0001539838-21-000015 | 10-K | XBRL Viewer

ASSET RETIREMENT OBLIGATIONS (Tables)

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligation [Abstract]

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


	Year Ended December 31,
	2020		2019
	(in millions)
Asset retirement obligations, beginning of period	$	94	$	136
Additional liabilities incurred	13		8
Liabilities acquired	2		4
Liabilities settled and divested	(8)		(61)
Accretion expense	7		7
Revisions in estimated liabilities	1		—
Asset retirement obligations, end of period	109		94
Less: current portion(1)	1		—
Asset retirement obligations - long-term	$	108	$	94

(1) The current portion of the asset retirement obligation is included in other accrued liabilities in the Company’s consolidated balance sheets.

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 104	$ 123
Restricted cash	4	5
Accounts receivable:
Joint interest and other, net	56	186
Oil and natural gas sales, net	281	429
Inventories	33	37
Derivative instruments	1	46
Income tax receivable	100	19
Prepaid expenses and other current assets	23	24
Total current assets	602	869
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($7,493 million and $9,207 million excluded from amortization at December 31, 2020 and December 31, 2019, respectively)	27,377	25,782
Midstream assets	1,013	931
Other property, equipment and land	138	125
Accumulated depletion, depreciation, amortization and impairment	(12,314)	(5,003)
Property and equipment, net	16,214	21,835
Funds held in escrow	51	0
Equity method investments	533	479
Derivative instruments	0	7
Deferred income taxes, net	73	142
Investment in real estate, net	101	109
Other assets	45	90
Total assets	17,619	23,531
Current liabilities:
Accounts payable - trade	71	179
Accrued capital expenditures	186	475
Current maturities of long-term debt	191	0
Other accrued liabilities	302	304
Revenues and royalties payable	237	278
Derivative instruments	249	27
Total current liabilities	1,236	1,263
Long-term debt	5,624	5,371
Derivative instruments	57	0
Asset retirement obligations	108	94
Deferred income taxes	783	1,886
Other long-term liabilities	7	11
Total liabilities	7,815	8,625
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 158,088,182 and 159,002,338 issued and outstanding at December 31, 2020 and December 31, 2019, respectively	2	2
Additional paid-in capital	12,656	12,357
Retained earnings (accumulated deficit)	(3,864)	890
Total Diamondback Energy, Inc. stockholders’ equity	8,794	13,249
Non-controlling interest	1,010	1,657
Total equity	9,804	14,906
Total liabilities and equity	$ 17,619	$ 23,531

Consolidated Statement of Stockholders' Equity - USD ($) $ in Millions	Total	Impact of adoption of ASU 2016-01, net of tax	Ajax	Viper Energy Partners LP	Rattler MIdstream LP	Common Stock	Common Stock Ajax	Additional Paid-in Capital	Additional Paid-in Capital Ajax	Retained Earnings (Accumulated Deficit)	Retained Earnings (Accumulated Deficit) Impact of adoption of ASU 2016-01, net of tax	Non-Controlling Interest	Non-Controlling Interest Impact of adoption of ASU 2016-01, net of tax	Non-Controlling Interest Viper Energy Partners LP	Non-Controlling Interest Rattler MIdstream LP
Balance at beginning of period (in shares) at Dec. 31, 2017						98,167,000
Balance at beginning of period at Dec. 31, 2017	$ 5,581	$ (16)				$ 1		$ 5,291		$ (38)	$ (9)	$ 327	$ (7)
Increase (Decrease) in Stockholders' Equity
Net proceeds from issuance of common units				$ 303										$ 303
Unit-based compensation	3											3
Stock-based compensation	34							34
Common shares issued for business combination (in shares)						63,126,000	2,584,000
Common shares issued for business combination	7,070		$ 340			$ 1		7,069	$ 340
Stock options assumed in business combination	14							14
Restricted stock units assumed in business combination	52							52
Repurchased shares for tax withholding (in shares)						(140,000)
Repurchased shares for tax withholding	(14)							(14)
Distribution to non-controlling interest	(98)											(98)
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 (loss)	945									846		99
Balance at end of period (in shares) at Dec. 31, 2018						164,273,000
Balance at end of period at Dec. 31, 2018	$ 14,167					$ 2		12,936		762		467
Increase (Decrease) in Stockholders' Equity
Accounting standards update extensible list	us-gaap:AccountingStandardsUpdate201601Member
Net proceeds from issuance of common units				$ 341	$ 720									$ 341	$ 720
Unit-based compensation	$ 7											7
Stock-based compensation	57							57
Common shares issued for business combination	124											124
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 under buyback program	(598)							(598)
Distribution to non-controlling interest	(122)											(122)
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 (loss)	$ 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
Increase (Decrease) in Stockholders' Equity
Unit-based compensation	10											10
Distribution equivalent rights payments	(3)									(1)		(2)
Stock-based compensation	43							43
Repurchased shares for tax withholding (in shares)						(75,000)
Repurchased shares for tax withholding	(7)							(5)				(2)
Repurchased shares for share buyback program (in shares)						(1,280,000)
Repurchased shares under buyback program	(98)							(98)
Repurchased units under buyback programs	(39)											(39)
Distribution to non-controlling interest	(93)											(93)
Dividend paid	(236)									(236)
Exercise of stock options and awards of restricted stock, shares						441,000
Exercise of stock options and vesting of restricted stock units	1							1
Change in ownership of consolidated subsidiaries, net	(8)							358				(366)
Net income (loss)	$ (4,672)									(4,517)		(155)
Balance at end of period (in shares) at Dec. 31, 2020	158,088,182					158,088,000
Balance at end of period at Dec. 31, 2020	$ 9,804					$ 2		$ 12,656		$ (3,864)		$ 1,010

REVENUE FROM CONTRACTS WITH CUSTOMERS - Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Revenues	$ 2,756	$ 3,887	$ 2,130
Midland Basin
Disaggregation of Revenue [Line Items]
Revenues	1,587	2,325	1,528
Delaware Basin
Disaggregation of Revenue [Line Items]
Revenues	1,161	1,494	577
Other
Disaggregation of Revenue [Line Items]
Revenues	8	68	25
Oil sales
Disaggregation of Revenue [Line Items]
Revenues	2,410	3,554	1,879
Oil sales \| Midland Basin
Disaggregation of Revenue [Line Items]
Revenues	1,393	2,139	1,350
Oil sales \| Delaware Basin
Disaggregation of Revenue [Line Items]
Revenues	1,011	1,351	508
Oil sales \| Other
Disaggregation of Revenue [Line Items]
Revenues	6	64	21
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues	107	66	61
Natural gas sales \| Midland Basin
Disaggregation of Revenue [Line Items]
Revenues	56	32	38
Natural gas sales \| Delaware Basin
Disaggregation of Revenue [Line Items]
Revenues	50	33	22
Natural gas sales \| Other
Disaggregation of Revenue [Line Items]
Revenues	1	1	1
Natural gas liquid sales
Disaggregation of Revenue [Line Items]
Revenues	239	267	190
Natural gas liquid sales \| Midland Basin
Disaggregation of Revenue [Line Items]
Revenues	138	154	140
Natural gas liquid sales \| Delaware Basin
Disaggregation of Revenue [Line Items]
Revenues	100	110	47
Natural gas liquid sales \| Other
Disaggregation of Revenue [Line Items]
Revenues	$ 1	$ 3	$ 3

- Definition

Amount, excluding tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value added and excise.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8906-108599

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9031-108599

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9038-108599

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 4
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130543-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8736-108599

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8736-108599

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9054-108599

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130545-203045

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 924
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB Topic 11.L)
-URI http://asc.fasb.org/extlink&oid=6472922&loc=d3e499488-122856

+ Details

DEBT - Viper's Credit Agreement (Details)		12 Months Ended
DEBT - Viper's Credit Agreement (Details)	Jul. 20, 2018 USD ($) redeterminations	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 5,815,000,000	$ 5,371,000,000
Viper revolving credit facility(1)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000,000,000.0
Current borrowing base		580,000,000
Number of additional redeterminations that may be requested \| redeterminations	3
Period of redeterminations	12 months
Remaining borrowing capacity		$ 496,000,000
Weighted average interest rate		2.20%	4.51%	4.37%
Issuance of unsecured debt		$ 1,000,000,000.0
Financial covenant, reduction of borrowing base (percentage)		25.00%
Viper revolving credit facility(1) \| Federal Funds Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate		0.50%
Viper revolving credit facility(1) \| LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.00%
Viper revolving credit facility(1) \| Minimum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base		0.375%
Viper revolving credit facility(1) \| Minimum \| Base Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate		0.75%
Viper revolving credit facility(1) \| Minimum \| LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.75%
Viper revolving credit facility(1) \| Maximum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base		0.50%
Viper revolving credit facility(1) \| Maximum \| Base Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate		1.75%
Viper revolving credit facility(1) \| Maximum \| LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate		2.75%

DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION	12 Months Ended
DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION	Dec. 31, 2020
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 currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. The wholly-owned subsidiaries of Diamondback, as of December 31, 2020, 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 subsidiaries Tall City Towers LLC, a Delaware limited liability company (“Tall City”), Rattler Ajax Processing LLC, a Delaware limited liability company, Rattler OMOG LLC, a Delaware limited liability company, Energen’s wholly owned subsidiaries Energen Resources Corporation, an Alabama corporation (“Energen Resources”), EGN Services, Inc., an Alabama corporation and Bohemia Merger Sub Inc., a Delaware 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 and Rattler are consolidated in the financial statements of the Company. As of December 31, 2020, the Company owned approximately 58% of Viper’s total units outstanding. The Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the general partner of Viper. As of December 31, 2020, the Company owned approximately 72% of Rattler’s total units outstanding. The Company’s wholly owned subsidiary, Rattler Midstream GP LLC, is the general partner of Rattler. The results of operations attributable to the non-controlling interest in Viper and Rattler are presented within equity and net income and are shown separately from the Company’s equity and net income attributable to the Company. The Company reports its operations in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which includes midstream services and real estate operations. Reclassifications Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.

EQUITY METHOD INVESTMENTS - Narrative (Details) bbl in Thousands, Mcf in Thousands	12 Months Ended
	Dec. 31, 2020 USD ($) bbl Mcf	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 20, 2019 Mcf mi	Nov. 07, 2019	Oct. 01, 2019	Jul. 30, 2019	Mar. 29, 2019 USD ($)	Feb. 15, 2019	Feb. 01, 2019
Schedule of Equity Method Investments
Equity method investment impairment \| $	$ 0	$ 0	$ 0
Rattler LLC \| EPIC Crude Holdings, LP
Schedule of Equity Method Investments
Ownership interest	10.00%									10.00%
Rattler LLC \| Gray Oak Pipeline, LLC
Schedule of Equity Method Investments
Ownership interest	10.00%								10.00%
Rattler LLC \| OMOG JV LLC
Schedule of Equity Method Investments
Ownership interest	60.00%					60.00%
Rattler LLC \| Amarillo Rattler, LLC
Schedule of Equity Method Investments
Ownership interest	50.00%			50.00%
Gas gathering and cryogenic processing system capacity (in Mcf/d)	30
Rattler LLC \| Wink to Webster Pipeline LLC
Schedule of Equity Method Investments
Ownership interest	4.00%						4.00%
Pipeline transportation capacity \| bbl	1,500
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, LLC
Schedule of Equity Method Investments
Equity method investment promissory note \| $								$ 123,000,000
Stated interest rate								2.52%
Dawson, Martin and Andrews Counties, Texas \| Rattler LLC \| Amarillo Rattler, LLC
Schedule of Equity Method Investments
Gas gathering and cryogenic processing system capacity (in Mcf/d)				40
Dawson, Martin and Andrews Counties, Texas \| Amarillo Rattler, LLC
Schedule of Equity Method Investments
Distance of gathering and regional transportation pipelines (over) (in miles) \| mi				84
Martin County, Texas \| Rattler LLC \| Amarillo Rattler, LLC
Schedule of Equity Method Investments
Gas gathering and cryogenic processing system capacity (in Mcf/d)				60

DEBT - Alliance with Obsidian Resources, L.L.C. (Details) - DrillCo Agreement $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)	Sep. 10, 2018 USD ($)
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	$ 79
Wells drilled and completed under joint venture agreement	15
CEMOF
Debt Instrument [Line Items]
Interest rate upon reaching final internal rate of return		15.00%

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Impairment of long-lived assets	$ 0	$ 0	$ 0
Equity method investment impairment	$ 0	$ 0	$ 0
Other Property and Equipment, Net \| Minimum
Debt Instrument [Line Items]
Estimated useful life of property and equipment	3 years
Other Property and Equipment, Net \| Maximum
Debt Instrument [Line Items]
Estimated useful life of property and equipment	15 years

PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

PROPERTY AND EQUIPMENT

Property and equipment includes the following:


	December 31,
	2020		2019
	(in millions)
Oil and natural gas properties:
Subject to depletion	$	19,884	$	16,575
Not subject to depletion	7,493		9,207
Gross oil and natural gas properties	27,377		25,782
Accumulated depletion	(4,237)		(2,995)
Accumulated impairment	(7,954)		(1,934)
Oil and natural gas properties, net	15,186		20,853
Midstream assets	1,013		931
Other property, equipment and land	138		125
Accumulated depreciation	(123)		(74)
Total property and equipment, net	$	16,214	$	21,835

Balance of costs not subject to depletion:
Incurred in 2020	$	71
Incurred in 2019	421
Incurred in 2018	5,090
Incurred in 2017	1,682
Incurred in 2016	229
Total not subject to depletion	$	7,493

Capitalized internal costs were approximately $53 million, $49 million and $29 million for the years ended December 31, 2020, 2019 and 2018, 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 five years.

As a result of the decline in commodity prices during 2020, the Company recorded a non-cash ceiling test impairment for the year ended December 31, 2020 of $6.0 billion which is included in accumulated depletion, depreciation, amortization and impairment on the consolidated balance sheet. 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. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, the Company may have material write downs in subsequent quarters. The Company also recorded a non-cash ceiling test impairment on proved oil and natural gas properties of $790 million for the year ended December 31, 2019. No such impairment was recorded for the year ended December 31, 2018. Given the rate of change impacting the oil and natural gas industry described above, it is possible that circumstances requiring additional impairment testing will occur in future interim periods, which could result in potentially material impairment charges being recorded.

