above-market leases. In addition, the Company owns $10 million in office buildings. The following schedules present the cost and related accumulated depreciation or amortization (as applicable) of Diamondback’s real estate assets including intangible lease assets: Estimated Useful Lives December 31, 2019 2018 (Years) (in millions) Buildings 20-30 $ 102 $ 103 Tenant improvements 15 5 4 Land N/A 2 1 Land improvements 15 1 1 Total real estate assets 110 109 Less: accumulated depreciation (9 ) (4 ) Total investment in land and buildings, net $ 101 $ 105 Weighted Average Useful Lives December 31, 2019 2018 (Months) (in millions) In-place lease intangibles 45 $ 11 $ 11 Less: accumulated amortization (6 ) (3 ) In-place lease intangibles, net 5 8 Above-market lease intangibles 45 4 4 Less: accumulated amortization (1 ) (1 ) Above-market lease intangibles, net 3 3 Total intangible lease assets, net $ 8 $ 11

PROPERTY AND EQUIPMENT

PROPERTY AND EQUIPMENT	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
PROPERTY AND EQUIPMENT	PROPERTY AND EQUIPMENT Property and equipment includes the following: December 31, 2019 2018 (in millions) Oil and natural gas properties: Subject to depletion $ 16,575 $ 12,629 Not subject to depletion 9,207 9,670 Gross oil and natural gas properties 25,782 22,299 Accumulated depletion (2,995 ) (1,599 ) Accumulated impairment (1,934 ) (1,144 ) Oil and natural gas properties, net 20,853 19,556 Midstream assets 931 700 Other property, equipment and land 125 147 Accumulated depreciation (74 ) (31 ) Property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 21,835 $ 20,372 Balance of costs not subject to depletion: Incurred in 2019 $ 604 Incurred in 2018 5,654 Incurred in 2017 2,329 Incurred in 2016 620 Total not subject to depletion $ 9,207 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 $49 million , $29 million and $22 million for the years ended December 31, 2019 , 2018 and 2017 , 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. 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. As a result of the decline in commodity prices during 2019, the Company recorded a non-cash ceiling test impairment for the year ended December 31, 2019 of $790 million which was included in accumulated depletion. The impairment charge 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. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2018 . At December 31, 2019 , there was $228 million in exploration costs and development costs and $118 million in capitalized interest that are not subject to depletion. At December 31, 2018 , there were $68 million exploration costs and development costs and $55 million capitalized interest that are not subject to depletion.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 (in millions) Asset retirement obligations, beginning of period $ 136 $ 21 $ 17 Additional liabilities incurred 8 3 2 Liabilities acquired 4 111 2 Liabilities settled (61 ) (2 ) (1 ) Accretion expense 7 2 1 Revisions in estimated liabilities — 1 — Asset retirement obligations, end of period 94 136 21 Less current portion — — 1 Asset retirement obligations - long-term $ 94 $ 136 $ 20 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

EQUITY METHOD INVESTMENTS	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
EQUITY METHOD INVESTMENTS	EQUITY METHOD INVESTMENTS At December 31, 2019 and 2018 , Rattler had the following investments: Net Ownership Interest December 31, 2019 December 31, 2018 (In millions) EPIC Crude Holdings, LP 10 % $ 110 $ — Gray Oak Pipeline, LLC 10 % 115 1 Wink to Webster Pipeline LLC 4 % 34 — OMOG JV LLC 60 % 219 — Amarillo Rattler, LLC 50 % 1 — $ 479 $ 1 The following summarizes the income (loss) of equity method investees for the periods presented: Year Ended December 31, 2019 2018 2017 (In millions) EPIC Crude Holdings, LP $ (6 ) $ — $ — Gray Oak Pipeline, LLC 1 — — Wink to Webster Pipeline LLC (1 ) — — OMOG JV LLC — — — HMW LLC — — 1 $ (6 ) $ — $ 1 In October 2014, the Company acquired a 25% interest in HMW Fluid Management LLC (“HMW 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. On June 30, 2018, HMW LLC’s operating agreement was amended. As a result of the amendment, Rattler no longer recognizes an equity investment in HMW LLC but instead consolidates its undivided interest in the produced water disposal (“PWD”) assets owned by HMW LLC. In exchange for Rattler’s 25% investment, Rattler received a 50% undivided ownership interest in two of the four PWD wells and associated assets previously owned by HMW LLC. Rattler’s basis in the assets is equivalent to its basis in the equity investment in HMW LLC. On February 1, 2019, Rattler LLC acquired a 10% equity interest in EPIC Crude Holdings, LP (“EPIC”), which is building a pipeline (the “EPIC project”) that, once fully operational, will transport crude and NGL across Texas for delivery into the Corpus Christi market. The EPIC project began initial operations during the third quarter of 2019. On February 15, 2019, Rattler LLC acquired a 10% equity interest in Gray Oak Pipeline, LLC (“Gray Oak”), which is building a pipeline (the “Gray Oak project”) that, once operational, will transport crude from the Permian to Corpus Christi on the Texas Gulf Coast. The Gray Oak project began initial operations during the fourth quarter of 2019. On March 29, 2019, Rattler LLC executed a short-term promissory note to Gray Oak. The note allows for borrowing by Gray Oak of up to $123 million at 2.52% interest rate with a maturity date of March 31, 2022. During the year ended December 31, 2019 , there were $23 million in borrowings and repayments under this note. The short-term promissory note was repaid on May 31, 2019. On June 4, 2019, Rattler entered into an equity contribution agreement with respect to Gray Oak. The equity contribution agreement requires Rattler to contribute equity or make loans to Gray Oak so that Gray Oak can, to the extent necessary, cure payment defaults under Gray Oak’s credit agreement and, in certain instances, repay Gray Oak’s credit agreement in full. Rattler’s obligations under the equity contribution agreement are limited to its proportionate ownership interest in Gray Oak, and such obligations are guaranteed by Rattler LLC, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. On July 30, 2019, Rattler LLC joined Wink to Webster Pipeline LLC as a 4% member, together with affiliates of ExxonMobil, Plains All American Pipeline, Delek US, MPLX LP and Lotus Midstream. The joint venture is developing a crude oil pipeline with origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations (the “Wink to Webster project”). The Wink to Webster project is expected to begin service in the first half of 2021. On October 1, 2019, Rattler LLC acquired a 60% equity interest in OMOG JV LLC (“OMOG”). On November 7, 2019, OMOG acquired 100% of Reliance Gathering, LLC which operates a crude oil gathering system in the Permian, and was renamed as Oryx Midland Oil Gathering LLC following the acquisition. While Rattler’s equity interest is 60% , the investment is accounted for as an equity method investment as Rattler does not control operating activities and substantive participating rights exist with the controlling minority investor. On December 20, 2019, Rattler LLC acquired a 50% equity interest in Amarillo Rattler LLC, which currently owns and operates the Yellow Rose gas gathering and processing system with estimated total processing capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. This joint venture also intends to construct and operate a new 60,000 Mcf/d cryogenic natural gas processing plant in Martin County, Texas. While Rattler’s equity interest is 50% , the investment is accounted for as an equity method investment as Rattler does not control operating activities and substantive participating rights exist with the controlling investor. No impairments were recorded for Rattler’s equity method investments for the year ended December 31, 2019 or 2018 . At December 31, 2019 , there was $1 million

DEBT

DEBT	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
DEBT	DEBT Long-term debt consisted of the following as of the dates indicated: December 31, 2019 2018 (in millions) 4.625% Notes due 2021 $ 399 $ 400 7.320% Medium-term Notes, Series A, due 2022 21 20 2.875% Senior Notes due 2024 1,000 — 4.750% Senior Notes due 2024 — 1,250 5.375% Senior Notes due 2025 800 800 3.250% Senior Notes due 2026 800 — 7.350% Medium-term Notes, Series A, due 2027 11 10 7.125% Medium-term Notes, Series B, due 2028 108 100 3.500% Senior Notes due 2029 1,200 — DrillCo Agreement 39 — Unamortized debt issuance costs (19 ) (27 ) Unamortized discount costs (31 ) — Unamortized premium costs 9 10 Revolving credit facility 13 1,490 Viper revolving credit facility 97 411 Viper 5.375% Senior Notes due 2027 500 — Rattler revolving credit facility 424 — Total long-term debt $ 5,371 $ 4,464 Diamondback Notes 4.750% Senior Notes On October 28, 2016, the Company issued $500 million in aggregate principal amount of 4.750% senior notes due 2024 (“4.750% senior notes”), under an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee. On September 25, 2018, the Company issued $750 million aggregate principal amount of new 4.750% senior notes as additional notes under, and subject to the terms of, the same indenture governing the 4.750% senior notes. The Company received approximately $741 million in net proceeds, after deducting the initial purchasers’ discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the new 4.750% senior notes. The Company used a portion of the net proceeds from the issuance of the new 4.750% senior notes to repay a portion of the outstanding borrowings its revolving credit facility and the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of certain assets from Ajax Resources, LLC.. On December 20, 2019, the Company redeemed all of the outstanding 4.750% senior notes. The redemption payment (the “Redemption Payment”) included $1.25 billion of outstanding principal at a redemption price of 103.563% of the principal amount of the 4.750% senior notes, plus accrued and unpaid interest on the outstanding principal amount to the Redemption Date. On December 5, 2019, the indenture governing the 4.750% senior notes was fully satisfied and discharged and the guarantors were released from their guarantees of the 4.750% senior notes. The Company funded the Redemption Payment with a portion of the net proceeds from the issuance of the December 2019 Notes. The 4.750% senior notes bore 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 would have matured on November 1, 2024. All of our restricted subsidiaries that guaranteed our revolving credit facility guaranteed the 4.750% senior notes; provided, however, that the 4.750% senior notes were not guaranteed by Viper, Viper’s General Partner, Viper LLC, Rattler, Rattler’s General Partner or Rattler LLC. 2025 Senior Notes On December 20, 2016, the Company issued $500 million in aggregate principal amount of 5.375% senior notes due 2025 (the “existing 2025 notes”), under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee (the “2025 indenture”). On January 29, 2018, the Company issued $300 million aggregate principal amount of new 5.375% senior notes due 2025 as additional notes under the 2025 indenture (the “new 2025 notes” and, together with the existing 2025 notes, the 2025 senior notes). The Company received approximately $308 million in net proceeds, after deducting the initial purchaser’s discount and the Company’s estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. The Company used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under its revolving credit facility. 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 and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility guarantee the 2025 senior notes. Currently, the 2025 senior notes are not guaranteed by any of the Company’s subsidiaries other than Diamondback O&G LLC and will not be guaranteed by any of the Company’s future 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. December 2019 Notes Offering On December 5, 2019, the Company issued $1.0 billion in aggregate principal amount of 2.875% senior notes due 2024 (the “2024 notes”), $800 million in aggregate principal amount of 3.250% senior notes due 2026 (the “2026 notes”), and $1.2 billion aggregate principal amount of 3.500% senior notes due 2029, (the “2029 notes” and, together with the 2024 notes and the 2026 notes, the “December 2019 Notes”). The 2024 notes will mature on December 1, 2024, the 2026 notes will mature on December 1, 2026 and the 2029 notes will mature on December 1, 2029. Interest will accrue and be payable semi-annually, in arrears on June 1 and December 1 of each year, commencing on June 1, 2020. The December 2019 Notes are fully and unconditionally guaranteed by Diamondback O&G LLC and are not guaranteed by any of the Company’s other subsidiaries. The December 2019 Notes were issued under an indenture, dated as of December 5, 2019, among the Company and Wells Fargo, as the trustee, as supplemented by the first supplemental indenture dated as of December 5, 2019 (the “December 2019 Notes Indenture”). The C ompany may redeem (i) the 2024 Notes in whole or in part at any time prior to November 1, 2024 (one month prior to the maturity date of the 2024 Notes), (ii) the 2026 Notes in whole or in part at any time prior to October 1, 2026 (two months prior to the maturity date of the 2026 Notes) and (iii) the 2029 Notes in whole or in part at any time prior to September 1, 2029 (three months prior to the maturity date of the 2029 Notes) (each such date, a “par call date”), in each case at the redemption price set forth in the indenture governing the December 2019 Notes. If the December 2019 Notes are redeemed on or after their respective par call dates, in each case, such December 2019 Notes will be redeemed at a redemption price equal to 100% of the principal amount of the December 2019 Notes to be redeemed plus interest accrued thereon to but not including the redemption date. Upon the occurrence of a Change of Control Triggering Event (as defined in the indenture governing the December 2019 Notes), holders may require the Company to purchase some or all of their December 2019 Notes for cash at a price equal to 101% of the principal amount of the December 2019 Notes being purchased, plus accrued and unpaid interest, if any, to the date of purchase. The indenture governing the December 2019 Notes contains customary terms and covenants, including limitations on the Company’s ability and the ability of certain of its subsidiaries to incur liens securing funded indebtedness and on the Company’s ability to consolidate, merge or sell, convey, transfer or lease all or substantially all of its assets. Second Amended and Restated 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, 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. On June 28, 2019, the credit agreement was amended pursuant to an eleventh amendment, which implemented certain changes to the credit facility for the period on and after the date on which our unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied (the “investment grade changeover date”). On November 20, 2019, Diamondback O&G LLC caused Diamondback O&G LLC to deliver a notice as borrower under the revolving credit facility to trigger the “investment grade changeover date.” As of December 31, 2019, the maximum credit amount available under the credit agreement is $2.0 billion . As of December 31, 2019 , the Company had approximately $13 million of outstanding borrowings under its revolving credit facility and $1.99 billion available for future borrowings under the revolving credit facility. Diamondback O&G LLC is the borrower under the credit agreement, and, as of December 31, 2019, the credit agreement is guaranteed by Diamondback Energy, Inc. None of the Company’s other subsidiaries are guarantors under the revolving credit facility. On December 5, 2019, Diamondback O&G LLC delivered a letter notifying the administrative agent under the credit agreement that as of such date, each of the guarantors, other than Diamondback Energy, Inc., ceased to be a guarantor under the credit agreement. The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to the 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 with range from 0.125% to 1.0% per annum and from 1.125% to 2.0% per annum in the case of LIBOR, in each case, depending on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage). Loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment due to any termination or reduction of the aggregate maximum credit amount and (b) at the maturity date of November 1, 2022. The credit agreement contains a financial covenant that requires us to maintain a Total Net Debt to Capitalization Ratio (as defined in the credit agreement) of no more than 65% . Our non-guarantor restricted subsidiaries may incur debt for borrowed money in an aggregate principal amount up to 15% of consolidated net tangible assets (as defined in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets. As of December 31, 2019 and 2018 , the Company was in compliance with all financial covenants under the revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the 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. Energen Notes At the effective time of the Merger, Energen became the Company’s wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530 million in notes (the “Energen Notes”), issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee (the “Energen Indenture”). As of December 31, 2019 , the Energen Notes consist of: (1) $399 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (2) $108 million of 7.125% notes due on February 15, 2028, (3) $21 million of 7.32% notes due on July 28, 2022, and (4) $11 million of 7.35% notes due on July 28, 2027. The Energen Notes are the senior unsecured obligations of Energen and, post-merger, Energen, as a wholly owned subsidiary, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen if any, and are effectively subordinated to Energen’s senior secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness. Neither we nor any of our subsidiaries guarantee the Energen Notes. The Energen Indenture contains certain covenants that, subject to certain exceptions and qualifications, limit Energen’s ability to incur or suffer to exist liens, to enter into sale and leaseback transactions, to consolidate with or merge into any other entity, and to convey, transfer or lease its properties and assets substantially as an entirety to any person or entity. The Energen Indenture not include a restriction on the payment of dividends. On November 29, 2018, Energen guaranteed the Company’s indebtedness under its credit facility and granted a lien on certain of its assets to secure such indebtedness, and on December 21, 2018, Energen’s subsidiaries guaranteed the Company’s indebtedness under its credit agreement and granted liens on certain of their assets to secure such indebtedness. As a result of such guarantees, under the terms of and the 2025 Indenture, Energen is also a guarantor of the 2025 Senior Notes. Viper’s Facility - Wells Fargo Bank On July 20, 2018, Viper LLC, as borrower, entered into an amended and restated credit agreement with Viper, as guarantor, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended (the “Viper credit agreement”), provides for a revolving credit facility in the maximum credit amount of $2 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $775 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 LLC and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12 -month period. In connection with Viper’s fall redetermination in November 2019, the borrowing base under the Viper credit agreement was increased to $775 million . As of December 31, 2019 , the borrowing base was set at $775 million , and Viper LLC had $97 million of outstanding borrowings and $678 million available for future borrowings under the Viper credit agreement. The outstanding borrowings under the Viper credit agreement bear interest at a per annum rate elected by Viper LLC 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. Viper LLC 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 assets of Viper and Viper LLC. The Viper 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, purchases of margin stock and entering into certain swap agreements and require the maintenance of the financial ratios described below. Financial Covenant Required Ratio Ratio of total net debt to EBITDAX, as defined in the Viper credit agreement Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined the Viper 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 $1.0 billion 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. The covenant limiting dividends and distributions includes an exception allowing Viper LLC to make distributions if no default, event of default or borrowing base deficiency exists. As of December 31, 2019 and 2018 , Viper and Viper LLC were in compliance with all financial covenants under the Viper credit agreement, as then in effect. The lenders may accelerate all of the indebtedness under the Viper credit agreement upon the occurrence and during the continuance of any event of default. The Viper credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. Viper’s Notes On October 16, 2019, Viper completed an offering in which it issued its 5.375% Senior Notes due 2027 in aggregate principal amount of $500 million (the “Viper Notes”). Viper received gross proceeds of $500 million from the such offering, which it loaned to Viper LLC. Viper LLC paid the expenses of the offering, resulting in net proceeds of the offering of $490 million , which Viper LLC used to pay down borrowings under the Viper credit agreement. The Viper Notes were issued under an indenture, dated as of October 16, 2019, among Viper, as issuer, Viper LLC, as guarantor and Wells Fargo, as trustee (the “Viper Indenture”). Pursuant to the Viper Indenture and the Viper Notes, interest on the Viper Notes accrues at a rate of 5.375% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2020. The Viper Notes will mature on November 1, 2027. Viper LLC guarantees the Viper Notes pursuant to the Viper Indenture. Neither the Company nor any of its other subsidiaries guarantee the Viper Notes. The Viper Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Viper’s ability and the ability of its restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events. Rattler’s Credit Agreement In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo Bank, as administrative agent, and a syndicate of banks, as lenders party thereto (the “Rattler credit agreement”). The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million . Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid at the maturity date of May 28, 2024. The Rattler credit agreement is guaranteed by Rattler, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. As of December 31, 2019 , Rattler LLC had $424 million of outstanding borrowings and $176 million available for future borrowings under the Rattler credit agreement. The outstanding borrowings under the Rattler credit agreement bear interest at a per annum rate elected by Rattler LLC that is based on the prime rate or LIBOR, in each case plus an applicable margin. The applicable margin ranges from 0.250% to 1.250% per annum for prime-based loans and 1.250% to 2.250% per annum for LIBOR loans, in each case depending on the Consolidated Total Leverage Ratio (as defined in the Rattler credit agreement). Rattler LLC is obligated to pay a quarterly commitment fee ranging from 0.250% to 0.375% per annum on the unused portion of the commitment, which fee is also dependent on the Consolidated Total Leverage Ratio. The Rattler credit agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, distributions and other restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case of Rattler, Rattler LLC and their restricted subsidiaries. The covenants are subject to exceptions set forth in the Rattler credit agreement, including an exception allowing Rattler LLC or Rattler to issue unsecured debt securities and an exception allowing payment of distributions if no default exists. The Rattler credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below: Financial Covenant Required Ratio Consolidated Total Leverage Ratio commencing with the fiscal quarter ending September 30, 2019 Not greater than 5.00 to 1.00 (or not greater than 5.50 to 1.00 for 3 fiscal quarters following certain acquisitions), but if the Consolidated Senior Secured Leverage Ratio (as defined in the Rattler credit agreement) is applicable, then not greater than 5.25 to 1.00) Consolidated Senior Secured Leverage Ratio commencing with the last day of any fiscal quarter in which the Financial Covenant Election (as defined in the Rattler credit agreement) is made Not greater than 3.50 to 1.00 Consolidated Interest Coverage Ratio (as defined in the Rattler credit agreement) commencing with the fiscal quarter ending September 30, 2019 Not less than 2.50 to 1.00 For purposes of calculating the financial maintenance covenants prior to the fiscal quarter ending June 30, 2020, EBITDA (as defined in the Rattler credit agreement) will be annualized based on the actual EBITDA for the preceding fiscal quarters starting with the fiscal quarter ending September 30, 2019. As of December 31, 2019 , Rattler and Rattler LLC were in compliance with all financial covenants under the Rattler credit agreement. The lenders may accelerate all of the indebtedness under the Rattler credit agreement upon the occurrence and during the continuance of any event of default. The Rattler credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control. Alliance with Obsidian Resources, L.L.C. The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. Funds managed by CEMOF and its affiliates have agreed to commit to funding certain costs out of CEMOF’s net production revenue and, for a period of time, to the extent not funded by such revenue, up to an additional $300 million , to fund drilling programs on locations provided by the Company. Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, CEMOF will fund up to 85% of the costs associated with new wells drilled under the DrillCo Agreement and is expected to receive an 80% working interest in these wells until it reaches certain payout thresholds equal to a cumulative 9% and then 13% internal rate of return. Upon reaching the final internal rate of return target, CEMOF’s interest will be reduced to 15% , while the Company’s interest will increase to 85% . As of December 31, 2019 , CEMOF had funded approximately $36 million . As of December 31, 2019 , eleven joint wells have been drilled and completed. Interest expense The following amounts have been incurred and charged to interest expense for the years ended December 31, 2019 , 2018 and 2017 : Year Ended December 31, 2019 2018 2017 (in millions) Interest expense $ 235 $ 110 $ 61 Less capitalized interest (66 ) (32 ) (22 ) Other fees and expenses 4 10 2 Total interest expense $ 173 $ 88 $ 41

CAPITAL STOCK AND EARNINGS PER

CAPITAL STOCK AND EARNINGS PER SHARE	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
CAPITAL STOCK AND EARNINGS PER SHARE	CAPITAL STOCK AND EARNINGS PER SHARE The Company did not complete any equity offerings during the years ended December 31, 2019 , 2018 and 2017 . Viper Equity Offerings For information regarding Viper’s completed equity offerings during the years ended December 31, 2019 , 2018 and 2017 , refer to Note 4—Viper Energy Partners LP. 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 Viper 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, 2019 2018 2017 (In millions, except per share amounts, shares in thousands) Net income attributable to common stock $ 240 $ 846 $ 482 Weighted average common shares outstanding: Basic weighted average common units outstanding 163,493 104,622 97,458 Effect of dilutive securities: Potential common shares issuable 350 307 230 Diluted weighted average common shares outstanding 163,843 104,929 97,688 Basic net income attributable to common stock $ 1.47 $ 8.09 $ 4.95 Diluted net income attributable to common stock $ 1.47 $ 8.06 $ 4.94 The Company had the following shares that were excluded from 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: Year Ended December 31, 2019 2018 2017 (in thousands) Restricted stock units 284 14 46

EQUITY-BASED COMPENSATION

EQUITY-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
EQUITY-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 1,313,588 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: Year Ended December 31, 2019 2018 2017 (In millions) General and administrative expenses $ 48 $ 27 $ 25 Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties $ 17 $ 10 $ 9 Restricted Stock Units Under the Equity 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 Equity Plan during the year ended December 31, 2019 : Restricted Stock Weighted Average Grant-Date Unvested at December 31, 2018 324,224 $ 116.01 Granted 697,679 $ 99.36 Vested (425,608 ) $ 105.09 Forfeited (90,428 ) $ 106.55 Unvested at December 31, 2019 505,867 $ 96.01 The aggregate fair value of restricted stock units that vested during the years ended December 31, 2019 , 2018 and 2017 was $45 million , $19 million and $15 million , respectively. As of December 31, 2019 , the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $38 million . Such cost is expected to be recognized over a weighted-average period of 2.2 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 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 vested 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 vested at December 31, 2019. In February 2018 , eligible employees received performance restricted stock unit awards totaling 117,423 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, 2018 to December 31, 2020 and cliff vest at December 31, 2020. In March 2019, eligible employees received performance restricted stock unit awards totaling 199,723 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, 2019 to December 31, 2021 and cliff vest at December 31, 2021. In March 2019, eligible employees received performance restricted stock unit awards totaling 32,958 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, 2019 to December 31, 2021 and vest in five equal installments beginning on March 1, 2025. 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. 2019 2018 2017 Three-Year Performance Period Three-Year Performance Period Two-Year Performance Period Three-Year Performance Period Grant-date fair value $ 137.22 $ 170.45 $ 162.13 $ 168.73 Grant-date fair value (5-year vesting) $ 132.48 Risk-free rate 2.55 % 1.99 % 1.27 % 1.59 % Company volatility 35.00 % 35.90 % 39.32 % 41.14 % The following table presents the Company’s performance restricted stock unit activity under the Equity Plan for the year ended December 31, 2019 : Performance Restricted Stock Units Weighted Average Grant-Date Fair Value Unvested at December 31, 2018 196,203 $ 169.76 Granted 356,227 $ 131.30 Vested (176,976 ) $ 93.32 Forfeited (103,635 ) $ 155.23 Unvested at December 31, 2019 (1) 271,819 $ 147.07 (1) A maximum of 543,638 units could be awarded based upon the Company’s final TSR ranking. As of December 31, 2019 , the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $24 million . Such cost is expected to be recognized over a weighted-average period of 2.6 years . Stock Appreciation Rights In connection with the Energen merger, each outstanding stock appreciation right in respect of Energen common stock that was outstanding immediately prior to the effective time of the merger was converted into a fully vested stock appreciation right in respect of (i) that number of whole shares of Diamondback common stock (rounded down to the nearest whole share) equal to the product of (A) the total number of shares of Energen common stock subject to such stock appreciation right immediately prior to the effective time of the merger multiplied by (B) the exchange ratio, (ii) at an exercise price per share of Diamondback common stock (rounded up to the nearest whole cent) equal to the quotient of (A) the exercise price per share of Energen common stock of such stock appreciation right immediately prior to the effective time of the merger divided by (B) the exchange ratio. These awards have a three-year requisite service period. The following table presents a summary of stock appreciation rights activity during the year ended December 31, 2019 : Shares Weighted Average Exercise Price Outstanding at December 31, 2018 57,721 $ 22.12 Exercised (11,399 ) $ 70.69 Expired (3,775 ) $ 96.91 Outstanding at December 31, 2019 42,547 $ 90.89 Stock Options In connection with the Energen Merger, each option to purchase shares of Energen common stock that was outstanding immediately prior to the effective time of the merger was converted into a fully vested option to purchase (i) that number of whole shares of Diamondback common stock (rounded down to the nearest whole share) equal to the product of (A) the total number of shares of Energen common stock subject to such option immediately prior to the effective time of the merger multiplied by (B) the exchange ratio, (ii) at an exercise price per share of Diamondback common stock (rounded up to the nearest whole cent) equal to the quotient of (A) the exercise price per share of Energen common stock of such option immediately prior to the effective time divided by (B) the exchange ratio. The exercise price of stock options granted may not be less than the market value of the stock at the date of grant. 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 expected term of options granted was determined based on the contractual term of the awards at effective time of the merger. 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. All such amounts represent the weighted-average amounts for each year. Weighted Average Exercise Remaining Intrinsic Options Price Term Value (in years) (in millions) Outstanding at December 31, 2018 332,387 $ 95.04 Exercised (116,044 ) $ 82.29 Outstanding at December 31, 2019 216,343 $ 89.90 1.67 $ — Vested and Expected to vest at December 31, 2019 216,343 $ 89.90 1.67 $ — Exercisable at December 31, 2019 216,343 $ 89.90 1.67 $ — Viper Long-Term Incentive Plan 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 Viper. 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 8,892,918 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. Under the Viper LTIP, the Board of Directors of Viper’s General Partner is authorized to issue phantom units to eligible employees. Viper estimates the fair value of phantom units as the closing price of Viper’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 Viper for each phantom unit. The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2019 : Phantom Units Weighted Average Grant-Date Unvested at December 31, 2018 125,053 $ 23.44 Granted 56,582 $ 30.33 Vested (85,359 ) $ 23.96 Forfeited (1,028 ) $ 42.50 Unvested at December 31, 2019 95,248 $ 26.87 The aggregate fair value of phantom units that vested during the year ended December 31, 2019 was $2 million . As of December 31, 2019 , the unrecognized compensation cost related to unvested phantom units was $1 million . Such cost is expected to be recognized over a weighted-average period of 1.0 years . Rattler Long-Term Incentive Plan On May 22, 2019, the board of directors of Rattler’s General Partner adopted the Rattler Midstream LP Long Term Incentive Plan (“Rattler LTIP”), for employees, consultants and directors of Rattler’s General Partner and any of its affiliates, including Diamondback, who perform services for Rattler. The Rattler 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. Under the Rattler LTIP, the board of directors of Rattler’s General Partner is authorized to issue phantom units to eligible employees and non-employee directors. Rattler estimates the fair value of phantom units as the closing price of Rattler’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 to one common unit of Rattler for each phantom unit. The recipients are also entitled to distribution equivalent rights, which represent the right to receive a cash payment equal to the value of the distributions paid on one phantom unit between the grant date and the vesting date. The following table presents the phantom unit activity under the Rattler LTIP for the year ended December 31, 2019 : Phantom Weighted Average Unvested at May 28, 2019 — $ — Granted 2,284,038 $ 19.14 Forfeited (57,143 ) $ 19.21 Unvested at December 31, 2019 2,226,895 $ 19.14 As of December 31, 2019 , the unrecognized compensation cost related to unvested phantom units was $37 million . Such cost is expected to be recognized over a weighted-average period of 2.4 years .