At December 31, 2020, there were $85 million in exploration costs and development costs and $51 million in capitalized interest that are not subject to depletion. At December 31, 2019, there were $228 million in exploration costs and development costs and $118 million capitalized interest that are not subject to depletion.

EQUITY METHOD INVESTMENTS - Investments (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 20, 2019	Oct. 01, 2019	Jul. 30, 2019	Feb. 15, 2019	Feb. 01, 2019
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 533	$ 479
Rattler LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 533	479
Rattler LLC \| EPIC Crude Holdings, LP
Schedule of Equity Method Investments [Line Items]
Ownership interest	10.00%						10.00%
Equity method investments	$ 121	110
Rattler LLC \| Gray Oak Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest	10.00%					10.00%
Equity method investments	$ 130	115
Rattler LLC \| Wink to Webster Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest	4.00%				4.00%
Equity method investments	$ 83	34
Rattler LLC \| OMOG JV LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest	60.00%			60.00%
Equity method investments	$ 194	219
Rattler LLC \| Amarillo Rattler, LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest	50.00%		50.00%
Equity method investments	$ 5	$ 1

EQUITY-BASED COMPENSATION - Restricted Stock Units (Details) - Equity Plan - Restricted Stock Units (RSUs)	12 Months Ended
	Dec. 31, 2020 $ / shares shares
Restricted Stock Awards & Units
Unvested, beginning balance (in shares) \| shares	505,867
Granted (in shares) \| shares	921,730
Vested (in shares) \| shares	(283,330)
Forfeited (in shares) \| shares	(30,787)
Unvested, ending balance (in shares) \| shares	1,113,480
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Unvested, beginning balance (in dollars per share) \| $ / shares	$ 96.01
Granted (in dollars per share) \| $ / shares	35.38
Vested (in dollars per share) \| $ / shares	86.81
Forfeited (in dollars per share) \| $ / shares	80.94
Unvested, ending balance (in dollars per share) \| $ / shares	$ 48.58

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, 2020 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregated fair value	$ 9
Share based award not recognized	$ 30
Unrecognized compensation cost, expected period of recognition	3 years 2 months 12 days

CAPITAL STOCK AND EARNINGS PER SHARE - Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Basic:
Net income (loss) attributable to common stock	$ (4,517)	$ 240	$ 846
Basic weighted average common units outstanding (in shares)	157,976,000	163,493,000	104,622,000
Effect of dilutive securities:
Potential common shares issuable (in shares)	0	350,000	307,000
Diluted:
Diluted weighted average common shares outstanding (in shares)	157,976,000	163,843,000	104,929,000
Basic net income attributable to common stock (in dollars per share)	$ (28.59)	$ 1.47	$ 8.09
Diluted net income attributable to common stock (in dollars per share)	$ (28.59)	$ 1.47	$ 8.06
Antidilutive securities, restricted stock units (in shares)	696,223

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, 2020 $ / bbl $ / Mcf	Dec. 31, 2019 $ / bbl $ / Mcf	Dec. 31, 2018 $ / bbl $ / Mcf
OIL
Oil and Gas, Delivery Commitment [Line Items]
Average sales prices (dollars per unit)	38.06	51.88	59.63
Natural Gas
Oil and Gas, Delivery Commitment [Line Items]
Average sales prices (dollars per unit) \| $ / Mcf	0.09	0.18	1.47
Natural Gas Liquids
Oil and Gas, Delivery Commitment [Line Items]
Average sales prices (dollars per unit)	10.83	15.65	24.43

REVENUE FROM CONTRACTS WITH CUSTOMERS - Concentrations (Details) - Customer Concentration Risk - Revenue Benchmark	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Vitol Midstream
Concentration Risk [Line Items]
Concentration risk, percentage	26.00%	15.00%
Shell Trading US Company
Concentration Risk [Line Items]
Concentration risk, percentage	22.00%	27.00%	26.00%
Plains Marketing LP
Concentration Risk [Line Items]
Concentration risk, percentage	20.00%	23.00%
Trafigura Trading LLC
Concentration Risk [Line Items]
Concentration risk, percentage	11.00%
Koch Supply & Trading LP
Concentration Risk [Line Items]
Concentration risk, percentage			15.00%
Occidental Energy Marketing Inc.
Concentration Risk [Line Items]
Concentration risk, percentage			11.00%

DEBT - Schedule of Long-term Debt Maturities (Details) $ in Millions	Dec. 31, 2020 USD ($)
Debt Disclosure [Abstract]
2021	$ 191
2022	127
2023	0
2024	1,079
2025	1,800
Thereafter	2,659
Total debt, net	$ 5,856

COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

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 crude oil and natural gas industry. 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’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. 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.

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, 2020:


Year Ending December 31,	Transportation Commitments(1)		Sand Supply Agreement(2)		Produced Water Disposal Commitments(3)
	(in millions)
2021	$	60	$	18	$	5
2022	60		18		5
2023	51		18		5
2024	48		18		5
2025	47		18		5
Thereafter	133		5		31
Total	$	399	$	95	$	56

(1)The Company has committed to transport gross quantities of crude oil on various pipelines under a variety of contracts including throughput and take-or-pay agreements. The Company’s failure to purchase the minimum level of quantities would require it to pay shortfall fees up to the amount of the original monthly commitment amounts included in the table above.

(2)The Company has committed to purchase minimum quantities of sand for use in its drilling operations. Our failure to purchase the minimum level of quantities would require us to pay shortfall fees up to the commitment amounts included in the table above.

(3)Rattler entered into a minimum volume commitment to purchase produced water disposal services under a 14 year agreement beginning in 2021.

At December 31, 2020, the Company’s delivery commitments covered the following gross volumes of oil:


Year Ending December 31,			Oil Volume Commitments (Bbl/d)
2021			175,000
2022			175,000
2023			175,000
2024			125,000
2025			125,000
Thereafter			400,000
Total			1,175,000

SUBSEQUENT EVENTS (Tables)

12 Months Ended

Dec. 31, 2020

Subsequent Events [Abstract]

Schedule of derivative instruments

As of December 31, 2020, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed:


					Swaps		Collars
Settlement Month	Settlement Year	Type of Contract	Bbls/Mmbtu/Gallons Per Day	Index	Weighted Average Differential	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Ceiling Price
OIL
Jan. - Mar.	2021	Costless Collars	37,000	WTI Cushing	$—	$—	$34.95	$45.17
Apr. - June	2021	Costless Collars	15,000	WTI Cushing	$—	$—	$33.00	$45.33
July - Dec.	2021	Costless Collars	10,000	WTI Cushing	$—	$—	$30.00	$43.05
Jan. - June	2021	Roll Hedge(2)	12,000	WTI	$(0.07)	$—	$—	$—
Jan. - Mar.	2021	Swaps	5,000	WTI	$—	$45.46	$—	$—
Apr. - June	2021	Swaps	2,000	WTI	$—	$47.35	$—	$—
Jan. - June	2021	Basis Swap	8,000	WTI Midland(1)	$0.52	$—	$—	$—
Jan. - Dec.	2021	Swaps	5,000	WTI Houston Argus	$—	$37.78	$—	$—
Jan. - Dec.	2021	Swaps	5,000	Brent	$—	$41.62	$—	$—
Jan. - Mar.	2021	Costless Collars	82,000	Brent	$—	$—	$39.04	$48.51
Apr. - June	2021	Costless Collars	80,000	Brent	$—	$—	$39.26	$48.62
Jul. - Dec.	2021	Costless Collars	60,000	Brent	$—	$—	$39.43	$48.12
Jul. - Dec.	2021	Swaptions	5,000	Brent	$—	$51.00	$—	$—

NATURAL GAS
Jan. - Dec.	2021	Swaps	200,000	Henry Hub	$—	$2.65	$—	$—
Jan. - Dec.	2021	Basis Swaps	230,000	Waha Hub(1)	$(0.69)	$—	$—	$—
Jan. - Dec.	2022	Basis Swaps	100,000	Waha Hub(1)	$(0.42)	$—	$—	$—

(1) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.

(2) The Company has rolling hedge basis swaps for the differential between the NYMEX prices between the calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, oil price for the notional volumes covered by the rolling hedge basis swap contracts.

Settlement Month

Settlement Year

Type of Contract

Bbls/Mcf Per Day

Index

Put Price

OIL

Jan. - Dec.

2022

Option

5,000

Brent

$35.00

The Company currently uses interest rate swaps to reduce the Company’s exposure to variable rate interest payments associated with the Company’s revolving credit facility. The interest rate swaps have not been designated as hedging instruments and as a result, the Company recognizes all changes in fair value immediately in earnings.


Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.692	%
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.8361	%
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.852	%
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.722	%


					Swaps		Collars
Settlement Month	Settlement Year	Type of Contract	Bbls/Mmbtu Per Day	Index	Weighted Average Differential	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Ceiling Price
OIL
July - Sep.	2021	Costless Collar	2,000	WTI	$—	$—	$45.00	$52.30
Oct. - Dec.	2021	Costless Collar	9,000	WTI	$—	$—	$45.00	$59.22
July - Sep.	2021	Costless Collar	5,000	WTI Houston Argus	$—	$—	$45.00	$57.90
Apr. - Sep.	2021	Costless Collar	2,000	IPE Brent	$—	$—	$45.00	$57.72
Oct. - Dec.	2021	Costless Collar	4,000	IPE Brent	$—	$—	$45.00	$60.64
Mar. - Dec.	2021	Roll Hedge(2)	25,000	WTI	$0.32	$—	$—	$—
Mar. - Dec.	2021	Swap	20,000	Henry Hub	$—	$2.95	$—	$—
Jan. - June	2021	Basis Swap	15,000	WTI Midland(1)	$0.95	$—	$—	$—
July - Dec.	2021	Basis Swap	18,000	WTI Midland(1)	$0.93	$—	$—	$—
Jan. - Mar.	2022	Costless Collar	18,000	IPE Brent	$—	$—	$45.00	$61.35
Apr. - Dec.	2022	Costless Collar	2,000	IPE Brent	$—	$—	$45.00	$60.00
NATURAL GAS
Apr. - Dec.	2021	Basis Swap	20,000	Waha Hub(1)	$(0.255)	$—	$—	$—
Jan. - Dec.	2022	Basis Swap	30,000	Waha Hub(1)	$(0.34)	$—	$—	$—
NATURAL GAS LIQUIDS
Feb. - Dec.	2021	Swap	84,000	Mont Belvieu	$—	$0.70	$—	$—

(1) The Company has fixed price basis swaps for the spread between the WTI Midland crude oil price and the NYMEX WTI crude oil price as well as the spread between the Waha Hub natural gas price and the Henry Hub natural gas price. The weighted average differential represents the amount of reduction to Cushing, Oklahoma oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.

(2) The Company has rolling hedge basis swaps for the differential between the NYMEX prices between the calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to Cushing, Oklahoma oil price for the notional volumes covered by the rolling hedge basis swap contracts.

Interest Rate Swaps

The following table presents the interest rate swap contracts terminated by the Company between January 1, 2021 and February 19, 2021:


Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.8361	%
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.852	%

- Definition

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

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5624163-113959

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5580258-113959

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=121590274&loc=d3e41620-113959

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5579245-113959

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=121590274&loc=d3e41638-113959

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=121590274&loc=d3e41678-113959

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=121590274&loc=d3e41641-113959

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5624171-113959

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=121590274&loc=SL5579240-113959

+ Details

EQUITY METHOD INVESTMENTS - Income (Loss) of Equity Method Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments	$ (10)	$ (6)	$ 0
EPIC Crude Holdings, LP
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments	(9)	(6)
Gray Oak Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments	10	1
Wink to Webster Pipeline LLC
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments	(2)	(1)
OMOG JV LLC
Schedule of Equity Method Investments [Line Items]
Income (loss) from equity investments	$ (9)	$ 0

FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

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 in Note 2—Summary of Significant Accounting Policies.

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 investment. Viper measured its previously outstanding investment, which was included in other assets on the consolidated balance sheet at December 31, 2019, utilizing the fair value option, and as such the investment was classified as Level 1 in the fair value hierarchy. The fair values of the Company’s derivative contracts 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 (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2020 and December 31, 2019. The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates.


	As of December 31, 2020
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(in millions)
Assets:
Current:

Derivative Instruments	$	—	$	43	$	—	$	43	$	(42)	$	1

Non-current:

Derivative Instruments	$	—	$	187	$	—	$	187	$	(187)	$	—

Liabilities:
Current:
Derivative Instruments	$	—	$	291	$	—	$	291	$	(42)	$	249

Non-current:
Derivative Instruments	$	—	$	244	$	—	$	244	$	(187)	$	57


	As of December 31, 2019
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(in millions)
Assets:
Current:

Derivative Instruments	$	—	$	64	$	—	$	64	$	(18)	$	46

Non-current:
Investment	$	19	$	—	$	—	$	19	$	—	$	19
Derivative Instruments	$	—	$	7	$	—	$	7	$	—	$	7

Liabilities:
Current:
Derivative Instruments	$	—	$	45	$	—	$	45	$	(18)	$	27

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, 2020				December 31, 2019
	Carrying				Carrying
	Value(1)		Fair Value		Value(1)		Fair Value
	(in millions)
Debt:
Revolving credit facility	$	23	$	23	$	13	$	13
4.625% Notes due 2021	$	191	$	193	$	399	$	411
7.320% Medium-term Notes, Series A, due 2022	$	21	$	22	$	21	$	22
2.875% Senior Notes due 2024	$	993	$	1,053	$	992	$	1,012
4.750% Senior Notes due 2025	$	496	$	565	$	—	$	—
5.375% Senior Notes due 2025	$	799	$	824	$	799	$	840
3.250% Senior Notes due 2026	$	793	$	857	$	792	$	812
7.350% Medium-term Notes, Series A, due 2027	$	—	$	—	$	11	$	12
7.125% Medium-term Notes, Series B, due 2028	$	107	$	119	$	108	$	116
3.500% Senior Notes due 2029	$	1,187	$	1,286	$	1,186	$	1,226
Viper revolving credit facility	$	84	$	84	$	97	$	97
Viper's 5.375% Senior Notes due 2027	$	472	$	501	$	490	$	521
Rattler revolving credit facility	$	79	$	79	$	424	$	424
Rattler’s 5.625% Senior Notes due 2025	$	491	$	528	$	—	$	—
DrillCo Agreement	$	79	$	79	$	39	$	39

(1)The carrying value includes associated deferred loan costs and any remaining discount or premium.