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS Advisory Services Agreement - Viper In connection with the closing of the Viper Offering, Viper and Viper’s General Partner entered into an advisory services agreement (the “Viper Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provided Viper and Viper’s General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $500,000 , plus reasonable out-of-pocket expenses. The Advisory Services Agreement was terminated on November 12, 2018 and Viper’s payment obligation ended in June 2019. During 2019, Viper did no t pay any amounts under the Advisory Services Agreement. For the year ended December 31, 2018 , Viper did no t pay any amounts under the Advisory Services Agreement. Lease Bonus - Viper During the year ended December 31, 2019 , the Company paid Viper $277,977 in lease bonus payments to extend the term of six leases and $182,646 in lease bonus payments for four new leases. During the year ended December 31, 2018 , the Company paid Viper $3 million in lease bonus payments to extend the term of 13 leases and less than $1 million in lease bonus payments for one new lease. During the year ended December 31, 2017 , the Company paid Viper $105,690 in lease bonus payments to extend the term of two leases. Please see Note 4 —Viper Energy Partners LP for additional information regarding relationships between the Company and Viper. Rattler Offering Please see Note 5 —Rattler Midstream LP for information regarding relationships between the Company and Rattler.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2019
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. The Company and its subsidiaries, other than Viper, Viper LLC, Rattler and Rattler LLC, file a federal corporate income tax return on a consolidated basis. As discussed further below, Viper is a taxable entity for federal income tax purposes effective May 10, 2018, and as such files a federal corporate income tax return including the activity of its investment in Viper LLC. Subsequent to Rattler’s election to be treated as a corporation for federal income tax purposes effective May 24, 2019, Rattler is also a taxable entity and as such files a federal corporate income tax return including the activity of its investment in Rattler LLC. Viper’s and Rattler’s provision for income taxes is included in the Company’s consolidated income tax provision and, to the extent applicable, in net income attributable to the non-controlling interest. The Tax Cuts and Jobs Act, a historic reform of the U.S. federal income tax statutes, was enacted on December 22, 2017. As of the completion of the Company’s financial statements for the year ended December 31, 2017, the Company had substantially completed its accounting for the effects of the enactment of the Tax Cuts and Jobs Act and with respect to those items for which the Company’s accounting was not complete, the Company made reasonable estimates of the effects on its deferred tax balances. 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 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 $68 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. At December 31, 2018, the Company completed its accounting for all of the enactment-date income tax effects of the Tax Cuts and Jobs Act and did not made any adjustments to the provisional amounts recorded December 31, 2017. The Company’s effective income tax rates were 13.0% and 15.1% for the years ended December 31, 2019 and 2018, respectively. Total income tax expense for the year ended December 31, 2019 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to the revision of estimated deferred taxes recognized as a result of Viper’s change in tax status, and state income taxes net of federal benefit. Total income tax expense for the year ended December 31, 2018 differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily due to the impact of deferred taxes recognized as a result of Viper’s change in tax status, net income attributable to the noncontrolling interest, and state income taxes net of federal benefit. The components of the Company’s consolidated provision for income taxes from continuing operations for the years ended December 31, 2019 , 2018 and 2017 are as follows: Year Ended December 31, 2019 2018 2017 (In millions) Current income tax provision (benefit): Federal $ — $ — $ — State — — — Total current income tax provision (benefit) — — — Deferred income tax provision (benefit): Federal 40 160 (21 ) State 7 8 1 Total deferred income tax provision (benefit) 47 168 (20 ) Total provision for (benefit from) income taxes $ 47 $ 168 $ (20 ) A reconciliation of the statutory federal income tax amount from continuing operations to the recorded expense is as follows: Year Ended December 31, 2019 2018 2017 (In millions) Income tax expense at the federal statutory rate (1) $ 76 $ 234 $ 174 Impact of nontaxable noncontrolling interest — (5 ) (12 ) Income tax benefit relating to change in statutory tax rate — — (68 ) State income tax expense, net of federal tax effect 6 8 3 Non-deductible compensation 4 5 13 Change in valuation allowance — — (127 ) Deferred taxes related to change in Viper LP's tax status (42 ) (73 ) — Other, net 3 (1 ) (3 ) Provision for (benefit from) income taxes $ 47 $ 168 $ (20 ) (1) The federal statutory rates for the years ended December 31, 2019 , 2018 and 2017 were 21% , 21% and 35% , respectively. The components of the Company’s deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows: December 31, 2019 2018 (In millions) Deferred tax assets: Net operating loss and other carryforwards $ 453 $ 155 Stock based compensation 7 7 Viper LP's investment in Viper LLC 134 94 Other 11 9 Deferred tax assets 605 265 Valuation allowance (7 ) (14 ) Deferred tax assets, net of valuation allowance 598 251 Deferred tax liabilities: Oil and natural gas properties and equipment 2,275 1,825 Midstream investments 50 67 Derivative instruments 6 47 Rattler LP's investment in Rattler LLC 8 — Other 3 — Total deferred tax liabilities 2,342 1,939 Net deferred tax liabilities $ 1,744 $ 1,688 The Company had net deferred tax liabilities of approximately $1.7 billion at December 31, 2019 and 2018 . On November 29, 2018, the Company completed its acquisition of Energen. For federal income tax purposes, the acquisition was a tax-free merger whereby the Company’s tax basis in Energen assets and liabilities was unaffected by the acquisition. As of December 31, 2018, the Company recorded a deferred tax liability of $1.4 billion associated with the acquired assets, which includes deferred tax assets related to tax attributes acquired from Energen. As of December 31, 2019, the Company has completed its purchase price allocation for the acquisition, including an increase of $23 million to the deferred tax liability as a result of adjustments to fair value of the acquired assets. 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 as a result of its loss, nor is there any current federal income tax payable. At December 31, 2019 , the Company had approximately $400 million of federal NOLs expiring in 2032 through 2037 and $1.3 billion of federal NOLs with an indefinite carryforward life, including NOLs acquired from Energen. 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’s federal tax attributes acquired from Energen are subject to an annual limitation under 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. The Company believes that the application of Section 382 will not have an adverse effect on future usage of the Company’s NOLs and credits, including federal tax attributes acquired from Energen. The Company’s minimum tax credits, including those acquired from Energen, are classified as $19 million current and $19 million noncurrent income tax receivables on the balance sheet. As of December 31, 2019 , the Company has a valuation allowance of $7 million primarily related to certain state NOL carryforwards which the Company does not believe are realizable as it does not anticipate future operations in those states. Management’s assessment at each balance sheet date 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 of December 31, 2019 , management determined that it is more likely than not that the Company will realize its remaining deferred tax assets. As discussed further in Note 4 —Viper Energy Partners LP, on March 29, 2018, Viper announced that the Board of Directors of its General Partner had unanimously approved a change of Viper’s federal income tax status from that of a pass- through partnership to that of a taxable entity, which change became effective on May 10, 2018. The transactions undertaken in connection with the change in Viper’s tax status were not taxable to the Company. Subsequent to Viper’s change in tax status, Viper’s provision for income taxes for the periods ended December 31, 2018 and 2019 are based on its estimated annual effective tax rate plus discrete items. As such, Viper’s provision for income taxes is included in the Company’s consolidated financial statements and to the extent applicable, in net income attributable to the non-controlling interest. At December 31, 2019 , the Company’s net deferred tax liabilities include a deferred tax asset of approximately $134 million related to Viper’s investment in Viper LLC, approximately $115 million of which was recorded as a result of Viper’s change in tax status. Under federal income tax provisions applicable to Viper’s change in tax status, Viper’s basis for federal income tax purposes in its interest in Viper LLC consisted primarily of the sum of Viper’s unitholders’ tax bases in their interests in Viper on the date of the tax status change. Viper prepared its best estimate of the tax basis in Viper LLC for purposes of Viper’s income tax provision for the period of the change, but information necessary for Viper to finalize its determination was not available until unitholders’ tax basis information was fully reported and Viper finalized its federal income tax computations for 2018. Based on such finalized information as of the third quarter 2019, Viper revised its estimate of the difference between its tax basis and its basis for financial accounting purposes in Viper LLC on the date of the tax status change, resulting in deferred income tax benefit of $42 million included in the Company’s consolidated income tax provision for the year ended December 31, 2019. As of December 31, 2019, Viper has federal net operating loss carryforwards of approximately $38 million which may be carried forward indefinitely to offset future taxable income. As discussed further in Note 5 —Rattler Midstream LP, on May 28, 2019, Rattler completed its initial public offering. Even though Rattler is organized as a limited partnership under state law, Rattler is subject to U.S. federal and state income tax at corporate rates, subsequent to the effective date of Rattler’s election to be treated as a corporation for U.S. federal income tax purposes. As such, Rattler’s provision for income taxes is included in the Company’s consolidated financial statements and to the extent applicable, in net income attributable to the non-controlling interest. At December 31, 2019, the Company’s net deferred tax liabilities include a deferred tax liability of approximately $8 million related to Rattler’s investment in Rattler LLC. Subsequent to the deemed formation of Rattler LLC as a partnership for federal income tax purposes upon Rattler’s IPO, deferred taxes are no longer provided on the underlying assets and liabilities of Rattler LLC but are provided on the difference between Rattler’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in Rattler LLC. Rattler incurred an NOL in the current year due principally to Rattler LLC’s tax deductions for accelerated depreciation, which exceeded its other items of taxable income. At December 31, 2019, Rattler has federal net operating loss carryforwards of approximately $1 million which may be carried forward indefinitely to offset future taxable income. The following table sets forth changes in the Company’s unrecognized tax benefits: December 31, 2019 2018 (in millions) Balance at beginning of year $ 7 $ — Increase resulting from tax positions acquired — 7 Increase resulting from prior period tax positions — — Increase resulting from current period tax positions — — Balance at end of year 7 7 Less: Effects of temporary items (5 ) (5 ) Total that, if recognized, would impact the effective income tax rate as of the end of the year $ 2 $ 2 The Company’s federal and state income tax returns for 2012 through the current tax year remain open and subject to examination by the IRS and major state taxing jurisdictions. Energen is currently under IRS examination of its federal consolidated income tax returns for 2014 and 2016. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax positions may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations is highly uncertain, the Company does not expect the change in unrecognized tax benefit within the next 12 months would have a material impact to the financial statements. 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, 2019 and 2018, there were no penalties and less than $1 million and $0 million

DERIVATIVES

DERIVATIVES	12 Months Ended
	Dec. 31, 2019
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.” Commodity Contracts The Company has used fixed price swap contracts, fixed price basis swap contracts, double-up swap contracts and three-way costless collars with corresponding put, short 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 contracts and fixed price basis swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap or basis 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 or basis price. The Company has fixed price basis swaps for the spread between the WTI Magellan East Houston oil price and the WTI Cushing oil price and for the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The Company also utilizes double-up swap contracts for a portion of its natural gas sales. These contracts include a traditional fixed price swap in addition to a call option at the same quantity and price, providing the counterparty the option to double the volume in the swap contract should the monthly settlement price exceed the fixed price contracted upon. Under the Company’s costless collar contracts, a three-way collar is a combination of three options: a ceiling call, a floor put, and a short put. The counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the ceiling price to a maximum of the difference between the floor price and the short put price. The Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the ceiling price. If the settlement price is between the floor and the ceiling 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 (Cushing and Magellan East Houston) and ICE Brent pricing, and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub and Waha Hub pricing and liquids derivative settlements based on Mt. Belvieu 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, 2019 , the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed: 2020 2021 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 4,754,000 $ 57.78 0 $ — Oil Swaps - WTI Magellan East Houston 2,196,000 $ 62.80 0 $ — Oil Swaps - BRENT 4,569,000 $ 61.84 0 $ — Oil Basis Swaps - WTI Cushing 13,860,000 $ (1.20 ) 0 $ — Oil Rolling Hedge - WTI Cushing 6,700,000 $ 0.44 0 $ — Natural Gas Swaps - Henry Hub 10,050,000 $ 2.55 0 $ — Natural Gas Swaps - Waha Hub 16,750,000 $ 1.67 0 $ — Natural Gas Basis Swaps - Waha Hub 23,450,000 $ (1.19 ) 54,750,000 $ (0.70 ) 2020 Oil Three-Way Collars WTI Cushing Brent WTI Magellan East Houston Volume (Bbls) 6,842,200 11,803,500 5,124,000 Short put price (per Bbl) $ 44.20 $ 50.00 $ 50.00 Floor price (per Bbl) $ 54.20 $ 60.00 $ 60.00 Ceiling price (per Bbl) $ 65.42 $ 70.86 $ 68.61 Gas Swap Double-Up - Waha Hub 2020 Volume (Mcf) 10,050,000 Swap price (per Mcf) $ 1.70 Option price $ 1.70 Interest Rate Swaps and Treasury Locks The Company has used interest rate swaps and treasury locks to reduce the Company’s exposure to variable rate interest payments associated with the Company’s revolving credit facility. The interest rate swaps and treasury locks have not been designated as hedging instruments and as a result, the Company recognizes all changes in fair value immediately in earnings. Effective November 2019, the Company terminated all of its interest rate swaps and treasury locks which resulted in a gain of $43 million , net of fees. 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, 2019 and 2018 : December 31, 2019 2018 (in millions) Gross amounts of assets presented in the Consolidated Balance Sheet $ 71 $ 233 Amounts netted in the Consolidated Balance Sheet (18 ) (2 ) Net amounts of assets presented in the Consolidated Balance Sheet $ 53 $ 231 Gross amounts of liabilities presented in the Consolidated Balance Sheet $ 45 $ 15 Amounts netted in the Consolidated Balance Sheet (18 ) — Net amounts of liabilities presented in the Consolidated Balance Sheet $ 27 $ 15 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, 2019 2018 (in millions) Current assets: derivative instruments $ 46 $ 231 Noncurrent assets: derivative instruments 7 — Total assets $ 53 $ 231 Current liabilities: derivative instruments $ 27 $ — Noncurrent liabilities: derivative instruments — 15 Total liabilities $ 27 $ 15 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, 2019 2018 2017 (in thousands) Change in fair value of open non-hedge derivative instruments: $ (188 ) $ 222 $ (84 ) Gain (loss) on settlement of non-hedge derivative instruments: 80 (121 ) 6 Gain (loss) on derivative instruments $ (108 ) $ 101 $ (78 )

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2019
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. The Company estimates the fair values of proved oil and natural gas properties assumed in business combinations using discounted cash flow techniques and based on market assumptions as to the future commodity prices, internal estimates of future quantities of oil and natural gas reserves, future estimated rates of production, expected recovery rates and risk-adjustment discounts. The estimated fair values of unevaluated oil and natural gas properties were based on the location, engineering and geological studies, historical well performance, and applicable mineral lease terms. Given the unobservable nature of the inputs, the estimated fair values of oil and natural gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of business combinations are estimated using the same assumptions and methodology as described below. The Company estimates asset retirement obligations pursuant to the provisions of the Financial Accounting Standards Board issued Accounting Standards Codification Topic 410, “Asset Retirement and Environmental Obligations”. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with the future plugging and abandonment of wells and related facilities. Given the unobservable nature of the inputs, including plugging costs and useful lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 8 —Asset Retirement Obligations for further discussion of the Company’s asset retirement obligations. 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 and Viper’s cost method investment. The fair value of Viper’s investment is determined using quoted market prices. These valuations are Level 1 inputs. The fair values of the Company’s fixed price swaps, fixed price basis swaps and costless collars 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, 2019 and 2018 : December 31, 2019 December 31, 2018 Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 (in millions) Assets: Investment $ 19 $ — $ — $ 14 $ — $ — Fixed price swaps $ — $ 26 $ — $ — $ 216 $ — Liabilities: Fixed price swaps $ — $ — $ — $ — $ — $ — The following table summarizes the changes in fair value of Viper’s cost method investment during the periods presented: (in millions) Value at December 31, 2018 $ 14 Gain on investment 5 Value at December 31, 2019 $ 19 Value at December 31, 2017 $ 34 Impact of adoption of Accounting Standards Update 2016-01 (19 ) Loss on investment (1 ) Value at December 31, 2018 $ 14 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, 2019 December 31, 2018 Carrying Carrying Amount Fair Value Amount Fair Value (in thousands) Debt: Revolving credit facility $ 13 $ 13 $ 1,490 $ 1,490 4.625% Notes due 2021 399 411 400 393 7.320% Medium-term Notes, Series A, due 2022 21 22 20 21 2.875% Senior Notes due 2024 (1) 992 1,012 — — 4.750% Senior Notes due 2024 (1) — — 1,236 1,204 5.375% Senior Notes due 2025 (1) 799 840 799 782 3.250% Senior Notes due 2026 (1) 792 812 — — 7.350% Medium-term Notes, Series A, due 2027 11 12 10 11 7.125% Medium-term Notes, Series B, due 2028 108 116 100 102 3.500% Senior Notes due 2029 (1) 1,186 1,226 — — Viper revolving credit facility 97 97 411 411 Viper's 5.375% Senior Notes due 2027 490 521 — — Rattler revolving credit facility 424 424 — — DrillCo Agreement $ 39 $ 39 $ — $ — (1) The carrying value includes associated deferred loan costs and any discount. The fair value of the revolving credit facility, the Viper credit agreement and the Rattler credit agreement 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 and the Energen Notes was determined using the December 31, 2019 quoted market price, a Level 1 classification in the fair value hierarchy.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
LEASES	LEASES The Company leases certain drilling rigs, facilities, compression and other equipment. As discussed in Note 2—Summary of Significant Accounting Policies, the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 on January 1, 2019 using the optional transition method of adoption. The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification and (iii) initial direct costs. In addition, the Company elected the following practical expedients: (i) to not reassess certain land easements; (ii) to not apply the recognition requirements under the standard to short-term leases; (iii) to not reassess lease terms on leases entered into prior to the effective date of adoption; and (iv) lessor accounting policy election to exclude lessor costs paid directly by the lessee. For leases where the Company is the lessee, the Company recorded a total of $13 million in right-of-use assets and corresponding new lease liabilities in other on its Condensed Consolidated Balance Sheet representing the present value of its future operating lease payments. Adoption of the standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date. The right-of-use assets and lease liabilities recognized upon adoption of ASU 2016-02 were based on the lease classifications, lease commitment amounts and terms recognized under the prior lease accounting guidance. Leases with an initial term of twelve months or less are considered short-term leases and are not recorded on the balance sheet. The following table summarizes operating lease costs for the year ended December 31, 2019 : Year Ended December 31, 2019 (in millions) Operating lease costs $ 26 For the year ended December 31, 2019 , cash paid for operating lease liabilities, and reported in cash flows provided by operating activities on the Company's Statement of Condensed Consolidated Cash Flows, was $26 million . During the year ended December 31, 2019 , the Company recorded an additional $17 million of right-of-use assets in exchange for new lease liabilities. The operating lease right-of-use assets were reported in other assets and the current and noncurrent portions of the operating lease liabilities were reported in other accrued liabilities and other long-term liabilities, respectively, on the Condensed Consolidated Balance Sheet. As of December 31, 2019 , the operating right-of-use assets were $15 million and operating lease liabilities were $15 million , of which $8 million was classified as current. As of December 31, 2019 , the weighted average remaining lease term was 2.1 years and the weighted average discount rate was 8.2% . Schedule of Operating Lease Liability Maturities . The following table summarizes undiscounted cash flows owed by the Company to lessors pursuant to contractual agreements in effect as of December 31, 2019 : As of December 31, 2019 (in millions) 2020 $ 9 2021 5 2022 2 2023 — 2024 — Thereafter — Total lease payments 16 Less: interest 1 Present value of lease liabilities $ 15 For leases in which the Company is the lessor, the Company (i) retained classification of our historical leases as we are not required to reassess classification upon adoption of the new standard, (ii) expensed indirect leasing costs in connection with new or extended tenant leases, the recognition of which would have been deferred under prior accounting guidance and (iii) aggregated revenue from our lease components and non-lease components (comprised of tenant expense reimbursements) into revenue from rental properties.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES The Company is a party to various legal proceedings, disputes and claims arising in the course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and gas exploration and development and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer part of the Company’s current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Company, cannot be predicted with certainty, the Company believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, cash flows or results of operations. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. The Company reassesses the probability and estimability of contingent losses as new information becomes available. Commitments The following is a schedule of minimum future payments with commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2019 : Year Ending December 31, Sand Supply Agreement (in millions) 2020 $ 18 2021 18 2022 18 2023 18 2024 18 Thereafter 23 Total $ 113 The Company leases office space in Oklahoma City, Oklahoma from an unrelated third party. Amounts prior to January 1, 2018, include rent expense related to the Company’s corporate office located in the Fasken Center in Midland, Texas. On January 31, 2018, the Company completed its acquisition of the Fasken Center office buildings. The following table presents rent expense for the years ended December 31, 2019 , 2018 and 2017 : Year ended December 31, 2019 2018 2017 (in millions) Rent Expense $ 3 $ 1 $ 2 Agreement with Trafigura Trading LLC The Company has entered into a firm commitment oil purchase agreement with Trafigura Trading LLC (“Trafigura”) in which the Company agreed to sell and deliver a firm quantity of 25,000 barrels of crude oil per day to Trafigura during the term of the agreement. Under this agreement, which has a seven-year term beginning on August 1, 2018, the price per barrel of oil paid to us by Trafigura is based on the average of the published settlement quotations for NYMEX CMA, as adjusted for different delivery methods and periods. If during the term of the agreement the Company fails to deliver the required quantities of oil for any month other than for specified force majeure events, the Company has agreed to pay Trafigura a deficiency payment equal to any unfavorable difference between the contract price and the spot price, multiplied by the deficiency volume. Agreement with Plains Marketing LP In July 2019, the Company’s wholly-owned subsidiary, Energen Resources Corporation (“Energen Resources”) entered into a long-term crude oil sales agreement with Plains Marketing LP (“Plains”) pursuant to which, among other things, the Company’s existing agreements with Plains were terminated. The Company’s new agreement with Plains requires that it makes available 50,000 barrels of crude oil per day until the date occurring ten years following the date service commences for ExxonMobil Oil Corporation (“Exxon”) pursuant to the transportation service agreement between Exxon and the Wink to Webster pipeline carrier (plus extensions for force majeure). If during the term of the agreement the Company fails to deliver the required quantities of oil for any month other than for specified force majeure events or acts or omissions of Plains, the Company has agreed to pay Plains a specified per barrel amount, subject to escalation, multiplied by the deficiency volume. If during the term of the agreement the Company fails to deliver the quantities of oil for any month that it has committed for such month other than for specified force majeure events or acts or omissions of Plains, the Company has agreed to pay Plains a deficiency payment . The Company has also dedicated certain crude oil production attributable to certain of its interests to Plains in connection with this agreement. Pricing for the Company’s production under the Plains agreement (i) prior to the date service commences for Exxon pursuant to the transportation service agreement between Exxon and the Wink to Webster pipeline carrier, is at a Midland WTI or WTL, as applicable, base price less certain costs and (ii) following the date service commences for Exxon pursuant to the transportation service agreement between Exxon and the Wink to Webster pipeline carrier, for volumes up to 100,000 barrels of crude oil per day, is at a MEH WTI or WTL base price, as applicable, less certain costs. Agreement with Shell Trading (USA) Company In December 2018, the Company entered into an oil purchase agreement with Shell Trading (USA) Company (“Shell”) which was amended and restated in December 2019, in which Shell agreed to transport crude oil it purchases from us through the EPIC pipeline, with which the Company has an agreement for the transportation of certain crude oil. The Company’s agreement with Shell provides for different purchase obligations during the pre-commencement and service commencement periods for the EPIC pipeline, and provides for a three-year term beginning on the service commencement date for the EPIC pipeline. Shell has the option to extend its purchase obligations for up to three one-year terms, but not beyond March 31, 2026 except in the event of force majeure. The Company’s delivery obligation (i) prior to the full service commencement of the EPIC pipeline will be, subject to certain conditions, including the Company’s right to repurchase certain volumes, either 30,000 or 40,000 barrels of crude oil per day and (ii) during the full service term will not exceed 50,000 barrels of crude oil per day. In addition, the Company’s wholly-owned subsidiary Energen Resources has signed an agreement with Shell in which all or a portion of the 50,000 barrels of crude oil per day referenced in the previous sentence could also be satisfied by Energen Resources. During different pre-commencement periods, Shell has agreed to pay the Company the price per barrel of oil based on the arithmetic average of the daily settlement price for the “Light Sweet Crude Oil” Prompt Month future contracts reported by the NYMEX over the applicable one-month period, subject to certain adjustments, plus a Corpus Christi differential determined based on Shell’s average sales price for its WTI barrels in Corpus Christi less certain other costs, expenses and fees. During the full service term, the price per barrel of oil payable by Shell to the Company is based on calendar dated Brent pricing plus a negotiated differential generally based on certain Argus WTI Houston CIF Rotterdam and Platts Midland DAP Rotterdam pricing, less certain adjustments. Agreement with Vitol Inc. On October 18, 2018, the Company entered into an agreement with Vitol to, among other things, sell an average of 23,750 barrels of crude oil per day plus other agreed upon volumes. The Company is continuing to sell crude to Vitol on a month-to-month basis and expects to continue to do so under its existing arrangement with Vitol until its new agreement with Vitol becomes effective. Under the Company’s new agreement with Vitol, the Company agreed to sell, and Vitol agreed to purchase, (i) subject to certain conditions, including accelerated commissioning service on the Gray Oak pipeline and completion of certain infrastructure connections, 50,000 barrels of crude oil per day on average during each month occurring during the first seven years of full service on the Gray Oak pipeline, (ii) subject to certain conditions and the satisfaction of other conditions, including full service on the Gray Oak pipeline and completion of certain infrastructure connections, an additional 50,000 barrels of crude oil per day on average during each month occurring during the first seven years following satisfaction of such conditions, (iii) subject to certain conditions, including notice that transportation services on the EPIC pipeline are ready to commence and completion of certain infrastructure connections, an additional 50,000 barrels of crude oil per day on average during each month occurring during the first seven years following satisfaction of such conditions and (iv) such other volumes of crude oil as agreed by the parties. The Company is entitled to receive payment for such crude oil under netback pricing, whereby the price for the Company’s crude oil is determined based on a formula which takes into consideration the final purchase price obtained by Vitol in marketing such crude oil in certain third party transactions less certain costs. In connection therewith, Vitol has agreed to, among other things, use commercially reasonable efforts to (i) maximize the final purchase price to the Company and mitigate any costs factored into the price determination and (ii) acquire third party crude oil to cover any shortfall below the Company’s volumes commitments. Vitol also agrees to (i) use the same care and apply the same policies as it would exercise and apply if it were trading the subject crude oil for Vitol’s own account and (ii) transport such crude oil on certain designated pipelines, including the Gray Oak pipeline pursuant to rights we have obtained through our Gray Oak transportation services agreement described below under third party shipper rights or term assignments, as applicable, prior to Vitol’s downstream marketing activities. Transportation Services Agreement with Gray Oak Pipeline, LLC Pursuant to an addendum, dated as of August 13, 2018, to the transportation services agreement with Gray Oak Pipeline, LLC, dated as of April 23, 2018 (the “Gray Oak TSA 1”), Diamondback E&P LLC agreed to accelerated commissioning service (“ACS”) on the Gray Oak pipeline in the amount of 50,000 barrels of crude oil per day. Under the ACS program, shippers must make a deficiency payment for any barrels not shipped during the ACS term, which expires the day before the Gray Oak pipeline goes into full service, which is currently anticipated to occur in the second quarter of 2020. The ACS commenced on November 12, 2019 and is ongoing. Due to restrictive API gravity provisions and the lack of markets, Diamondback E&P LLC has been unable to ship any volumes over the Gray Oak pipeline since the inception of ACS. This has resulted in Diamondback E&P LLC owing deficiency payments to Gray Oak Pipeline, LLC during 2019 in the aggregate amount of $11 million . The deficiency payment rate varies depending upon the month in which the deficiency occurs. Certain deficiencies can be used as a credit against volumes shipped in excess of a customer’s minimum contract volume each quarter during the first two years of full service on the Gray Oak pipeline, subject to certain restrictions. Once full service commences on the Gray Oak pipeline, subject to the terms and conditions of the Gray Oak TSA 1, Diamondback E&P LLC will be required to ship 50,000 barrels per day of crude oil on the Gray Oak pipeline or pay a deficiency payment for any shortfall in volumes as measured on a quarterly basis. Such deficiency payments can be used as a credit against future shipments in excess of our minimum contract volume each quarter, subject to certain restrictions. 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, 2019 , 2018 and 2017 the Company paid $8 million , $2 million and $2 million

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS Fourth Quarter 2019 Dividend Declaration On February 14, 2020 , the Board of Directors of the Company declared a cash dividend for the fourth quarter of 2019 of $0.3750 per share of common stock, payable on March 10, 2020 to its stockholders of record at the close of business on March 3, 2020 . Commodity Contracts Subsequent to December 31, 2019 , the Company entered into new fixed price swaps, fixed price basis swaps, three-way collars and put spreads. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on WTI and Crude Oil Brent and gas derivative settlements based on Waha Hub and Brent. The following tables present the derivative contracts entered into by the Company subsequent to December 31, 2019 . When aggregating multiple contracts, the weighted average contract price is disclosed. 2020 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 732,000 $ 60.50 Oil Swaps - BRENT 732,000 $ 65.00 Natural Gas Swaps - Waha Hub 1,840,000 $ 0.75 Natural Gas Basis Swaps - Waha Hub 13,750,000 $ (1.85 ) Diesel Price Swaps 11,000,000 $ 1.60 2020 Oil Three-Way Collars Brent Volume (Bbls) 732,000 Short put price (per Bbl) $ 50.00 Floor price (per Bbl) $ 60.00 Ceiling price (per Bbl) $ 69.25 2020 Oil Put Spreads - WTI Volume (Bbls) 829,125 Short put price (per Bbl) $ 50.50 Floor price (per Bbl) $ 60.50 Oil Put Spreads - Brent Volume (Bbls) 1,758,750 Short put price (per Bbl) $ 52.38 Floor price (per Bbl) $ 65.00

REPORT OF BUSINESS SEGMENTS (No

REPORT OF BUSINESS SEGMENTS (Notes)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
REPORT OF BUSINESS SEGMENTS	REPORT OF BUSINESS SEGMENTS The Company reports its operations in two business segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas and (ii) the midstream operations segment includes midstream services and real estate. All of Rattler’s equity method investments are included in the midstream segment. The following tables summarize the results of the Company's business segments during the periods presented: Upstream Midstream Services Eliminations Total Year Ended December 31, 2019: (in millions) Third-party revenues $ 3,891 $ 73 $ — $ 3,964 Intersegment revenues — 375 (375 ) — Total revenues 3,891 448 (375 ) 3,964 Depreciation, depletion and amortization $ 1,405 $ 42 $ — $ 1,447 Impairment of oil and natural gas properties $ 790 $ — $ — $ 790 Income from operations $ 790 $ 219 $ (314 ) $ 695 Interest expense, net $ (171 ) $ (1 ) $ — $ (172 ) Total other income (expense), net (1) $ (320 ) $ (7 ) $ (6 ) $ (333 ) Provision for income taxes $ 21 $ 26 $ — $ 47 Net income attributable to non-controlling interest $ 75 $ 91 $ (91 ) $ 75 Net income attributable to Diamondback Energy $ 374 $ 95 $ (229 ) $ 240 Total assets $ 22,125 $ 1,636 $ (230 ) $ 23,531 (1) The impairment for the midstream services segment of $2 million is included in other income (expense). Upstream Midstream Services Eliminations Total Year Ended December 31, 2018: (in millions) Third-party revenues $ 2,132 $ 44 $ — $ 2,176 Intersegment revenues — 140 (140 ) — Total revenues 2,132 184 (140 ) 2,176 Depreciation, depletion and amortization $ 598 $ 25 $ — $ 623 Income from operations $ 1,071 $ 80 $ (140 ) $ 1,011 Interest expense, net $ (87 ) $ — $ — $ (87 ) Total other income (expense), net $ 102 $ — $ — $ 102 Provision for income taxes $ 151 $ 17 $ — $ 168 Net income attributable to non-controlling interest $ 99 $ — $ — $ 99 Net income attributable to Diamondback Energy $ 923 $ 63 $ (140 ) $ 846 Total assets $ 21,096 $ 604 $ (104 ) $ 21,596 Upstream Midstream Services Eliminations Total Year Ended December 31, 2017: (in millions) Third-party revenues $ 1,198 $ 7 $ — $ 1,205 Intersegment revenues — 32 (32 ) — Total revenues 1,198 39 (32 ) 1,205 Depreciation, depletion and amortization $ 324 $ 3 $ — $ 327 Income from operations $ 613 $ 24 $ (32 ) $ 605 Interest expense, net $ (41 ) $ — $ — $ (41 ) Total other income (expense), net $ (109 ) $ 1 $ — $ (108 ) Provision for income taxes $ (24 ) $ 4 $ — $ (20 ) Net income attributable to non-controlling interest $ 35 $ — $ — $ 35 Net income attributable to Diamondback Energy $ 493 $ 21 $ (32 ) $ 482 Total assets $ 7,475 $ 300 $ (4 ) $ 7,771

GUARANTOR FINANCIAL STATEMENTS

GUARANTOR FINANCIAL STATEMENTS	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
GUARANTOR FINANCIAL STATEMENTS	GUARANTOR FINANCIAL STATEMENTS As of December 31, 2019 , Diamondback O&G LLC is a guarantor under the indenture relating to the Series of Senior Notes. In connection with the satisfaction and discharge of the indenture governing the 2024 Senior Notes, Diamondback E&P LLC and Energen Corporation and its subsidiaries were released as guarantors under the 2024 Senior Notes, the 2025 Senior Notes and Diamondback O&G LLC’s revolving credit facility. Rattler LLC was released as a guarantor under Diamondback O&G LLC’s credit agreement on May 28, 2019. Viper, Viper’s General Partner, Viper LLC, Rattler, Rattler’s General Partner and Rattler’s subsidiaries remain Non-Guarantor Subsidiaries. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 21 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. None of Rattler, Rattler’s General Partner or Rattler’s subsidiaries were guarantors under the 2024 Senior Notes, the 2025 Senior Notes or Diamondback O&G LLC’s revolving credit facility for the previous periods presented; therefore, the schedules that follow have been adjusted to reflect this correction of an immaterial change. Rattler LLC was a guarantor under Diamondback O&G LLC’s credit agreement until May 28, 2019. Condensed Consolidated Balance Sheet December 31, 2019 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 93 $ — $ 30 $ — $ 123 Restricted cash 5 — — — 5 Accounts receivable, net — 248 367 — 615 Intercompany receivable 5,331 — 572 (5,903 ) — Inventories — 1 36 — 37 Derivative instruments — 46 — — 46 Prepaid expenses and other 2 1 21 19 43 Total current assets 5,431 296 1,026 (5,884 ) 869 Property and equipment: Oil and natural gas properties, full cost method of accounting — 13,276 12,707 (201 ) 25,782 Midstream assets — — 931 — 931 Other property, equipment and land — — 125 — 125 Accumulated depletion, depreciation, amortization and impairment — (3,167 ) (1,831 ) (5 ) (5,003 ) Net property and equipment — 10,109 11,932 (206 ) 21,835 Equity method investments — — 479 — 479 Derivative instruments — 7 — — 7 Investment in subsidiaries 10,414 — — (10,414 ) — Investment in real estate, net — — 109 — 109 Deferred tax asset — — 142 — 142 Other assets — 10 310 (230 ) 90 Total assets $ 15,845 $ 10,422 $ 13,998 $ (16,734 ) $ 23,531 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ — $ 179 $ — $ 179 Intercompany payable — 5,930 (27 ) (5,903 ) — Accrued capital expenditures — — 475 — 475 Other accrued liabilities 17 132 155 — 304 Revenues and royalties payable — — 278 — 278 Derivative instruments — 18 8 1 27 Total current liabilities 17 6,080 1,068 (5,902 ) 1,263 Long-term debt 3,769 13 1,589 — 5,371 Asset retirement obligations — 34 60 — 94 Deferred income taxes 470 — 1,416 — 1,886 Other long-term liabilities — — 11 — 11 Total liabilities 4,256 6,127 4,144 (5,902 ) 8,625 Commitments and contingencies Stockholders’ equity 11,589 4,295 7,908 (10,543 ) 13,249 Non-controlling interest — — 1,946 (289 ) 1,657 Total equity 11,589 4,295 9,854 (10,832 ) 14,906 Total liabilities and equity $ 15,845 $ 10,422 $ 13,998 $ (16,734 ) $ 23,531 Condensed Consolidated Balance Sheet December 31, 2018 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 84 $ 2 $ 129 $ — $ 215 Accounts receivable, net — 143 249 — 392 Accounts receivable - related party — — 4 (4 ) — Intercompany receivable 4,469 — 201 (4,670 ) — Inventories — 2 35 — 37 Derivative instruments — 197 34 — 231 Prepaid expenses and other 2 — 48 — 50 Total current assets 4,555 344 700 (4,674 ) 925 Property and equipment: Oil and natural gas properties, full cost method of accounting — 11,170 11,132 (3 ) 22,299 Midstream assets — 21 679 — 700 Other property, equipment and land — 1 146 — 147 Accumulated depletion, depreciation, amortization and impairment — (2,432 ) (330 ) (12 ) (2,774 ) Net property and equipment — 8,760 11,627 (15 ) 20,372 Equity method investments — — 1 — 1 Investment in subsidiaries 12,689 — 112 (12,801 ) — Deferred tax asset — — 97 — 97 Investment in real estate, net — — 116 — 116 Other assets — 10 75 — 85 Total assets $ 17,244 $ 9,114 $ 12,728 $ (17,490 ) $ 21,596 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ — $ 128 $ — $ 128 Intercompany payable — 3,939 734 (4,673 ) — Accrued capital expenditures — — 495 — 495 Other accrued liabilities 14 23 216 — 253 Revenues and royalties payable — — 143 — 143 Total current liabilities 14 3,962 1,716 (4,673 ) 1,019 Long-term debt 2,036 1,490 938 — 4,464 Derivative instruments — 11 4 — 15 Asset retirement obligations — 30 106 — 136 Deferred income taxes 382 — 1,403 — 1,785 Other long-term liabilities — — 10 — 10 Total liabilities 2,432 5,493 4,177 (4,673 ) 7,429 Commitments and contingencies Stockholders’ equity 14,812 3,621 7,856 (12,589 ) 13,700 Non-controlling interest — — 695 (228 ) 467 Total equity 14,812 3,621 8,551 (12,817 ) 14,167 Total liabilities and equity $ 17,244 $ 9,114 $ 12,728 $ (17,490 ) $ 21,596 Condensed Consolidated Statement of Operations Year Ended December 31, 2019 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 1,972 $ 1,318 $ 264 $ 3,554 Natural gas sales — 27 31 8 66 Natural gas liquid sales — 132 114 21 267 Royalty income — — 293 (293 ) — Lease bonus — — 4 — 4 Midstream services — — 434 (370 ) 64 Other operating income — — 14 (5 ) 9 Total revenues — 2,131 2,208 (375 ) 3,964 Costs and expenses: Lease operating expenses — 390 243 (143 ) 490 Production and ad valorem taxes — 130 118 — 248 Gathering and transportation — 75 34 (21 ) 88 Midstream services — — 170 (79 ) 91 Depreciation, depletion and amortization — 735 720 (8 ) 1,447 Impairment of oil and natural gas properties — — 790 — 790 General and administrative expenses 48 1 67 (12 ) 104 Asset retirement obligation accretion — 2 5 — 7 Other operating expense — — 4 — 4 Total costs and expenses 48 1,333 2,151 (263 ) 3,269 Income (loss) from operations (48 ) 798 57 (112 ) 695 Other income (expense): Interest expense, net (47 ) (74 ) (51 ) — (172 ) Other income (expense), net 3 — 2 (7 ) (2 ) Gain on derivative instruments, net — (56 ) (52 ) — (108 ) Gain on revaluation of investment — — 5 — 5 Loss on extinguishment of debt (56 ) — — — (56 ) Income from subsidiaries 764 — — (764 ) — Total other income (expense), net 664 (130 ) (96 ) (771 ) (333 ) Income (loss) before income taxes 616 668 (39 ) (883 ) 362 Provision for (benefit from) income taxes 81 — (33 ) (1 ) 47 Net income (loss) 535 668 (6 ) (882 ) 315 Net income (loss) attributable to non-controlling interest — — 266 (191 ) 75 Net income (loss) attributable to Diamondback Energy, Inc. $ 535 $ 668 $ (272 ) $ (691 ) $ 240 Condensed Consolidated Statement of Operations Year Ended December 31, 2018 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 1,545 $ 87 $ 247 $ 1,879 Natural gas sales — 43 5 13 61 Natural gas liquid sales — 158 9 23 190 Royalty income — — 283 (283 ) — Lease bonus — — 6 (3 ) 3 Midstream services — — 172 (138 ) 34 Other operating income — — 9 — 9 Total revenues — 1,746 571 (141 ) 2,176 Costs and expenses: Lease operating expenses — 230 17 (42 ) 205 Production and ad valorem taxes — 106 27 — 133 Gathering and transportation — 41 1 (16 ) 26 Midstream services — — 72 — 72 Depreciation, depletion and amortization — 472 134 17 623 General and administrative expenses 28 1 38 (2 ) 65 Merger and integration expense 18 — 18 — 36 Asset retirement obligation accretion — 1 1 — 2 Other operating expenses — — 3 — 3 Total costs and expenses 46 851 311 (43 ) 1,165 Income (loss) from operations (46 ) 895 260 (98 ) 1,011 Other income (expense): Interest expense, net (43 ) (20 ) (24 ) — (87 ) Other income (expense), net 1 — 90 (2 ) 89 Loss on derivative instruments, net — 169 (68 ) — 101 Gain on revaluation of investment — — (1 ) — (1 ) Income from subsidiaries 1,113 — — (1,113 ) — Total other expense, net 1,071 149 (3 ) (1,115 ) 102 Income (loss) before income taxes 1,025 1,044 257 (1,213 ) 1,113 Provision for (benefit from) income taxes 241 — (73 ) — 168 Net income (loss) 784 1,044 330 (1,213 ) 945 Net income attributable to non-controlling interest — — 119 (20 ) 99 Net income (loss) attributable to Diamondback Energy, Inc. $ 784 $ 1,044 $ 211 $ (1,193 ) $ 846 Condensed Consolidated Statement of Operations Year Ended December 31, 2017 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 904 $ — $ 140 $ 1,044 Natural gas sales — 43 — 9 52 Natural gas liquid sales — 79 — 11 90 Royalty income — — 160 (160 ) — Lease bonus income — — 12 — 12 Midstream services — — 39 (32 ) 7 Total revenues — 1,026 211 (32 ) 1,205 Costs and expenses: Lease operating expenses — 143 — (16 ) 127 Production and ad valorem taxes — 63 11 — 74 Gathering and transportation — 21 — (8 ) 13 Midstream services — — 11 (1 ) 10 Depreciation, depletion and amortization — 277 46 4 327 General and administrative expenses 27 — 23 (2 ) 48 Asset retirement obligation accretion expense — 1 — — 1 Total costs and expenses 27 505 91 (23 ) 600 Income (loss) from operations (27 ) 521 120 (9 ) 605 Other income (expense): Interest expense, net (30 ) (6 ) (5 ) — (41 ) Other income (expense), net 1 — 12 (2 ) 11 Loss on derivative instruments, net — (77 ) (1 ) — (78 ) Income from subsidiaries 446 — — (446 ) — Total other expense, net 417 (83 ) 6 (448 ) (108 ) Income (loss) before income taxes 390 438 126 (457 ) 497 Provision for income taxes (20 ) — — — (20 ) Net income (loss) 410 438 126 (457 ) 517 Net income attributable to non-controlling interest — — — 35 35 Net income (loss) attributable to Diamondback Energy, Inc. $ 410 $ 438 $ 126 $ (492 ) $ 482 Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2019 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash (used in) provided by operating activities $ (956 ) $ 1,433 $ 2,257 $ — $ 2,734 Cash flows from investing activities: Additions to oil and natural gas properties — (2,038 ) (639 ) — (2,677 ) Additions to midstream assets — (38 ) (206 ) — (244 ) Purchase of other property, equipment and land — — (5 ) — (5 ) Acquisition of leasehold interests — (360 ) (83 ) — (443 ) Acquisition of mineral interests — — (523 ) 190 (333 ) Proceeds from sale of assets — 118 372 (190 ) 300 Investment in real estate — — (1 ) — (1 ) Equity investments — — (485 ) — (485 ) Intercompany transfers (860 ) — 860 — — Net cash used in investing activities (860 ) (2,318 ) (710 ) — (3,888 ) Cash flows from financing activities: Proceeds from borrowing under credit facility — 1,292 1,058 — 2,350 Repayment under credit facility — (2,769 ) (949 ) — (3,718 ) Proceeds from senior notes 2,968 — 501 — 3,469 Repayment of senior notes (1,250 ) — — — (1,250 ) Premium on extinguishment of debt (44 ) — — — (44 ) Proceeds from joint venture — — 39 — 39 Debt issuance costs — — (18 ) — (18 ) Public offering costs — — (41 ) — (41 ) Proceeds from public offerings — — 1,106 — 1,106 Distributions from subsidiary 860 — — (860 ) — Proceeds from exercise of stock options 9 — — — 9 Repurchased for tax withholdings (13 ) — — — (13 ) Repurchased as part of share buyback (593 ) — — — (593 ) Dividends to stockholders (112 ) — — — (112 ) Distributions to non-controlling interest — — (982 ) 860 (122 ) Intercompany transfers — 2,360 (2,360 ) — — Net cash (used in) provided by financing activities 1,825 883 (1,646 ) — 1,062 Net increase (decrease) in cash and cash equivalents 9 (2 ) (99 ) — (92 ) Cash and cash equivalents at beginning of period 84 2 129 — 215 Cash and cash equivalents at end of period $ 93 $ — $ 30 $ — $ 123 Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2018 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ (58 ) $ 1,224 $ 399 $ — $ 1,565 Cash flows from investing activities: Additions to oil and natural gas properties — (1,461 ) — — (1,461 ) Additions to midstream assets — (21 ) (183 ) — (204 ) Purchase of other property, equipment and land — (7 ) — — (7 ) Acquisition of leasehold interests — (1,371 ) — — (1,371 ) Acquisition of mineral interests — — (440 ) — (440 ) Proceeds from sale of assets — 79 1 — 80 Investment in real estate — — (111 ) — (111 ) Funds held in escrow — 27 (16 ) — 11 Intercompany transfers (367 ) 989 (622 ) — — Net cash used in investing activities (367 ) (1,765 ) (1,371 ) — (3,503 ) Cash flows from financing activities: Proceeds from borrowing under credit facility — 1,960 692 — 2,652 Repayment under credit facility — (867 ) (375 ) — (1,242 ) Repayment on Energen's credit facility — — (559 ) — (559 ) Proceeds from senior notes 1,062 — — — 1,062 Debt issuance costs (14 ) — (11 ) — (25 ) Public offering costs — — (3 ) — (3 ) Proceeds from public offerings — — 305 — 305 Contributions to subsidiaries (1 ) — (1 ) 2 — Distribution to parent 155 — — (155 ) — Distributions from subsidiary (696 ) — 696 — — Repurchased for tax withholdings (14 ) — — — (14 ) Dividends to stockholders (37 ) — — — (37 ) Distributions to non-controlling interest — — (253 ) 155 (98 ) Intercompany transfers — (550 ) 552 (2 ) — Net cash provided by financing activities 455 543 1,043 — 2,041 Net increase (decrease) in cash and cash equivalents 30 2 71 — 103 Cash and cash equivalents at beginning of period 54 — 58 — 112 Cash and cash equivalents at end of period $ 84 $ 2 $ 129 $ — $ 215 Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2017 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (29 ) $ 768 $ 150 $ — $ 889 Cash flows from investing activities: Additions to oil and natural gas properties — (790 ) (3 ) — (793 ) Additions to midstream assets — — (68 ) — (68 ) Purchase of other property, equipment and land — (22 ) (1 ) — (23 ) Acquisition of leasehold interests — (1,961 ) — — (1,961 ) Acquisition of mineral interests — (63 ) (344 ) — (407 ) Acquisition of midstream assets — — (50 ) — (50 ) Proceeds from sale of assets — 66 — — 66 Funds held in escrow — (27 ) 131 — 104 Intercompany transfers (1,631 ) 1,631 — — — Net cash used in investing activities (1,631 ) (1,166 ) (335 ) — (3,132 ) Cash flows from financing activities: Proceeds from borrowing under credit facility — 475 279 — 754 Repayment under credit facility — (78 ) (306 ) — (384 ) Purchase of subsidiary units by parent (10 ) — — 10 — Debt issuance costs (8 ) 1 (2 ) — (9 ) Public offering costs — — (1 ) — (1 ) Proceeds from public offerings — — 380 (10 ) 370 Distribution from subsidiary 90 — (1 ) (89 ) — Distribution to non-controlling interest — — (130 ) 89 (41 ) Net cash provided by financing activities 72 398 219 — 689 Net increase (decrease) in cash and cash equivalents (1,588 ) — 34 — (1,554 ) Cash and cash equivalents at beginning of period 1,642 — 24 — 1,666 Cash and cash equivalents at end of period $ 54 $ — $ 58 $ — $ 112

SUPPLEMENTAL INFORMATION ON OIL

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)	12 Months Ended
	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)	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, 2019 2018 (In millions) Oil and natural gas properties: Proved properties $ 16,575 $ 12,629 Unproved properties 9,207 9,670 Total oil and natural gas properties 25,782 22,299 Accumulated depreciation, depletion, amortization (2,995 ) (1,599 ) Accumulated impairment (1,934 ) (1,144 ) Net oil and natural gas properties capitalized $ 20,853 $ 19,556 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, 2019 2018 2017 (In millions) Acquisition costs: Proved properties $ 194 $ 5,665 $ 455 Unproved properties 418 5,818 2,692 Development costs 956 493 145 Exploration costs 1,915 1,090 780 Total $ 3,483 $ 13,066 $ 4,072 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, natural gas and natural gas liquids. It does not include any interest costs or general and administrative costs and it reflects estimated corporate income taxes at enacted tax rates expected to be applicable the Company. Therefore, the following schedule is not necessarily indicative of the contribution to the net operating results of the Company’s oil, natural gas and natural gas liquids operations. Year Ended December 31, 2019 2018 2017 (In millions) Oil, natural gas and natural gas liquid sales $ 3,887 $ 2,130 $ 1,186 Lease operating expenses (490 ) (205 ) (127 ) Production and ad valorem taxes (248 ) (133 ) (74 ) Gathering and transportation (88 ) (26 ) (13 ) Depreciation, depletion, and amortization (1,447 ) (595 ) (321 ) Impairment (790 ) — — Asset retirement obligation accretion expense (7 ) (2 ) (1 ) Income tax benefit (expense) (89 ) (241 ) 20 Results of operations $ 728 $ 928 $ 670 Oil and Natural Gas Reserves Proved oil and natural gas reserve estimates as of December 31, 2019 , 2018 and 2017 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 Natural Gas Natural Gas Proved Developed and Undeveloped Reserves: As of January 1, 2017 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 Extensions and discoveries 143,256 33,152 154,088 Revisions of previous estimates 3,689 11,138 3,642 Purchase of reserves in place 281,333 98,865 640,761 Divestitures (156 ) (8 ) (543 ) Production (34,367 ) (7,465 ) (34,668 ) As of December 31, 2018 626,936 190,291 1,048,649 Extensions and discoveries 256,569 66,572 318,874 Revisions of previous estimates (84,789 ) (8,166 ) (149,657 ) Purchase of reserves in place 13,974 3,813 19,830 Divestitures (33,269 ) (3,809 ) (21,272 ) Production (68,518 ) (18,498 ) (97,613 ) As of December 31, 2019 710,903 230,203 1,118,811 Proved Developed Reserves: January 1, 2017 79,457 22,080 105,399 December 31, 2017 141,246 35,412 190,740 December 31, 2018 403,051 125,509 705,084 December 31, 2019 457,083 165,173 824,760 Proved Undeveloped Reserves: January 1, 2017 59,717 15,054 69,497 December 31, 2017 91,935 19,198 94,629 December 31, 2018 223,885 64,782 343,565 December 31, 2019 253,820 65,030 294,051 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, 2019, the Company’s extensions and discoveries totaling 376,287 MBOE resulted primarily from the drilling of 283 new wells and from 291 new proved undeveloped locations added in which the Company owns a working interest. Viper royalty interests accounted for 5% of the extension volumes. The Company’s downward revisions of 117,898 MBOE were the result of proved undeveloped downgrades associated with inventory refinement following the Energen acquisition along with updated development plans and lower realized prices. Purchases of 21,092 MBOE were the result of 10,939 MBOE of working interest purchases and 10,153 MBOE of Viper royalty purchases, excluding mineral interests dropped down to Viper. During the year ended December 31, 2018, the Company’s extensions and discoveries of 202,089 MBOE resulted primarily from the drilling of 135 new wells and from 138 new proved undeveloped locations added in which the Company owns a working interest. Viper royalty interests accounted for 10% of the extension volumes. The Company’s revisions of previous estimates were primarily the result of positive technical and performance revisions of 14,218 MBOE, upward revisions of 6,032 MBOE due to higher pricing and downward revisions of 4,815 MBOE from PUD reclassifications due to timing. Purchases of 486,992 MBOE were the result of 477,686 of working interest purchases, primarily attributable to Energen, and 9,306 MBOE of Viper royalty purchases. 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. Viper 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 Viper royalty interest purchases accounted for 10% , with working interest purchases contributing the remainder. At December 31, 2019 , the Company’s estimated PUD reserves were approximately 367,859 MBOE, a 21,931 MBOE increase over the reserve estimate at December 31, 2018 of 345,928 MBOE. The following table includes the changes in PUD reserves for 2019 : (MBOE) Beginning proved undeveloped reserves at December 31, 2018 345,928 Undeveloped reserves transferred to developed (120,920 ) Revisions (77,519 ) Net purchases 4,542 Divestitures (5,672 ) Extensions and discoveries 221,500 Ending proved undeveloped reserves at December 31, 2019 367,859 The increase in proved undeveloped reserves was primarily attributable to extensions of 213,909 MBOE from 291 gross ( 262 net) wells in which the Company has a working interest and 7,591 MBOE from 97 gross wells in which Viper owns royalty interests. Of the 291 gross working interest wells, 64 were in the Delaware Basin. Transfers of 120,920 MBOE were the result of drilling or participating in 135 gross ( 119 net) horizontal wells in which the Company has a working interest and 79 gross wells in which the Company has a royalty interest or mineral interest through Viper. The Company owns a working interest in 75 of the 79 gross Viper wells. Downward revisions of 77,519 MBOE resulted from 67,114 MBOE of PUD downgrades due to refinement of the PUD inventory following the acquisition of Energen. These downgrades were offset with Extensions. The remaining 10,405 MOE of downward revisions were mostly from lower benchmark commodity prices. As of December 31, 2019 , all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2019 , approximately $956 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, 2019 , 2018 and 2017 . December 31, 2019 2018 2017 (In millions) Future cash inflows $ 40,681 $ 43,578 $ 12,922 Future development costs (3,809 ) (3,560 ) (1,124 ) Future production costs (9,319 ) (7,727 ) (2,995 ) Future production taxes (2,905 ) (2,935 ) (929 ) Future income tax expenses (2,635 ) (3,913 ) (84 ) Future net cash flows 22,013 25,443 7,790 10% discount to reflect timing of cash flows (11,829 ) (13,767 ) (4,033 ) Standardized measure of discounted future net cash flows $ 10,184 $ 11,676 $ 3,757 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, 2019 2018 2017 Unweighted Arithmetic Average First-Day-of-the-Month Prices Oil (per Bbl) $ 51.88 $ 59.63 $ 48.03 Natural gas (per Mcf) $ 0.18 $ 1.47 $ 2.06 Natural gas liquids (per Bbl) $ 15.65 $ 24.43 $ 20.79 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, 2019 2018 2017 (In millions) Standardized measure of discounted future net cash flows at the beginning of the period $ 11,676 $ 3,757 $ 1,711 Sales of oil and natural gas, net of production costs (3,334 ) (1,786 ) (986 ) Acquisition of reserves 309 5,520 439 Divestiture of reserves (500 ) (2 ) (11 ) Extensions and discoveries, net of future development costs 4,004 3,287 1,792 Previously estimated development costs incurred during the period 120 535 190 Net changes in prices and production costs 831 1,805 578 Changes in estimated future development costs (3,190 ) (81 ) (53 ) Revisions of previous quantity estimates (1,242 ) 271 (99 ) Accretion of discount 1,344 380 174 Net change in income taxes 693 (1,728 ) (9 ) Net changes in timing of production and other (527 ) (282 ) 31 Standardized measure of discounted future net cash flows at the end of the period $ 10,184 $ 11,676 $ 3,757

QUARTERLY FINANCIAL DATA (Unaud

QUARTERLY FINANCIAL DATA (Unaudited)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA (Unaudited)	QUARTERLY FINANCIAL DATA (Unaudited) The Company’s unaudited quarterly financial data for 2019 and 2018 is summarized below. 2019 (in millions) First Second Third Fourth Revenues $ 864 $ 1,021 $ 975 $ 1,104 Income (loss) from operations 319 411 349 (384 ) Income tax expense (benefit) (33 ) 102 102 (124 ) Net income (loss) 43 356 388 (472 ) Net income attributable to non-controlling interest 33 7 20 15 Net income (loss) attributable to Diamondback Energy, Inc. $ 10 $ 349 $ 368 $ (487 ) Earnings per common share Basic $ 0.06 $ 2.12 $ 2.27 $ (3.04 ) Diluted $ 0.06 $ 2.11 $ 2.26 $ (3.04 ) 2018 (in millions) First Second Third Fourth Revenues $ 479 $ 527 $ 537 $ 633 Income from operations 267 281 268 195 Income tax expense (benefit) 47 (7 ) 43 85 Net income 178 301 160 306 Net income attributable to non-controlling interest 15 82 3 (1 ) Net income attributable to Diamondback Energy, Inc. $ 163 $ 219 $ 157 $ 307 Earnings per common share Basic $ 1.65 $ 2.22 $ 1.59 $ 2.50 Diluted $ 1.65 $ 2.22 $ 1.59 $ 2.50

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2019
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	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 As of December 31, 2019, the Company had restricted cash of $5 million related to the Company’s obligations under its participation and development agreement with Obsidian Resources, L.L.C.
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.
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 16 —Fair Value Measurements).
Oil and Natural Gas Properties	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. 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. 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 9
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 15 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
Capitalized Interest	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 unevaluated properties to their intended use. Capitalized interest cannot exceed gross interest expense. The Company capitalized interest of $66 million , $32 million and $22 million for the years ended December 31, 2019 , 2018 and 2017 , respectively.
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 Revenue from Contracts with Customers Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies. Oil sales The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations. Natural gas and natural gas liquids sales Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations. Midstream Revenue Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler provides to exploration and production operations. The portion of such fees shown in the Company’s consolidated financial statements represent amounts charged to interest owners in the Company’s operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement. Transaction price allocated to remaining performance obligations The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligations under any of our product sales contracts. The majority of the Company’s midstream revenue agreements have a term greater than one year, and as such the Company has utilized the practical expedient in ASC 606, which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The remainder of the Company’s midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. The Company has utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less. Contract balances Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. Prior-period performance obligations The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2019 , revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.
Investments	Investments
Accounting for Stock-based Compensation	Accounting for Equity-Based Compensation The Company has granted various types of stock-based awards including stock options and restricted stock units. Viper has granted various unit-based awards including unit options and phantom units to employees, officers and directors of Viper’s General Partner and the Company who perform services for Viper. Rattler has granted unit-based awards consisting of phantom units to employees, officers and directors of Rattler’s General Partner and the Company who perform services for Rattler. These plans and related accounting policies are defined and described more fully in Note 12 —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
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 The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Company’s analysis of the effects on its financial statements: Standard Description Date of Adoption Effect on Financial Statements or Other Significant Matters Recently Adopted Pronouncements ASU 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. Q1 2020 The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses. ASU 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement” This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. Q1 2020 The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels. ASU 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract” This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement. Q1 2020 The Company adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity. ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)” This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis. Q1 2020 The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have any cost method investments. Pronouncements Not Yet Adopted ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes” This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance. Q1 2021 This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company does not believe that the adoption of this update will have an impact on its financial position, results of operations or liquidity.
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. The Company estimates the fair values of proved oil and natural gas properties assumed in business combinations using discounted cash flow techniques and based on market assumptions as to the future commodity prices, internal estimates of future quantities of oil and natural gas reserves, future estimated rates of production, expected recovery rates and risk-adjustment discounts. The estimated fair values of unevaluated oil and natural gas properties were based on the location, engineering and geological studies, historical well performance, and applicable mineral lease terms. Given the unobservable nature of the inputs, the estimated fair values of oil and natural gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of business combinations are estimated using the same assumptions and methodology as described below.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Schedule of prepaid expenses and other	Prepaid expenses and other consist of the following: Year Ended December 31, 2019 2018 (In millions) Prepaid insurance $ 6 $ 4 Prepaid fees and licenses 4 3 Income tax receivable 19 38 Other 14 5 Total prepaid expenses and other $ 43 $ 50
Schedule of other accrued liabilities	Other accrued liabilities consist of the following: December 31, 2019 2018 (In millions) Liability for drilling costs prepaid by joint interest partners $ 12 $ 16 Interest payable 27 26 Lease operating expenses payable 119 59 Ad valorem taxes payable 68 49 Other 78 103 Total other accrued liabilities $ 304 $ 253

ACQUISITIONS AND DIVESTITURES (

ACQUISITIONS AND DIVESTITURES (Tables)	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Schedule of estimated fair values of assets acquired and liabilities assumed	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 millions) Proved oil and natural gas properties $ 386 Unevaluated oil and natural gas properties 2,123 Midstream assets 47 Prepaid capital costs 4 Oil inventory 1 Revenues and royalties payable (10 ) Asset retirement obligations (2 ) Total fair value of net assets $ 2,549 The following table sets forth the Company’s purchase price allocation: (In millions) Consideration: Fair value of the Company's common stock issued $ 7,136 Total consideration $ 7,136 Fair value of liabilities assumed: Current liabilities $ 388 Asset retirement obligation 105 Long-term debt 1,099 Noncurrent derivative instruments 17 Deferred income taxes 1,425 Other long-term liabilities 7 Amount attributable to liabilities assumed $ 3,041 Fair value of assets acquired: Total current assets $ 298 Oil and natural gas properties 9,361 Midstream assets 253 Investment in real estate 11 Other property, equipment and land 58 Asset retirement obligation 105 Other postretirement assets 3 Noncurrent income tax receivable, net 76 Other long term assets 12 Amount attributable to assets acquired $ 10,177
Schedule of business acquisition pro forma	The pro forma consolidated statement of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2017 and is not intended to be a projection of future results. Year Ended December 31, 2018 2017 (in millions, except per share amounts) Revenues $ 3,532 $ 2,196 Income from operations 1,559 900 Net income 1,320 875 Basic earnings per common share $ 7.54 $ 5.26 Diluted earnings per common share $ 7.53 $ 5.24 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 millions, except per share amounts) Revenues $ 1,228 $ 627 Income (loss) from operations 619 (13 ) Net income (loss) 473 (109 ) Basic earnings per common share $ 4.85 $ (1.45 ) Diluted earnings per common share $ 4.84 $ (1.45 )

VIPER ENERGY PARTNERS LP (Table

VIPER ENERGY PARTNERS LP (Tables)	12 Months Ended
	Dec. 31, 2019
Noncontrolling Interest [Abstract]
Schedule of sale of stock	Viper completed the following equity offerings during the years ended December 31, 2019 , 2018 and 2017 : Date Number of Units of Common Units Sold Number of Units of Common Units Issued to Underwriters Proceeds Received by Viper Amount Repaid on Viper LLC’s Credit Facility (in millions) January 2017 9,775,000 1,275,000 $ 148 $ 121 July 2017 (1) 16,100,000 2,100,000 $ 232 $ 153 July 2018 10,080,000 1,080,000 $ 303 $ 362 March 2019 10,925,000 1,425,000 $ 341 $ 314 (1) In this offering, Diamondback 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.