The fair values of the revolving credit facility, the Viper credit agreement and the Rattler credit agreement approximate their carrying values 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 values of the outstanding notes were determined using the December 31, 2020 quoted market prices, a Level 1 classification in the fair value hierarchy.

Fair Value of Financial AssetsThe carrying amount of cash and cash equivalents, receivables, funds held for escrow, prepaid expenses and other current assets, payables and other accrued liabilities approximate their fair value because of the short-term nature of the instruments.

- Definition

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

+ References + Details

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties, Other Property, Equipment and Land (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) $ / Boe	Dec. 31, 2019 USD ($) $ / Boe	Dec. 31, 2018 USD ($) $ / Boe
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization excluding amortization of financing costs	$ 1,304	$ 1,447	$ 623
Estimated future net revenue discounted rate per annum	10.00%
Impairment of oil and natural gas properties	$ 6,021	$ 790	$ 0
Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Average depletion rate per barrel equivalent unit of production \| $ / Boe	11.30	13.54	12.62
Depreciation, depletion and amortization excluding amortization of financing costs	$ 1,200	$ 1,400	$ 595

ACQUISITIONS AND DIVESTITURES - 2019 Activity (Details) shares in Millions	Jul. 29, 2019 USD ($) a shares	Jul. 01, 2019 USD ($) a	May 23, 2019 USD ($) 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
Business combination, fair value of consideration	$ 497,000,000

INCOME TAXES - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns
Balance at beginning of year	$ 7	$ 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

ACQUISITIONS AND DIVESTITURES - 2018 Activity (Details) $ / shares in Units, shares in Millions, $ in Millions							1 Months Ended	12 Months Ended
	Jul. 01, 2019 USD ($)	May 23, 2019 USD ($)	Nov. 29, 2018 USD ($) a $ / shares location shares	Oct. 31, 2018 USD ($) a shares	Aug. 15, 2018 USD ($) a	Jan. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)
Business Acquisition [Line Items]
Proceeds from divestiture of certain conventional and non-core assets	$ 285	$ 37
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]
Number of shares to be issued in acquisition (in Shares) \| shares			62.8
Combined tier one acres \| a			273,000
Estimated total net horizontal permian locations \| location			7,200
Business acquisition, share price (USD per share) \| $ / shares			$ 112.00
Common stock, per share conversion basis \| $ / shares			0.6442
Business combination, consideration transferred			$ 7,100
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
Midland and Delaware Basins \| Energen
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

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019
	(In millions)
Oil and natural gas properties:
Proved properties	$	19,884	$	16,575
Unproved properties	7,493		9,207
Total oil and natural gas properties	27,377		25,782
Accumulated depletion	(4,237)		(2,995)
Accumulated impairment	(7,954)		(1,934)
Net oil and natural gas properties capitalized	$	15,186	$	20,853

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,
	2020		2019		2018
	(In millions)
Acquisition costs:
Proved properties	$	13	$	194	$	5,665
Unproved properties	106		418		5,818
Development costs	381		956		493
Exploration costs	1,098		1,915		1,090

Total	$	1,598	$	3,483	$	13,066

Schedule of changes in estimated proved reserves

The changes in estimated proved reserves are as follows:


	Oil (MBbls)	Natural Gas Liquids (MBbls)	Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves:
As of 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
Extensions and discoveries	191,009	58,410	316,035
Revisions of previous estimates	(78,244)	21,927	300,160
Purchase of reserves in place	2,124	778	3,512
Divestitures	(209)	(141)	(905)
Production	(66,182)	(21,981)	(130,549)
As of December 31, 2020	759,401	289,196	1,607,064

Proved Developed Reserves:
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
December 31, 2020	443,464	192,495	1,085,035

Proved Undeveloped Reserves:
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
December 31, 2020	315,937	96,701	522,029

The following table includes the changes in PUD reserves for 2020 (MBOE):


Beginning proved undeveloped reserves at December 31, 2019			367,859
Undeveloped reserves transferred to developed			(89,133)
Revisions			(15,742)
Purchases			964
Divestitures			(14)
Extensions and discoveries			235,709
Ending proved undeveloped reserves at December 31, 2020			499,643

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, 2020, 2019 and 2018.


	December 31,
	2020		2019		2018
	(In millions)
Future cash inflows	$	32,173	$	40,681	$	43,578
Future development costs	(3,585)		(3,809)		(3,560)
Future production costs	(10,763)		(9,319)		(7,727)
Future production taxes	(2,354)		(2,905)		(2,935)
Future income tax expenses	(727)		(2,635)		(3,913)
Future net cash flows	14,744		22,013		25,443
10% discount to reflect timing of cash flows	(7,986)		(11,829)		(13,767)
Standardized measure of discounted future net cash flows(1)	$	6,758	$	10,184	$	11,676

(1) Includes $1.0 billion, $1.3 billion, and $1.1 billion, for the years ended December 31, 2020, 2019 and 2018, respectively, attributable to the Company’s consolidated subsidiary, Viper, in which there is a 42% non-controlling interest at December 31, 2020.

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

The table below presents the unweighted arithmetic average first-day-of–the-month price for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows.


	December 31,
	2020		2019		2018


Oil (per Bbl)	$	38.06	$	51.88	$	59.63
Natural gas (per Mcf)	$	0.09	$	0.18	$	1.47
Natural gas liquids (per Bbl)	$	10.83	$	15.65	$	24.43

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,
	2020		2019		2018
	(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period	$	10,184	$	11,676	$	3,757
Sales of oil and natural gas, net of production costs	(2,225)		(3,334)		(1,786)
Acquisitions of reserves	30		309		5,520
Divestitures of reserves	(4)		(500)		(2)
Extensions and discoveries, net of future development costs	1,514		4,004		3,287
Previously estimated development costs incurred during the period	704		120		535
Net changes in prices and production costs	(5,273)		831		1,805
Changes in estimated future development costs	526		(3,190)		(81)
Revisions of previous quantity estimates	(462)		(1,242)		271
Accretion of discount	1,126		1,344		380
Net change in income taxes	807		693		(1,728)
Net changes in timing of production and other	(169)		(527)		(282)
Standardized measure of discounted future net cash flows at the end of the period	$	6,758	$	10,184	$	11,676

- Definition

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

+ References + Details

- Definition

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

+ References + Details

REAL ESTATE ASSETS (Details) - USD ($) $ in Millions		12 Months Ended
REAL ESTATE ASSETS (Details) - USD ($) $ in Millions	Jan. 31, 2018	Dec. 31, 2020	Dec. 31, 2019
Real Estate [Line Items]
Buildings		$ 102	$ 102
Tenant improvements		5	5
Land		2	2
Land improvements		1	1
Total real estate assets		110	110
Less: accumulated depreciation		(13)	(9)
Total investment in land and buildings, net		$ 97	$ 101
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

DEBT - Energen Notes (Details) - USD ($)	3 Months Ended
DEBT - Energen Notes (Details) - USD ($)	Sep. 30, 2020	Dec. 31, 2020	Dec. 31, 2019	Nov. 29, 2018
Debt Instrument [Line Items]
Long-term debt, gross		$ 5,815,000,000	$ 5,371,000,000
Energen Notes
Debt Instrument [Line Items]
Long-term debt, gross		311,000,000		$ 530,000,000
4.625% Notes due 2021
Debt Instrument [Line Items]
Long-term debt, gross		$ 191,000,000	399,000,000
Stated interest rate		4.625%
Repurchased face amount		$ 209,000,000
7.125% Medium-term Notes, Series B, due 2028
Debt Instrument [Line Items]
Long-term debt, gross		$ 100,000,000	108,000,000
Stated interest rate		7.125%
7.320% Medium-term Notes, Series A, due 2022
Debt Instrument [Line Items]
Long-term debt, gross		$ 20,000,000	21,000,000
Stated interest rate		7.32%
7.350% Medium-term Notes, Series A, due 2027
Debt Instrument [Line Items]
Long-term debt, gross		$ 0	$ 11,000,000
Stated interest rate	7.35%	7.35%
Repurchased face amount	$ 10,000,000
Percentage of principal amount redeemed	120.00%

SUBSEQUENT EVENTS - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Feb. 18, 2021	Dec. 21, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 18, 2020	Sep. 30, 2020
Subsequent Event [Line Items]
Dividends declared per share (in dollars per share)			$ 1.5250	$ 0.9375	$ 0.50
Funds held in escrow			$ 51	$ 0
QEP
Subsequent Event [Line Items]
Business combination, consideration transferred		$ 2,200
Debt in business combination							$ 1,600
Number of shares issued per share of acquire stock		0.050
Business acquisition, share price (USD per share)						$ 2.29
Guidon Operating LLC
Subsequent Event [Line Items]
Number of shares issued		10,600,000
Payments for asset acquisition		$ 375
Funds held in escrow			$ 50
Subsequent Event
Subsequent Event [Line Items]
Dividends declared per share (in dollars per share)	$ 0.40

DEBT

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

DEBT

The Company’s debt consisted of the following as of the dates indicated:


	December 31,
	2020		2019
	(in millions)
4.625% Notes due 2021	$	191	$	399
7.320% Medium-term Notes, Series A, due 2022	20		21
2.875% Senior Notes due 2024	1,000		1,000
4.750% Senior Notes due 2025	500		—
5.375% Senior Notes due 2025	800		800
3.250% Senior Notes due 2026	800		800

7.350% Medium-term Notes, Series A, due 2027	—		11
7.125% Medium-term Notes, Series B, due 2028	100		108
3.500% Senior Notes due 2029	1,200		1,200
DrillCo Agreement	79		39
Unamortized debt issuance costs	(29)		(19)
Unamortized discount costs	(27)		(31)
Unamortized premium costs	15		9
Revolving credit facility(1)	23		13
Viper revolving credit facility(1)	84		97
Viper 5.375% Senior Notes due 2027	480		500
Rattler revolving credit facility(2)	79		424
Rattler 5.625% Senior Notes due 2025	500		—
Total debt, net	5,815		5,371
Less: current maturities of long-term debt	(191)		—
Total long-term debt	$	5,624	$	5,371

(1) Each of these revolving credit facilities matures on November 1, 2022.

(2) The Rattler revolving credit facility matures on May 28, 2024.

Debt maturities as of December 31, 2020, excluding debt issuance costs, premiums and discounts, are as follows:


Year Ending December 31,	Total
	(in millions)
2021	$	191
2022	127
2023	—
2024	1,079
2025	1,800
Thereafter	2,659
Total	$	5,856

Diamondback Notes

May 2020 Notes Offering

On May 26, 2020, the Company completed a notes offering of $500 million in aggregate principal amount of its 4.750% Senior Notes due 2025 (the “May 2020 Notes”). Interest on the May 2020 Notes accrues from May 26, 2020, and is payable in cash semi-annually on May 31 and November 30 of each year, beginning November 30, 2020. The May 2020 Notes mature on May 31, 2025. The Company received net proceeds of approximately $496 million from the offering of the May 2020 Notes. The May 2020 Notes are the Company’s senior unsecured obligations and are guaranteed by Diamondback O&G LLC (the “Guarantor”), but are not guaranteed by any of the Company’s other subsidiaries. The May 2020 Notes are senior in right or payment to any of the Company’s and the Guarantor’s future subordinated indebtedness and rank equal in right of payment with all of the Company’s and the Guarantor’s existing and future senior indebtedness. The May 2020 Notes are effectively subordinated to the Company’s and the Guarantor’s existing and future secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all of the existing and future indebtedness and other liabilities of the Company’s subsidiaries other than the Guarantor.

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.

On December 20, 2019, the Company redeemed all of the outstanding 4.750% senior notes, which included $1.25 billion of aggregate outstanding principal at a redemption price of 103.563% plus accrued and unpaid interest on the outstanding principal amount to the Redemption Date, resulting in a loss on extinguishment of debt of $56 million. 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 with a portion of the net proceeds from the issuance of the December 2019 Notes.

2025 Senior Notes

On December 20, 2016, the Company issued $500 million in aggregate principal amount of 5.375% senior notes due 2025, 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 an additional $300 million aggregate principal amount of new 5.375% senior notes due 2025 as additional notes under the 2025 indenture and received approximately $308 million in net proceeds, after deducting discounts and offering expenses, but disregarding accrued interest. The Company used these net proceeds to repay a portion of the outstanding borrowings under its revolving credit facility. Collectively, the aggregate $800 million principal amount of 5.375% senior notes due in 2025 are referred to as the 2025 senior notes.

All of the 2025 senior notes will mature on May 31, 2025 and the 5.375% per annum interest is payable semi-annually, in arrears on May 31 and November 30 each year. Currently, the 2025 senior notes are not guaranteed by any of the

Company’s subsidiaries other than its restricted subsidiary, Diamondback O&G LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries. These notes may be guaranteed by future restricted 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.

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 Company 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 any of the December 2019 Notes are redeemed on or after their respective par call dates, in each case, they will be redeemed at a redemption price equal to 100% of the principal amount plus interest accrued thereon up 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, 2020, the maximum credit amount available under the credit agreement is $2.0 billion. As of December 31, 2020, the Company had approximately $23 million of outstanding borrowings under its revolving credit facility and $1.98 billion available for future borrowings under the revolving credit facility. As of December 31, 2020, there was an aggregate of $3 million in letters of credit outstanding under the credit agreement, which reduce available borrowings on a dollar for dollar basis.

Diamondback O&G LLC is the borrower under the credit agreement and, as of December 31, 2020, the credit agreement is guaranteed by Diamondback Energy, Inc. None of the Company’s other subsidiaries are guarantors under the revolving credit facility.

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. The weighted average interest rates on the credit facility were 2.02%, 4.10% and 3.75% for the years ended December 31, 2020, 2019 and 2018, respectively.

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, 2020 and 2019, the Company was in compliance with all financial maintenance 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, 2020, the aggregate principal amount of the Energen Notes had been reduced to $311 million, consisting of: (1) $191 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (2) $100 million of 7.125% notes due on February 15, 2028 and (3) $20 million of 7.32% notes due on July 28, 2022.

The Company used the net proceeds from the offering of May 2020 Notes, among other things, to make an equity contribution to Energen to purchase $209 million in previously outstanding aggregate principal amount of Energen’s 4.625% senior notes pursuant to a tender offer.

During the third quarter of 2020, the Company repurchased $10 million in principal amount of the outstanding Energen 7.35% medium-term notes due on July 28, 2027 at a price of 120% of the aggregate principal amount, which resulted in an immaterial loss on extinguishment of debt.

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. None of the Company’s other 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.

Viper’s Credit Agreement

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 $2.0 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $580 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. The borrowing base was reaffirmed at $580 million by the lenders during the regularly scheduled (semi-annual) fall 2020 redetermination in November 2020. As of December 31, 2020, Viper LLC had $84 million of outstanding borrowings and $496 million available for future borrowings under the Viper credit agreement. The weighted average interest rates on borrowings under the Viper credit agreement were 2.20%, 4.51%, and 4.37% for the years ended December 31, 2020, 2019 and 2018, respectively.

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 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. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

As of December 31, 2020, Viper LLC was in compliance with all financial maintenance 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. With certain specified exceptions, the terms and provisions of the credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

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.

During the year ended December 31, 2020, Viper repurchased $20 million of outstanding principal of the Viper notes at a cash price ranging from 97.5% to 98.5% of the aggregate principal amount, which resulted in an immaterial gain on extinguishment of debt, and $480 million in aggregate principal amount remained outstanding at December 31, 2020.

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, 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, 2020, Rattler LLC had $79 million of outstanding borrowings and $521 million available for future borrowings under the Rattler credit agreement. The weighted average interest rates on borrowings under the Rattler credit agreement were 2.10% and 3.13% for the years ended December 31, 2020 and 2019, respectively.

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 may be used to fund capital expenditures, to finance working

capital, for general company purposes, to pay fees and expenses related to the credit agreement, and to make distributions permitted under the Rattler credit agreement.

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

As of December 31, 2020, Rattler LLC was in compliance with all financial maintenance 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.

Rattler’s Notes

On July 14, 2020, Rattler completed an offering of $500 million in aggregate principal amount of its 5.625% Senior Notes due 2025, (the “Rattler Notes”). The Rattler Notes mature on July 15, 2025, and interest on the Rattler Notes is payable on January 15 and July 15 of each year, beginning on January 15, 2021. Rattler received net proceeds of approximately $490 million from the Rattler Notes and loaned the gross proceeds to Rattler LLC to repay then outstanding borrowings under the Rattler Credit Agreement. The Rattler Notes are senior unsecured obligations of Rattler, rank equally in right of payment with all of Rattler’s existing and future senior indebtedness and initially are guaranteed on a senior unsecured basis by Rattler LLC, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. Neither the Company nor Rattler’s General Partner guarantee the Rattler Notes. In the future, each of Rattler’s restricted subsidiaries that either (1) guarantees any of its or a guarantor’s other indebtedness or (2) is classified as a domestic restricted subsidiary under the indenture governing the Rattler Notes and is an obligor with respect to any indebtedness under any credit facility will be required to guarantee the Rattler Notes.

The indenture under which the Rattler Notes were issued contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Rattler’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.

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, 2020, the amount due to CEMOF related to this alliance was $79 million. As of December 31, 2020, fifteen 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, 2020, 2019 and 2018:


	Year Ended December 31,
	2020		2019		2018
	(in millions)
Interest expense	$	250	$	235	$	110
Other fees and expenses	6		4		10
Less: interest income	4		1		1
Less: capitalized interest	55		66		32
Interest expense, net	$	197	$	172	$	87

CAPITAL STOCK AND EARNINGS PER SHARE - Change in Ownership of Consolidated Subsidiaries (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income (loss) attributable to Diamondback Energy, Inc.	$ (4,517,000)	$ 240,000	$ 846,000
Change in ownership of consolidated subsidiaries, net	(8,000)	12,000	(10,000)
Additional Paid-in Capital
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Change in ownership of consolidated subsidiaries, net	358,000	(33,000)	150,000
Rattler LLC
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Change in ownership of consolidated subsidiaries, net	329,000
Rattler LLC \| Additional Paid-in Capital
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Change in ownership of consolidated subsidiaries, net	329,000
Limited Partner
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income (loss) attributable to Diamondback Energy, Inc.	(4,517,000)	240,000	846,000
Change in ownership of consolidated subsidiaries, net	358,000	(33,000)	150,000
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest	$ (4,159,000)	$ 207,000	$ 996,000

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1A
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121641772&loc=SL7669619-108580

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8924-108599

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 11
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22694-107794

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04(22))
-URI http://asc.fasb.org/extlink&oid=120399700&loc=SL114874048-224260

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 11
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22694-107794

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=109222650&loc=SL51721683-107760

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22595-107794

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1B
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121641772&loc=SL7669625-108580

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8736-108599

Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(18))
-URI http://asc.fasb.org/extlink&oid=120400993&loc=SL114874131-224263

Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(20))
-URI http://asc.fasb.org/extlink&oid=120395209&loc=SL114868664-224227

Reference 13: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=121586364&loc=d3e3602-108585

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22499-107794

Reference 15: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22663-107794

Reference 16: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 28
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=75031198&loc=d3e14064-108612

Reference 17: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8906-108599

Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22583-107794

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(ii))
-URI http://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 20: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 45
-Paragraph 60B
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121326447&loc=SL5780133-109256

Reference 21: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 323
-SubTopic 10
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=114001798&loc=d3e33918-111571

Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 23: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22658-107794

+ Details

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Standardized measure of discounted future net cash flows at the beginning of the period	$ 10,184	$ 11,676	$ 3,757
Sales of oil and natural gas, net of production costs	(2,225)	(3,334)	(1,786)
Acquisitions of reserves	30	309	5,520
Divestitures of reserves	(4)	(500)	(2)
Extensions and discoveries, net of future development costs	1,514	4,004	3,287
Previously estimated development costs incurred during the period	704	120	535
Net changes in prices and production costs	(5,273)	831	1,805
Changes in estimated future development costs	526	(3,190)	(81)
Revisions of previous quantity estimates	(462)	(1,242)	271
Accretion of discount	1,126	1,344	380
Net change in income taxes	807	693	(1,728)
Net changes in timing of production and other	(169)	(527)	(282)
Standardized measure of discounted future net cash flows at the end of the period	$ 6,758	$ 10,184	$ 11,676

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Capitalized Oil and Natural Gas Costs (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Oil and natural gas properties:
Proved properties	$ 19,884	$ 16,575
Unproved properties	7,493	9,207
Total oil and natural gas properties	27,377	25,782
Accumulated depletion	(4,237)	(2,995)
Accumulated impairment	(7,954)	(1,934)
Oil and natural gas properties, net	$ 15,186	$ 20,853

DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION (Details) - segment	12 Months Ended
	Dec. 31, 2020	May 28, 2019
Noncontrolling Interest [Line Items]
Number of business segments	2
Viper Energy Partners LP
Noncontrolling Interest [Line Items]
Ownership percentage	58.00%
Rattler MIdstream LP
Noncontrolling Interest [Line Items]
Ownership percentage	72.00%	29.00%

EQUITY-BASED COMPENSATION - Performance-Based Restricted Stock Units (Narratives) (Details) - Performance Shares - Equity Plan $ in Millions	1 Months Ended				3 Months Ended	12 Months Ended
	Mar. 31, 2020 shares	Mar. 31, 2019 installment shares	Feb. 28, 2018	Feb. 27, 2017 shares	Mar. 31, 2019 shares	Dec. 31, 2020 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares, performance period	3 years
Granted (in shares)	225,047			117,423	199,723	281,519
Number of vesting installments \| installment		5
Share based award not recognized \| $						$ 22
Unrecognized compensation cost, expected period of recognition						2 years 1 month 6 days
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%
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%
Share-based Payment Arrangement, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares, performance period						3 years
Share based compensation arrangement by share-based payment award number of shares authorized percent of shares granted	250.00%
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%
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%
Share-based Payment Arrangement, Tranche Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		32,958
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%
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%

INCOME TAXES - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets:
Net operating loss and other carryforwards	$ 524	$ 453
Derivative instruments	60	0
Stock based compensation	7	7
Viper's investment in Viper LLC	150	134
Rattler's investment in Rattler LLC	58	0
Other	8	11
Deferred tax assets	807	605
Valuation allowance	(166)	(7)
Deferred tax assets, net of valuation allowance	641	598
Deferred tax liabilities:
Oil and natural gas properties and equipment	1,156	2,275
Midstream investments	192	50
Derivative instruments	0	6
Rattler's investment in Rattler LLC	0	8
Other	3	3
Total deferred tax liabilities	1,351	2,342
Net deferred tax liabilities	$ 710	$ 1,744

RATTLER MIDSTREAM LP

12 Months Ended

Dec. 31, 2020

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 to, among other things, own, acquire and exploit oil and natural gas properties in the Permian Basin in North America.

During the years ended December 31, 2020, 2019, and 2018, Diamondback received distributions of $62 million, $133 million and $155 million, respectively, in respect of its interests in Viper and Viper LLC.

Viper completed the following equity offerings during the years ended December 31, 2019 and 2018:


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)
July 2018	10,080,000	1,080,000	$	303	$	362
March 2019	10,925,000	1,425,000	$	341	$	314

There were no equity offerings during the year ended December 31, 2020.

The Company’s ownership percentage in Viper is reflected as a non-controlling interest in the consolidated financial statements of Viper. The Company’s ownership percentage in Viper changes as a result of Viper’s public offerings, issuance of units for acquisitions, issuance of unit-based compensation, repurchases of common units and distribution equivalent rights paid on its units. These changes in ownership percentage and the disproportionate allocation of net income to the Company under Viper’s partnership agreement for a set period of time following Viper’s tax status change result in the difference between the Company’s share of the underlying net book value in Viper before and after the respective Partnership common unit transactions. See Note 12—Capital Stock and Earnings Per Share for further details.

Recapitalization, Tax Status Election and Related Transactions by Viper

In March 2018, the Board of Directors of Viper’s General Partner 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 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. 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, in connection with the change in Viper’s income tax status becoming effective, the Company, among other things, exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of 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. The Company is party to a partnership agreement and tax sharing agreement with Viper which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2020, 2019 and 2018.

Implementation of Viper’s Common Unit Repurchase Program

On November 6, 2020, the board of directors of Viper’s general partner approved an expansion of Viper’s return of capital program with the implementation of a common unit repurchase program to acquire up to $100 million of Viper’s outstanding common units through December 31, 2021. During the year ended December 31, 2020, Viper repurchased approximately $24 million of its common units under its repurchase program. As of December 31, 2020, $76 million remained available for use to repurchase Viper’s common units under its common unit repurchase program.

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 11—Debt for a description of this credit facility.

RATTLER MIDSTREAM LP

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 Midstream GP LLC (“Rattler’s General Partner”), a wholly owned subsidiary of Diamondback, serves as the general partner of Rattler. As of December 31, 2020, Diamondback owned approximately 72% 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. 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.

The Company is party to a partnership agreement, services and secondment agreement and tax sharing agreement with Rattler which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2020, 2019 and 2018.

Implementation of Rattler’s Common Unit Repurchase Program

On October 29, 2020, the board of directors of Rattler’s general partner approved a common unit repurchase program to acquire up to $100 million of Rattler’s outstanding common units through December 31, 2021. During the year ended December 31, 2020, Rattler repurchased approximately $15 million of its common units under its repurchase program. As of December 31, 2020, $85 million remained available for use to repurchase common units under Rattler’s common unit repurchase program.

Rattler LLC’s Revolving Credit Facility

Rattler LLC has entered into a secured revolving credit facility with Wells Fargo, as administrative agent, sole book runner and lead arranger. See Note 11—Debt for a description of this credit facility.

EQUITY-BASED COMPENSATION - Performance-Based Restricted Stock Activity (Details) - Performance Shares - Equity Plan - $ / shares	1 Months Ended		3 Months Ended	12 Months Ended
	Mar. 31, 2020	Feb. 27, 2017	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Fair Value Assumptions
Grant-date fair value (in dollars per share)				$ 70.17	$ 137.22	$ 170.45
Granted (in dollars per share)				$ 70.17	$ 137.22	$ 170.45
Risk-free rate				0.86%	2.55%	1.99%
Company volatility				36.70%	35.00%	35.90%
Performance Restricted Stock Units
Unvested, beginning balance (in shares)				271,819
Granted (in shares)	225,047	117,423	199,723	281,519
Vested (in shares)				(133,355)
Forfeited (in shares)				(8,396)
Unvested, ending balance (in shares)				411,587	271,819
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Unvested, beginning balance (in dollars per share)				$ 147.07
Granted (in dollars per share)				88.41
Vested (in dollars per share)				139.43
Forfeited (in dollars per share)				170.45
Unvested, ending balance (in dollars per share)				$ 99.10	$ 147.07
Maximum units could be awarded (in shares)				935,698
Five-Year
Fair Value Assumptions
Grant-date fair value (in dollars per share)					132.48
Granted (in dollars per share)					$ 132.48

CAPITAL STOCK AND EARNINGS PER SHARE - Capital Stock (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	May 31, 2019
Equity [Abstract]
Stock repurchase program authorized amount			$ 2,000,000,000
Stock repurchase program amount repurchased	$ 98,000,000	$ 598,000,000

INCOME TAXES

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

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 Company’s effective income tax rates were 19.1%, 13.0% and 15.1% for the years ended December 31, 2020, 2019 and 2018, respectively. Total income tax benefit for the year ended December 31, 2020 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss for the period primarily due to the impact of recording a valuation allowance on Viper’s deferred tax assets, partially offset by state income taxes net of federal benefit and by tax benefit resulting from the carryback of federal net operating losses. Total income tax expense for the year ended December 31, 2019 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 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 Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted on March 27, 2020. This legislation included a number of provisions applicable to U.S. income taxes for corporations, including providing for carryback of certain net operating losses, accelerated refund of minimum tax credits, and modifications to the rules limiting the deductibility of business interest expense. The Company considered the impact of this legislation in the period of enactment, resulting in current income tax benefit of $62 million, offset by deferred income tax expense of $38 million, for the year ended December 31, 2020 related to the carryback of approximately $179 million of the Company’s federal net operating losses to tax years in which the corporate income tax rate was 35%. Prior to the enactment of the CARES Act in the first quarter of 2020, there was no tax refund available to the Company with respect to its losses, resulting in deferred tax assets associated with federal net operating loss carryforwards at the statutory 21% corporate income tax rate. As a result of the refund associated with such carryback as well as the accelerated refund available for minimum tax credits, the Company’s current federal taxes receivable totaled approximately $100 million as of December 31, 2020.