REAL ESTATE ASSETS (Tables)

REAL ESTATE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2019
Real Estate [Line Items]
Schedule of real estate assets	The following schedules present the cost and related accumulated depreciation or amortization (as applicable) of Diamondback’s real estate assets including intangible lease assets: Estimated Useful Lives December 31, 2019 2018 (Years) (in millions) Buildings 20-30 $ 102 $ 103 Tenant improvements 15 5 4 Land N/A 2 1 Land improvements 15 1 1 Total real estate assets 110 109 Less: accumulated depreciation (9 ) (4 ) Total investment in land and buildings, net $ 101 $ 105 Weighted Average Useful Lives December 31, 2019 2018 (Months) (in millions) In-place lease intangibles 45 $ 11 $ 11 Less: accumulated amortization (6 ) (3 ) In-place lease intangibles, net 5 8 Above-market lease intangibles 45 4 4 Less: accumulated amortization (1 ) (1 ) Above-market lease intangibles, net 3 3 Total intangible lease assets, net $ 8 $ 11

PROPERTY AND EQUIPMENT (Tables)

PROPERTY AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Schedule of property and equipment	Property and equipment includes the following: December 31, 2019 2018 (in millions) Oil and natural gas properties: Subject to depletion $ 16,575 $ 12,629 Not subject to depletion 9,207 9,670 Gross oil and natural gas properties 25,782 22,299 Accumulated depletion (2,995 ) (1,599 ) Accumulated impairment (1,934 ) (1,144 ) Oil and natural gas properties, net 20,853 19,556 Midstream assets 931 700 Other property, equipment and land 125 147 Accumulated depreciation (74 ) (31 ) Property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 21,835 $ 20,372 Balance of costs not subject to depletion: Incurred in 2019 $ 604 Incurred in 2018 5,654 Incurred in 2017 2,329 Incurred in 2016 620 Total not subject to depletion $ 9,207

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 2017 (in millions) Asset retirement obligations, beginning of period $ 136 $ 21 $ 17 Additional liabilities incurred 8 3 2 Liabilities acquired 4 111 2 Liabilities settled (61 ) (2 ) (1 ) Accretion expense 7 2 1 Revisions in estimated liabilities — 1 — Asset retirement obligations, end of period 94 136 21 Less current portion — — 1 Asset retirement obligations - long-term $ 94 $ 136 $ 20

EQUITY METHOD INVESTMENTS (Tabl

EQUITY METHOD INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
Equity Method Investments and Joint Ventures [Abstract]
Equity method investments	At December 31, 2019 and 2018 , Rattler had the following investments: Net Ownership Interest December 31, 2019 December 31, 2018 (In millions) EPIC Crude Holdings, LP 10 % $ 110 $ — Gray Oak Pipeline, LLC 10 % 115 1 Wink to Webster Pipeline LLC 4 % 34 — OMOG JV LLC 60 % 219 — Amarillo Rattler, LLC 50 % 1 — $ 479 $ 1 The following summarizes the income (loss) of equity method investees for the periods presented: Year Ended December 31, 2019 2018 2017 (In millions) EPIC Crude Holdings, LP $ (6 ) $ — $ — Gray Oak Pipeline, LLC 1 — — Wink to Webster Pipeline LLC (1 ) — — OMOG JV LLC — — — HMW LLC — — 1 $ (6 ) $ — $ 1

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Schedule of long-term debt	Long-term debt consisted of the following as of the dates indicated: December 31, 2019 2018 (in millions) 4.625% Notes due 2021 $ 399 $ 400 7.320% Medium-term Notes, Series A, due 2022 21 20 2.875% Senior Notes due 2024 1,000 — 4.750% Senior Notes due 2024 — 1,250 5.375% Senior Notes due 2025 800 800 3.250% Senior Notes due 2026 800 — 7.350% Medium-term Notes, Series A, due 2027 11 10 7.125% Medium-term Notes, Series B, due 2028 108 100 3.500% Senior Notes due 2029 1,200 — DrillCo Agreement 39 — Unamortized debt issuance costs (19 ) (27 ) Unamortized discount costs (31 ) — Unamortized premium costs 9 10 Revolving credit facility 13 1,490 Viper revolving credit facility 97 411 Viper 5.375% Senior Notes due 2027 500 — Rattler revolving credit facility 424 — Total long-term debt $ 5,371 $ 4,464
Financial covenants	The Rattler credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below: Financial Covenant Required Ratio Consolidated Total Leverage Ratio commencing with the fiscal quarter ending September 30, 2019 Not greater than 5.00 to 1.00 (or not greater than 5.50 to 1.00 for 3 fiscal quarters following certain acquisitions), but if the Consolidated Senior Secured Leverage Ratio (as defined in the Rattler credit agreement) is applicable, then not greater than 5.25 to 1.00) Consolidated Senior Secured Leverage Ratio commencing with the last day of any fiscal quarter in which the Financial Covenant Election (as defined in the Rattler credit agreement) is made Not greater than 3.50 to 1.00 Consolidated Interest Coverage Ratio (as defined in the Rattler credit agreement) commencing with the fiscal quarter ending September 30, 2019 Not less than 2.50 to 1.00 Financial Covenant Required Ratio Ratio of total net debt to EBITDAX, as defined in the Viper credit agreement Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined the Viper credit agreement Not less than 1.0 to 1.0
Schedule of interest expense	The following amounts have been incurred and charged to interest expense for the years ended December 31, 2019 , 2018 and 2017 : Year Ended December 31, 2019 2018 2017 (in millions) Interest expense $ 235 $ 110 $ 61 Less capitalized interest (66 ) (32 ) (22 ) Other fees and expenses 4 10 2 Total interest expense $ 173 $ 88 $ 41

CAPITAL STOCK AND EARNINGS PE_2

CAPITAL STOCK AND EARNINGS PER SHARE (Tables)	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Schedule of reconciliation of basic and diluted net income per share	A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: Year Ended December 31, 2019 2018 2017 (In millions, except per share amounts, shares in thousands) Net income attributable to common stock $ 240 $ 846 $ 482 Weighted average common shares outstanding: Basic weighted average common units outstanding 163,493 104,622 97,458 Effect of dilutive securities: Potential common shares issuable 350 307 230 Diluted weighted average common shares outstanding 163,843 104,929 97,688 Basic net income attributable to common stock $ 1.47 $ 8.09 $ 4.95 Diluted net income attributable to common stock $ 1.47 $ 8.06 $ 4.94
Schedule of antidilutive securities excluded from computation of earnings per share	The Company had the following shares that were excluded from 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: Year Ended December 31, 2019 2018 2017 (in thousands) Restricted stock units 284 14 46

EQUITY-BASED COMPENSATION (Tabl

EQUITY-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Schedule 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: Year Ended December 31, 2019 2018 2017 (In millions) General and administrative expenses $ 48 $ 27 $ 25 Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties $ 17 $ 10 $ 9
Summary of restricted stock units	The following table presents the Company’s restricted stock units activity under the Equity Plan during the year ended December 31, 2019 : Restricted Stock Weighted Average Grant-Date Unvested at December 31, 2018 324,224 $ 116.01 Granted 697,679 $ 99.36 Vested (425,608 ) $ 105.09 Forfeited (90,428 ) $ 106.55 Unvested at December 31, 2019 505,867 $ 96.01
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. 2019 2018 2017 Three-Year Performance Period Three-Year Performance Period Two-Year Performance Period Three-Year Performance Period Grant-date fair value $ 137.22 $ 170.45 $ 162.13 $ 168.73 Grant-date fair value (5-year vesting) $ 132.48 Risk-free rate 2.55 % 1.99 % 1.27 % 1.59 % Company volatility 35.00 % 35.90 % 39.32 % 41.14 %
Schedule of performance restricted stock units activity	The following table presents the Company’s performance restricted stock unit activity under the Equity Plan for the year ended December 31, 2019 : Performance Restricted Stock Units Weighted Average Grant-Date Fair Value Unvested at December 31, 2018 196,203 $ 169.76 Granted 356,227 $ 131.30 Vested (176,976 ) $ 93.32 Forfeited (103,635 ) $ 155.23 Unvested at December 31, 2019 (1) 271,819 $ 147.07 (1) A maximum of 543,638 units could be awarded based upon the Company’s final TSR ranking.
Summary of stock appreciation rights activity	The following table presents a summary of stock appreciation rights activity during the year ended December 31, 2019 : Shares Weighted Average Exercise Price Outstanding at December 31, 2018 57,721 $ 22.12 Exercised (11,399 ) $ 70.69 Expired (3,775 ) $ 96.91 Outstanding at December 31, 2019 42,547 $ 90.89
Schedule of stock option activity	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 expected term of options granted was determined based on the contractual term of the awards at effective time of the merger. 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. All such amounts represent the weighted-average amounts for each year. Weighted Average Exercise Remaining Intrinsic Options Price Term Value (in years) (in millions) Outstanding at December 31, 2018 332,387 $ 95.04 Exercised (116,044 ) $ 82.29 Outstanding at December 31, 2019 216,343 $ 89.90 1.67 $ — Vested and Expected to vest at December 31, 2019 216,343 $ 89.90 1.67 $ — Exercisable at December 31, 2019 216,343 $ 89.90 1.67 $ —
Schedule of phantom units activity	The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2019 : Phantom Units Weighted Average Grant-Date Unvested at December 31, 2018 125,053 $ 23.44 Granted 56,582 $ 30.33 Vested (85,359 ) $ 23.96 Forfeited (1,028 ) $ 42.50 Unvested at December 31, 2019 95,248 $ 26.87 The following table presents the phantom unit activity under the Rattler LTIP for the year ended December 31, 2019 : Phantom Weighted Average Unvested at May 28, 2019 — $ — Granted 2,284,038 $ 19.14 Forfeited (57,143 ) $ 19.21 Unvested at December 31, 2019 2,226,895 $ 19.14

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Schedule of components of income tax provision (benefit)	The components of the Company’s consolidated provision for income taxes from continuing operations for the years ended December 31, 2019 , 2018 and 2017 are as follows: Year Ended December 31, 2019 2018 2017 (In millions) Current income tax provision (benefit): Federal $ — $ — $ — State — — — Total current income tax provision (benefit) — — — Deferred income tax provision (benefit): Federal 40 160 (21 ) State 7 8 1 Total deferred income tax provision (benefit) 47 168 (20 ) Total provision for (benefit from) income taxes $ 47 $ 168 $ (20 )
Reconciliation of statutory federal income tax	A reconciliation of the statutory federal income tax amount from continuing operations to the recorded expense is as follows: Year Ended December 31, 2019 2018 2017 (In millions) Income tax expense at the federal statutory rate (1) $ 76 $ 234 $ 174 Impact of nontaxable noncontrolling interest — (5 ) (12 ) Income tax benefit relating to change in statutory tax rate — — (68 ) State income tax expense, net of federal tax effect 6 8 3 Non-deductible compensation 4 5 13 Change in valuation allowance — — (127 ) Deferred taxes related to change in Viper LP's tax status (42 ) (73 ) — Other, net 3 (1 ) (3 ) Provision for (benefit from) income taxes $ 47 $ 168 $ (20 ) (1) The federal statutory rates for the years ended December 31, 2019 , 2018 and 2017 were 21% , 21% and 35% , respectively.
Schedule of deferred tax assets and liabilities	The components of the Company’s deferred tax assets and liabilities as of December 31, 2019 and 2018 are as follows: December 31, 2019 2018 (In millions) Deferred tax assets: Net operating loss and other carryforwards $ 453 $ 155 Stock based compensation 7 7 Viper LP's investment in Viper LLC 134 94 Other 11 9 Deferred tax assets 605 265 Valuation allowance (7 ) (14 ) Deferred tax assets, net of valuation allowance 598 251 Deferred tax liabilities: Oil and natural gas properties and equipment 2,275 1,825 Midstream investments 50 67 Derivative instruments 6 47 Rattler LP's investment in Rattler LLC 8 — Other 3 — Total deferred tax liabilities 2,342 1,939 Net deferred tax liabilities $ 1,744 $ 1,688
Schedule of unrecognized tax benefits	The following table sets forth changes in the Company’s unrecognized tax benefits: December 31, 2019 2018 (in millions) Balance at beginning of year $ 7 $ — Increase resulting from tax positions acquired — 7 Increase resulting from prior period tax positions — — Increase resulting from current period tax positions — — Balance at end of year 7 7 Less: Effects of temporary items (5 ) (5 ) Total that, if recognized, would impact the effective income tax rate as of the end of the year $ 2 $ 2

DERIVATIVES (Tables)

DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of derivative instruments	As of December 31, 2019 , the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed: 2020 2021 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 4,754,000 $ 57.78 0 $ — Oil Swaps - WTI Magellan East Houston 2,196,000 $ 62.80 0 $ — Oil Swaps - BRENT 4,569,000 $ 61.84 0 $ — Oil Basis Swaps - WTI Cushing 13,860,000 $ (1.20 ) 0 $ — Oil Rolling Hedge - WTI Cushing 6,700,000 $ 0.44 0 $ — Natural Gas Swaps - Henry Hub 10,050,000 $ 2.55 0 $ — Natural Gas Swaps - Waha Hub 16,750,000 $ 1.67 0 $ — Natural Gas Basis Swaps - Waha Hub 23,450,000 $ (1.19 ) 54,750,000 $ (0.70 ) 2020 Oil Three-Way Collars WTI Cushing Brent WTI Magellan East Houston Volume (Bbls) 6,842,200 11,803,500 5,124,000 Short put price (per Bbl) $ 44.20 $ 50.00 $ 50.00 Floor price (per Bbl) $ 54.20 $ 60.00 $ 60.00 Ceiling price (per Bbl) $ 65.42 $ 70.86 $ 68.61 Gas Swap Double-Up - Waha Hub 2020 Volume (Mcf) 10,050,000 Swap price (per Mcf) $ 1.70 Option price $ 1.70 The following tables present the derivative contracts entered into by the Company subsequent to December 31, 2019 . When aggregating multiple contracts, the weighted average contract price is disclosed. 2020 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 732,000 $ 60.50 Oil Swaps - BRENT 732,000 $ 65.00 Natural Gas Swaps - Waha Hub 1,840,000 $ 0.75 Natural Gas Basis Swaps - Waha Hub 13,750,000 $ (1.85 ) Diesel Price Swaps 11,000,000 $ 1.60 2020 Oil Three-Way Collars Brent Volume (Bbls) 732,000 Short put price (per Bbl) $ 50.00 Floor price (per Bbl) $ 60.00 Ceiling price (per Bbl) $ 69.25 2020 Oil Put Spreads - WTI Volume (Bbls) 829,125 Short put price (per Bbl) $ 50.50 Floor price (per Bbl) $ 60.50 Oil Put Spreads - Brent Volume (Bbls) 1,758,750 Short put price (per Bbl) $ 52.38 Floor price (per Bbl) $ 65.00
Schedule of netting offsets of derivative assets and liabilities	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, 2019 and 2018 : December 31, 2019 2018 (in millions) Gross amounts of assets presented in the Consolidated Balance Sheet $ 71 $ 233 Amounts netted in the Consolidated Balance Sheet (18 ) (2 ) Net amounts of assets presented in the Consolidated Balance Sheet $ 53 $ 231 Gross amounts of liabilities presented in the Consolidated Balance Sheet $ 45 $ 15 Amounts netted in the Consolidated Balance Sheet (18 ) — Net amounts of liabilities presented in the Consolidated Balance Sheet $ 27 $ 15
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, 2019 2018 (in millions) Current assets: derivative instruments $ 46 $ 231 Noncurrent assets: derivative instruments 7 — Total assets $ 53 $ 231 Current liabilities: derivative instruments $ 27 $ — Noncurrent liabilities: derivative instruments — 15 Total liabilities $ 27 $ 15
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, 2019 2018 2017 (in thousands) Change in fair value of open non-hedge derivative instruments: $ (188 ) $ 222 $ (84 ) Gain (loss) on settlement of non-hedge derivative instruments: 80 (121 ) 6 Gain (loss) on derivative instruments $ (108 ) $ 101 $ (78 )

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of 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, 2019 and 2018 : December 31, 2019 December 31, 2018 Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 (in millions) Assets: Investment $ 19 $ — $ — $ 14 $ — $ — Fixed price swaps $ — $ 26 $ — $ — $ 216 $ — Liabilities: Fixed price swaps $ — $ — $ — $ — $ — $ — The following table summarizes the changes in fair value of Viper’s cost method investment during the periods presented: (in millions) Value at December 31, 2018 $ 14 Gain on investment 5 Value at December 31, 2019 $ 19 Value at December 31, 2017 $ 34 Impact of adoption of Accounting Standards Update 2016-01 (19 ) Loss on investment (1 ) Value at December 31, 2018 $ 14
Schedule of 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, 2019 December 31, 2018 Carrying Carrying Amount Fair Value Amount Fair Value (in thousands) Debt: Revolving credit facility $ 13 $ 13 $ 1,490 $ 1,490 4.625% Notes due 2021 399 411 400 393 7.320% Medium-term Notes, Series A, due 2022 21 22 20 21 2.875% Senior Notes due 2024 (1) 992 1,012 — — 4.750% Senior Notes due 2024 (1) — — 1,236 1,204 5.375% Senior Notes due 2025 (1) 799 840 799 782 3.250% Senior Notes due 2026 (1) 792 812 — — 7.350% Medium-term Notes, Series A, due 2027 11 12 10 11 7.125% Medium-term Notes, Series B, due 2028 108 116 100 102 3.500% Senior Notes due 2029 (1) 1,186 1,226 — — Viper revolving credit facility 97 97 411 411 Viper's 5.375% Senior Notes due 2027 490 521 — — Rattler revolving credit facility 424 424 — — DrillCo Agreement $ 39 $ 39 $ — $ — (1) The carrying value includes associated deferred loan costs and any discount.

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Schedule of operating lease costs	The following table summarizes operating lease costs for the year ended December 31, 2019 : Year Ended December 31, 2019 (in millions) Operating lease costs $ 26
Schedule of undiscounted cash flows owned by company to lessors pursuant to contractual agreements	Schedule of Operating Lease Liability Maturities . The following table summarizes undiscounted cash flows owed by the Company to lessors pursuant to contractual agreements in effect as of December 31, 2019 : As of December 31, 2019 (in millions) 2020 $ 9 2021 5 2022 2 2023 — 2024 — Thereafter — Total lease payments 16 Less: interest 1 Present value of lease liabilities $ 15

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Schedule of minimum future payments	The following is a schedule of minimum future payments with commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2019 : Year Ending December 31, Sand Supply Agreement (in millions) 2020 $ 18 2021 18 2022 18 2023 18 2024 18 Thereafter 23 Total $ 113
Schedule of rent expense	The following table presents rent expense for the years ended December 31, 2019 , 2018 and 2017 : Year ended December 31, 2019 2018 2017 (in millions) Rent Expense $ 3 $ 1 $ 2

SUBSEQUENT EVENTS SUBSEQUENT EV

SUBSEQUENT EVENTS SUBSEQUENT EVENTS (Tables)	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Schedule of derivative instruments	As of December 31, 2019 , the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed: 2020 2021 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 4,754,000 $ 57.78 0 $ — Oil Swaps - WTI Magellan East Houston 2,196,000 $ 62.80 0 $ — Oil Swaps - BRENT 4,569,000 $ 61.84 0 $ — Oil Basis Swaps - WTI Cushing 13,860,000 $ (1.20 ) 0 $ — Oil Rolling Hedge - WTI Cushing 6,700,000 $ 0.44 0 $ — Natural Gas Swaps - Henry Hub 10,050,000 $ 2.55 0 $ — Natural Gas Swaps - Waha Hub 16,750,000 $ 1.67 0 $ — Natural Gas Basis Swaps - Waha Hub 23,450,000 $ (1.19 ) 54,750,000 $ (0.70 ) 2020 Oil Three-Way Collars WTI Cushing Brent WTI Magellan East Houston Volume (Bbls) 6,842,200 11,803,500 5,124,000 Short put price (per Bbl) $ 44.20 $ 50.00 $ 50.00 Floor price (per Bbl) $ 54.20 $ 60.00 $ 60.00 Ceiling price (per Bbl) $ 65.42 $ 70.86 $ 68.61 Gas Swap Double-Up - Waha Hub 2020 Volume (Mcf) 10,050,000 Swap price (per Mcf) $ 1.70 Option price $ 1.70 The following tables present the derivative contracts entered into by the Company subsequent to December 31, 2019 . When aggregating multiple contracts, the weighted average contract price is disclosed. 2020 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Oil Swaps - WTI Cushing 732,000 $ 60.50 Oil Swaps - BRENT 732,000 $ 65.00 Natural Gas Swaps - Waha Hub 1,840,000 $ 0.75 Natural Gas Basis Swaps - Waha Hub 13,750,000 $ (1.85 ) Diesel Price Swaps 11,000,000 $ 1.60 2020 Oil Three-Way Collars Brent Volume (Bbls) 732,000 Short put price (per Bbl) $ 50.00 Floor price (per Bbl) $ 60.00 Ceiling price (per Bbl) $ 69.25 2020 Oil Put Spreads - WTI Volume (Bbls) 829,125 Short put price (per Bbl) $ 50.50 Floor price (per Bbl) $ 60.50 Oil Put Spreads - Brent Volume (Bbls) 1,758,750 Short put price (per Bbl) $ 52.38 Floor price (per Bbl) $ 65.00

REPORT OF BUSINESS SEGMENTS REP

REPORT OF BUSINESS SEGMENTS REPORT OF BUSINESS SEGMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Reporting [Abstract]
Schedule of results of the company business segments	The following tables summarize the results of the Company's business segments during the periods presented: Upstream Midstream Services Eliminations Total Year Ended December 31, 2019: (in millions) Third-party revenues $ 3,891 $ 73 $ — $ 3,964 Intersegment revenues — 375 (375 ) — Total revenues 3,891 448 (375 ) 3,964 Depreciation, depletion and amortization $ 1,405 $ 42 $ — $ 1,447 Impairment of oil and natural gas properties $ 790 $ — $ — $ 790 Income from operations $ 790 $ 219 $ (314 ) $ 695 Interest expense, net $ (171 ) $ (1 ) $ — $ (172 ) Total other income (expense), net (1) $ (320 ) $ (7 ) $ (6 ) $ (333 ) Provision for income taxes $ 21 $ 26 $ — $ 47 Net income attributable to non-controlling interest $ 75 $ 91 $ (91 ) $ 75 Net income attributable to Diamondback Energy $ 374 $ 95 $ (229 ) $ 240 Total assets $ 22,125 $ 1,636 $ (230 ) $ 23,531 (1) The impairment for the midstream services segment of $2 million is included in other income (expense). Upstream Midstream Services Eliminations Total Year Ended December 31, 2018: (in millions) Third-party revenues $ 2,132 $ 44 $ — $ 2,176 Intersegment revenues — 140 (140 ) — Total revenues 2,132 184 (140 ) 2,176 Depreciation, depletion and amortization $ 598 $ 25 $ — $ 623 Income from operations $ 1,071 $ 80 $ (140 ) $ 1,011 Interest expense, net $ (87 ) $ — $ — $ (87 ) Total other income (expense), net $ 102 $ — $ — $ 102 Provision for income taxes $ 151 $ 17 $ — $ 168 Net income attributable to non-controlling interest $ 99 $ — $ — $ 99 Net income attributable to Diamondback Energy $ 923 $ 63 $ (140 ) $ 846 Total assets $ 21,096 $ 604 $ (104 ) $ 21,596 Upstream Midstream Services Eliminations Total Year Ended December 31, 2017: (in millions) Third-party revenues $ 1,198 $ 7 $ — $ 1,205 Intersegment revenues — 32 (32 ) — Total revenues 1,198 39 (32 ) 1,205 Depreciation, depletion and amortization $ 324 $ 3 $ — $ 327 Income from operations $ 613 $ 24 $ (32 ) $ 605 Interest expense, net $ (41 ) $ — $ — $ (41 ) Total other income (expense), net $ (109 ) $ 1 $ — $ (108 ) Provision for income taxes $ (24 ) $ 4 $ — $ (20 ) Net income attributable to non-controlling interest $ 35 $ — $ — $ 35 Net income attributable to Diamondback Energy $ 493 $ 21 $ (32 ) $ 482 Total assets $ 7,475 $ 300 $ (4 ) $ 7,771