The components of the Company’s consolidated provision for income taxes from continuing operations for the years ended December 31, 2020, 2019 and 2018 are as follows:


	Year Ended December 31,
	2020		2019		2018
	(In millions)
Current income tax provision (benefit):
Federal	$	(62)	$	—	$	—
State	—		—		—
Total current income tax provision (benefit)	(62)		—		—
Deferred income tax provision (benefit):
Federal	(1,010)		40		160
State	(32)		7		8
Total deferred income tax provision (benefit)	(1,042)		47		168
Total provision for (benefit from) income taxes	$	(1,104)	$	47	$	168

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


	Year Ended December 31,
	2020		2019		2018
	(In millions)
Income tax expense at the federal statutory rate (21%)	$	(1,213)	$	76	$	234
Impact of nontaxable noncontrolling interest	—		—		(5)
Income tax benefit relating to net operating loss carryback	(25)		—		—
State income tax expense, net of federal tax effect	(30)		6		8
Non-deductible compensation	6		4		5
Change in valuation allowance	153		—		—
Deferred taxes related to change in Viper LP's tax status	—		(42)		(73)
Other, net	5		3		(1)
Provision for (benefit from) income taxes	$	(1,104)	$	47	$	168

The components of the Company’s deferred tax assets and liabilities as of December 31, 2020 and 2019 are as follows:


	December 31,
	2020		2019
	(In millions)












Deferred tax assets:
Net operating loss and other carryforwards	$	524	$	453
Derivative instruments	60		—
Stock based compensation	7		7

Viper's investment in Viper LLC	150		134
Rattler's investment in Rattler LLC	58		—
Other	8		11
Deferred tax assets	807		605
Valuation allowance	(166)		(7)
Deferred tax assets, net of valuation allowance	641		598
Deferred tax liabilities:
Oil and natural gas properties and equipment	1,156		2,275
Midstream investments	192		50
Derivative instruments	—		6
Rattler's investment in Rattler LLC	—		8
Other	3		3
Total deferred tax liabilities	1,351		2,342
Net deferred tax liabilities	$	710	$	1,744

The Company had net deferred tax liabilities of approximately $0.7 billion and $1.7 billion at December 31, 2020 and 2019, respectively. 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, 2019, the Company had completed its purchase price allocation for the acquisition, including a deferred tax liability of $1.4 billion associated with 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, 2020, the Company had approximately $0.4 billion of federal NOLs expiring in 2032 through 2037 and $1.9 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.

In addition to the carryback of certain of the Company’s federal NOLs pursuant to the CARES Act as noted above, modifications to the rules regarding deductibility of business interest expense resulting from enactment of the CARES Act and from the issuance of final regulations by the U.S. Department of Treasury in July 2020 resulted in a reduction to carryforwards of the Company’s business interest expense and corresponding increase to its federal net operating loss carryforwards.

As of December 31, 2020, the Company had a valuation allowance of $5 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 and a valuation allowance of $161 million related to Viper’s deferred tax assets, as discussed further below. 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, 2020, management determined that it is more likely than not that the Company will realize its remaining deferred tax assets.

As discussed further in Note 5—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 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, 2020, the Company’s net deferred tax liabilities include deferred tax assets of approximately $11 million related to Viper’s NOL carryforwards and approximately $150 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. Based on information available regarding unitholders; tax basis, 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 and $73 million included in the Company’s consolidated income tax provision for the years ended December 31, 2019 and 2018, respectively. As of December 31, 2020, Viper had federal NOL carryforwards of approximately $50 million which may be carried forward indefinitely to offset future taxable income.

As of December 31, 2020, Viper had a valuation allowance of approximately $161 million related to deferred tax assets that Viper does not believe are more likely than not to be realized. Management considers the likelihood that Viper’s NOLs and other deferred tax attributes will be utilized prior to their expiration, if applicable. The determination to record a valuation allowance was based on Management’s assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets as required by applicable accounting standards. In light of those criteria for recognizing the tax benefit of deferred tax assets, the assessment resulted in application of a valuation allowance against Viper’s federal deferred tax assets as of March 31, 2020 and subsequent balance sheet dates within the year ended December 31, 2020.

As discussed further in Note 6—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, 2020, the Company’s net deferred tax liabilities include a deferred tax asset of approximately $58 million related to Rattler’s investment in Rattler LLC. In the second quarter of 2020, the Company recorded an increase through stockholders’ equity to the carrying value of its investment in Rattler LLC. A corresponding adjustment to the noncontrolling interest resulted in a decrease in Rattler’s deferred tax liability related to its investment in Rattler LLC and a

total net deferred tax asset balance for Rattler. 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, 2020, Rattler has federal net operating loss carryforwards of approximately $75 million which may be carried forward indefinitely to offset future taxable income.

Management considers the likelihood that Rattler’s NOLs and other deferred tax attributes will be utilized prior to their expiration, if applicable. At December 31, 2020, Rattler’s assessment included consideration of all available positive and negative evidence, including Rattler’s projected future taxable income and the anticipated timing of reversal of deferred tax assets. As a result of the assessment, management determined that it is more likely than not that Rattler will realize its deferred tax assets as of December 31, 2020.

The following table sets forth changes in the Company’s unrecognized tax benefits:


	December 31,
	2020		2019
	(in millions)
Balance at beginning of year	$	7	$	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 recognizes the tax benefit from a tax position only if it is more likely than not that it will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. During the year ended December 31, 2020, the statute of limitations related to an uncertain tax position of the Company expired, and upon expiration the Company recognized tax benefit of $0.3 million and recorded a reduction to interest expense of less than $0.1 million. 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, 2020 and 2019, there was less than $0.2 million of interest and no penalties related to each period associated with uncertain tax positions recognized in the Company’s consolidated financial statements.

- Definition

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

+ References + Details

INCOME TAXES - Narrative (Details) - USD ($)	12 Months Ended
INCOME TAXES - Narrative (Details) - USD ($)	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Nov. 29, 2018
Operating Loss Carryforwards [Line Items]
Effective income tax rate	19.10%	13.00%	15.10%
Current income tax expense (benefit)	$ (62,000,000)	$ 0	$ 0
Deferred income tax expense	38,000,000
Change in enacted tax rate, amount	179,000,000
Current federal taxes receivable	100,000,000
Net deferred tax liabilities	710,000,000	1,744,000,000
Operating loss carryforwards, subject to expiration	400,000,000
Operating loss carryforwards, not subject to expiration	1,900,000,000
Valuation allowance	(166,000,000)	(7,000,000)
Deferred tax liability includes deferred tax asset	150,000,000	134,000,000
Change in deferred tax asset due to change in tax status	0	(42,000,000)	$ (73,000,000)
Rattler's investment in Rattler LLC	58,000,000	0
Benefit from lapse of applicable statute of limitations	300,000
Interest expense	100,000
Interest associated with uncertain tax positions (less than)	200,000	200,000
Penalties associated with uncertain tax positions	0	0
State
Operating Loss Carryforwards [Line Items]
Valuation allowance	(5,000,000)
Energen
Operating Loss Carryforwards [Line Items]
Business acquisition, deferred tax liabilities		$ 1,400,000,000		$ 1,425,000,000
Viper LLC
Operating Loss Carryforwards [Line Items]
Valuation allowance	(161,000,000)
Deferred tax liability includes deferred tax asset	11,000,000
Change in deferred tax asset due to change in tax status	115,000,000
Operating loss carryforwards	50,000,000
Rattler MIdstream LP
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 75,000,000

REAL ESTATE ASSETS

12 Months Ended

Dec. 31, 2020

Real Estate [Abstract]

REAL ESTATE ASSETS

In conjunction with Diamondback’s acquisition of the Fasken Center, the Company allocated the $110 million purchase price between real estate assets and an insignificant amount of intangible lease assets related to in-place and above-market leases. The following schedules present the cost and related accumulated depreciation or amortization (as applicable) of Diamondback’s real estate assets:


	Estimated Useful Lives	December 31,
		2020		2019
	(Years)	(in millions)
Buildings	20-30	$	102	$	102
Tenant improvements	15	5		5
Land	N/A	2		2
Land improvements	15	1		1
Total real estate assets		110		110
Less: accumulated depreciation		(13)		(9)
Total investment in land and buildings, net		$	97	$	101

DEBT - Rattler's Credit Agreement (Details) - USD ($)	12 Months Ended
DEBT - Rattler's Credit Agreement (Details) - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Line of Credit Facility [Line Items]
Long-term debt, gross	$ 5,815,000,000	$ 5,371,000,000
Rattler revolving credit facility(2)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	600,000,000
Long-term debt, gross	79,000,000	$ 424,000,000
Remaining borrowing capacity	$ 521,000,000
Rattler revolving credit facility(2) \| Rattler LLC
Line of Credit Facility [Line Items]
Weighted average interest rate	2.10%	3.13%
Rattler revolving credit facility(2) \| Minimum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.25%
Rattler revolving credit facility(2) \| Minimum \| Prime Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.25%
Rattler revolving credit facility(2) \| Minimum \| LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.25%
Rattler revolving credit facility(2) \| Maximum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.375%
Rattler revolving credit facility(2) \| Maximum \| Prime Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.25%
Rattler revolving credit facility(2) \| Maximum \| LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.25%

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, 2020 bbl Mcf	Dec. 31, 2019 bbl Mcf	Dec. 31, 2018 bbl Mcf	Dec. 31, 2017 bbl Mcf
OIL
Proved Developed and Undeveloped Reserves (Volume)
Beginning of the period	710,903	626,936	233,181
Extensions and discoveries	191,009	256,569	143,256
Revisions of previous estimates	(78,244)	(84,789)	3,689
Purchase of reserves in place	2,124	13,974	281,333
Divestitures	(209)	(33,269)	(156)
Production	(66,182)	(68,518)	(34,367)
End of the period	759,401	710,903	626,936
Proved Developed Reserves (Volume)	443,464	457,083	403,051	141,246
Proved Undeveloped Reserve (Volume)	315,937	253,820	223,885	91,935
Natural Gas Liquids
Proved Developed and Undeveloped Reserves (Volume)
Beginning of the period	230,203	190,291	54,609
Extensions and discoveries	58,410	66,572	33,152
Revisions of previous estimates	21,927	(8,166)	11,138
Purchase of reserves in place	778	3,813	98,865
Divestitures	(141)	(3,809)	(8)
Production	(21,981)	(18,498)	(7,465)
End of the period	289,196	230,203	190,291
Proved Developed Reserves (Volume)	192,495	165,173	125,509	35,412
Proved Undeveloped Reserve (Volume)	96,701	65,030	64,782	19,198
Natural Gas
Proved Developed and Undeveloped Reserves (Volume)
Beginning of the period \| Mcf	1,118,811	1,048,649	285,369
Extensions and discoveries \| Mcf	316,035	318,874	154,088
Revisions of previous estimates \| Mcf	300,160	(149,657)	3,642
Purchase of reserves in place \| Mcf	3,512	19,830	640,761
Divestitures \| Mcf	(905)	(21,272)	(543)
Production \| Mcf	(130,549)	(97,613)	(34,668)
End of the period \| Mcf	1,607,064	1,118,811	1,048,649
Proved Developed Reserves (Volume) \| Mcf	1,085,035	824,760	705,084	190,740
Proved Undeveloped Reserve (Volume) \| Mcf	522,029	294,051	343,565	94,629

ACQUISITIONS AND DIVESTITURES - 2020 Activity (Details) - Mineral Interests In Permian Basin - Viper LLC $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) a
Business Acquisition [Line Items]
Mineral properties acquired, gross acres	4,948
Mineral properties acquired net royalty acres	417
Business combination, consideration transferred \| $	$ 64

EQUITY-BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019		2018
	(In millions)
General and administrative expenses	$	37	$	48	$	27
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$	16	$	17	$	10

Summary of restricted stock units

The following table presents the Company’s restricted stock awards and units activity under the Equity Plan during the year ended December 31, 2020:


	Restricted Stock Awards & Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	505,867	$	96.01
Granted	921,730	$	35.38
Vested	(283,330)	$	86.81
Forfeited	(30,787)	$	80.94
Unvested at December 31, 2020	1,113,480	$	48.58

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:


	2020			2019			2018
Grant-date fair value	$	70.17		$	137.22		$	170.45
Grant-date fair value (5-year vesting)				$	132.48
Risk-free rate	0.86		%	2.55		%	1.99		%
Company volatility	36.70		%	35.00		%	35.90		%

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, 2020:


	Performance Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	271,819	$	147.07
Granted(1)	281,519	$	88.41
Vested	(133,355)	$	139.43
Forfeited	(8,396)	$	170.45
Unvested at December 31, 2020(2)	411,587	$	99.10

(1)Includes units granted to satisfy the final payout of vested performance restricted stock units based on the TSR ranking for the performance period.