GUARANTOR FINANCIAL STATEMENTS

GUARANTOR FINANCIAL STATEMENTS (Tables)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Condensed consolidated balance sheet	Condensed Consolidated Balance Sheet December 31, 2019 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 93 $ — $ 30 $ — $ 123 Restricted cash 5 — — — 5 Accounts receivable, net — 248 367 — 615 Intercompany receivable 5,331 — 572 (5,903 ) — Inventories — 1 36 — 37 Derivative instruments — 46 — — 46 Prepaid expenses and other 2 1 21 19 43 Total current assets 5,431 296 1,026 (5,884 ) 869 Property and equipment: Oil and natural gas properties, full cost method of accounting — 13,276 12,707 (201 ) 25,782 Midstream assets — — 931 — 931 Other property, equipment and land — — 125 — 125 Accumulated depletion, depreciation, amortization and impairment — (3,167 ) (1,831 ) (5 ) (5,003 ) Net property and equipment — 10,109 11,932 (206 ) 21,835 Equity method investments — — 479 — 479 Derivative instruments — 7 — — 7 Investment in subsidiaries 10,414 — — (10,414 ) — Investment in real estate, net — — 109 — 109 Deferred tax asset — — 142 — 142 Other assets — 10 310 (230 ) 90 Total assets $ 15,845 $ 10,422 $ 13,998 $ (16,734 ) $ 23,531 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ — $ 179 $ — $ 179 Intercompany payable — 5,930 (27 ) (5,903 ) — Accrued capital expenditures — — 475 — 475 Other accrued liabilities 17 132 155 — 304 Revenues and royalties payable — — 278 — 278 Derivative instruments — 18 8 1 27 Total current liabilities 17 6,080 1,068 (5,902 ) 1,263 Long-term debt 3,769 13 1,589 — 5,371 Asset retirement obligations — 34 60 — 94 Deferred income taxes 470 — 1,416 — 1,886 Other long-term liabilities — — 11 — 11 Total liabilities 4,256 6,127 4,144 (5,902 ) 8,625 Commitments and contingencies Stockholders’ equity 11,589 4,295 7,908 (10,543 ) 13,249 Non-controlling interest — — 1,946 (289 ) 1,657 Total equity 11,589 4,295 9,854 (10,832 ) 14,906 Total liabilities and equity $ 15,845 $ 10,422 $ 13,998 $ (16,734 ) $ 23,531 Condensed Consolidated Balance Sheet December 31, 2018 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 84 $ 2 $ 129 $ — $ 215 Accounts receivable, net — 143 249 — 392 Accounts receivable - related party — — 4 (4 ) — Intercompany receivable 4,469 — 201 (4,670 ) — Inventories — 2 35 — 37 Derivative instruments — 197 34 — 231 Prepaid expenses and other 2 — 48 — 50 Total current assets 4,555 344 700 (4,674 ) 925 Property and equipment: Oil and natural gas properties, full cost method of accounting — 11,170 11,132 (3 ) 22,299 Midstream assets — 21 679 — 700 Other property, equipment and land — 1 146 — 147 Accumulated depletion, depreciation, amortization and impairment — (2,432 ) (330 ) (12 ) (2,774 ) Net property and equipment — 8,760 11,627 (15 ) 20,372 Equity method investments — — 1 — 1 Investment in subsidiaries 12,689 — 112 (12,801 ) — Deferred tax asset — — 97 — 97 Investment in real estate, net — — 116 — 116 Other assets — 10 75 — 85 Total assets $ 17,244 $ 9,114 $ 12,728 $ (17,490 ) $ 21,596 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ — $ 128 $ — $ 128 Intercompany payable — 3,939 734 (4,673 ) — Accrued capital expenditures — — 495 — 495 Other accrued liabilities 14 23 216 — 253 Revenues and royalties payable — — 143 — 143 Total current liabilities 14 3,962 1,716 (4,673 ) 1,019 Long-term debt 2,036 1,490 938 — 4,464 Derivative instruments — 11 4 — 15 Asset retirement obligations — 30 106 — 136 Deferred income taxes 382 — 1,403 — 1,785 Other long-term liabilities — — 10 — 10 Total liabilities 2,432 5,493 4,177 (4,673 ) 7,429 Commitments and contingencies Stockholders’ equity 14,812 3,621 7,856 (12,589 ) 13,700 Non-controlling interest — — 695 (228 ) 467 Total equity 14,812 3,621 8,551 (12,817 ) 14,167 Total liabilities and equity $ 17,244 $ 9,114 $ 12,728 $ (17,490 ) $ 21,596
Condensed consolidated statement of operations	Condensed Consolidated Statement of Operations Year Ended December 31, 2019 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 1,972 $ 1,318 $ 264 $ 3,554 Natural gas sales — 27 31 8 66 Natural gas liquid sales — 132 114 21 267 Royalty income — — 293 (293 ) — Lease bonus — — 4 — 4 Midstream services — — 434 (370 ) 64 Other operating income — — 14 (5 ) 9 Total revenues — 2,131 2,208 (375 ) 3,964 Costs and expenses: Lease operating expenses — 390 243 (143 ) 490 Production and ad valorem taxes — 130 118 — 248 Gathering and transportation — 75 34 (21 ) 88 Midstream services — — 170 (79 ) 91 Depreciation, depletion and amortization — 735 720 (8 ) 1,447 Impairment of oil and natural gas properties — — 790 — 790 General and administrative expenses 48 1 67 (12 ) 104 Asset retirement obligation accretion — 2 5 — 7 Other operating expense — — 4 — 4 Total costs and expenses 48 1,333 2,151 (263 ) 3,269 Income (loss) from operations (48 ) 798 57 (112 ) 695 Other income (expense): Interest expense, net (47 ) (74 ) (51 ) — (172 ) Other income (expense), net 3 — 2 (7 ) (2 ) Gain on derivative instruments, net — (56 ) (52 ) — (108 ) Gain on revaluation of investment — — 5 — 5 Loss on extinguishment of debt (56 ) — — — (56 ) Income from subsidiaries 764 — — (764 ) — Total other income (expense), net 664 (130 ) (96 ) (771 ) (333 ) Income (loss) before income taxes 616 668 (39 ) (883 ) 362 Provision for (benefit from) income taxes 81 — (33 ) (1 ) 47 Net income (loss) 535 668 (6 ) (882 ) 315 Net income (loss) attributable to non-controlling interest — — 266 (191 ) 75 Net income (loss) attributable to Diamondback Energy, Inc. $ 535 $ 668 $ (272 ) $ (691 ) $ 240 Condensed Consolidated Statement of Operations Year Ended December 31, 2018 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 1,545 $ 87 $ 247 $ 1,879 Natural gas sales — 43 5 13 61 Natural gas liquid sales — 158 9 23 190 Royalty income — — 283 (283 ) — Lease bonus — — 6 (3 ) 3 Midstream services — — 172 (138 ) 34 Other operating income — — 9 — 9 Total revenues — 1,746 571 (141 ) 2,176 Costs and expenses: Lease operating expenses — 230 17 (42 ) 205 Production and ad valorem taxes — 106 27 — 133 Gathering and transportation — 41 1 (16 ) 26 Midstream services — — 72 — 72 Depreciation, depletion and amortization — 472 134 17 623 General and administrative expenses 28 1 38 (2 ) 65 Merger and integration expense 18 — 18 — 36 Asset retirement obligation accretion — 1 1 — 2 Other operating expenses — — 3 — 3 Total costs and expenses 46 851 311 (43 ) 1,165 Income (loss) from operations (46 ) 895 260 (98 ) 1,011 Other income (expense): Interest expense, net (43 ) (20 ) (24 ) — (87 ) Other income (expense), net 1 — 90 (2 ) 89 Loss on derivative instruments, net — 169 (68 ) — 101 Gain on revaluation of investment — — (1 ) — (1 ) Income from subsidiaries 1,113 — — (1,113 ) — Total other expense, net 1,071 149 (3 ) (1,115 ) 102 Income (loss) before income taxes 1,025 1,044 257 (1,213 ) 1,113 Provision for (benefit from) income taxes 241 — (73 ) — 168 Net income (loss) 784 1,044 330 (1,213 ) 945 Net income attributable to non-controlling interest — — 119 (20 ) 99 Net income (loss) attributable to Diamondback Energy, Inc. $ 784 $ 1,044 $ 211 $ (1,193 ) $ 846 Condensed Consolidated Statement of Operations Year Ended December 31, 2017 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 904 $ — $ 140 $ 1,044 Natural gas sales — 43 — 9 52 Natural gas liquid sales — 79 — 11 90 Royalty income — — 160 (160 ) — Lease bonus income — — 12 — 12 Midstream services — — 39 (32 ) 7 Total revenues — 1,026 211 (32 ) 1,205 Costs and expenses: Lease operating expenses — 143 — (16 ) 127 Production and ad valorem taxes — 63 11 — 74 Gathering and transportation — 21 — (8 ) 13 Midstream services — — 11 (1 ) 10 Depreciation, depletion and amortization — 277 46 4 327 General and administrative expenses 27 — 23 (2 ) 48 Asset retirement obligation accretion expense — 1 — — 1 Total costs and expenses 27 505 91 (23 ) 600 Income (loss) from operations (27 ) 521 120 (9 ) 605 Other income (expense): Interest expense, net (30 ) (6 ) (5 ) — (41 ) Other income (expense), net 1 — 12 (2 ) 11 Loss on derivative instruments, net — (77 ) (1 ) — (78 ) Income from subsidiaries 446 — — (446 ) — Total other expense, net 417 (83 ) 6 (448 ) (108 ) Income (loss) before income taxes 390 438 126 (457 ) 497 Provision for income taxes (20 ) — — — (20 ) Net income (loss) 410 438 126 (457 ) 517 Net income attributable to non-controlling interest — — — 35 35 Net income (loss) attributable to Diamondback Energy, Inc. $ 410 $ 438 $ 126 $ (492 ) $ 482
Condensed consolidated statement of cash flows	Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2019 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash (used in) provided by operating activities $ (956 ) $ 1,433 $ 2,257 $ — $ 2,734 Cash flows from investing activities: Additions to oil and natural gas properties — (2,038 ) (639 ) — (2,677 ) Additions to midstream assets — (38 ) (206 ) — (244 ) Purchase of other property, equipment and land — — (5 ) — (5 ) Acquisition of leasehold interests — (360 ) (83 ) — (443 ) Acquisition of mineral interests — — (523 ) 190 (333 ) Proceeds from sale of assets — 118 372 (190 ) 300 Investment in real estate — — (1 ) — (1 ) Equity investments — — (485 ) — (485 ) Intercompany transfers (860 ) — 860 — — Net cash used in investing activities (860 ) (2,318 ) (710 ) — (3,888 ) Cash flows from financing activities: Proceeds from borrowing under credit facility — 1,292 1,058 — 2,350 Repayment under credit facility — (2,769 ) (949 ) — (3,718 ) Proceeds from senior notes 2,968 — 501 — 3,469 Repayment of senior notes (1,250 ) — — — (1,250 ) Premium on extinguishment of debt (44 ) — — — (44 ) Proceeds from joint venture — — 39 — 39 Debt issuance costs — — (18 ) — (18 ) Public offering costs — — (41 ) — (41 ) Proceeds from public offerings — — 1,106 — 1,106 Distributions from subsidiary 860 — — (860 ) — Proceeds from exercise of stock options 9 — — — 9 Repurchased for tax withholdings (13 ) — — — (13 ) Repurchased as part of share buyback (593 ) — — — (593 ) Dividends to stockholders (112 ) — — — (112 ) Distributions to non-controlling interest — — (982 ) 860 (122 ) Intercompany transfers — 2,360 (2,360 ) — — Net cash (used in) provided by financing activities 1,825 883 (1,646 ) — 1,062 Net increase (decrease) in cash and cash equivalents 9 (2 ) (99 ) — (92 ) Cash and cash equivalents at beginning of period 84 2 129 — 215 Cash and cash equivalents at end of period $ 93 $ — $ 30 $ — $ 123 Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2018 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ (58 ) $ 1,224 $ 399 $ — $ 1,565 Cash flows from investing activities: Additions to oil and natural gas properties — (1,461 ) — — (1,461 ) Additions to midstream assets — (21 ) (183 ) — (204 ) Purchase of other property, equipment and land — (7 ) — — (7 ) Acquisition of leasehold interests — (1,371 ) — — (1,371 ) Acquisition of mineral interests — — (440 ) — (440 ) Proceeds from sale of assets — 79 1 — 80 Investment in real estate — — (111 ) — (111 ) Funds held in escrow — 27 (16 ) — 11 Intercompany transfers (367 ) 989 (622 ) — — Net cash used in investing activities (367 ) (1,765 ) (1,371 ) — (3,503 ) Cash flows from financing activities: Proceeds from borrowing under credit facility — 1,960 692 — 2,652 Repayment under credit facility — (867 ) (375 ) — (1,242 ) Repayment on Energen's credit facility — — (559 ) — (559 ) Proceeds from senior notes 1,062 — — — 1,062 Debt issuance costs (14 ) — (11 ) — (25 ) Public offering costs — — (3 ) — (3 ) Proceeds from public offerings — — 305 — 305 Contributions to subsidiaries (1 ) — (1 ) 2 — Distribution to parent 155 — — (155 ) — Distributions from subsidiary (696 ) — 696 — — Repurchased for tax withholdings (14 ) — — — (14 ) Dividends to stockholders (37 ) — — — (37 ) Distributions to non-controlling interest — — (253 ) 155 (98 ) Intercompany transfers — (550 ) 552 (2 ) — Net cash provided by financing activities 455 543 1,043 — 2,041 Net increase (decrease) in cash and cash equivalents 30 2 71 — 103 Cash and cash equivalents at beginning of period 54 — 58 — 112 Cash and cash equivalents at end of period $ 84 $ 2 $ 129 $ — $ 215 Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2017 (In millions) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (29 ) $ 768 $ 150 $ — $ 889 Cash flows from investing activities: Additions to oil and natural gas properties — (790 ) (3 ) — (793 ) Additions to midstream assets — — (68 ) — (68 ) Purchase of other property, equipment and land — (22 ) (1 ) — (23 ) Acquisition of leasehold interests — (1,961 ) — — (1,961 ) Acquisition of mineral interests — (63 ) (344 ) — (407 ) Acquisition of midstream assets — — (50 ) — (50 ) Proceeds from sale of assets — 66 — — 66 Funds held in escrow — (27 ) 131 — 104 Intercompany transfers (1,631 ) 1,631 — — — Net cash used in investing activities (1,631 ) (1,166 ) (335 ) — (3,132 ) Cash flows from financing activities: Proceeds from borrowing under credit facility — 475 279 — 754 Repayment under credit facility — (78 ) (306 ) — (384 ) Purchase of subsidiary units by parent (10 ) — — 10 — Debt issuance costs (8 ) 1 (2 ) — (9 ) Public offering costs — — (1 ) — (1 ) Proceeds from public offerings — — 380 (10 ) 370 Distribution from subsidiary 90 — (1 ) (89 ) — Distribution to non-controlling interest — — (130 ) 89 (41 ) Net cash provided by financing activities 72 398 219 — 689 Net increase (decrease) in cash and cash equivalents (1,588 ) — 34 — (1,554 ) Cash and cash equivalents at beginning of period 1,642 — 24 — 1,666 Cash and cash equivalents at end of period $ 54 $ — $ 58 $ — $ 112

SUPPLEMENTAL INFORMATION ON O_2

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 (In millions) Oil and natural gas properties: Proved properties $ 16,575 $ 12,629 Unproved properties 9,207 9,670 Total oil and natural gas properties 25,782 22,299 Accumulated depreciation, depletion, amortization (2,995 ) (1,599 ) Accumulated impairment (1,934 ) (1,144 ) Net oil and natural gas properties capitalized $ 20,853 $ 19,556
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, 2019 2018 2017 (In millions) Acquisition costs: Proved properties $ 194 $ 5,665 $ 455 Unproved properties 418 5,818 2,692 Development costs 956 493 145 Exploration costs 1,915 1,090 780 Total $ 3,483 $ 13,066 $ 4,072
Results of operations from oil and natural gas producing activities	Year Ended December 31, 2019 2018 2017 (In millions) Oil, natural gas and natural gas liquid sales $ 3,887 $ 2,130 $ 1,186 Lease operating expenses (490 ) (205 ) (127 ) Production and ad valorem taxes (248 ) (133 ) (74 ) Gathering and transportation (88 ) (26 ) (13 ) Depreciation, depletion, and amortization (1,447 ) (595 ) (321 ) Impairment (790 ) — — Asset retirement obligation accretion expense (7 ) (2 ) (1 ) Income tax benefit (expense) (89 ) (241 ) 20 Results of operations $ 728 $ 928 $ 670
Schedule of changes in estimated proved reserves	The changes in estimated proved reserves are as follows: Oil Natural Gas Natural Gas Proved Developed and Undeveloped Reserves: As of January 1, 2017 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 Extensions and discoveries 143,256 33,152 154,088 Revisions of previous estimates 3,689 11,138 3,642 Purchase of reserves in place 281,333 98,865 640,761 Divestitures (156 ) (8 ) (543 ) Production (34,367 ) (7,465 ) (34,668 ) As of December 31, 2018 626,936 190,291 1,048,649 Extensions and discoveries 256,569 66,572 318,874 Revisions of previous estimates (84,789 ) (8,166 ) (149,657 ) Purchase of reserves in place 13,974 3,813 19,830 Divestitures (33,269 ) (3,809 ) (21,272 ) Production (68,518 ) (18,498 ) (97,613 ) As of December 31, 2019 710,903 230,203 1,118,811 Proved Developed Reserves: January 1, 2017 79,457 22,080 105,399 December 31, 2017 141,246 35,412 190,740 December 31, 2018 403,051 125,509 705,084 December 31, 2019 457,083 165,173 824,760 Proved Undeveloped Reserves: January 1, 2017 59,717 15,054 69,497 December 31, 2017 91,935 19,198 94,629 December 31, 2018 223,885 64,782 343,565 December 31, 2019 253,820 65,030 294,051 2019 : (MBOE) Beginning proved undeveloped reserves at December 31, 2018 345,928 Undeveloped reserves transferred to developed (120,920 ) Revisions (77,519 ) Net purchases 4,542 Divestitures (5,672 ) Extensions and discoveries 221,500 Ending proved undeveloped reserves at December 31, 2019 367,859
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, 2019 , 2018 and 2017 . December 31, 2019 2018 2017 (In millions) Future cash inflows $ 40,681 $ 43,578 $ 12,922 Future development costs (3,809 ) (3,560 ) (1,124 ) Future production costs (9,319 ) (7,727 ) (2,995 ) Future production taxes (2,905 ) (2,935 ) (929 ) Future income tax expenses (2,635 ) (3,913 ) (84 ) Future net cash flows 22,013 25,443 7,790 10% discount to reflect timing of cash flows (11,829 ) (13,767 ) (4,033 ) Standardized measure of discounted future net cash flows $ 10,184 $ 11,676 $ 3,757
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, 2019 2018 2017 Unweighted Arithmetic Average First-Day-of-the-Month Prices Oil (per Bbl) $ 51.88 $ 59.63 $ 48.03 Natural gas (per Mcf) $ 0.18 $ 1.47 $ 2.06 Natural gas liquids (per Bbl) $ 15.65 $ 24.43 $ 20.79
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, 2019 2018 2017 (In millions) Standardized measure of discounted future net cash flows at the beginning of the period $ 11,676 $ 3,757 $ 1,711 Sales of oil and natural gas, net of production costs (3,334 ) (1,786 ) (986 ) Acquisition of reserves 309 5,520 439 Divestiture of reserves (500 ) (2 ) (11 ) Extensions and discoveries, net of future development costs 4,004 3,287 1,792 Previously estimated development costs incurred during the period 120 535 190 Net changes in prices and production costs 831 1,805 578 Changes in estimated future development costs (3,190 ) (81 ) (53 ) Revisions of previous quantity estimates (1,242 ) 271 (99 ) Accretion of discount 1,344 380 174 Net change in income taxes 693 (1,728 ) (9 ) Net changes in timing of production and other (527 ) (282 ) 31 Standardized measure of discounted future net cash flows at the end of the period $ 10,184 $ 11,676 $ 3,757

QUARTERLY FINANCIAL DATA (Una_2

QUARTERLY FINANCIAL DATA (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Schedule of quarterly financial data	The Company’s unaudited quarterly financial data for 2019 and 2018 is summarized below. 2019 (in millions) First Second Third Fourth Revenues $ 864 $ 1,021 $ 975 $ 1,104 Income (loss) from operations 319 411 349 (384 ) Income tax expense (benefit) (33 ) 102 102 (124 ) Net income (loss) 43 356 388 (472 ) Net income attributable to non-controlling interest 33 7 20 15 Net income (loss) attributable to Diamondback Energy, Inc. $ 10 $ 349 $ 368 $ (487 ) Earnings per common share Basic $ 0.06 $ 2.12 $ 2.27 $ (3.04 ) Diluted $ 0.06 $ 2.11 $ 2.26 $ (3.04 ) 2018 (in millions) First Second Third Fourth Revenues $ 479 $ 527 $ 537 $ 633 Income from operations 267 281 268 195 Income tax expense (benefit) 47 (7 ) 43 85 Net income 178 301 160 306 Net income attributable to non-controlling interest 15 82 3 (1 ) Net income attributable to Diamondback Energy, Inc. $ 163 $ 219 $ 157 $ 307 Earnings per common share Basic $ 1.65 $ 2.22 $ 1.59 $ 2.50 Diluted $ 1.65 $ 2.22 $ 1.59 $ 2.50

DESCRIPTION OF THE BUSINESS A_2

DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION (Details)	Dec. 31, 2019	May 28, 2019
Viper Energy Partners LP
Noncontrolling Interest [Line Items]
Ownership percentage	58.00%
Rattler MIdstream LP
Noncontrolling Interest [Line Items]
Ownership percentage	71.00%	29.00%

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Restricted cash	$ 5,000,000	$ 0
Allowance for doubtful accounts	2,000,000	2,000,000
Impairment of long-lived assets	0	0	$ 0
Interest capitalized	66,000,000	32,000,000	22,000,000
Equity method investment impairment	0	0	0
Unrecognized tax benefits	7,000,000	7,000,000	0
Margin tax expense	0	0	0
Interest or penalties associated with uncertain tax positions	0	0	$ 0
Revolving Credit Facility
Debt Instrument [Line Items]
Debt issuance costs	36,000,000	28,000,000
Debt issuance costs, accumulated amortization	15,000,000	9,000,000
Senior Notes
Debt Instrument [Line Items]
Debt issuance costs	24,000,000	32,000,000
Debt issuance costs, accumulated amortization	$ 14,000,000	$ 15,000,000

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Prepaid Expenses and Other (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Prepaid insurance	$ 6	$ 4
Prepaid fees and licenses	4	3
Income tax receivable	19	38
Other	14	5
Total prepaid expenses and other	$ 43	$ 50

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties, Other Property, Equipment and Land (Details)	12 Months Ended
	Dec. 31, 2019USD ($)$ / Boe	Dec. 31, 2018USD ($)$ / Boe	Dec. 31, 2017USD ($)$ / Boe
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization excluding amortization of financing costs	$ 1,447,000,000	$ 623,000,000	$ 327,000,000
Estimated future net revenue discounted rate per annum	10.00%
Impairment of oil and natural gas properties	$ 790,000,000	$ 0	$ 0
Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Average depletion rate per barrel equivalent unit of production | $ / Boe	13.54	12.62	11.11
Depreciation, depletion and amortization excluding amortization of financing costs	$ 1,400,000,000	$ 595,000,000	$ 321,000,000
Other Property and Equipment, Net
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization excluding amortization of financing costs	$ 16,000,000	$ 9,000,000	$ 1,000,000
Other Property and Equipment, Net | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life of property and equipment	3 years
Other Property and Equipment, Net | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life of property and equipment	15 years

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Accounting Policies [Abstract]
Liability for drilling costs prepaid by joint interest partners	$ 12	$ 16
Interest payable	27	26
Lease operating expenses payable	119	59
Ad valorem taxes payable	68	49
Other	78	103
Total other accrued liabilities	$ 304	$ 253

SUMMARY OF SIGNIFICANT ACCOUN_8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentrations (Details) - Customer Concentration Risk - Revenue Benchmark	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Shell Trading US Company
Concentration Risk [Line Items]
Concentration risk, percentage	27.00%	26.00%	31.00%
Plains Marketing LP
Concentration Risk [Line Items]
Concentration risk, percentage	23.00%
Vitol Midstream
Concentration Risk [Line Items]
Concentration risk, percentage	15.00%
Koch Supply & Trading LP
Concentration Risk [Line Items]
Concentration risk, percentage		15.00%	19.00%
Occidental Energy Marketing Inc.
Concentration Risk [Line Items]
Concentration risk, percentage		11.00%
Enterprise Crude Oil LLC
Concentration Risk [Line Items]
Concentration risk, percentage			11.00%

ACQUISITIONS AND DIVESTITURES -

ACQUISITIONS AND DIVESTITURES - 2019 Activity (Details) shares in Millions	Jul. 29, 2019USD ($)ashares	Jul. 01, 2019USD ($)a	May 23, 2019USD ($)a
Business Acquisition [Line Items]
Conventional and non-core Permian assets divested, area (in acre) | a		103,750	6,589
Proceeds from divestiture of certain conventional and non-core assets		$ 285,000,000	$ 37,000,000
Gain (loss) from divestiture of certain conventional and non-core assets		$ 0	$ 0
2019 Drop-Down Acquisition
Business Acquisition [Line Items]
Conventional and non-core Permian assets divested, area (in acre) | a	5,490
Proceeds from divestiture of certain conventional and non-core assets	$ 190,000,000
Percentage of mineral acres operated	95.00%
Percentage of average net royalty interest in acquired mineral and royalty interests	3.20%
Viper Energy Partners LP | 2019 Drop-Down Acquisition
Business Acquisition [Line Items]
Number of shares to be issued in acquisition (in Shares) | shares	18.3
Business combination, fair value of consideration	$ 497,000,000

ACQUISITIONS AND DIVESTITURES_2

ACQUISITIONS AND DIVESTITURES - 2018 Activity (Details) $ / shares in Units, shares in Millions, $ in Millions	Jul. 01, 2019USD ($)	May 23, 2019USD ($)	Nov. 29, 2018USD ($)afraction_per_sharelocation$ / sharesshares	Oct. 31, 2018USD ($)ashares	Aug. 15, 2018USD ($)a	Jan. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018USD ($)
Business Acquisition [Line Items]
Proceeds from divestiture of certain conventional and non-core assets	$ 285	$ 37
Estimated total net horizontal permian locations | location			7,200
Ajax Acquisition
Business Acquisition [Line Items]
Area of land (in acres) | a				25,493
Payment to acquire businesses				$ 900
Number of shares to be issued in acquisition (in Shares) | shares				2.6
2018 Drop-Down Transaction
Business Acquisition [Line Items]
Percentage of mineral acres operated					80.00%
Proceeds from divestiture of certain conventional and non-core assets					$ 175
ExL Acquisition
Business Acquisition [Line Items]
Area of land (in acres) | a				3,646
Payment to acquire businesses				$ 313
Energen
Business Acquisition [Line Items]
Common stock, per share conversion basis | fraction_per_share			0.6442
Number of shares to be issued in acquisition (in Shares) | shares			62.8
Business combination, consideration transferred			$ 7,100
Business acquisition, share price | $ / shares			$ 112
Business combination, pro forma information, revenue of acquiree since acquisition date, actual							$ 102
Business combination, pro forma information, direct operating expenses since acquisition date, actual							$ 17
Minimum
Business Acquisition [Line Items]
Combined tier one acres | a			273,000
Midland and Delaware Basins
Business Acquisition [Line Items]
Area of land (in acres) | a			394,000
Viper Energy Partners LP | 2018 Drop-Down Transaction
Business Acquisition [Line Items]
Mineral properties acquired, gross acres | a					32,424
Mineral properties acquired net royalty acres | a					1,696
Diamondback Energy, Inc.
Business Acquisition [Line Items]
Acquisition related costs incurred								$ 37
Energen
Business Acquisition [Line Items]
Acquisition related costs incurred								$ 59
Office Building | Midland, TX
Business Acquisition [Line Items]
Payments to acquire property, plant, and equipment						$ 110

ACQUISITIONS AND DIVESTITURES_3

ACQUISITIONS AND DIVESTITURES - 2017 Activity (Details) shares in Thousands, $ in Millions	Feb. 28, 2017USD ($)ashares	Dec. 31, 2017USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Business Acquisition [Line Items]
Acquisition of leasehold interests			$ 443	$ 1,371	$ 1,961
Additions to midstream assets			$ 244	$ 204	$ 68
Delaware Basin Interests
Business Acquisition [Line Items]
Payment to acquire businesses	$ 1,700
Number of shares to be issued in acquisition (in Shares) | shares	7,690
Shares held in escrow | shares	1,150
Oil and gas area, gross | a	100,306
Oil and gas area, net | a	80,339
Acquisition of leasehold interests	$ 2,500
Additions to midstream assets	48
Total fair value of net assets	$ 2,549
Business combination, pro forma information, revenue of acquiree since acquisition date, actual		$ 81
Business combination, pro forma information, direct operating expenses since acquisition date, actual		$ 24

ACQUISITIONS AND DIVESTITURES_4

ACQUISITIONS AND DIVESTITURES - Estimated Fair Values of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions	Nov. 29, 2018	Dec. 31, 2018	Feb. 28, 2017
Energen
Business Acquisition [Line Items]
Consideration	$ 7,136
Fair value of liabilities assumed:
Current liabilities	388
Asset retirement obligations	(105)
Long-term debt	1,099
Noncurrent derivative instruments	17
Deferred income taxes	1,425	$ 1,400
Other long-term liabilities	7
Amount attributable to liabilities assumed	3,041
Fair value of assets acquired:
Total current assets	298
Oil and natural gas properties	9,361
Midstream assets	253
Investment in real estate	11
Other property, equipment and land	58
Asset retirement obligation	105
Other postretirement assets	3
Noncurrent income tax receivable, net	76
Other long term assets	12
Amount attributable to assets acquired	$ 10,177
Delaware Basin Interests
Fair value of liabilities assumed:
Asset retirement obligations			$ (2)
Revenues and royalties payable			(10)
Fair value of assets acquired:
Proved oil and natural gas properties			386
Unevaluated oil and natural gas properties			2,123
Midstream assets			47
Prepaid capital costs			4
Oil inventory			1
Total fair value of net assets			$ 2,549

ACQUISITIONS AND DIVESTITURES_5

ACQUISITIONS AND DIVESTITURES - Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Energen
Business Acquisition [Line Items]
Revenues	$ 3,532	$ 2,196
Income (loss) from operations	1,559	900
Net income (loss)	$ 1,320	$ 875
Basic earnings per common share (in dollars per share)	$ 7.54	$ 5.26
Diluted earnings per common share (in dollars per share)	$ 7.53	$ 5.24
Delaware Basin Interests
Business Acquisition [Line Items]
Revenues		$ 1,228	$ 627
Income (loss) from operations		619	(13)
Net income (loss)		$ 473	$ (109)
Basic earnings per common share (in dollars per share)		$ 4.85	$ (1.45)
Diluted earnings per common share (in dollars per share)		$ 4.84	$ (1.45)

VIPER ENERGY PARTNERS LP - Narr

VIPER ENERGY PARTNERS LP - Narrative (Details) - USD ($)	May 10, 2018	May 09, 2018	Jul. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	May 28, 2019
Noncontrolling Interest [Line Items]
Decrease of noncontrolling interest decrease				$ 45,000,000
Limited partners capital contribution						$ 1,000,000
Viper Energy Partners LP | Diamondback Energy, Inc.
Noncontrolling Interest [Line Items]
Cash distributions paid				133,000,000
Viper Energy Partners LP
Noncontrolling Interest [Line Items]
Number of common stock exchanged (in shares)		73,150,000
Number of stock issued (in shares)		73,150,000
General partners cash contribution	$ 1,000,000
Limited partners capital contribution	$ 1,000,000
Limited partners capital account, percentage of distribution	8.00%
Limited partners' capital account, distribution amount	$ 10,000
Amount allocated by general partner				$ 3,000,000	$ 2,000,000
Viper Energy Partners LP | Class B Units
Noncontrolling Interest [Line Items]
Units of partnership interest (in shares)		73,150,000
Number of class B units converted	731,500
Viper Energy Partners LP | Common Stock
Noncontrolling Interest [Line Items]
Exchange of membership interests for common units	731,500
Viper LLC
Noncontrolling Interest [Line Items]
Members ownership percentage	64.00%
Viper LLC | Viper Energy Partners LP
Noncontrolling Interest [Line Items]
Ownership interest	36.00%		41.00%
Viper Energy Partners LP
Noncontrolling Interest [Line Items]
Ownership percentage				58.00%
State income tax expense				$ 0
Viper Energy Partners LP | Diamondback Energy, Inc.
Noncontrolling Interest [Line Items]
Members ownership percentage			59.00%

VIPER ENERGY PARTNERS LP - Sche

VIPER ENERGY PARTNERS LP - Schedule of Sale of Stock (Details) - USD ($) $ in Millions	1 Months Ended				12 Months Ended
	Mar. 31, 2019	Jul. 31, 2018	Jul. 31, 2017	Jan. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Noncontrolling Interest [Line Items]
Amount Repaid on Viper LLC’s Credit Facility					$ 3,718	$ 1,242	$ 384
Follow-on Public Offering
Noncontrolling Interest [Line Items]
Number of Units of Common Units Sold	10,925,000	10,080,000	16,100,000	9,775,000
Amount Repaid on Viper LLC’s Credit Facility	$ 314	$ 362	$ 153	$ 121
Follow-on Public Offering | Viper Energy Partners LP
Noncontrolling Interest [Line Items]
Proceeds Received by Viper	$ 341	$ 303	$ 232	$ 148
Over-Allotment Option
Noncontrolling Interest [Line Items]
Number of Units of Common Units Sold	1,425,000	1,080,000	2,100,000	1,275,000
Over-Allotment Option | Viper Energy Partners LP | Affiliated Entity
Noncontrolling Interest [Line Items]
Number of Units of Common Units Sold			3,000,000
Over-Allotment Option | Viper Energy Partners LP | Executive Officer
Noncontrolling Interest [Line Items]
Number of Units of Common Units Sold			114,000
Over-Allotment Option | Diamondback Energy, Inc.
Noncontrolling Interest [Line Items]
Number of Units of Common Units Sold			700,000

RATTLER MIDSTREAM LP (Details)

RATTLER MIDSTREAM LP (Details) - USD ($)	May 28, 2019	Mar. 31, 2019	Jul. 31, 2018	Jul. 31, 2017	Jan. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Noncontrolling Interest [Line Items]
Limited partners capital contribution	$ 1,000,000
Accrued state income tax expense						$ 0	$ 0	$ 0
Over-Allotment Option
Noncontrolling Interest [Line Items]
Offer and issuance of stock (in Shares)		1,425,000	1,080,000	2,100,000	1,275,000
Rattler LLC
Noncontrolling Interest [Line Items]
Distribution to affiliates	727,000,000
Rattler MIdstream LP
Noncontrolling Interest [Line Items]
General partners cash contribution	$ 1,000,000
Percentage of preferred cash distribution received	8.00%
Rattler MIdstream LP | Rattler Partnership Agreement
Noncontrolling Interest [Line Items]
Amount allocated by general partner						364,342
Rattler MIdstream LP | Rattler's Services and Secondment Agreement
Noncontrolling Interest [Line Items]
Amount allocated by general partner						5,000,000
Rattler MIdstream LP | Rattler Tax Sharing Agreement
Noncontrolling Interest [Line Items]
Accrued state income tax expense						$ 188,808
Rattler MIdstream LP | Class B Units
Noncontrolling Interest [Line Items]
Limited partners' capital account, units issued (in Shares)	107,815,152
Rattler MIdstream LP | IPO
Noncontrolling Interest [Line Items]
Offer and issuance of stock (in Shares)	43,700,000
Shares issued (in dollars per share)	$ 17.50
Consideration received from offering	$ 720,000,000
Rattler MIdstream LP | Over-Allotment Option
Noncontrolling Interest [Line Items]
Offer and issuance of stock (in Shares)	5,700,000
Rattler MIdstream LP
Noncontrolling Interest [Line Items]
Ownership percentage	29.00%					71.00%
Limited partners ownership percentage	71.00%

REAL ESTATE ASSETS (Details)