(2)A maximum of 935,698 units could be awarded based upon the Company’s final TSR ranking.

Schedule of phantom units activity

The following table presents the phantom unit activity under the Rattler LTIP for the year ended December 31, 2020:


	Phantom Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	2,226,895	$	19.14
Granted	348,379	$	6.51
Vested	(460,781)	$	19.06
Forfeited	(24,825)	$	17.54
Unvested at December 31, 2020	2,089,668	$	17.07

COMMITMENTS AND CONTINGENCIES - Delivery Commitments (Details)	Dec. 31, 2020 bbl
Commitments and Contingencies Disclosure [Abstract]
2021	175,000
2022	175,000
2023	175,000
2024	125,000
2025	125,000
Thereafter	400,000
Total	1,175,000

PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2020

Property, Plant and Equipment [Abstract]

Schedule of property and equipment

Property and equipment includes the following:


	December 31,
	2020		2019
	(in millions)
Oil and natural gas properties:
Subject to depletion	$	19,884	$	16,575
Not subject to depletion	7,493		9,207
Gross oil and natural gas properties	27,377		25,782
Accumulated depletion	(4,237)		(2,995)
Accumulated impairment	(7,954)		(1,934)
Oil and natural gas properties, net	15,186		20,853
Midstream assets	1,013		931
Other property, equipment and land	138		125
Accumulated depreciation	(123)		(74)
Total property and equipment, net	$	16,214	$	21,835

Balance of costs not subject to depletion:
Incurred in 2020	$	71
Incurred in 2019	421
Incurred in 2018	5,090
Incurred in 2017	1,682
Incurred in 2016	229
Total not subject to depletion	$	7,493

SUBSEQUENT EVENTS - Schedule of Derivative Contracts (Details) $ in Millions	2 Months Ended	12 Months Ended
	Feb. 19, 2021 USD ($) MMBTU $ / bbl $ / MMBTU bbl	Dec. 31, 2020 USD ($) MMBTU $ / bbl $ / MMBTU bbl
WTI \| OIL \| Costless Collars \| Subsequent Event \| July - Sep.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl	2,000
Derivative, Floor Price	45.00
Derivative, Cap Price	52.30
WTI \| OIL \| Costless Collars \| Subsequent Event \| Oct. - Dec.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl	9,000
Derivative, Floor Price	45.00
Derivative, Cap Price	59.22
WTI \| OIL \| Rolling Hedge \| Jan. - June
Subsequent Event [Line Items]
Volume (Bbls) \| bbl		12,000
Weighted Average Differential		0.07
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)		0
WTI \| OIL \| Rolling Hedge \| Subsequent Event \| Mar. - Dec.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl	25,000
Weighted Average Differential	0.32
WTI \| OIL \| Swaps \| Jan. - Mar.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl		5,000
Weighted Average Differential		0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)		45.46
WTI \| OIL \| Basis Swap \| Jan. - June
Subsequent Event [Line Items]
Volume (Bbls) \| bbl		8,000
Weighted Average Differential		(0.52)
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)		0
WTI Houston Argus \| OIL \| Costless Collars \| Subsequent Event \| July - Sep.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl	5,000
Derivative, Floor Price	45.00
Derivative, Cap Price	57.90
WTI Houston Argus \| OIL \| Swaps \| Jan. - Dec.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl		5,000
Weighted Average Differential		0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)		37.78
IPE Brent \| OIL \| Costless Collars \| Subsequent Event \| Oct. - Dec.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl	4,000
Derivative, Floor Price	45.00
Derivative, Cap Price	60.64
IPE Brent \| OIL \| Costless Collars \| Subsequent Event \| Apr. - Sep.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl	2,000
Derivative, Floor Price	45.00
Derivative, Cap Price	57.72
IPE Brent \| OIL \| Costless Collars \| Subsequent Event \| Jan. - Mar.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl	18,000
Derivative, Floor Price	45.00
Derivative, Cap Price	61.35
IPE Brent \| OIL \| Costless Collars \| Subsequent Event \| Apr. - Dec.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl	2,000
Derivative, Floor Price	45.00
Derivative, Cap Price	60.00
Henry Hub \| OIL \| Swaps \| Subsequent Event \| Mar. - Dec.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl	20,000
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	2.95
Henry Hub \| NATURAL GAS \| Swaps \| Jan. - Dec.
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) \| MMBTU		200,000
Weighted Average Differential \| $ / MMBTU		0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) \| $ / MMBTU		2.65
WTI Midland \| OIL \| Basis Swap \| Subsequent Event \| Jan. - June
Subsequent Event [Line Items]
Volume (Bbls) \| bbl	15,000
Weighted Average Differential	0.95
WTI Midland \| OIL \| Basis Swap \| Subsequent Event \| July - Dec.
Subsequent Event [Line Items]
Volume (Bbls) \| bbl	18,000
Weighted Average Differential	0.93
Waha Hub \| NATURAL GAS \| Basis Swap \| Jan. - Dec.
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) \| MMBTU		230,000
Weighted Average Differential \| $ / MMBTU		0.69
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) \| $ / MMBTU		0
Waha Hub \| NATURAL GAS \| Basis Swap \| Subsequent Event \| Apr. - Dec.
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) \| MMBTU	20,000
Weighted Average Differential \| $ / MMBTU	(0.255)
Waha Hub \| NATURAL GAS \| Basis Swap \| Subsequent Event \| Jan. - Dec.
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) \| MMBTU	30,000
Weighted Average Differential \| $ / MMBTU	0.34
Mont Belvieu \| NATURAL GAS LIQUIDS \| Swaps \| Subsequent Event \| Feb. - Dec.
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) \| MMBTU	84,000
Weighted Average Differential \| $ / MMBTU	0.70
Interest Rate Swap One
Subsequent Event [Line Items]
Notional Amount \| $		$ 250
Interest Rate		1.692%
Interest Rate Swap One \| Subsequent Event
Subsequent Event [Line Items]
Notional Amount \| $	$ 250
Interest Rate	1.8361%
Interest Rate Swap Two
Subsequent Event [Line Items]
Notional Amount \| $		$ 250
Interest Rate		1.8361%
Interest Rate Swap Two \| Subsequent Event
Subsequent Event [Line Items]
Notional Amount \| $	$ 250
Interest Rate	1.852%

EQUITY-BASED COMPENSATION - Schedule of Stock-Based Compensation Plans and Related Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 16	$ 17	$ 10
General and administrative expenses
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
General and administrative expenses	$ 37	$ 48	$ 27

COMMITMENTS AND CONTINGENCIES - Commitments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Water Services Agreement \| Forecast
Supply Commitment [Line Items]
Produced water disposal services term	14 years
Sand Supply Agreement
Supply Commitment [Line Items]
2021		$ 18
2022		18
2023		18
2024		18
2025		18
Thereafter		5
Total		95
Transportation Commitments
Supply Commitment [Line Items]
2021		60
2022		60
2023		51
2024		48
2025		47
Thereafter		133
Total		399
Produced Water Disposal Commitments
Supply Commitment [Line Items]
2021		5
2022		5
2023		5
2024		5
2025		5
Thereafter		31
Total		56
Equity Method Investments \| Rattler LLC
Supply Commitment [Line Items]
2021		57
2022		7
2023		8
Total		$ 72

FAIR VALUE MEASUREMENTS - Recurring Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Current:
Net Fair Value Presented in Balance Sheet	$ 1	$ 46
Non-current:
Net Fair Value Presented in Balance Sheet	0	7
Current:
Net Fair Value Presented in Balance Sheet	249	27
Non-current:
Net Fair Value Presented in Balance Sheet	57	0
Viper Energy Partners LP \| Recurring \| Derivative Instruments
Current:
Total Gross Fair Value	43	64
Gross Amounts Offset in Balance Sheet	(42)	(18)
Net Fair Value Presented in Balance Sheet	1	46
Non-current:
Total Gross Fair Value	187	7
Gross Amounts Offset in Balance Sheet	(187)	0
Net Fair Value Presented in Balance Sheet	0	7
Current:
Total Gross Fair Value	291	45
Gross Amounts Offset in Balance Sheet	(42)	(18)
Net Fair Value Presented in Balance Sheet	249	27
Non-current:
Total Gross Fair Value	244
Gross Amounts Offset in Balance Sheet	(187)
Net Fair Value Presented in Balance Sheet	57
Viper Energy Partners LP \| Recurring \| Investment
Non-current:
Total Gross Fair Value		19
Gross Amounts Offset in Balance Sheet		0
Net Fair Value Presented in Balance Sheet		19
Viper Energy Partners LP \| Recurring \| Level 1 \| Derivative Instruments
Current:
Total Gross Fair Value	0	0
Non-current:
Total Gross Fair Value	0	0
Current:
Total Gross Fair Value	0	0
Non-current:
Total Gross Fair Value	0
Viper Energy Partners LP \| Recurring \| Level 1 \| Investment
Non-current:
Total Gross Fair Value		19
Viper Energy Partners LP \| Recurring \| Level 2 \| Derivative Instruments
Current:
Total Gross Fair Value	43	64
Non-current:
Total Gross Fair Value	187	7
Current:
Total Gross Fair Value	291	45
Non-current:
Total Gross Fair Value	244
Viper Energy Partners LP \| Recurring \| Level 2 \| Investment
Non-current:
Total Gross Fair Value		0
Viper Energy Partners LP \| Recurring \| Level 3 \| Derivative Instruments
Current:
Total Gross Fair Value	0	0
Non-current:
Total Gross Fair Value	0	0
Current:
Total Gross Fair Value	0	0
Non-current:
Total Gross Fair Value	$ 0
Viper Energy Partners LP \| Recurring \| Level 3 \| Investment
Non-current:
Total Gross Fair Value		$ 0

DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivative instruments

As of December 31, 2020, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed:


					Swaps		Collars
Settlement Month	Settlement Year	Type of Contract	Bbls/Mmbtu/Gallons Per Day	Index	Weighted Average Differential	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Ceiling Price
OIL
Jan. - Mar.	2021	Costless Collars	37,000	WTI Cushing	$—	$—	$34.95	$45.17
Apr. - June	2021	Costless Collars	15,000	WTI Cushing	$—	$—	$33.00	$45.33
July - Dec.	2021	Costless Collars	10,000	WTI Cushing	$—	$—	$30.00	$43.05
Jan. - June	2021	Roll Hedge(2)	12,000	WTI	$(0.07)	$—	$—	$—
Jan. - Mar.	2021	Swaps	5,000	WTI	$—	$45.46	$—	$—
Apr. - June	2021	Swaps	2,000	WTI	$—	$47.35	$—	$—
Jan. - June	2021	Basis Swap	8,000	WTI Midland(1)	$0.52	$—	$—	$—
Jan. - Dec.	2021	Swaps	5,000	WTI Houston Argus	$—	$37.78	$—	$—
Jan. - Dec.	2021	Swaps	5,000	Brent	$—	$41.62	$—	$—
Jan. - Mar.	2021	Costless Collars	82,000	Brent	$—	$—	$39.04	$48.51
Apr. - June	2021	Costless Collars	80,000	Brent	$—	$—	$39.26	$48.62
Jul. - Dec.	2021	Costless Collars	60,000	Brent	$—	$—	$39.43	$48.12
Jul. - Dec.	2021	Swaptions	5,000	Brent	$—	$51.00	$—	$—

NATURAL GAS
Jan. - Dec.	2021	Swaps	200,000	Henry Hub	$—	$2.65	$—	$—
Jan. - Dec.	2021	Basis Swaps	230,000	Waha Hub(1)	$(0.69)	$—	$—	$—
Jan. - Dec.	2022	Basis Swaps	100,000	Waha Hub(1)	$(0.42)	$—	$—	$—

Settlement Month

Settlement Year

Type of Contract

Bbls/Mcf Per Day

Index

Put Price

OIL

Jan. - Dec.

2022

Option

5,000

Brent

$35.00


Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.692	%
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.8361	%
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.852	%
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.722	%


					Swaps		Collars
Settlement Month	Settlement Year	Type of Contract	Bbls/Mmbtu Per Day	Index	Weighted Average Differential	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Ceiling Price
OIL
July - Sep.	2021	Costless Collar	2,000	WTI	$—	$—	$45.00	$52.30
Oct. - Dec.	2021	Costless Collar	9,000	WTI	$—	$—	$45.00	$59.22
July - Sep.	2021	Costless Collar	5,000	WTI Houston Argus	$—	$—	$45.00	$57.90
Apr. - Sep.	2021	Costless Collar	2,000	IPE Brent	$—	$—	$45.00	$57.72
Oct. - Dec.	2021	Costless Collar	4,000	IPE Brent	$—	$—	$45.00	$60.64
Mar. - Dec.	2021	Roll Hedge(2)	25,000	WTI	$0.32	$—	$—	$—
Mar. - Dec.	2021	Swap	20,000	Henry Hub	$—	$2.95	$—	$—
Jan. - June	2021	Basis Swap	15,000	WTI Midland(1)	$0.95	$—	$—	$—
July - Dec.	2021	Basis Swap	18,000	WTI Midland(1)	$0.93	$—	$—	$—
Jan. - Mar.	2022	Costless Collar	18,000	IPE Brent	$—	$—	$45.00	$61.35
Apr. - Dec.	2022	Costless Collar	2,000	IPE Brent	$—	$—	$45.00	$60.00
NATURAL GAS
Apr. - Dec.	2021	Basis Swap	20,000	Waha Hub(1)	$(0.255)	$—	$—	$—
Jan. - Dec.	2022	Basis Swap	30,000	Waha Hub(1)	$(0.34)	$—	$—	$—
NATURAL GAS LIQUIDS
Feb. - Dec.	2021	Swap	84,000	Mont Belvieu	$—	$0.70	$—	$—

(2) The Company has rolling hedge basis swaps for the differential between the NYMEX prices between the calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to Cushing, Oklahoma oil price for the notional volumes covered by the rolling hedge basis swap contracts.