REAL ESTATE ASSETS (Details) - USD ($) $ in Millions	Jan. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Real Estate [Line Items]
Buildings		$ 102	$ 103
Tenant improvements		5	4
Land		2	1
Land improvements		1	1
Total real estate assets		110	109
Less: accumulated depreciation		(9)	(4)
Total investment in land and buildings, net		101	105
Finite-lived intangible assets, net		$ 8	11
In-place lease intangibles
Real Estate [Line Items]
Lease intangible assets, useful life		45 months
Finite-lived intangible assets, gross		$ 11	11
Less: accumulated amortization		(6)	(3)
Finite-lived intangible assets, net		$ 5	8
Above-market lease intangibles
Real Estate [Line Items]
Lease intangible assets, useful life		45 months
Finite-lived intangible assets, gross		$ 4	4
Less: accumulated amortization		(1)	(1)
Finite-lived intangible assets, net		3	$ 3
Office Buildings
Real Estate [Line Items]
Buildings		$ 10
Tenant improvements
Real Estate [Line Items]
Real estate assets, estimated useful lives		15 years
Land improvements
Real Estate [Line Items]
Real estate assets, estimated useful lives		15 years
Midland, TX | Office Buildings
Real Estate [Line Items]
Purchase price to acquire property, plant and equipment	$ 110
Maximum | Buildings
Real Estate [Line Items]
Real estate assets, estimated useful lives		30 years
Minimum | Buildings
Real Estate [Line Items]
Real estate assets, estimated useful lives		20 years

PROPERTY AND EQUIPMENT (Details

PROPERTY AND EQUIPMENT (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and natural gas properties:
Subject to depletion	$ 16,575,000,000	$ 12,629,000,000
Not subject to depletion	9,207,000,000	9,670,000,000
Gross oil and natural gas properties	25,782,000,000	22,299,000,000
Accumulated depletion and depreciation	(5,003,000,000)	(2,774,000,000)
Accumulated impairment	(1,934,000,000)	(1,144,000,000)
Oil and natural gas properties, net	20,853,000,000	19,556,000,000
Midstream assets	931,000,000	700,000,000
Other property, equipment and land	125,000,000	147,000,000
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	21,835,000,000	20,372,000,000
Capitalized internal costs	$ 49,000,000	29,000,000	$ 22,000,000
Estimated future net revenue discounted rate per annum	10.00%
Impairment of oil and natural gas properties	$ 790,000,000	0	0
Exploration costs or development costs not subject to depletion	228,000,000	68,000,000
Capitalized interest not subject to depletion	$ 118,000,000	55,000,000
Minimum
Oil and natural gas properties:
Timing of inclusion of costs in amortization calculation	3 years
Maximum
Oil and natural gas properties:
Timing of inclusion of costs in amortization calculation	5 years
Oil and Gas Properties
Oil and natural gas properties:
Subject to depletion	$ 16,575,000,000	12,629,000,000
Not subject to depletion	9,207,000,000	9,670,000,000
Gross oil and natural gas properties	25,782,000,000	22,299,000,000
Accumulated depletion and depreciation	(2,995,000,000)	(1,599,000,000)
Accumulated impairment	(1,934,000,000)	(1,144,000,000)
Oil and natural gas properties, net	20,853,000,000	19,556,000,000
Balance of costs not subject to depletion	604,000,000	5,654,000,000	$ 2,329,000,000	$ 620,000,000
Other Property and Equipment, Net
Oil and natural gas properties:
Accumulated depletion and depreciation	(74,000,000)	(31,000,000)
Other property, equipment and land	$ 125,000,000	$ 147,000,000

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Changes in ARO liability
Asset retirement obligations, beginning of period	$ 136	$ 21	$ 17
Additional liabilities incurred	8	3	2
Liabilities acquired	4	111	2
Liabilities settled	(61)	(2)	(1)
Accretion expense	7	2	1
Revisions in estimated liabilities	0	1	0
Asset retirement obligations, end of period	94	136	21
Less current portion	0	0	1
Asset retirement obligations - long-term	$ 94	$ 136	$ 20

EQUITY METHOD INVESTMENTS - Inv

EQUITY METHOD INVESTMENTS - Investments (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 20, 2019	Oct. 01, 2019	Jul. 30, 2019	Feb. 15, 2019	Feb. 01, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 479						$ 1
Rattler LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	479						1
Rattler LLC | Epic Pipeline
Schedule of Equity Method Investments [Line Items]
Ownership interest						10.00%
Equity method investments	110						0
Rattler LLC | Gray Oak Pipeline
Schedule of Equity Method Investments [Line Items]
Ownership interest					10.00%
Equity method investments	115						1
Rattler LLC | Wink To Webster Pipeline
Schedule of Equity Method Investments [Line Items]
Ownership interest				4.00%
Equity method investments	34						0
Rattler LLC | OMOG JV LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest			60.00%
Equity method investments	219						0
Rattler LLC | Amarillo Rattler, LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.00%
Equity method investments	$ 1						$ 0

EQUITY METHOD INVESTMENTS - Inc

EQUITY METHOD INVESTMENTS - Income (Loss) of Equity Method Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity method investments	$ (6)	$ 0	$ 1
Epic Pipeline
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity method investments	(6)	0	0
Gray Oak Pipeline
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity method investments	1	0	0
Wink To Webster Pipeline
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity method investments	(1)	0	0
OMOG JV LLC
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity method investments	0	0	0
HMW LLC
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity method investments	$ 0	$ 0	$ 1

EQUITY METHOD INVESTMENTS - Nar

EQUITY METHOD INVESTMENTS - Narrative (Details)

Jun. 30, 2018PWD_well

Dec. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Dec. 20, 2019Mcf / dmi

Nov. 07, 2019

Oct. 01, 2019

Jul. 30, 2019

Mar. 29, 2019USD ($)

Feb. 15, 2019

Feb. 01, 2019

Oct. 31, 2014

Schedule of Equity Method Investments

Equity method investment impairment

$ 0

$ 0

$ 0

Investment capitalized interest

1,000,000

HMW Fluid Management LLC

Schedule of Equity Method Investments

Ownership interest

25.00%

Rattler LLC | Epic Pipeline

Schedule of Equity Method Investments

Ownership interest

10.00%

Rattler LLC | Gray Oak Pipeline

Schedule of Equity Method Investments

Ownership interest

10.00%

Rattler LLC | OMOG JV LLC

Schedule of Equity Method Investments

Ownership interest

60.00%

Rattler LLC | Amarillo Rattler, LLC

Schedule of Equity Method Investments

Ownership interest

50.00%

OMOG JV LLC | Reliance Gathering LLC

Schedule of Equity Method Investments

Percentage acquired

100.00%

2.52% Short-Term Promissory Note | Rattler LLC | Gray Oak Pipeline

Schedule of Equity Method Investments

Equity method investment promissory note

$ 123,000,000

Stated interest rate

2.52%

Repayments of short-term debt

$ 23,000,000

Joint Venture Of Wink To Webster Project | Rattler LLC

Schedule of Equity Method Investments

Noncontrolling interest, ownership percentage

4.00%

PWD Wells | Rattler MIdstream LP | HMW Fluid Management LLC

Schedule of Equity Method Investments

Ownership percentage of oil and gas property

50.00%

Oil and gas properties, number of units | PWD_well

2

PWD Wells | HMW Fluid Management LLC

Schedule of Equity Method Investments

Oil and gas properties, number of units | PWD_well

4

Dawson, Martin and Andrews Counties, Texas | Amarillo Rattler, LLC

Schedule of Equity Method Investments

Gas gathering and cryogenic processing system capacity (in Mcf/d) | Mcf / d

40,000

Distance of gathering and regional transportation pipelines (over) (in miles) | mi

84

Martin County, Texas | Amarillo Rattler, LLC

Schedule of Equity Method Investments

Gas gathering and cryogenic processing system capacity (in Mcf/d) | Mcf / d

60,000

DEBT - Schedule of Long-term De

DEBT - Schedule of Long-term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 05, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Unamortized debt issuance costs	$ (19)		$ (27)
Unamortized discount costs	(31)		0
Unamortized premium costs	9		10
Total long-term debt	5,371		4,464
4.625% Notes due 2021
Debt Instrument [Line Items]
Long-term debt, gross	$ 399		400
Stated interest rate	4.625%
7.320% Medium-term Notes, Series A, due 2022
Debt Instrument [Line Items]
Long-term debt, gross	$ 21		20
Stated interest rate	7.32%
2.875% Senior Notes due 2024
Debt Instrument [Line Items]
Long-term debt, gross	$ 1,000		0
Stated interest rate	2.875%	2.875%
4.750% Senior Notes due 2024
Debt Instrument [Line Items]
Long-term debt, gross	$ 0		1,250
Stated interest rate	4.75%
5.375% Senior Notes due 2025
Debt Instrument [Line Items]
Long-term debt, gross	$ 800		800
Stated interest rate	5.375%
3.250% Senior Notes due 2026
Debt Instrument [Line Items]
Long-term debt, gross	$ 800		0
Stated interest rate	3.25%	3.25%
7.350% Medium-term Notes, Series A, due 2027
Debt Instrument [Line Items]
Long-term debt, gross	$ 11		10
Stated interest rate	7.35%
7.125% Medium-term Notes, Series B, due 2028
Debt Instrument [Line Items]
Long-term debt, gross	$ 108		100
Stated interest rate	7.125%
3.500% Senior Notes due 2029
Debt Instrument [Line Items]
Long-term debt, gross	$ 1,200		0
Stated interest rate	3.50%	3.50%
DrillCo Agreement
Debt Instrument [Line Items]
Long-term debt, gross	$ 39		0
Revolving credit facility
Debt Instrument [Line Items]
Long-term debt, gross	13		1,490
Viper revolving credit facility
Debt Instrument [Line Items]
Long-term debt, gross	97		411
Viper 5.375% Senior Notes due 2027
Debt Instrument [Line Items]
Long-term debt, gross	$ 500		0
Stated interest rate	5.375%
Rattler revolving credit facility
Debt Instrument [Line Items]
Long-term debt, gross	$ 424		$ 0

DEBT - Diamondback Notes (Detai

DEBT - Diamondback Notes (Details) - USD ($) $ in Millions	Dec. 05, 2019	Sep. 25, 2018	Jan. 29, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 20, 2016	Oct. 28, 2016
Debt Instrument [Line Items]
Proceeds from senior notes				$ 3,469	$ 1,062	$ 0
Existing 2024 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount								$ 500
Stated interest rate								4.75%
Debt, redemption price, percentage	103.563%
Redemption premium	$ 1,250
New 2024 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount		$ 750
Stated interest rate		4.75%
Proceeds from senior notes		$ 741
2.875% Senior Notes due 2024
Debt Instrument [Line Items]
Aggregate principal amount	$ 1,000
Stated interest rate	2.875%			2.875%
4.750% Senior Notes due 2024
Debt Instrument [Line Items]
Stated interest rate				4.75%
Existing 2025 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount							$ 500
Stated interest rate							5.375%
New 2025 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount			$ 300
Stated interest rate			5.375%
Proceeds from senior notes			$ 308
5.375% Senior Notes due 2025
Debt Instrument [Line Items]
Stated interest rate				5.375%
Debt, redemption price, percentage				100.00%
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period One
Debt Instrument [Line Items]
Debt, redemption price, percentage				104.031%
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period Two
Debt Instrument [Line Items]
Debt, redemption price, percentage				102.688%
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period Three
Debt Instrument [Line Items]
Debt, redemption price, percentage				101.344%
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period Four
Debt Instrument [Line Items]
Debt, redemption price, percentage				100.00%
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period Five
Debt Instrument [Line Items]
Debt, redemption price, percentage				105.375%
5.375% Senior Notes due 2025 | Debt Instrument, Redemption, Period Five | Maximum
Debt Instrument [Line Items]
Debt instrument percentage eligible for redemption				35.00%
3.250% Senior Notes due 2026
Debt Instrument [Line Items]
Aggregate principal amount	$ 800
Stated interest rate	3.25%			3.25%
3.500% Senior Notes due 2029
Debt Instrument [Line Items]
Aggregate principal amount	$ 1,200
Stated interest rate	3.50%			3.50%
Senior Notes | December 2019 Notes
Debt Instrument [Line Items]
Debt, redemption price, percentage				100.00%
Debt, redemption price, percentage upon change of control triggering event				101.00%

DEBT - Second Amended and Resta

DEBT - Second Amended and Restated Credit Facility (Details) - Revolving credit facility - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000,000,000
Outstanding borrowings	13,000,000	$ 1,490,000,000
Remaining borrowing capacity	$ 1,990,000,000
Maximum
Line of Credit Facility [Line Items]
Debt covenant, total net debt to capitalization ratio	65.00%
Debt covenant, debt principal amount as percentage of net tangible assets	15.00%
Federal Funds Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Investment Grade Annually | Minimum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.125%
Investment Grade Annually | Maximum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.35%
Investment Grade Annually | Base Rate | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.125%
Investment Grade Annually | Base Rate | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Investment Grade Annually | LIBOR | Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.125%
Investment Grade Annually | LIBOR | Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.00%

DEBT - Energen Notes (Details)

DEBT - Energen Notes (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Nov. 29, 2018
Energen Notes
Debt Instrument [Line Items]
Long-term debt, gross			$ 530
4.625% Notes due 2021
Debt Instrument [Line Items]
Long-term debt, gross	$ 399	$ 400
Stated interest rate	4.625%
7.125% Medium-term Notes, Series B, due 2028
Debt Instrument [Line Items]
Long-term debt, gross	$ 108	100
Stated interest rate	7.125%
7.320% Medium-term Notes, Series A, due 2022
Debt Instrument [Line Items]
Long-term debt, gross	$ 21	20
Stated interest rate	7.32%
7.350% Medium-term Notes, Series A, due 2027
Debt Instrument [Line Items]
Long-term debt, gross	$ 11	$ 10
Stated interest rate	7.35%

DEBT - Vipers Facility - Wells

DEBT - Vipers Facility - Wells Fargo Bank (Details) - Viper revolving credit facility	Jul. 20, 2018USD ($)redetermindation	Dec. 31, 2019USD ($)	Nov. 30, 2019USD ($)	Dec. 31, 2018USD ($)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000,000,000
Current borrowing base			$ 775,000,000
Number of additional redeterminations that may be requested | redetermindation	3
Period of redeterminations	12 months
Outstanding borrowings		$ 97,000,000		$ 411,000,000
Remaining borrowing capacity		678,000,000
Issuance of unsecured debt		$ 1,000,000,000
Financial covenant, reduction of borrowing base (percentage)		25.00%
Federal Funds Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate		0.50%
LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.00%
Minimum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base		0.375%
Minimum | Base Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate		0.75%
Minimum | LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.75%
Maximum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base		0.50%
Maximum | Base Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.75%
Maximum | LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate		2.75%

DEBT - Financial Covenant Table

DEBT - Financial Covenant Table (Details)	12 Months Ended
	Dec. 31, 2019
Maximum | Rattler revolving credit facility
Line of Credit Facility [Line Items]
Line of credit, covenant terms, consolidated total leverage ratio	5
Line of credit, covenant terms, consolidated total leverage ratio, for three fiscal quarters following certain acquisitions	5.50
Line of credit, covenant terms, consolidated total leverage ratio when consolidated senior secured leverage ration is applicable	5.25
Line of credit facility, covenant terms, ratio of consolidated senior secured leverage ratio	3.5
Maximum | Viper revolving credit facility
Line of Credit Facility [Line Items]
Ratio of total net debt to EBITDAX, as defined in the credit agreement	4
Minimum | Rattler revolving credit facility
Line of Credit Facility [Line Items]
Line of credit facility, covenant terms ratio of consolidated interest coverage	2.5
Minimum | Viper revolving credit facility
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement	1

DEBT - Viper's Notes (Details)

DEBT - Viper's Notes (Details) - USD ($) $ in Millions	Oct. 16, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Proceeds from senior notes		$ 3,469	$ 1,062	$ 0
Viper 5.375% Senior Notes due 2027
Line of Credit Facility [Line Items]
Stated interest rate		5.375%
Senior Notes | Viper 5.375% Senior Notes due 2027 | Viper Energy Partners LP
Line of Credit Facility [Line Items]
Stated interest rate	5.375%
Aggregate principal amount	$ 500
Gross proceeds from senior notes	500
Proceeds from senior notes	$ 490

DEBT - Rattler's Credit Agreeme

DEBT - Rattler's Credit Agreement (Details) - Rattler revolving credit facility - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 600
Long-term debt, gross	424	$ 0
Remaining borrowing capacity	$ 176
Minimum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.25%
Minimum | Prime Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.25%
Minimum | LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.25%
Maximum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.375%
Maximum | Prime Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.25%
Maximum | LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.25%

DEBT - Alliance with Obsidian R

DEBT - Alliance with Obsidian Resources, L.L.C. (Details) - DrillCo Agreement $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)	Sep. 10, 2018USD ($)
Debt Instrument [Line Items]
Maximum funding amount through joint venture		$ 300
Percentage of funded costs associated with wells drilled		85.00%
Percentage of working interest on wells expected to receive		80.00%
Cumulative percentage of certain payout thresholds		9.00%
Internal rate of return		13.00%
Interest rate upon reaching final internal rate of return		85.00%
Amounts received from joint venture	$ 36
Wells drilled and completed under joint venture agreement	11
CEMOF
Debt Instrument [Line Items]
Interest rate upon reaching final internal rate of return		15.00%

DEBT - Interest Expense (Detail

DEBT - Interest Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Interest expense	$ 235	$ 110	$ 61
Less capitalized interest	(66)	(32)	(22)
Other fees and expenses	4	10	2
Total interest expense	$ 173	$ 88	$ 41

CAPITAL STOCK AND EARNINGS PE_3

CAPITAL STOCK AND EARNINGS PER SHARE - Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Basic:
Net income attributable to common stock	$ (487)	$ 368	$ 349	$ 10	$ 307	$ 157	$ 219	$ 163	$ 240	$ 846	$ 482
Basic weighted average common units outstanding (in shares)									163,493	104,622	97,458
Effect of dilutive securities:
Potential common shares issuable (in shares)									350	307	230
Diluted:
Diluted weighted average common shares outstanding (in shares)									163,843	104,929	97,688
Basic net income attributable to common stock (in dollars per share)	$ (3.04)	$ 2.27	$ 2.12	$ 0.06	$ 2.50	$ 1.59	$ 2.22	$ 1.65	$ 1.47	$ 8.09	$ 4.95
Diluted net income attributable to common stock (in dollars per share)	$ (3.04)	$ 2.26	$ 2.11	$ 0.06	$ 2.50	$ 1.59	$ 2.22	$ 1.65	$ 1.47	$ 8.06	$ 4.94
Antidilutive securities, restricted stock units (in shares)									284	14	46

EQUITY-BASED COMPENSATION - Sch

EQUITY-BASED COMPENSATION - Schedule of Stock-Based Compensation Plans and Related Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$ 17	$ 10	$ 9
General and administrative expenses
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
General and administrative expenses	$ 48	$ 27	$ 25
Equity Plan
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
Common stock reserved for future issuance (in shares)	1,313,588

EQUITY-BASED COMPENSATION - Res

EQUITY-BASED COMPENSATION - Restricted Stock Units (Details) - Equity Plan - Restricted Stock Units (RSUs)	12 Months Ended
	Dec. 31, 2019$ / sharesshares
Restricted Stock Awards & Units
Unvested, beginning balance (in shares) | shares	324,224
Granted (in shares) | shares	697,679
Vested (in shares) | shares	(425,608)
Forfeited (in shares) | shares	(90,428)
Unvested, ending balance (in shares) | shares	505,867
Weighted Average Grant-Date Fair Value
Unvested, beginning balance (in dollars per share) | $ / shares	$ 116.01
Granted (in dollars per share) | $ / shares	99.36
Vested (in dollars per share) | $ / shares	105.09
Forfeited (in dollars per share) | $ / shares	106.55
Unvested, ending balance (in dollars per share) | $ / shares	$ 96.01

EQUITY-BASED COMPENSATION - R_2

EQUITY-BASED COMPENSATION - Restricted Stock Units (Narratives) (Details) - Restricted Stock Units (RSUs) - Equity Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregated fair value of restricted stock	$ 45	$ 19	$ 15
Share based award not recognized	$ 38
Unrecognized compensation cost, expected period of recognition	2 years 2 months 12 days

EQUITY-BASED COMPENSATION - Per

EQUITY-BASED COMPENSATION - Performance-Based Restricted Stock Units (Narratives) (Details) - Equity Plan $ in Millions	1 Months Ended			12 Months Ended
	Mar. 31, 2019installmentshares	Feb. 28, 2018shares	Feb. 27, 2017shares	Dec. 31, 2019USD ($)shares
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		117,423		356,227
Number of vesting installments | installment	5
Share based award not recognized | $				$ 24
Unrecognized compensation cost, expected period of recognition				2 years 7 months 6 days
Performance Shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation arrangement by share-based payment award number of shares authorized percent of shares granted		0.00%	0.00%
Performance Shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation arrangement by share-based payment award number of shares authorized percent of shares granted		200.00%	200.00%
Performance Shares | Share-based Payment Arrangement, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares, performance period				3 years
Granted (in shares)	199,723
Performance Shares | Share-based Payment Arrangement, Tranche One | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation arrangement by share-based payment award number of shares authorized percent of shares granted	0.00%
Performance Shares | Share-based Payment Arrangement, Tranche One | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation arrangement by share-based payment award number of shares authorized percent of shares granted	200.00%
Performance Shares | Share-based Payment Arrangement, Tranche Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	32,958
Performance Shares | Share-based Payment Arrangement, Tranche Two | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation arrangement by share-based payment award number of shares authorized percent of shares granted	0.00%
Performance Shares | Share-based Payment Arrangement, Tranche Two | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based compensation arrangement by share-based payment award number of shares authorized percent of shares granted	200.00%
Performance Based RSU, Performance Period Of Jan 1, 2017 To Dec 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)			74,880
Performance Based RSU, Performance Period Of Jan 1, 2017 To Dec 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)			37,440

EQUITY-BASED COMPENSATION - P_2

EQUITY-BASED COMPENSATION - Performance-Based Restricted Stock Activity (Details) - Performance Shares - Equity Plan - $ / shares	1 Months Ended		12 Months Ended
	Mar. 31, 2019	Feb. 28, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair Value Assumptions
Grant-date fair value (in dollars per share)			$ 131.30
Performance Restricted Stock Units
Unvested, beginning balance (in shares)			196,203
Granted (in shares)		117,423	356,227
Vested (in shares)			(176,976)
Forfeited (in shares)			(103,635)
Unvested, ending balance (in shares)			271,819	196,203
Weighted Average Grant-Date Fair Value
Unvested, beginning balance (in dollars per share)			$ 169.76
Granted (in dollars per share)			131.30
Vested (in dollars per share)			93.32
Forfeited (in dollars per share)			155.23
Unvested, ending balance (in dollars per share)			$ 147.07	$ 169.76
Maximum units could be awarded (in shares)			543,638
Two-Year
Fair Value Assumptions
Grant-date fair value (in dollars per share)					$ 162.13
Risk-free rate					1.27%
Company volatility					39.32%
Performance Restricted Stock Units
Granted (in shares)	199,723
Weighted Average Grant-Date Fair Value
Granted (in dollars per share)					$ 162.13
Three-Year
Fair Value Assumptions
Grant-date fair value (in dollars per share)			$ 137.22	$ 170.45	$ 168.73
Risk-free rate			2.55%	1.99%	1.59%
Company volatility			35.00%	35.90%	41.14%
Performance Restricted Stock Units
Granted (in shares)	32,958
Weighted Average Grant-Date Fair Value
Granted (in dollars per share)			$ 137.22	$ 170.45	$ 168.73
Five-Year
Fair Value Assumptions
Grant-date fair value (in dollars per share)			132.48
Weighted Average Grant-Date Fair Value
Granted (in dollars per share)			$ 132.48

EQUITY-BASED COMPENSATION - Sto

EQUITY-BASED COMPENSATION - Stock Appreciation Rights (Details)	12 Months Ended
	Dec. 31, 2019$ / sharesshares
Restricted Stock Awards & Units
Outstanding at December 31, 2018 (in shares) | shares	332,387
Exercised (in shares) | shares	(116,044)
Outstanding at December 31, 2019 (in shares) | shares	216,343
Weighted Average Exercise Price
Outstanding at December 31, 2018 (in dollars per share) | $ / shares	$ 95.04
Exercised (in dollars per share) | $ / shares	82.29
Outstanding at December 31, 2019 (in dollars per share) | $ / shares	$ 89.90
Stock Appreciation Rights (SARs) | Equity Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award requisite service period	3 years
Restricted Stock Awards & Units
Outstanding at December 31, 2018 (in shares) | shares	57,721
Exercised (in shares) | shares	(11,399)
Expired (in shares) | shares	(3,775)
Outstanding at December 31, 2019 (in shares) | shares	42,547
Weighted Average Exercise Price
Outstanding at December 31, 2018 (in dollars per share) | $ / shares	$ 22.12
Exercised (in dollars per share) | $ / shares	70.69
Expired (in dollars per share) | $ / shares	96.91
Outstanding at December 31, 2019 (in dollars per share) | $ / shares	$ 90.89

EQUITY-BASED COMPENSATION - S_2

EQUITY-BASED COMPENSATION - Stock Options (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)$ / sharesshares
Options
Outstanding at December 31, 2018 (in shares) | shares	332,387
Exercised (in shares) | shares	(116,044)
Outstanding at December 31, 2019 (in shares) | shares	216,343
Options, Vested and Expected to vest at December 31, 2019 (in shares) | shares	216,343
Options, Exercisable at December 31, 2019 (in shares) | shares	216,343
Weighted Average Exercise Price
Outstanding at December 31, 2018 (in dollars per share) | $ / shares	$ 95.04
Exercised (in dollars per share) | $ / shares	82.29
Outstanding at December 31, 2019 (in dollars per share) | $ / shares	89.90
Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price (in dollars per share) | $ / shares	89.90
Options, Exercisable, Outstanding, Weighted Average Exercise Price (in dollars per share) | $ / shares	$ 89.90
Weighted Average Remaining Term	1 year 8 months 1 day
Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term	1 year 8 months 1 day
Options, Exercisable, Outstanding, Weighted Average Remaining Contractual Term	1 year 8 months 1 day
Options, Outstanding, Intrinsic Value | $	$ 0
Options, Vested and Expected to Vest, Outstanding, Intrinsic Value | $	0
Options, Exercisable, Outstanding, Intrinsic Value | $	$ 0

EQUITY-BASED COMPENSATION - Vip

EQUITY-BASED COMPENSATION - Viper Long-Term Incentive Plan (Details) - Viper Energy Partners LP Long Term Incentive Plan - Phantom Share Units (PSUs)	12 Months Ended
	Dec. 31, 2019$ / sharesshares
Restricted Stock Awards & Units
Unvested, beginning balance (in shares) | shares	125,053
Granted (in shares) | shares	56,582
Vested (in shares) | shares	(85,359)
Forfeited (in shares) | shares	(1,028)
Unvested, ending balance (in shares) | shares	95,248
Weighted Average Grant-Date Fair Value
Unvested, beginning balance (in dollars per share) | $ / shares	$ 23.44
Granted (in dollars per share) | $ / shares	30.33
Vested (in dollars per share) | $ / shares	23.96
Forfeited (in dollars per share) | $ / shares	42.50
Unvested, ending balance (in dollars per share) | $ / shares	$ 26.87

EQUITY-BASED COMPENSATION - V_2

EQUITY-BASED COMPENSATION - Viper Long-Term Incentive Plan (Narratives) (Details) - Viper Energy Partners LP Long Term Incentive Plan $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock reserved for future issuance (in shares) | shares	8,892,918
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregated fair value of restricted stock	$ 2
Share based award not recognized	$ 1
Unrecognized compensation cost, expected period of recognition	1 year

EQUITY-BASED COMPENSATION - Rat

EQUITY-BASED COMPENSATION - Rattler Long-Term Incentive Plan (Details) - Phantom Share Units (PSUs) - Rattler Midstream LP Long-Term Incentive Plan	7 Months Ended
	Dec. 31, 2019$ / sharesshares
Restricted Stock Awards & Units
Unvested, beginning balance (in shares) | shares	0
Granted (in shares) | shares	2,284,038
Forfeited (in shares) | shares	(57,143)
Unvested, ending balance (in shares) | shares	2,226,895
Weighted Average Grant-Date Fair Value
Unvested, beginning balance (in dollars per share) | $ / shares	$ 0
Granted (in dollars per share) | $ / shares	19.14
Forfeited (in dollars per share) | $ / shares	19.21
Unvested, ending balance (in dollars per share) | $ / shares	$ 19.14

EQUITY-BASED COMPENSATION - R_3

EQUITY-BASED COMPENSATION - Rattler Long-Term Incentive Plan (Narratives) (Details) - Phantom Share Units (PSUs) - Rattler Midstream LP Long-Term Incentive Plan $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share based award not recognized	$ 37
Unrecognized compensation cost, expected period of recognition	2 years 4 months 24 days

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) - Subsidiaries	Jun. 23, 2014USD ($)	Dec. 31, 2019USD ($)lease	Dec. 31, 2018USD ($)lease	Dec. 31, 2017USD ($)lease
Wexford | Advisory Services Agreement
Related Party Transaction [Line Items]
Related party transaction annual fee for advisory services with related party	$ 500,000
Related party transaction amounts		$ 0	$ 0
Viper Energy Partners LP
Related Party Transaction [Line Items]
Related party transaction amounts		$ 277,977	$ 3,000,000	$ 105,690
Number of leases extended | lease		6	13	2
Revenue from related parties on new leases		$ 182,646	$ 1,000,000
Number of new leases | lease		4	1

INCOME TAXES - Components of In

INCOME TAXES - Components of Income Tax Provision (Benefit) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current income tax provision (benefit):
Federal									$ 0	$ 0	$ 0
State									0	0	0
Total current income tax provision (benefit)									0	0	0
Deferred income tax provision (benefit):
Federal									40	160	(21)
State									7	8	1
Total deferred income tax provision (benefit)									47	168	(20)
Provision for (benefit from) income taxes	$ (124)	$ 102	$ 102	$ (33)	$ 85	$ 43	$ (7)	$ 47	$ 47	$ 168	$ (20)

INCOME TAXES - Reconciliation o

INCOME TAXES - Reconciliation of Statutory Federal Income Tax (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended			24 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income tax expense at the federal statutory rate									$ 76	$ 234	$ 174
Impact of nontaxable noncontrolling interest									0	(5)	(12)
Income tax benefit relating to change in statutory tax rate									0	0	(68)
State income tax expense, net of federal tax effect									6	8	3
Non-deductible compensation									4	5	13
Change in valuation allowance									0	0	(127)
Deferred taxes related to change in Viper LP's tax status		$ 42							(42)	(73)	0	$ 115
Other, net									3	(1)	(3)
Provision for (benefit from) income taxes	$ (124)	$ 102	$ 102	$ (33)	$ 85	$ 43	$ (7)	$ 47	$ 47	$ 168	$ (20)

INCOME TAXES - Components of De

INCOME TAXES - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets:
Net operating loss and other carryforwards	$ 453	$ 155
Stock based compensation	7	7
Viper LP's investment in Viper LLC	134	94
Other	11	9
Deferred tax assets	605	265
Valuation allowance	(7)	(14)
Deferred tax assets, net of valuation allowance	598	251
Deferred tax liabilities:
Oil and natural gas properties and equipment	2,275	1,825
Midstream investments	50	67
Derivative instruments	6	47
Rattler LP's investment in Rattler LLC	8	0
Other	3	0
Total deferred tax liabilities	2,342	1,939
Net deferred tax liabilities	$ 1,744	$ 1,688

INCOME TAXES - Unrecognized Tax

INCOME TAXES - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of year	$ 7	$ 0
Increase resulting from tax positions acquired	0	7
Increase resulting from prior period tax positions	0	0
Increase resulting from current period tax positions	0	0
Balance at end of year	7	7
Less: Effects of temporary items	(5)	(5)
Total that, if recognized, would impact the effective income tax rate as of the end of the year	$ 2	$ 2

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($)	3 Months Ended	12 Months Ended			24 Months Ended
	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Nov. 29, 2018
Operating Loss Carryforwards [Line Items]
Change in enacted tax rate, amount		$ 0	$ 0	$ 68,000,000
Effective income tax rate		13.00%	15.10%
Net deferred tax liabilities		$ 1,744,000,000	$ 1,688,000,000		$ 1,744,000,000
Increase ff deferred tax liability due to adjustments to fair value of acquired assets		23,000,000
Operating loss carryforwards, subject to expiration		400,000,000			400,000,000
Operating loss carryforwards, not subject to expiration		1,300,000,000			1,300,000,000
Deferred tax assets, valuation allowance		7,000,000	14,000,000		7,000,000
Deferred tax liability includes deferred tax asset		134,000,000	94,000,000		134,000,000
Change in deferred tax asset due to change in tax status	$ 42,000,000	(42,000,000)	(73,000,000)	$ 0	115,000,000
Operating loss carryforwards		38,000,000			38,000,000
Net operating loss and credit carryforwards		453,000,000	155,000,000		453,000,000
Penalties associated with uncertain tax positions (less than)		0	0
Interest associated with uncertain tax positions		1,000,000	0
Energen
Operating Loss Carryforwards [Line Items]
Minimum tax credits, current income tax receivables		19,000,000			19,000,000
Minimum tax credits, noncurrent income tax receivables		19,000,000			19,000,000
Energen
Operating Loss Carryforwards [Line Items]
Business acquisition, deferred tax liabilities			$ 1,400,000,000			$ 1,425,000,000
Minimum tax credits, noncurrent income tax receivables						$ 76,000,000
Rattler MIdstream LP
Operating Loss Carryforwards [Line Items]
Net deferred tax liabilities		8,000,000			8,000,000
Net operating loss and credit carryforwards		$ 1,000,000			$ 1,000,000

DERIVATIVES - Open Derivative P

DERIVATIVES - Open Derivative Positions (Details) Mcf in Thousands, MMBTU in Thousands	12 Months Ended
	Dec. 31, 2019MMBTU$ / Mcf$ / bbl$ / MMBTUMcfbbl
WTI Cushing Oil Swaps 2020
Derivative [Line Items]
Volume (Bbls) | bbl	4,754,000
Fixed Price Swap (per Bbl/MMBtu)	57.78
WTI Cushing Oil Swaps 2021
Derivative [Line Items]
Volume (Bbls) | bbl	0
Fixed Price Swap (per Bbl/MMBtu)	0
WTI Magellan East Houston Oil Swaps 2020
Derivative [Line Items]
Volume (Bbls) | bbl	2,196,000
Fixed Price Swap (per Bbl/MMBtu)	62.80
WTI Magellan East Houston Oil Swaps 2021
Derivative [Line Items]
Volume (Bbls) | bbl	0
Fixed Price Swap (per Bbl/MMBtu)	0
BRENT Oil Swaps 2020
Derivative [Line Items]
Volume (Bbls) | bbl	4,569,000
Fixed Price Swap (per Bbl/MMBtu)	61.84
BRENT Oil Swaps 2021
Derivative [Line Items]
Volume (Bbls) | bbl	0
Fixed Price Swap (per Bbl/MMBtu)	0
Oil Basis Swaps 2020
Derivative [Line Items]
Volume (Bbls) | bbl	13,860,000
Fixed Price Swap (per Bbl/MMBtu)	(1.20)
Oil Basis Swaps 2021
Derivative [Line Items]
Volume (Bbls) | bbl	0
Fixed Price Swap (per Bbl/MMBtu)	0
Oil Rolling Hedge 2020
Derivative [Line Items]
Volume (Bbls) | bbl	6,700,000
Fixed Price Swap (per Bbl/MMBtu)	0.44
Oil Rolling Hedge 2021
Derivative [Line Items]
Volume (Bbls) | bbl	0
Fixed Price Swap (per Bbl/MMBtu)	0
Natural Gas Swaps - Henry Hub 2020
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	10,050
Fixed Price Swap (per Bbl/MMBtu) | $ / MMBTU	2.55
Natural Gas Swaps - Henry Hub 2021
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	0
Fixed Price Swap (per Bbl/MMBtu) | $ / MMBTU	0
Natural Gas Swaps - Waha Hub 2020
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	16,750
Fixed Price Swap (per Bbl/MMBtu) | $ / MMBTU	1.67
Natural Gas Swaps - Waha Hub 2021
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	0
Fixed Price Swap (per Bbl/MMBtu) | $ / MMBTU	0
Natural Gas Basis Swaps - Waha Hub 2020
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	23,450
Fixed Price Swap (per Bbl/MMBtu) | $ / MMBTU	(1.19)
Natural Gas Basis Swaps - Waha Hub 2021
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	54,750
Fixed Price Swap (per Bbl/MMBtu) | $ / MMBTU	(0.70)
2020 Three-Way Collars - WTI
Derivative [Line Items]
Volume (Bbls) | bbl	6,842,200
Short put price (per Bbl)	44.20
Floor price (per Bbl)	54.20
Ceiling price (per Bbl)	65.42
2020 Three-Way Collars - BRENT
Derivative [Line Items]
Volume (Bbls) | bbl	11,803,500
Short put price (per Bbl)	50
Floor price (per Bbl)	60
Ceiling price (per Bbl)	70.86
2020 Three-Way Collars - WTI Magellan East Houston
Derivative [Line Items]
Volume (Bbls) | bbl	5,124,000
Short put price (per Bbl)	50
Floor price (per Bbl)	60
Ceiling price (per Bbl)	68.61
Gas Swap Double-Up - Waha Hub
Derivative [Line Items]
Volume (Bbls) | Mcf	10,050
Fixed Price Swap (per Bbl/MMBtu) | $ / Mcf	1.70
Option price (per Mcf) | $ / Mcf	1.70

DERIVATIVES - Interest Rate Swa

DERIVATIVES - Interest Rate Swaps and Treasury Locks (Details) - USD ($) $ in Millions	2 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Offsetting Assets [Line Items]
Net gain on sale of interest rate swaps and treasury locks		$ 80	$ (121)	$ 6
Interest Rate Swaps and Treasury Locks
Offsetting Assets [Line Items]
Net gain on sale of interest rate swaps and treasury locks	$ 43

DERIVATIVES - Offsetting Deriva

DERIVATIVES - Offsetting Derivative Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross amounts of assets presented in the Consolidated Balance Sheet	$ 71	$ 233
Amounts netted in the Consolidated Balance Sheet	(18)	(2)
Total assets	53	231
Gross amounts of liabilities presented in the Consolidated Balance Sheet	45	15
Amounts netted in the Consolidated Balance Sheet	(18)	0
Total liabilities	$ 27	$ 15

DERIVATIVES - Derivative Assets

DERIVATIVES - Derivative Assets and Liabilities on Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current assets: derivative instruments	$ 46	$ 231
Noncurrent assets: derivative instruments	7	0
Total assets	53	231
Current liabilities: derivative instruments	27	0
Noncurrent liabilities: derivative instruments	0	15
Total liabilities	$ 27	$ 15

DERIVATIVES - Gains and Losses

DERIVATIVES - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Change in fair value of open non-hedge derivative instruments:	$ (188)	$ 222	$ (84)
Gain (loss) on settlement of non-hedge derivative instruments:	80	(121)	6
Gain (loss) on derivative instruments	$ (108)	$ 101	$ (78)

FAIR VALUE MEASUREMENTS - Recur

FAIR VALUE MEASUREMENTS - Recurring Measurements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2018
Assets:
Fixed price swaps				$ 53	$ 231
Liabilities:
Fixed price swaps				27	15
Summary Of Changes In Cost Method Investment [Roll Forward]
Gain (loss) on investment	$ 5	$ (1)	$ 0
Impact of adoption of Accounting Standards Update 2016-01						$ (16)
Viper Energy Partners LP | Recurring | Level 1
Assets:
Investment	14	34	34	19	14
Fixed price swaps				0	0
Liabilities:
Fixed price swaps				0	0
Summary Of Changes In Cost Method Investment [Roll Forward]
Investment, beginning balance	14	34
Gain (loss) on investment	5	(1)
Investment, ending balance	19	14	$ 34
Viper Energy Partners LP | Recurring | Level 2
Assets:
Investment	0	0		0	0
Fixed price swaps				26	216
Liabilities:
Fixed price swaps				0	0
Summary Of Changes In Cost Method Investment [Roll Forward]
Investment, beginning balance	0
Investment, ending balance	0	0
Viper Energy Partners LP | Recurring | Level 3
Assets:
Investment	0	0		0	0
Fixed price swaps				0	0
Liabilities:
Fixed price swaps				$ 0	$ 0
Summary Of Changes In Cost Method Investment [Roll Forward]
Investment, beginning balance	0
Investment, ending balance	$ 0	$ 0
Accounting Standards Update 2016-01 | Viper Energy Partners LP
Summary Of Changes In Cost Method Investment [Roll Forward]
Impact of adoption of Accounting Standards Update 2016-01						$ (19)

FAIR VALUE MEASUREMENTS - Nonre

FAIR VALUE MEASUREMENTS - Nonrecurring Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 05, 2019	Dec. 31, 2018
4.625% Notes due 2021
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	4.625%
7.320% Medium-term Notes, Series A, due 2022
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	7.32%
2.875% Senior Notes due 2024
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	2.875%	2.875%
4.750% Senior Notes due 2024
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	4.75%
5.375% Senior Notes due 2025
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	5.375%
3.250% Senior Notes due 2026
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	3.25%	3.25%
7.350% Medium-term Notes, Series A, due 2027
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	7.35%
7.125% Medium-term Notes, Series B, due 2028
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	7.125%
3.500% Senior Notes due 2029
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	3.50%	3.50%
Viper 5.375% Senior Notes due 2027
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	5.375%
Reported Value Measurement | Revolving credit facility | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	$ 13		$ 1,490
Reported Value Measurement | 4.625% Notes due 2021 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	399		400
Reported Value Measurement | 7.320% Medium-term Notes, Series A, due 2022 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	21		20
Reported Value Measurement | 2.875% Senior Notes due 2024 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	992		0
Reported Value Measurement | 4.750% Senior Notes due 2024 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	0		1,236
Reported Value Measurement | 5.375% Senior Notes due 2025 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	799		799
Reported Value Measurement | 3.250% Senior Notes due 2026 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	792		0
Reported Value Measurement | 7.350% Medium-term Notes, Series A, due 2027 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	11		10
Reported Value Measurement | 7.125% Medium-term Notes, Series B, due 2028 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	108		100
Reported Value Measurement | 3.500% Senior Notes due 2029 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	1,186		0
Reported Value Measurement | Viper revolving credit facility | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	97		411
Reported Value Measurement | Viper 5.375% Senior Notes due 2027 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	490		0
Reported Value Measurement | Rattler revolving credit facility | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	424		0
Reported Value Measurement | DrillCo Agreement | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt, fair value	39		0
Estimate of Fair Value Measurement | 4.625% Notes due 2021 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	411		393
Estimate of Fair Value Measurement | 7.320% Medium-term Notes, Series A, due 2022 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	22		21
Estimate of Fair Value Measurement | 7.350% Medium-term Notes, Series A, due 2027 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	12		11
Estimate of Fair Value Measurement | 7.125% Medium-term Notes, Series B, due 2028 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	116		102
Estimate of Fair Value Measurement | DrillCo Agreement | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt, fair value	39		0
Estimate of Fair Value Measurement | Level 1 | 2.875% Senior Notes due 2024 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	1,012		0
Estimate of Fair Value Measurement | Level 1 | 4.750% Senior Notes due 2024 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	0		1,204
Estimate of Fair Value Measurement | Level 1 | 5.375% Senior Notes due 2025 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	840		782
Estimate of Fair Value Measurement | Level 1 | 3.250% Senior Notes due 2026 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	812		0
Estimate of Fair Value Measurement | Level 1 | 3.500% Senior Notes due 2029 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	1,226		0
Estimate of Fair Value Measurement | Level 1 | Viper 5.375% Senior Notes due 2027 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	521		0
Estimate of Fair Value Measurement | Level 2 | Revolving credit facility | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	13		1,490
Estimate of Fair Value Measurement | Level 2 | Viper revolving credit facility | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	97		411
Estimate of Fair Value Measurement | Level 2 | Rattler revolving credit facility | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	$ 424		$ 0

LEASES - Additional Information

LEASES - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Operating right of use asset	$ 15
Statement of consolidated cash flow	26
Additional amount of operating lease right of use asset recorded	17
Operating lease liabilities	15
Operating lease liability current	$ 8
Weighted average remaining lease term	2 years 1 month 6 days
Weighted average discount rate	8.20%
Accounting Standards Update 2016-02
Lessee, Lease, Description [Line Items]
Operating right of use asset		$ 13
Operating lease liabilities		$ 13

LEASES - Summary of Operating L

LEASES - Summary of Operating Lease Costs (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating lease costs	$ 26

LEASES - Summary of Undiscounte

LEASES - Summary of Undiscounted Cash Flows Owed by the Company to Lessors Pursuant to Contractual Agreements (Details) $ in Millions	Dec. 31, 2019USD ($)
Leases [Abstract]
2020	$ 9
2021	5
2022	2
2023	0
2024	0
Thereafter	0
Total lease payments	16
Less: interest	1
Present value of lease liabilities	$ 15

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Commitments (Details) - Sand Supply Agreements $ in Millions	Dec. 31, 2019USD ($)
Supply Commitment [Line Items]
2020	$ 18
2021	18
2022	18
2023	18
2024	18
Thereafter	23
Total	$ 113

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - Rent Expenses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Rent Expense	$ 3	$ 1	$ 2

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES - Agreements (Details) $ in Millions	Nov. 12, 2019bbl / d	Oct. 18, 2018bbl / d	Aug. 01, 2018bbl / d	Apr. 23, 2018bbl / d	Dec. 31, 2019bbl / d	Jul. 31, 2019bbl / d	Dec. 31, 2019USD ($)
Gray Oak Pipeline | Diamondback E&P LLC
Supply Commitment [Line Items]
Number of barrels per day				50,000
Deficiency Payments | $							$ 11
Full Service Term | Gray Oak Pipeline | Diamondback E&P LLC
Supply Commitment [Line Items]
Number of barrels per day	50,000
Trafigura Trading LLC
Supply Commitment [Line Items]
Number of barrels per day			25,000
Commitment, period			7 years
Plains Marketing LP
Supply Commitment [Line Items]
Number of barrels per day						50,000
Commitment, period						10 years
Plains Marketing LP | Maximum
Supply Commitment [Line Items]
Number of barrels per day						100,000
Shell Trading US Company
Supply Commitment [Line Items]
Commitment, period					3 years
Number of options to extend purchase agreement term					3		3
Purchase obligation extension period					1 year
Shell Trading US Company | Pre Commencement Terms | Minimum
Supply Commitment [Line Items]
Number of barrels per day					30,000
Shell Trading US Company | Pre Commencement Terms | Maximum
Supply Commitment [Line Items]
Number of barrels per day					40,000
Shell Trading US Company | Full Service Term | Maximum
Supply Commitment [Line Items]
Number of barrels per day					50,000
Vitol Inc
Supply Commitment [Line Items]
Number of barrels per day		23,750
Vitol Inc | Epic Pipeline
Supply Commitment [Line Items]
Commitment, period		7 years
Additional number of barrels per day		50,000
Vitol Inc | Full Service Term | Gray Oak Pipeline
Supply Commitment [Line Items]
Number of barrels per day		50,000
Commitment, period		7 years
Additional number of barrels per day		50,000

COMMITMENTS AND CONTINGENCIES_4

COMMITMENTS AND CONTINGENCIES - Defined Contribution Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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	$ 8	$ 2	$ 2

SUBSEQUENT EVENTS - Additional

SUBSEQUENT EVENTS - Additional Information (Details) - $ / shares	Feb. 14, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Subsequent Event [Line Items]
Dividends declared per share (in dollars per share)		$ 0.9375	$ 0.5000	$ 0
Subsequent Event
Subsequent Event [Line Items]
Dividends declared per share (in dollars per share)	$ 0.3750

SUBSEQUENT EVENTS - Derivative

SUBSEQUENT EVENTS - Derivative Contracts (Details) MMBTU in Thousands	12 Months Ended
	Dec. 31, 2020MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2019MMBTU$ / bbl$ / MMBTUbbl
WTI Cushing Oil Swaps 2020
Subsequent Event [Line Items]
Volume (Bbls) | bbl		4,754,000
Fixed Price Swap (per Bbl/MMBtu)		57.78
BRENT Oil Swaps 2020
Subsequent Event [Line Items]
Volume (Bbls) | bbl		4,569,000
Fixed Price Swap (per Bbl/MMBtu)		61.84
Natural Gas Swaps - Waha Hub 2020
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) | MMBTU		16,750
Fixed Price Swap (per Bbl/MMBtu) | $ / MMBTU		1.67
Natural Gas Basis Swaps - Waha Hub 2020
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) | MMBTU		23,450
Fixed Price Swap (per Bbl/MMBtu) | $ / MMBTU		(1.19)
2020 Three-Way Collars - BRENT
Subsequent Event [Line Items]
Volume (Bbls) | bbl		11,803,500
Short put price (per Bbl)		50
Floor price (per Bbl)		60
Ceiling price (per Bbl)		70.86
Forecast | WTI Cushing Oil Swaps 2020
Subsequent Event [Line Items]
Volume (Bbls) | bbl	732,000
Fixed Price Swap (per Bbl/MMBtu)	60.50
Forecast | BRENT Oil Swaps 2020
Subsequent Event [Line Items]
Volume (Bbls) | bbl	732,000
Fixed Price Swap (per Bbl/MMBtu)	65
Forecast | Natural Gas Swaps - Waha Hub 2020
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) | MMBTU	1,840
Fixed Price Swap (per Bbl/MMBtu) | $ / MMBTU	0.75
Forecast | Natural Gas Basis Swaps - Waha Hub 2020
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) | MMBTU	13,750
Fixed Price Swap (per Bbl/MMBtu) | $ / MMBTU	(1.85)
Forecast | Diesel Price Swaps 2020
Subsequent Event [Line Items]
Volume (Bbls) | bbl	11,000,000
Fixed Price Swap (per Bbl/MMBtu)	1.60
Forecast | 2020 Three-Way Collars - BRENT
Subsequent Event [Line Items]
Volume (Bbls) | bbl	732,000
Short put price (per Bbl)	50
Floor price (per Bbl)	60
Ceiling price (per Bbl)	69.25
Forecast | Oil Put Spreads - WTI
Subsequent Event [Line Items]
Volume (Bbls) | bbl	829,125
Short put price (per Bbl)	50.50
Floor price (per Bbl)	60.50
Forecast | Oil Put Spreads - Brent
Subsequent Event [Line Items]
Volume (Bbls) | bbl	1,758,750
Short put price (per Bbl)	52.38
Floor price (per Bbl)	65

REPORT OF BUSINESS SEGMENTS R_2

REPORT OF BUSINESS SEGMENTS REPORT OF BUSINESS SEGMENTS - Additional Information (Details)	12 Months Ended
	Dec. 31, 2019segment
Segment Reporting [Abstract]
Number of business segments	2

REPORT OF BUSINESS SEGMENTS - S

REPORT OF BUSINESS SEGMENTS - Summary of Business Segments (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenues	$ 1,104,000,000	$ 975,000,000	$ 1,021,000,000	$ 864,000,000	$ 633,000,000	$ 537,000,000	$ 527,000,000	$ 479,000,000	$ 3,964,000,000	$ 2,176,000,000	$ 1,205,000,000
Depreciation, depletion and amortization									1,447,000,000	623,000,000	327,000,000
Impairment of oil and natural gas properties									790,000,000	0	0
Income from operations	(384,000,000)	349,000,000	411,000,000	319,000,000	195,000,000	268,000,000	281,000,000	267,000,000	695,000,000	1,011,000,000	605,000,000
Interest expense, net									(172,000,000)	(87,000,000)	(41,000,000)
Total other income (expense), net									(333,000,000)	102,000,000	(108,000,000)
Provision for income taxes	(124,000,000)	102,000,000	102,000,000	(33,000,000)	85,000,000	43,000,000	(7,000,000)	47,000,000	47,000,000	168,000,000	(20,000,000)
Net income attributable to non-controlling interest	15,000,000	20,000,000	7,000,000	33,000,000	(1,000,000)	3,000,000	82,000,000	15,000,000	75,000,000	99,000,000	35,000,000
Net income attributable to Diamondback Energy	(487,000,000)	$ 368,000,000	$ 349,000,000	$ 10,000,000	307,000,000	$ 157,000,000	$ 219,000,000	$ 163,000,000	240,000,000	846,000,000	482,000,000
Total assets	23,531,000,000				21,596,000,000				23,531,000,000	21,596,000,000	7,771,000,000
Upstream
Segment Reporting Information [Line Items]
Revenues									3,891,000,000	2,132,000,000	1,198,000,000
Midstream Services
Segment Reporting Information [Line Items]
Revenues									448,000,000	184,000,000	39,000,000
Impairment of oil and natural gas properties									2,000,000
Operating Segments | Upstream
Segment Reporting Information [Line Items]
Revenues									3,891,000,000	2,132,000,000	1,198,000,000
Depreciation, depletion and amortization									1,405,000,000	598,000,000	324,000,000
Impairment of oil and natural gas properties									790,000,000
Income from operations									790,000,000	1,071,000,000	613,000,000
Interest expense, net									(171,000,000)	(87,000,000)	(41,000,000)
Total other income (expense), net									(320,000,000)	102,000,000	(109,000,000)
Provision for income taxes									21,000,000	151,000,000	(24,000,000)
Net income attributable to non-controlling interest									75,000,000	99,000,000	35,000,000
Net income attributable to Diamondback Energy									374,000,000	923,000,000	493,000,000
Total assets	22,125,000,000				21,096,000,000				22,125,000,000	21,096,000,000	7,475,000,000
Operating Segments | Midstream Services
Segment Reporting Information [Line Items]
Revenues									73,000,000	44,000,000	7,000,000
Depreciation, depletion and amortization									42,000,000	25,000,000	3,000,000
Impairment of oil and natural gas properties									0
Income from operations									219,000,000	80,000,000	24,000,000
Interest expense, net									(1,000,000)	0	0
Total other income (expense), net									(7,000,000)	0	1,000,000
Provision for income taxes									26,000,000	17,000,000	4,000,000
Net income attributable to non-controlling interest									91,000,000	0	0
Net income attributable to Diamondback Energy									95,000,000	63,000,000	21,000,000
Total assets	1,636,000,000				604,000,000				1,636,000,000	604,000,000	300,000,000
Eliminations
Segment Reporting Information [Line Items]
Revenues									(375,000,000)	(140,000,000)	(32,000,000)
Depreciation, depletion and amortization									0	0	0
Impairment of oil and natural gas properties									0
Income from operations									(314,000,000)	(140,000,000)	(32,000,000)
Interest expense, net									0	0	0
Total other income (expense), net									(6,000,000)	0	0
Provision for income taxes									0	0	0
Net income attributable to non-controlling interest									(91,000,000)	0	0
Net income attributable to Diamondback Energy									(229,000,000)	(140,000,000)	(32,000,000)
Total assets	$ (230,000,000)				$ (104,000,000)				$ (230,000,000)	$ (104,000,000)	$ (4,000,000)

GUARANTOR FINANCIAL STATEMENT_2

GUARANTOR FINANCIAL STATEMENTS - Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 123	$ 215
Restricted cash	5	0
Accounts receivable, net	615	392
Accounts receivable - related party		0
Intercompany receivable	0	0
Inventories	37	37
Derivative instruments	46	231
Prepaid expenses and other	43	50
Total current assets	869	925
Property and equipment:
Oil and natural gas properties, full cost method of accounting	25,782	22,299
Midstream assets	931	700
Other property, equipment and land	125	147
Accumulated depletion, depreciation, amortization and impairment	(5,003)	(2,774)
Net property and equipment	21,835	20,372
Equity method investments	479	1
Derivative instruments	7	0
Investment in subsidiaries	0	0
Investment in real estate, net	109	116
Deferred tax asset	142	97
Other assets	90	85
Total assets	23,531	21,596	$ 7,771
Current liabilities:
Accounts payable-trade	179	128
Intercompany payable	0	0
Accrued capital expenditures	475	495
Other accrued liabilities	304	253
Revenues and royalties payable	278	143
Derivative instruments	27	0
Total current liabilities	1,263	1,019
Long-term debt	5,371	4,464
Derivative instruments	0	15
Asset retirement obligations	94	136	20
Deferred income taxes	1,886	1,785
Other long-term liabilities	11	10
Total liabilities	8,625	7,429
Commitments and contingencies
Stockholders’ equity:
Stockholders’ equity	13,249	13,700
Non-controlling interest	1,657	467
Total equity	14,906	14,167	$ 5,581	$ 4,018
Total liabilities and equity	23,531	21,596
Eliminations
Current assets:
Cash and cash equivalents	0	0
Restricted cash	0
Accounts receivable, net	0	0
Accounts receivable - related party		(4)
Intercompany receivable	(5,903)	(4,670)
Inventories	0	0
Derivative instruments	0	0
Prepaid expenses and other	19	0
Total current assets	(5,884)	(4,674)
Property and equipment:
Oil and natural gas properties, full cost method of accounting	(201)	(3)
Midstream assets	0	0
Other property, equipment and land	0	0
Accumulated depletion, depreciation, amortization and impairment	(5)	(12)
Net property and equipment	(206)	(15)
Equity method investments	0	0
Derivative instruments	0
Investment in subsidiaries	(10,414)	(12,801)
Investment in real estate, net	0	0
Deferred tax asset	0	0
Other assets	(230)	0
Total assets	(16,734)	(17,490)
Current liabilities:
Accounts payable-trade	0	0
Intercompany payable	(5,903)	(4,673)
Accrued capital expenditures	0	0
Other accrued liabilities	0	0
Revenues and royalties payable	0	0
Derivative instruments	1
Total current liabilities	(5,902)	(4,673)
Long-term debt	0	0
Derivative instruments		0
Asset retirement obligations	0	0
Deferred income taxes	0	0
Other long-term liabilities	0	0
Total liabilities	(5,902)	(4,673)
Commitments and contingencies
Stockholders’ equity:
Stockholders’ equity	(10,543)	(12,589)
Non-controlling interest	(289)	(228)
Total equity	(10,832)	(12,817)
Total liabilities and equity	(16,734)	(17,490)
Parent | Reportable Legal Entities
Current assets:
Cash and cash equivalents	93	84
Restricted cash	5
Accounts receivable, net	0	0
Accounts receivable - related party		0
Intercompany receivable	5,331	4,469
Inventories	0	0
Derivative instruments	0	0
Prepaid expenses and other	2	2
Total current assets	5,431	4,555
Property and equipment:
Oil and natural gas properties, 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
Equity method investments	0	0
Derivative instruments	0
Investment in subsidiaries	10,414	12,689
Investment in real estate, net	0	0
Deferred tax asset	0	0
Other assets	0	0
Total assets	15,845	17,244
Current liabilities:
Accounts payable-trade	0	0
Intercompany payable	0	0
Accrued capital expenditures	0	0
Other accrued liabilities	17	14
Revenues and royalties payable	0	0
Derivative instruments	0
Total current liabilities	17	14
Long-term debt	3,769	2,036
Derivative instruments		0
Asset retirement obligations	0	0
Deferred income taxes	470	382
Other long-term liabilities	0	0
Total liabilities	4,256	2,432
Commitments and contingencies
Stockholders’ equity:
Stockholders’ equity	11,589	14,812
Non-controlling interest	0	0
Total equity	11,589	14,812
Total liabilities and equity	15,845	17,244
Guarantor Subsidiaries | Reportable Legal Entities
Current assets:
Cash and cash equivalents	0	2
Restricted cash	0
Accounts receivable, net	248	143
Accounts receivable - related party		0
Intercompany receivable	0	0
Inventories	1	2
Derivative instruments	46	197
Prepaid expenses and other	1	0
Total current assets	296	344
Property and equipment:
Oil and natural gas properties, full cost method of accounting	13,276	11,170
Midstream assets	0	21
Other property, equipment and land	0	1
Accumulated depletion, depreciation, amortization and impairment	(3,167)	(2,432)
Net property and equipment	10,109	8,760
Equity method investments	0	0
Derivative instruments	7
Investment in subsidiaries	0	0
Investment in real estate, net	0	0
Deferred tax asset	0	0
Other assets	10	10
Total assets	10,422	9,114
Current liabilities:
Accounts payable-trade	0	0
Intercompany payable	5,930	3,939
Accrued capital expenditures	0	0
Other accrued liabilities	132	23
Revenues and royalties payable	0	0
Derivative instruments	18
Total current liabilities	6,080	3,962
Long-term debt	13	1,490
Derivative instruments		11
Asset retirement obligations	34	30
Deferred income taxes	0	0
Other long-term liabilities	0	0
Total liabilities	6,127	5,493
Commitments and contingencies
Stockholders’ equity:
Stockholders’ equity	4,295	3,621
Non-controlling interest	0	0
Total equity	4,295	3,621
Total liabilities and equity	10,422	9,114
Non-Guarantor Subsidiaries | Reportable Legal Entities
Current assets:
Cash and cash equivalents	30	129
Restricted cash	0
Accounts receivable, net	367	249
Accounts receivable - related party		4
Intercompany receivable	572	201
Inventories	36	35
Derivative instruments	0	34
Prepaid expenses and other	21	48
Total current assets	1,026	700
Property and equipment:
Oil and natural gas properties, full cost method of accounting	12,707	11,132
Midstream assets	931	679
Other property, equipment and land	125	146
Accumulated depletion, depreciation, amortization and impairment	(1,831)	(330)
Net property and equipment	11,932	11,627
Equity method investments	479	1
Derivative instruments	0
Investment in subsidiaries	0	112
Investment in real estate, net	109	116
Deferred tax asset	142	97
Other assets	310	75
Total assets	13,998	12,728
Current liabilities:
Accounts payable-trade	179	128
Intercompany payable	(27)	734
Accrued capital expenditures	475	495
Other accrued liabilities	155	216
Revenues and royalties payable	278	143
Derivative instruments	8
Total current liabilities	1,068	1,716
Long-term debt	1,589	938
Derivative instruments		4
Asset retirement obligations	60	106
Deferred income taxes	1,416	1,403
Other long-term liabilities	11	10
Total liabilities	4,144	4,177
Commitments and contingencies
Stockholders’ equity:
Stockholders’ equity	7,908	7,856
Non-controlling interest	1,946	695
Total equity	9,854	8,551
Total liabilities and equity	$ 13,998	$ 12,728

GUARANTOR FINANCIAL STATEMENT_3

GUARANTOR FINANCIAL STATEMENTS - Income Statement (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Lease bonus									$ 4,000,000	$ 3,000,000	$ 12,000,000
Other operating income									9,000,000	9,000,000	0
Total revenues	$ 1,104,000,000	$ 975,000,000	$ 1,021,000,000	$ 864,000,000	$ 633,000,000	$ 537,000,000	$ 527,000,000	$ 479,000,000	3,964,000,000	2,176,000,000	1,205,000,000
Costs and expenses:
Lease operating expenses									490,000,000	205,000,000	127,000,000
Production and ad valorem taxes									248,000,000	133,000,000	74,000,000
Depreciation, depletion and amortization									1,447,000,000	623,000,000	327,000,000
Impairment of oil and natural gas properties									790,000,000	0	0
General and administrative expenses									104,000,000	65,000,000	48,000,000
Merger and integration expense									0	36,000,000	0
Asset retirement obligation accretion									7,000,000	2,000,000	1,000,000
Other operating expense									4,000,000	3,000,000	0
Total costs and expenses									3,269,000,000	1,165,000,000	600,000,000
Income from operations	(384,000,000)	349,000,000	411,000,000	319,000,000	195,000,000	268,000,000	281,000,000	267,000,000	695,000,000	1,011,000,000	605,000,000
Other income (expense):
Interest expense, net									(172,000,000)	(87,000,000)	(41,000,000)
Other (expense) income, net									(2,000,000)	89,000,000	11,000,000
Gain on derivative instruments, net									(108,000,000)	101,000,000	(78,000,000)
Gain (loss) on revaluation of investment									5,000,000	(1,000,000)	0
Loss on extinguishment of debt									(56,000,000)	0	0
Income from subsidiaries									0	0	0
Total other income (expense), net									(333,000,000)	102,000,000	(108,000,000)
Income (loss) before income taxes									362,000,000	1,113,000,000	497,000,000
Provision for (benefit from) income taxes	(124,000,000)	102,000,000	102,000,000	(33,000,000)	85,000,000	43,000,000	(7,000,000)	47,000,000	47,000,000	168,000,000	(20,000,000)
Net income (loss)	(472,000,000)	388,000,000	356,000,000	43,000,000	306,000,000	160,000,000	301,000,000	178,000,000	315,000,000	945,000,000	517,000,000
Net income (loss) attributable to non-controlling interest	15,000,000	20,000,000	7,000,000	33,000,000	(1,000,000)	3,000,000	82,000,000	15,000,000	75,000,000	99,000,000	35,000,000
Net income (loss) attributable to Diamondback Energy, Inc.	$ (487,000,000)	$ 368,000,000	$ 349,000,000	$ 10,000,000	$ 307,000,000	$ 157,000,000	$ 219,000,000	$ 163,000,000	240,000,000	846,000,000	482,000,000
Oil sales
Revenues:
Revenues									3,554,000,000	1,879,000,000	1,044,000,000
Natural gas sales
Revenues:
Revenues									66,000,000	61,000,000	52,000,000
Natural gas liquid sales
Revenues:
Revenues									267,000,000	190,000,000	90,000,000
Royalty income
Revenues:
Revenues									0	0	0
Midstream services
Revenues:
Revenues									64,000,000	34,000,000	7,000,000
Costs and expenses:
Cost of goods and services sold									91,000,000	72,000,000	10,000,000
Gathering and transportation
Costs and expenses:
Cost of goods and services sold									88,000,000	26,000,000	13,000,000
Eliminations
Revenues:
Lease bonus									0	(3,000,000)	0
Other operating income									(5,000,000)	0
Total revenues									(375,000,000)	(141,000,000)	(32,000,000)
Costs and expenses:
Lease operating expenses									(143,000,000)	(42,000,000)	(16,000,000)
Production and ad valorem taxes									0	0	0
Depreciation, depletion and amortization									(8,000,000)	17,000,000	4,000,000
Impairment of oil and natural gas properties									0
General and administrative expenses									(12,000,000)	(2,000,000)	(2,000,000)
Merger and integration expense										0
Asset retirement obligation accretion									0	0	0
Other operating expense									0	0
Total costs and expenses									(263,000,000)	(43,000,000)	(23,000,000)
Income from operations									(112,000,000)	(98,000,000)	(9,000,000)
Other income (expense):
Interest expense, net									0	0	0
Other (expense) income, net									(7,000,000)	(2,000,000)	(2,000,000)
Gain on derivative instruments, net									0	0	0
Gain (loss) on revaluation of investment									0	0
Loss on extinguishment of debt									0
Income from subsidiaries									(764,000,000)	(1,113,000,000)	(446,000,000)
Total other income (expense), net									(771,000,000)	(1,115,000,000)	(448,000,000)
Income (loss) before income taxes									(883,000,000)	(1,213,000,000)	(457,000,000)
Provision for (benefit from) income taxes									(1,000,000)	0	0
Net income (loss)									(882,000,000)	(1,213,000,000)	(457,000,000)
Net income (loss) attributable to non-controlling interest									(191,000,000)	(20,000,000)	35,000,000
Net income (loss) attributable to Diamondback Energy, Inc.									(691,000,000)	(1,193,000,000)	(492,000,000)
Eliminations | Oil sales
Revenues:
Revenues									264,000,000	247,000,000	140,000,000
Eliminations | Natural gas sales
Revenues:
Revenues									8,000,000	13,000,000	9,000,000
Eliminations | Natural gas liquid sales
Revenues:
Revenues									21,000,000	23,000,000	11,000,000
Eliminations | Royalty income
Revenues:
Revenues									(293,000,000)	(283,000,000)	(160,000,000)
Eliminations | Midstream services
Revenues:
Revenues									(370,000,000)	(138,000,000)	(32,000,000)
Costs and expenses:
Cost of goods and services sold									(79,000,000)	0	(1,000,000)
Eliminations | Gathering and transportation
Costs and expenses:
Cost of goods and services sold									(21,000,000)	(16,000,000)	(8,000,000)
Parent | Reportable Legal Entities
Revenues:
Lease bonus									0	0	0
Other operating income									0	0
Total revenues									0	0	0
Costs and expenses:
Lease operating expenses									0	0	0
Production and ad valorem taxes									0	0	0
Depreciation, depletion and amortization									0	0	0
Impairment of oil and natural gas properties									0
General and administrative expenses									48,000,000	28,000,000	27,000,000
Merger and integration expense										18,000,000
Asset retirement obligation accretion									0	0	0
Other operating expense									0	0
Total costs and expenses									48,000,000	46,000,000	27,000,000
Income from operations									(48,000,000)	(46,000,000)	(27,000,000)
Other income (expense):
Interest expense, net									(47,000,000)	(43,000,000)	(30,000,000)
Other (expense) income, net									3,000,000	1,000,000	1,000,000
Gain on derivative instruments, net									0	0	0
Gain (loss) on revaluation of investment									0	0
Loss on extinguishment of debt									(56,000,000)
Income from subsidiaries									764,000,000	1,113,000,000	446,000,000
Total other income (expense), net									664,000,000	1,071,000,000	417,000,000
Income (loss) before income taxes									616,000,000	1,025,000,000	390,000,000
Provision for (benefit from) income taxes									81,000,000	241,000,000	(20,000,000)
Net income (loss)									535,000,000	784,000,000	410,000,000
Net income (loss) attributable to non-controlling interest									0	0	0
Net income (loss) attributable to Diamondback Energy, Inc.									535,000,000	784,000,000	410,000,000
Parent | Reportable Legal Entities | Oil sales
Revenues:
Revenues									0	0	0
Parent | Reportable Legal Entities | Natural gas sales
Revenues:
Revenues									0	0	0
Parent | Reportable Legal Entities | Natural gas liquid sales
Revenues:
Revenues									0	0	0
Parent | Reportable Legal Entities | Royalty income
Revenues:
Revenues									0	0	0
Parent | Reportable Legal Entities | Midstream services
Revenues:
Revenues									0	0	0
Costs and expenses:
Cost of goods and services sold									0	0	0
Parent | Reportable Legal Entities | Gathering and transportation
Costs and expenses:
Cost of goods and services sold									0	0	0
Guarantor Subsidiaries | Reportable Legal Entities
Revenues:
Lease bonus									0	0	0
Other operating income									0	0
Total revenues									2,131,000,000	1,746,000,000	1,026,000,000
Costs and expenses:
Lease operating expenses									390,000,000	230,000,000	143,000,000
Production and ad valorem taxes									130,000,000	106,000,000	63,000,000
Depreciation, depletion and amortization									735,000,000	472,000,000	277,000,000
Impairment of oil and natural gas properties									0
General and administrative expenses									1,000,000	1,000,000	0
Merger and integration expense										0
Asset retirement obligation accretion									2,000,000	1,000,000	1,000,000
Other operating expense									0	0
Total costs and expenses									1,333,000,000	851,000,000	505,000,000
Income from operations									798,000,000	895,000,000	521,000,000
Other income (expense):
Interest expense, net									(74,000,000)	(20,000,000)	(6,000,000)
Other (expense) income, net									0	0	0
Gain on derivative instruments, net									(56,000,000)	169,000,000	(77,000,000)
Gain (loss) on revaluation of investment									0	0
Loss on extinguishment of debt									0
Income from subsidiaries									0	0	0
Total other income (expense), net									(130,000,000)	149,000,000	(83,000,000)
Income (loss) before income taxes									668,000,000	1,044,000,000	438,000,000
Provision for (benefit from) income taxes									0	0	0
Net income (loss)									668,000,000	1,044,000,000	438,000,000
Net income (loss) attributable to non-controlling interest									0	0	0
Net income (loss) attributable to Diamondback Energy, Inc.									668,000,000	1,044,000,000	438,000,000
Guarantor Subsidiaries | Reportable Legal Entities | Oil sales
Revenues:
Revenues									1,972,000,000	1,545,000,000	904,000,000
Guarantor Subsidiaries | Reportable Legal Entities | Natural gas sales
Revenues:
Revenues									27,000,000	43,000,000	43,000,000
Guarantor Subsidiaries | Reportable Legal Entities | Natural gas liquid sales
Revenues:
Revenues									132,000,000	158,000,000	79,000,000
Guarantor Subsidiaries | Reportable Legal Entities | Royalty income
Revenues:
Revenues									0	0	0
Guarantor Subsidiaries | Reportable Legal Entities | Midstream services
Revenues:
Revenues									0	0	0
Costs and expenses:
Cost of goods and services sold									0	0	0
Guarantor Subsidiaries | Reportable Legal Entities | Gathering and transportation
Costs and expenses:
Cost of goods and services sold									75,000,000	41,000,000	21,000,000
Non-Guarantor Subsidiaries | Reportable Legal Entities
Revenues:
Lease bonus									4,000,000	6,000,000	12,000,000
Other operating income									14,000,000	9,000,000
Total revenues									2,208,000,000	571,000,000	211,000,000
Costs and expenses:
Lease operating expenses									243,000,000	17,000,000	0
Production and ad valorem taxes									118,000,000	27,000,000	11,000,000
Depreciation, depletion and amortization									720,000,000	134,000,000	46,000,000
Impairment of oil and natural gas properties									790,000,000
General and administrative expenses									67,000,000	38,000,000	23,000,000
Merger and integration expense										18,000,000
Asset retirement obligation accretion									5,000,000	1,000,000	0
Other operating expense									4,000,000	3,000,000
Total costs and expenses									2,151,000,000	311,000,000	91,000,000
Income from operations									57,000,000	260,000,000	120,000,000
Other income (expense):
Interest expense, net									(51,000,000)	(24,000,000)	(5,000,000)
Other (expense) income, net									2,000,000	90,000,000	12,000,000
Gain on derivative instruments, net									(52,000,000)	(68,000,000)	(1,000,000)
Gain (loss) on revaluation of investment									5,000,000	(1,000,000)
Loss on extinguishment of debt									0
Income from subsidiaries									0	0	0
Total other income (expense), net									(96,000,000)	(3,000,000)	6,000,000
Income (loss) before income taxes									(39,000,000)	257,000,000	126,000,000
Provision for (benefit from) income taxes									(33,000,000)	(73,000,000)	0
Net income (loss)									(6,000,000)	330,000,000	126,000,000
Net income (loss) attributable to non-controlling interest									266,000,000	119,000,000	0
Net income (loss) attributable to Diamondback Energy, Inc.									(272,000,000)	211,000,000	126,000,000
Non-Guarantor Subsidiaries | Reportable Legal Entities | Oil sales
Revenues:
Revenues									1,318,000,000	87,000,000	0
Non-Guarantor Subsidiaries | Reportable Legal Entities | Natural gas sales
Revenues:
Revenues									31,000,000	5,000,000	0
Non-Guarantor Subsidiaries | Reportable Legal Entities | Natural gas liquid sales
Revenues:
Revenues									114,000,000	9,000,000	0
Non-Guarantor Subsidiaries | Reportable Legal Entities | Royalty income
Revenues:
Revenues									293,000,000	283,000,000	160,000,000
Non-Guarantor Subsidiaries | Reportable Legal Entities | Midstream services
Revenues:
Revenues									434,000,000	172,000,000	39,000,000
Costs and expenses:
Cost of goods and services sold									170,000,000	72,000,000	11,000,000
Non-Guarantor Subsidiaries | Reportable Legal Entities | Gathering and transportation
Costs and expenses:
Cost of goods and services sold									$ 34,000,000	$ 1,000,000	$ 0

GUARANTOR FINANCIAL STATEMENT_4

GUARANTOR FINANCIAL STATEMENTS - Cash Flow Statement (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	$ 2,734	$ 1,565	$ 889
Cash flows from investing activities:
Additions to oil and natural gas properties	(2,677)	(1,461)	(793)
Additions to midstream assets	(244)	(204)	(68)
Purchase of other property, equipment and land	(5)	(7)	(23)
Acquisition of leasehold interests	(443)	(1,371)	(1,961)
Acquisition of mineral interests	(333)	(440)	(407)
Acquisition of midstream assets	0	0	(50)
Proceeds from sale of assets	300	80	66
Investment in real estate	(1)	(111)	0
Funds held in escrow	0	11	104
Equity investments	(485)	0	0
Intercompany transfers	0	0	0
Net cash used in investing activities	(3,888)	(3,503)	(3,132)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	2,350	2,652	754
Repayment under credit facility	(3,718)	(1,242)	(384)
Purchase of subsidiary units by parent			0
Repayment on Energen's credit facility	0	(559)	0
Proceeds from senior notes	3,469	1,062	0
Repayment of senior notes	(1,250)	0	0
Premium on extinguishment of debt	(44)	0	0
Proceeds from joint venture	39	0	0
Debt issuance costs	(18)	(25)	(9)
Public offering costs	(41)	(3)	(1)
Proceeds from public offerings	1,106	305	370
Contributions to subsidiaries		0
Distribution to parent		0
Distributions from subsidiary	0	0	0
Proceeds from exercise of stock options	9	0	0
Repurchased for tax withholdings	(13)	(14)	0
Repurchased as part of share buyback	593	0	0
Dividends to stockholders	(112)	(37)	0
Distributions to non-controlling interest	(122)	(98)	(41)
Intercompany transfers	0	0
Net cash (used in) provided by financing activities	1,062	2,041	689
Net increase (decrease) in cash and cash equivalents	(92)	103	(1,554)
Cash and cash equivalents at beginning of period	215	112	1,666
Cash and cash equivalents at end of period	123	215	112
Eliminations
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by 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	0
Purchase of other property, equipment and land	0	0	0
Acquisition of leasehold interests	0	0	0
Acquisition of mineral interests	190	0	0
Acquisition of midstream assets			0
Proceeds from sale of assets	(190)	0	0
Investment in real estate	0	0
Funds held in escrow		0	0
Equity investments	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 under credit facility	0	0	0
Purchase of subsidiary units by parent			10
Repayment on Energen's credit facility		0
Proceeds from senior notes	0	0
Repayment of senior notes	0
Premium on extinguishment of debt	0
Proceeds from joint venture	0
Debt issuance costs	0	0	0
Public offering costs	0	0	0
Proceeds from public offerings	0	0	(10)
Contributions to subsidiaries		2
Distribution to parent		(155)
Distributions from subsidiary	(860)	0	(89)
Proceeds from exercise of stock options	0
Repurchased for tax withholdings	0	0
Repurchased as part of share buyback	0
Dividends to stockholders	0	0
Distributions to non-controlling interest	860	155	89
Intercompany transfers	0	(2)
Net cash (used in) 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 | Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	(956)	(58)	(29)
Cash flows from investing activities:
Additions to oil and natural gas properties	0	0	0
Additions to midstream assets	0	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
Investment in real estate	0	0
Funds held in escrow		0	0
Equity investments	0
Intercompany transfers	(860)	(367)	(1,631)
Net cash used in investing activities	(860)	(367)	(1,631)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	0	0	0
Repayment under credit facility	0	0	0
Purchase of subsidiary units by parent			(10)
Repayment on Energen's credit facility		0
Proceeds from senior notes	2,968	1,062
Repayment of senior notes	(1,250)
Premium on extinguishment of debt	(44)
Proceeds from joint venture	0
Debt issuance costs	0	(14)	(8)
Public offering costs	0	0	0
Proceeds from public offerings	0	0	0
Contributions to subsidiaries		(1)
Distribution to parent		155
Distributions from subsidiary	860	(696)	90
Proceeds from exercise of stock options	9
Repurchased for tax withholdings	(13)	(14)
Repurchased as part of share buyback	593
Dividends to stockholders	(112)	(37)
Distributions to non-controlling interest	0	0	0
Intercompany transfers	0	0
Net cash (used in) provided by financing activities	1,825	455	72
Net increase (decrease) in cash and cash equivalents	9	30	(1,588)
Cash and cash equivalents at beginning of period	84	54	1,642
Cash and cash equivalents at end of period	93	84	54
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	1,433	1,224	768
Cash flows from investing activities:
Additions to oil and natural gas properties	(2,038)	(1,461)	(790)
Additions to midstream assets	(38)	(21)	0
Purchase of other property, equipment and land	0	(7)	(22)
Acquisition of leasehold interests	(360)	(1,371)	(1,961)
Acquisition of mineral interests	0	0	(63)
Acquisition of midstream assets			0
Proceeds from sale of assets	118	79	66
Investment in real estate	0	0
Funds held in escrow		27	(27)
Equity investments	0
Intercompany transfers	0	989	1,631
Net cash used in investing activities	(2,318)	(1,765)	(1,166)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	1,292	1,960	475
Repayment under credit facility	(2,769)	(867)	(78)
Purchase of subsidiary units by parent			0
Repayment on Energen's credit facility		0
Proceeds from senior notes	0	0
Repayment of senior notes	0
Premium on extinguishment of debt	0
Proceeds from joint venture	0
Debt issuance costs	0	0	1
Public offering costs	0	0	0
Proceeds from public offerings	0	0	0
Contributions to subsidiaries		0
Distribution to parent		0
Distributions from subsidiary	0	0	0
Proceeds from exercise of stock options	0
Repurchased for tax withholdings	0	0
Repurchased as part of share buyback	0
Dividends to stockholders	0	0
Distributions to non-controlling interest	0	0	0
Intercompany transfers	2,360	(550)
Net cash (used in) provided by financing activities	883	543	398
Net increase (decrease) in cash and cash equivalents	(2)	2	0
Cash and cash equivalents at beginning of period	2	0	0
Cash and cash equivalents at end of period	0	2	0
Non-Guarantor Subsidiaries | Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	2,257	399	150
Cash flows from investing activities:
Additions to oil and natural gas properties	(639)	0	(3)
Additions to midstream assets	(206)	(183)	(68)
Purchase of other property, equipment and land	(5)	0	(1)
Acquisition of leasehold interests	(83)	0	0
Acquisition of mineral interests	(523)	(440)	(344)
Acquisition of midstream assets			(50)
Proceeds from sale of assets	372	1	0
Investment in real estate	(1)	(111)
Funds held in escrow		(16)	131
Equity investments	(485)
Intercompany transfers	860	(622)	0
Net cash used in investing activities	(710)	(1,371)	(335)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	1,058	692	279
Repayment under credit facility	(949)	(375)	(306)
Purchase of subsidiary units by parent			0
Repayment on Energen's credit facility		(559)
Proceeds from senior notes	501	0
Repayment of senior notes	0
Premium on extinguishment of debt	0
Proceeds from joint venture	39
Debt issuance costs	(18)	(11)	(2)
Public offering costs	(41)	(3)	(1)
Proceeds from public offerings	1,106	305	380
Contributions to subsidiaries		(1)
Distribution to parent		0
Distributions from subsidiary	0	696	(1)
Proceeds from exercise of stock options	0
Repurchased for tax withholdings	0	0
Repurchased as part of share buyback	0
Dividends to stockholders	0	0
Distributions to non-controlling interest	(982)	(253)	(130)
Intercompany transfers	(2,360)	552
Net cash (used in) provided by financing activities	(1,646)	1,043	219
Net increase (decrease) in cash and cash equivalents	(99)	71	34
Cash and cash equivalents at beginning of period	129	58	24
Cash and cash equivalents at end of period	$ 30	$ 129	$ 58

SUPPLEMENTAL INFORMATION ON O_3

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Capitalized Oil and Natural Gas Costs (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Oil and natural gas properties:
Proved properties	$ 16,575	$ 12,629
Unproved properties	9,207	9,670
Total oil and natural gas properties	25,782	22,299
Accumulated depreciation, depletion, amortization	(2,995)	(1,599)
Accumulated impairment	(1,934)	(1,144)
Oil and natural gas properties, net	$ 20,853	$ 19,556

SUPPLEMENTAL INFORMATION ON O_4

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Costs Incurred in Crude Oil and Natural Gas Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Acquisition costs:
Proved properties	$ 194	$ 5,665	$ 455
Unproved properties	418	5,818	2,692
Development costs	956	493	145
Exploration costs	1,915	1,090	780
Total	$ 3,483	$ 13,066	$ 4,072

SUPPLEMENTAL INFORMATION ON O_5

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Results of Operations for Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil, natural gas and natural gas liquid sales	$ 3,887	$ 2,130	$ 1,186
Lease operating expenses	(490)	(205)	(127)
Production and ad valorem taxes	(248)	(133)	(74)
Gathering and transportation	(88)	(26)	(13)
Depreciation, depletion, and amortization	(1,447)	(595)	(321)
Impairment	(790)	0	0
Asset retirement obligation accretion expense	(7)	(2)	(1)
Income tax benefit (expense)	(89)	(241)	20
Results of operations	$ 728	$ 928	$ 670

SUPPLEMENTAL INFORMATION ON O_6

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Oil and Natural Gas Reserves (Details) bbl in Thousands, Mcf in Thousands	12 Months Ended
	Dec. 31, 2019Mcfbbl	Dec. 31, 2018Mcfbbl	Dec. 31, 2017Mcfbbl	Dec. 31, 2016Mcfbbl
Oil
Proved Developed and Undeveloped Reserves (Volume)
Beginning of the period	626,936	233,181	139,174
Extensions and discoveries	256,569	143,256	99,980
Revisions of previous estimates	(84,789)	3,689	(7,715)
Purchase of reserves in place	13,974	281,333	24,322
Divestitures	(33,269)	(156)	(1,163)
Production	(68,518)	(34,367)	(21,417)
End of the period	710,903	626,936	233,181
Proved Developed Reserves (Volume)	457,083	403,051	141,246	79,457
Proved Undeveloped Reserve (Volume)	253,820	223,885	91,935	59,717
Natural Gas Liquids
Proved Developed and Undeveloped Reserves (Volume)
Beginning of the period	190,291	54,609	37,134
Extensions and discoveries	66,572	33,152	20,825
Revisions of previous estimates	(8,166)	11,138	(1,466)
Purchase of reserves in place	3,813	98,865	2,633
Divestitures	(3,809)	(8)	(461)
Production	(18,498)	(7,465)	(4,056)
End of the period	230,203	190,291	54,609
Proved Developed Reserves (Volume)	165,173	125,509	35,412	22,080
Proved Undeveloped Reserve (Volume)	65,030	64,782	19,198	15,054
Natural Gas
Proved Developed and Undeveloped Reserves (Volume)
Beginning of the period | Mcf	1,048,649	285,369	174,896
Extensions and discoveries | Mcf	318,874	154,088	109,032
Revisions of previous estimates | Mcf	(149,657)	3,642	(10,065)
Purchase of reserves in place | Mcf	19,830	640,761	34,640
Divestitures | Mcf	(21,272)	(543)	(2,474)
Production | Mcf	(97,613)	(34,668)	(20,660)
End of the period | Mcf	1,118,811	1,048,649	285,369
Proved Developed Reserves (Volume) | Mcf	824,760	705,084	190,740	105,399
Proved Undeveloped Reserve (Volume) | Mcf	294,051	343,565	94,629	69,497

SUPPLEMENTAL INFORMATION ON O_7

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Narrative (Details) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019USD ($)Boe	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)Boe	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2019USD ($)BoeMBoewellSWD	Dec. 31, 2018USD ($)BoeMBoeSWD	Dec. 31, 2017USD ($)Boe
Oil and Gas, Delivery Commitment [Line Items]
Provision for income taxes | $	$ (124)	$ 102	$ 102	$ (33)	$ 85	$ 43	$ (7)	$ 47	$ 47	$ 168	$ (20)
Revised income tax expense | $									$ (89)	$ (241)	$ 20
Extensions and discoveries (in MBOE)									376,287,000	202,089,000	138,977,000
Oil and gas development well drilled net productive									283	135	102
Proved undeveloped reserves number of wells added									291	138	87
Percentage of extension volumes attributable to subsidiary									5.00%	10.00%	8.00%
Revision of previous estimate as result of positive technical and performance revisions (in MBOE)										14,218,000	8,308,000
Revisions due to higher pricing (in MBOE) | MBoe										6,032
Revisions from PUD reclassifications due to timing									(117,898,000)	(4,815,000)	2,550,000
Increase due to purchase of reserves									21,092,000	486,992
Purchase of working interest in Reserves									10,939,000	477,686
Proved undeveloped reserves (energy)	367,859,000				345,928,000				367,859,000	345,928,000
Proved undeveloped reserves, increase (energy)									21,931,000
Extensions and discoveries, working interest (in MBOE) | MBoe									213,909
Number of horizontal wells developed, working interest gross | well									291
Number of horizontal wells developed, working interest | well									262
Proved undeveloped reserves extensions and discoveries mineral interest | MBoe									7,591
Number of horizontal wells developed, mineral interest | well									97
Undeveloped reserves transferred to developed									120,920,000
Number of horizontal wells developed working interest gross | well									135
Number of horizontal wells developed working interest net | well									119
Number of horizontal wells developed mineral interest gross | well									79
Number of horizontal wells developed working and mineral interest | well									75
Revisions									(77,519,000)
Revisions from PUD reclassifications due to refinement									67,114,000
Revisions from PUD reclassifications due to lower benchmark commodity prices									10,405,000
Proved undeveloped reserves, planned development period									5 years
Capital expenditures towards development of proved undeveloped reserves | $									$ 956	$ 493	$ 145
Delaware Basin
Oil and Gas, Delivery Commitment [Line Items]
Percentage of total purchase volumes											87.00%
Number of horizontal wells developed working interest | well									64
Viper Energy Partners LP
Oil and Gas, Delivery Commitment [Line Items]
Royalty purchases									10,153,000	9,306
Percentage of total purchase volumes											10.00%

SUPPLEMENTAL INFORMATION ON O_8

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Proved Undeveloped Reserves (Details) Boe in Thousands	12 Months Ended
	Dec. 31, 2019Boe
Proved Undeveloped Reserves (Energy)
Beginning proved undeveloped reserves at December 31, 2018	345,928
Undeveloped reserves transferred to developed	(120,920)
Revisions	(77,519)
Net purchases	4,542
Divestitures	(5,672)
Extensions and discoveries	221,500
Ending proved undeveloped reserves at December 31, 2019	367,859

SUPPLEMENTAL INFORMATION ON O_9

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 Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Future cash inflows	$ 40,681	$ 43,578	$ 12,922
Future development costs	(3,809)	(3,560)	(1,124)
Future production costs	(9,319)	(7,727)	(2,995)
Future production taxes	(2,905)	(2,935)	(929)
Future income tax expenses	(2,635)	(3,913)	(84)
Future net cash flows	22,013	25,443	7,790
10% discount to reflect timing of cash flows	(11,829)	(13,767)	(4,033)
Standardized measure of discounted future net cash flows	$ 10,184	$ 11,676	$ 3,757	$ 1,711

SUPPLEMENTAL INFORMATION ON _10

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, 2019$ / Mcf$ / bbl	Dec. 31, 2018$ / Mcf$ / bbl	Dec. 31, 2017$ / Mcf$ / bbl
Oil
Oil and Gas, Delivery Commitment [Line Items]
Average sales prices (dollars per unit)	51.88	59.63	48.03
Natural Gas
Oil and Gas, Delivery Commitment [Line Items]
Average sales prices (dollars per unit) | $ / Mcf	0.18	1.47	2.06
Natural Gas Liquids
Oil and Gas, Delivery Commitment [Line Items]
Average sales prices (dollars per unit) | $ / bbl	15.65	24.43	20.79

SUPPLEMENTAL INFORMATION ON _11

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows at the beginning of the period	$ 11,676	$ 3,757	$ 1,711
Sales of oil and natural gas, net of production costs	(3,334)	(1,786)	(986)
Acquisition of reserves	309	5,520	439
Divestiture of reserves	(500)	(2)	(11)
Extensions and discoveries, net of future development costs	4,004	3,287	1,792
Previously estimated development costs incurred during the period	120	535	190
Net changes in prices and production costs	831	1,805	578
Changes in estimated future development costs	(3,190)	(81)	(53)
Revisions of previous quantity estimates	(1,242)	271	(99)
Accretion of discount	1,344	380	174
Net change in income taxes	693	(1,728)	(9)
Net changes in timing of production and other	(527)	(282)	31
Standardized measure of discounted future net cash flows at the end of the period	$ 10,184	$ 11,676	$ 3,757

QUARTERLY FINANCIAL DATA (Una_3

QUARTERLY FINANCIAL DATA (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 1,104	$ 975	$ 1,021	$ 864	$ 633	$ 537	$ 527	$ 479	$ 3,964	$ 2,176	$ 1,205
Income (loss) from operations	(384)	349	411	319	195	268	281	267	695	1,011	605
Income tax expense (benefit)	(124)	102	102	(33)	85	43	(7)	47	47	168	(20)
Net income (loss)	(472)	388	356	43	306	160	301	178	315	945	517
Net income attributable to non-controlling interest	15	20	7	33	(1)	3	82	15	75	99	35
Net income (loss) attributable to Diamondback Energy, Inc.	$ (487)	$ 368	$ 349	$ 10	$ 307	$ 157	$ 219	$ 163	$ 240	$ 846	$ 482
Earnings per common share
Basic (in dollars per share)	$ (3.04)	$ 2.27	$ 2.12	$ 0.06	$ 2.50	$ 1.59	$ 2.22	$ 1.65	$ 1.47	$ 8.09	$ 4.95
Diluted (in dollars per share)	$ (3.04)	$ 2.26	$ 2.11	$ 0.06	$ 2.50	$ 1.59	$ 2.22	$ 1.65	$ 1.47	$ 8.06	$ 4.94

Uncategorized Items - diamondba

Label	Element	Value
Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (9,000,000)
Noncontrolling Interest [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (7,000,000)