Interest Rate Swaps

The following table presents the interest rate swap contracts terminated by the Company between January 1, 2021 and February 19, 2021:


Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.8361	%
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.852	%

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,
	2020		2019		2018
	(in millions)
Gain (loss) on derivative instruments, net
Commodity contracts	$	(32)	$	(151)	$	101
Interest rate swaps	(49)		43		—
Total	$	(81)	$	(108)	$	101

Net cash received (paid) on settlements
Commodity contracts(1)	250		37		(121)
Interest rate swaps(2)	—		43		—
Total	$	250	$	80	$	(121)

(1)The year ended December 31, 2020 includes cash received on commodity contracts terminated prior to their contractual maturity of $17 million.

(2)The year ended December 31, 2019 includes cash received on interest rate swap contracts terminated prior to their contractual maturity of $43 million.

- Definition

+ References

+ Details

Cover - USD ($) $ in Billions	12 Months Ended
Cover - USD ($) $ in Billions	Dec. 31, 2020	Feb. 19, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
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
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 6.6
Entity Common Stock, Shares Outstanding		158,015,647
Documents Incorporated by Reference	Portions of Diamondback Energy, Inc.’s Proxy Statement for the 2021 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	2020
Document Fiscal Period Focus	FY
Entity Central Index Key	0001539838
Current Fiscal Year End Date	--12-31

ACQUISITIONS AND DIVESTITURES (Tables)

12 Months Ended

Dec. 31, 2020

Business Combinations [Abstract]

Schedule of estimated fair values of assets acquired and liabilities assumed

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

EQUITY-BASED COMPENSATION

12 Months Ended

Dec. 31, 2020

Share-based Payment Arrangement [Abstract]

EQUITY-BASED COMPENSATION

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


	Year Ended December 31,
	2020		2019		2018
	(In millions)
General and administrative expenses	$	37	$	48	$	27
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$	16	$	17	$	10

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 awards and units activity under the Equity Plan during the year ended December 31, 2020:


	Restricted Stock Awards & Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	505,867	$	96.01
Granted	921,730	$	35.38
Vested	(283,330)	$	86.81
Forfeited	(30,787)	$	80.94
Unvested at December 31, 2020	1,113,480	$	48.58

The aggregate fair value of restricted stock units that vested during the years ended December 31, 2020, 2019 and 2018 was $25 million, $45 million and $19 million, respectively. As of December 31, 2020, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $41 million. Such cost is expected to be recognized over a weighted-average period of 2.3 years.

During the year ended December 31, 2020, the Company modified an insignificant amount of restricted stock units to include dividend equivalent rights during the vesting period which did not result in any incremental compensation costs.

Performance-Based Restricted Stock Units

To provide long-term incentives for 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 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 based upon the TSR during the performance period of January 1, 2018 to December 31, 2020, subject to continued employment. All remaining awards under this grant cliff vested 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 based upon the TSR during the performance period of January 1, 2019 to December 31, 2021 and cliff vest at December 31, 2021 subject to continued employment. 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.

In March 2020, eligible employees received performance restricted stock unit awards totaling 225,047 units from which a minimum of 0% and a maximum of 200% units could be awarded based upon the TSR during the three-year performance period of January 1, 2020 to December 31, 2022 and cliff vest at December 31, 2022 subject to continued employment. The initial payout of the March 2020 awards will be further adjusted by a TSR modifier that may reduce the payout or increase the payout up to a maximum of 250%.

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:


	2020			2019			2018
Grant-date fair value	$	70.17		$	137.22		$	170.45
Grant-date fair value (5-year vesting)				$	132.48
Risk-free rate	0.86		%	2.55		%	1.99		%
Company volatility	36.70		%	35.00		%	35.90		%

The following table presents the Company’s performance restricted stock unit activity under the Equity Plan for the year ended December 31, 2020:


	Performance Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	271,819	$	147.07
Granted(1)	281,519	$	88.41
Vested	(133,355)	$	139.43
Forfeited	(8,396)	$	170.45
Unvested at December 31, 2020(2)	411,587	$	99.10

(1)Includes units granted to satisfy the final payout of vested performance restricted stock units based on the TSR ranking for the performance period.

(2)A maximum of 935,698 units could be awarded based upon the Company’s final TSR ranking.

As of December 31, 2020, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $22 million, which is expected to be recognized over a weighted-average period of 2.1 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, 2020:


	Phantom Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	2,226,895	$	19.14
Granted	348,379	$	6.51
Vested	(460,781)	$	19.06
Forfeited	(24,825)	$	17.54
Unvested at December 31, 2020	2,089,668	$	17.07

The aggregate fair value of phantom units that vested during the year ended December 31, 2020 was $9 million. As of December 31, 2020, the unrecognized compensation cost related to unvested phantom units was $30 million which is expected to be recognized over a weighted-average period of 3.2 years.

DEBT - Rattler's Notes (Details) - Notes Offering - Rattler LLC	Jul. 14, 2020 USD ($)
Debt Instrument [Line Items]
Aggregate principal amount	$ 500,000,000
Stated interest rate	5.625%
Proceeds from issuance of debt	$ 490,000,000

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Oil and natural gas properties, amortization excluded	$ 7,493	$ 9,207
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)	158,088,182	159,002,338
Shares outstanding (in Shares)	158,088,182	159,002,338

Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Statement of Cash Flows [Abstract]
Common shares issued for business combination	$ 124	$ 7,070
Stock options assumed in business combination		14
Restricted stock units assumed in business combinations		$ 52

CAPITAL STOCK AND EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019		2018
	(In millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common stock	$	(4,517)	$	240	$	846
Weighted average common shares outstanding:
Basic weighted average common units outstanding	157,976		163,493		104,622
Effect of dilutive securities:
Potential common shares issuable(1)	—		350		307
Diluted weighted average common shares outstanding	157,976		163,843		104,929
Basic net income (loss) attributable to common stock	$	(28.59)	$	1.47	$	8.09
Diluted net income (loss) attributable to common stock	$	(28.59)	$	1.47	$	8.06

(1) For the year ended December 31, 2020, there were 696,223 potential common shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive due to recording a net loss.

Schedule of change in ownership of consolidated subsidiaries

The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period:


	Year Ended December 31,
	2020		2019		2018
	(in millions)
Net income (loss) attributable to the Company	$	(4,517)	$	240	$	846
Change in ownership of consolidated subsidiaries(1)	358		(33)		150
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest	$	(4,159)	$	207	$	996

(1) The year ended December 31, 2020 includes an adjustment to non-controlling interest for Rattler of $329 million and to additional paid-in-capital of $329 million to reflect the ownership structure that was effective at June 30, 2020. The adjustment had no impact on earnings.

SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2020

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

Announced Acquisition of QEP Resources

On December 21, 2020, the Company announced a definitive agreement to acquire QEP Resources Inc. (“QEP”) in an all-stock transaction valued at $2.2 billion including QEP’s net debt of $1.6 billion as of September 30, 2020 based upon closing share prices on October 16, 2020. The consideration will consist of 0.050 shares of Diamondback common stock for each share of QEP common stock, representing an implied value to each QEP stockholder of $2.29 per share based on the closing price of Diamondback common stock on December 18, 2020. The transaction was unanimously approved by the Board of Directors of each company. The transaction is anticipated to close shortly following the special meeting of QEP Stockholders, which is scheduled for March 16, 2021, subject to QEP stockholder approval and other customary closing conditions. See Item 1A. “Risk Factors” for further discussion of risks related to the QEP acquisition.

Announced Acquisition of Guidon Operating LLC

On December 21, 2020, the Company announced a definitive purchase agreement to acquire all leasehold interests and related assets of Guidon Operating LLC (“Guidon”) in exchange for 10.6 million shares of Diamondback common stock and $375 million of cash. In accordance with the terms of the purchase agreement, the Company deposited $50 million into an escrow account in December 2020, which will be released to Guidon upon the closing of the transaction. The cash portion of this transaction is expected to be funded through a combination of cash on hand and borrowings under the Company’s credit facility. The transaction is anticipated to close on February 26, 2021.

Fourth Quarter 2020 Dividend Declaration

On February 18, 2021, the Board of Directors of the Company declared a cash dividend for the fourth quarter of 2020 of $0.40 per share of common stock, payable on March 11, 2021 to its stockholders of record at the close of business on March 4, 2021.

Commodity Contracts

Subsequent to December 31, 2020, the Company entered into new fixed price swaps and basis swaps, costless collars and roll hedges. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges noted in the table below. When aggregating multiple contracts, the weighted average contract price is disclosed. The following table presents the derivative contracts entered into by the Company between January 1, 2021 and February 19, 2021:


					Swaps		Collars
Settlement Month	Settlement Year	Type of Contract	Bbls/Mmbtu Per Day	Index	Weighted Average Differential	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Ceiling Price
OIL
July - Sep.	2021	Costless Collar	2,000	WTI	$—	$—	$45.00	$52.30
Oct. - Dec.	2021	Costless Collar	9,000	WTI	$—	$—	$45.00	$59.22
July - Sep.	2021	Costless Collar	5,000	WTI Houston Argus	$—	$—	$45.00	$57.90
Apr. - Sep.	2021	Costless Collar	2,000	IPE Brent	$—	$—	$45.00	$57.72
Oct. - Dec.	2021	Costless Collar	4,000	IPE Brent	$—	$—	$45.00	$60.64
Mar. - Dec.	2021	Roll Hedge(2)	25,000	WTI	$0.32	$—	$—	$—
Mar. - Dec.	2021	Swap	20,000	Henry Hub	$—	$2.95	$—	$—
Jan. - June	2021	Basis Swap	15,000	WTI Midland(1)	$0.95	$—	$—	$—
July - Dec.	2021	Basis Swap	18,000	WTI Midland(1)	$0.93	$—	$—	$—
Jan. - Mar.	2022	Costless Collar	18,000	IPE Brent	$—	$—	$45.00	$61.35
Apr. - Dec.	2022	Costless Collar	2,000	IPE Brent	$—	$—	$45.00	$60.00
NATURAL GAS
Apr. - Dec.	2021	Basis Swap	20,000	Waha Hub(1)	$(0.255)	$—	$—	$—
Jan. - Dec.	2022	Basis Swap	30,000	Waha Hub(1)	$(0.34)	$—	$—	$—
NATURAL GAS LIQUIDS
Feb. - Dec.	2021	Swap	84,000	Mont Belvieu	$—	$0.70	$—	$—

(2) The Company has rolling hedge basis swaps for the differential between the NYMEX prices between the calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to Cushing, Oklahoma oil price for the notional volumes covered by the rolling hedge basis swap contracts.

REAL ESTATE ASSETS (Tables)

12 Months Ended

Dec. 31, 2020

Real Estate [Abstract]

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:


	Estimated Useful Lives	December 31,
		2020		2019
	(Years)	(in millions)
Buildings	20-30	$	102	$	102
Tenant improvements	15	5		5
Land	N/A	2		2
Land improvements	15	1		1
Total real estate assets		110		110
Less: accumulated depreciation		(13)		(9)
Total investment in land and buildings, net		$	97	$	101

EQUITY METHOD INVESTMENTS

12 Months Ended

Dec. 31, 2020

Equity Method Investments and Joint Ventures [Abstract]

EQUITY METHOD INVESTMENTS

At December 31, 2020 and 2019, Rattler had the following investments:


	Ownership Interest		December 31, 2020		December 31, 2019
			(in millions)
EPIC Crude Holdings, LP	10	%	$	121	$	110
Gray Oak Pipeline, LLC	10	%	130		115
Wink to Webster Pipeline LLC	4	%	83		34
OMOG JV LLC	60	%	194		219
Amarillo Rattler, LLC	50	%	5		1
Total			$	533	$	479

The following summarizes the income (loss) of equity method investees for the periods presented:


	Year Ended December 31,
	2020		2019
	(in millions)
EPIC Crude Holdings, LP	$	(9)	$	(6)
Gray Oak Pipeline, LLC	10		1
Wink to Webster Pipeline LLC	(2)		(1)
OMOG JV LLC	(9)		—

Total	$	(10)	$	(6)

On February 1, 2019, Rattler LLC acquired a 10% equity interest in EPIC Crude Holdings, LP (“EPIC”), which owns and operates a pipeline (the “EPIC pipeline”) that transports crude oil and natural gas liquids across Texas for delivery into the Corpus Christi market. The EPIC pipeline became fully operational in April 2020.

On February 15, 2019, Rattler LLC acquired a 10% equity interest in Gray Oak Pipeline, LLC (“Gray Oak”), which owns and operates a pipeline (the “Gray Oak pipeline”) that transports crude oil from the Permian to Corpus Christi on the Texas Gulf Coast. The Gray Oak pipeline became fully operational in April 2020.

On March 29, 2019, Rattler LLC executed a short-term promissory note to Gray Oak. The note allowed for borrowing by Gray Oak of up to $123 million at a 2.52% interest rate with a maturity date of March 31, 2022. The short-term promissory note was repaid on May 31, 2019 and was terminated in the third quarter of 2020.

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 and delivery points at multiple Houston area locations (the “Wink to Webster pipeline”). The Wink to Webster pipeline’s main segment began interim service operation in the fourth quarter of 2020, and the joint venture is expected to begin full commercial operations in the fourth quarter of 2021. Upon completion, this pipeline will be capable of transporting approximately 1,500,000 Bbl/d.

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 owns and 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, as well as incremental gas gathering and compression and regional transportation pipelines. However, development of the new processing plant has been postponed pending a recovery in commodity prices and activity levels. The Company has contracted for up to 30,000 Mcf/d of the capacity of the new processing plant pursuant to a gas gathering and processing agreement entered into with the joint venture in exchange for the Company’s dedication of certain leasehold interests to that agreement. 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.

Rattler reviews its investments to determine if a loss in value which is other than temporary has occurred. If such a loss has occurred, Rattler recognizes an impairment provision. No significant impairments were recorded for Rattler’s equity method investments for the year ended December 31, 2020, 2019 or 2018. Rattler’s investees all serve customers in the oil and natural gas industry, which has been experiencing economic challenges as described above. It is possible that prolonged industry challenges could result in circumstances requiring impairment testing, which could result in potentially material impairment charges in future interim periods.

SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

SEGMENT INFORMATION

The Company reports its operations in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which includes midstream services and real estate operations. All of the Company’s equity method investments are included in the midstream operations segment. The segments comprise the structure used by its Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance.

The following tables summarize the results of the Company's operating segments during the periods presented:


	Upstream		Midstream Operations		Eliminations		Total
	(in millions)
Year Ended December 31, 2020:
Third-party revenues	$	2,756	$	57	$	—	$	2,813
Intersegment revenues	—		367		(367)		—
Total revenues	$	2,756	$	424	$	(367)	$	2,813
Lease operating expenses	$	425	$	—	$	—	$	425
Depreciation, depletion and amortization	$	1,251	$	53	$	—	$	1,304
Impairment of oil and natural gas properties	$	6,021	$	—	$	—	$	6,021
Income (loss) from operations	$	(5,562)	$	182	$	(96)	$	(5,476)
Interest expense, net	$	(180)	$	(17)	$	—	$	(197)
Other income (expense)	$	(87)	$	(10)	$	(6)	$	(103)
Provision for (benefit from) income taxes	$	(1,114)	$	10	$	—	$	(1,104)
Net income (loss) attributable to non-controlling interest	$	(190)	$	35	$	—	$	(155)
Net income (loss) attributable to Diamondback Energy, Inc.	$	(4,525)	$	110	$	(102)	$	(4,517)
Total assets	$	16,128	$	1,809	$	(318)	$	17,619


	Upstream		Midstream Operations		Eliminations		Total
	(in millions)
Year Ended December 31, 2019:
Third-party revenues	$	3,891	$	73	$	—	$	3,964
Intersegment revenues	—		375		(375)		—
Total revenues	$	3,891	$	448	$	(375)	$	3,964
Lease operating expenses	$	490	$	—	$	—	$	490
Depreciation, depletion and amortization	$	1,405	$	42	$	—	$	1,447
Impairment of oil and natural gas properties	$	790	$	—	$	—	$	790
Income (loss) from operations	$	790	$	219	$	(314)	$	695
Interest expense, net	$	(171)	$	(1)	$	—	$	(172)
Other income (expense)	$	(149)	$	(6)	$	(6)	$	(161)
Provision for (benefit from) income taxes	$	21	$	26	$	—	$	47
Net income (loss) attributable to non-controlling interest	$	75	$	91	$	(91)	$	75
Net income (loss) attributable to Diamondback Energy, Inc.	$	374	$	95	$	(229)	$	240
Total assets	$	22,125	$	1,636	$	(230)	$	23,531


	Upstream		Midstream Operations		Eliminations		Total
	(in millions)
Year Ended December 31, 2018:
Third-party revenues	$	2,132	$	44	$	—	$	2,176
Intersegment revenues	—		140		(140)		—
Total revenues	$	2,132	$	184	$	(140)	$	2,176
Lease operating expenses	$	205	$	—	$	—	$	205
Depreciation, depletion and amortization	$	598	$	25	$	—	$	623
Income (loss) from operations	$	1,071	$	80	$	(140)	$	1,011
Interest expense, net	$	(87)	$	—	$	—	$	(87)
Other income (expense)	$	189	$	—	$	—	$	189
Provision for (benefit from) income taxes	$	151	$	17	$	—	$	168
Net income (loss) attributable to non-controlling interest	$	99	$	—	$	—	$	99
Net income (loss) attributable to Diamondback Energy, Inc.	$	923	$	63	$	(140)	$	846
Total assets	$	21,096	$	604	$	(104)	$	21,596

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8924-108599

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8981-108599

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 21
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8721-108599

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9031-108599

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (f)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9038-108599

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8933-108599

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8736-108599

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e9054-108599

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8657-108599

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 21
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=120311839&loc=d3e8721-108599

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-URI http://asc.fasb.org/topic&trid=2134510

+ Details

ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2020

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,
	2020		2019
	(in millions)
Asset retirement obligations, beginning of period	$	94	$	136
Additional liabilities incurred	13		8
Liabilities acquired	2		4
Liabilities settled and divested	(8)		(61)
Accretion expense	7		7
Revisions in estimated liabilities	1		—
Asset retirement obligations, end of period	109		94
Less: current portion(1)	1		—
Asset retirement obligations - long-term	$	108	$	94

(1) The current portion of the asset retirement obligation is included in other accrued liabilities in the Company’s consolidated balance sheets.

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.

DERIVATIVES

12 Months Ended

Dec. 31, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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 entered into multiple crude oil, natural gas, natural gas liquids and diesel fuel derivatives, indexed to the respective indices as noted in the table below, to reduce price volatility associated with certain of its oil and natural gas sales.

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, 2020, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed:


					Swaps		Collars
Settlement Month	Settlement Year	Type of Contract	Bbls/Mmbtu/Gallons Per Day	Index	Weighted Average Differential	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Ceiling Price
OIL
Jan. - Mar.	2021	Costless Collars	37,000	WTI Cushing	$—	$—	$34.95	$45.17
Apr. - June	2021	Costless Collars	15,000	WTI Cushing	$—	$—	$33.00	$45.33
July - Dec.	2021	Costless Collars	10,000	WTI Cushing	$—	$—	$30.00	$43.05
Jan. - June	2021	Roll Hedge(2)	12,000	WTI	$(0.07)	$—	$—	$—
Jan. - Mar.	2021	Swaps	5,000	WTI	$—	$45.46	$—	$—
Apr. - June	2021	Swaps	2,000	WTI	$—	$47.35	$—	$—
Jan. - June	2021	Basis Swap	8,000	WTI Midland(1)	$0.52	$—	$—	$—
Jan. - Dec.	2021	Swaps	5,000	WTI Houston Argus	$—	$37.78	$—	$—
Jan. - Dec.	2021	Swaps	5,000	Brent	$—	$41.62	$—	$—
Jan. - Mar.	2021	Costless Collars	82,000	Brent	$—	$—	$39.04	$48.51
Apr. - June	2021	Costless Collars	80,000	Brent	$—	$—	$39.26	$48.62
Jul. - Dec.	2021	Costless Collars	60,000	Brent	$—	$—	$39.43	$48.12
Jul. - Dec.	2021	Swaptions	5,000	Brent	$—	$51.00	$—	$—

NATURAL GAS
Jan. - Dec.	2021	Swaps	200,000	Henry Hub	$—	$2.65	$—	$—
Jan. - Dec.	2021	Basis Swaps	230,000	Waha Hub(1)	$(0.69)	$—	$—	$—
Jan. - Dec.	2022	Basis Swaps	100,000	Waha Hub(1)	$(0.42)	$—	$—	$—

Settlement Month

Settlement Year

Type of Contract

Bbls/Mcf Per Day

Index

Put Price

OIL

Jan. - Dec.

2022

Option

5,000

Brent

$35.00

Interest Rate Swaps


Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.692	%
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.8361	%
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.852	%
Interest Rate Swap	December 31, 2024	December 31, 2054	$	250	1.722	%

See Note 18—Subsequent Events for discussion of derivative transactions which occurred subsequent to December 31, 2020.

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, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 16—Fair Value Measurements for further details.

Gains and Losses on Derivative Instruments

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,
	2020		2019		2018
	(in millions)
Gain (loss) on derivative instruments, net
Commodity contracts	$	(32)	$	(151)	$	101
Interest rate swaps	(49)		43		—
Total	$	(81)	$	(108)	$	101

Net cash received (paid) on settlements
Commodity contracts(1)	250		37		(121)
Interest rate swaps(2)	—		43		—
Total	$	250	$	80	$	(121)

(1)The year ended December 31, 2020 includes cash received on commodity contracts terminated prior to their contractual maturity of $17 million.

(2)The year ended December 31, 2019 includes cash received on interest rate swap contracts terminated prior to their contractual maturity of $43 million.

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenues:
Revenues	$ 2,756	$ 3,887	$ 2,130
Other operating income	7	13	12
Total revenues	2,813	3,964	2,176
Costs and expenses:
Lease operating expenses	425	490	205
Production and ad valorem taxes	195	248	133
Depreciation, depletion and amortization	1,304	1,447	623
Impairment of oil and natural gas properties	6,021	790	0
General and administrative expenses	88	104	65
Asset retirement obligation accretion	7	7	2
Merger and integration expense	0	0	36
Other operating expense	4	4	3
Total costs and expenses	8,289	3,269	1,165
Income (loss) from operations	(5,476)	695	1,011
Other income (expense):
Interest expense, net	(197)	(172)	(87)
Other income (expense), net	2	4	89
Gain (loss) on derivative instruments, net	(81)	(108)	101
Gain (loss) on revaluation of investment	(9)	5	(1)
Loss on extinguishment of debt	(5)	(56)	0
Income (loss) from equity investments	(10)	(6)	0
Total other income (expense), net	(300)	(333)	102
Income (loss) before income taxes	(5,776)	362	1,113
Provision for (benefit from) income taxes	(1,104)	47	168
Net income (loss)	(4,672)	315	945
Net income (loss) attributable to non-controlling interest	(155)	75	99
Net income (loss) attributable to Diamondback Energy, Inc.	$ (4,517)	$ 240	$ 846
Earnings (loss) per common share:
Basic (in dollars per share)	$ (28.59)	$ 1.47	$ 8.09
Diluted (in dollars per share)	$ (28.59)	$ 1.47	$ 8.06
Weighted average common shares outstanding:
Basic (in shares)	157,976	163,493	104,622
Diluted (in shares)	157,976	163,843	104,929
Dividends declared per share (in dollars per share)	$ 1.5250	$ 0.9375	$ 0.50
Oil sales
Revenues:
Revenues	$ 2,410	$ 3,554	$ 1,879
Natural gas sales
Revenues:
Revenues	107	66	61
Natural gas liquid sales
Revenues:
Revenues	239	267	190
Gathering and transportation
Costs and expenses:
Cost of goods and services sold	140	88	26
Midstream services expense
Revenues:
Revenues	50	64	34
Costs and expenses:
Cost of goods and services sold	$ 105	$ 91	$ 72

ACQUISITIONS AND DIVESTITURES - Pro Forma Financial Information (Details) - Energen - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Revenues	$ 3,532	$ 2,196
Pro forma income (loss) from operations	1,559	900
Business Acquisition, Pro Forma 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

DEBT - Viper's Notes (Details) - USD ($) $ in Millions		12 Months Ended
DEBT - Viper's Notes (Details) - USD ($) $ in Millions	Oct. 16, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Proceeds from senior notes		$ 997	$ 3,469	$ 1,062
Long-term debt, gross		$ 5,815	5,371
Viper 5.375% Senior Notes due 2027
Line of Credit Facility [Line Items]
Stated interest rate		5.375%
Viper 5.375% Senior Notes due 2027 \| Viper Energy Partners LP
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 480	$ 500
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
Repurchase of debt		$ 20
Senior Notes \| Viper 5.375% Senior Notes due 2027 \| Viper Energy Partners LP \| Minimum
Line of Credit Facility [Line Items]
Discount percentage		97.50%
Senior Notes \| Viper 5.375% Senior Notes due 2027 \| Viper Energy Partners LP \| Maximum
Line of Credit Facility [Line Items]
Discount percentage		98.50%

DEBT - Diamondback Notes (Details) - USD ($)					12 Months Ended
DEBT - Diamondback Notes (Details) - USD ($)	May 26, 2020	Dec. 20, 2019	Dec. 05, 2019	Jan. 29, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Sep. 25, 2018	Dec. 20, 2016	Oct. 28, 2016
Debt Instrument [Line Items]
Loss on extinguishment of debt					$ (5,000,000)	$ (56,000,000)	$ 0
Proceeds from senior notes					$ 997,000,000	$ 3,469,000,000	$ 1,062,000,000
Existing 2024 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount										$ 500,000,000
Stated interest rate										4.75%
Redemption premium			$ 1,250,000,000
Debt, redemption price, percentage		103.563%
Loss on extinguishment of debt		$ 56,000,000
New 2024 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount								$ 750,000,000
Stated interest rate								4.75%
2.875% Senior Notes due 2024
Debt Instrument [Line Items]
Aggregate principal amount			$ 1,000,000,000.0
Stated interest rate			2.875%		2.875%
Existing 2025 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount									$ 500,000,000
Stated interest rate									5.375%
New 2025 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount				$ 300,000,000
Stated interest rate				5.375%
Proceeds from senior notes				$ 308,000,000
2025 Senior Notes
Debt Instrument [Line Items]
Aggregate principal amount									$ 800,000,000
5.375% Senior Notes due 2025
Debt Instrument [Line Items]
Stated interest rate					5.375%
5.375% Senior Notes due 2025 \| 12-month period beginning on May 31, 2020
Debt Instrument [Line Items]
Debt, redemption price, percentage					104.031%
5.375% Senior Notes due 2025 \| 12-month period beginning on May 31, 2021
Debt Instrument [Line Items]
Debt, redemption price, percentage					102.688%
5.375% Senior Notes due 2025 \| 12-month period beginning on May 31, 2022
Debt Instrument [Line Items]
Debt, redemption price, percentage					101.344%
5.375% Senior Notes due 2025 \| Beginning on May 31, 2023
Debt Instrument [Line Items]
Debt, redemption price, percentage					100.00%
3.250% Senior Notes due 2026
Debt Instrument [Line Items]
Aggregate principal amount			$ 800,000,000
Stated interest rate			3.25%		3.25%
3.500% Senior Notes due 2029
Debt Instrument [Line Items]
Aggregate principal amount			$ 1,200,000,000
Stated interest rate			3.50%		3.50%
Senior Notes \| May 2020 Notes
Debt Instrument [Line Items]
Aggregate principal amount	$ 500,000,000
Stated interest rate	4.75%
Proceeds from senior notes	$ 496,000,000
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%

CAPITAL STOCK AND EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2020

Equity [Abstract]

CAPITAL STOCK AND EARNINGS PER SHARE

The Company did not complete any equity offerings during the years ended December 31, 2020, 2019 and 2018.

Viper Equity Offerings

For information regarding Viper’s completed equity offerings during the years ended December 31, 2019 and 2018, refer to Note 5—Viper Energy Partners LP.

Rattler’s Initial Public Offering

For information regarding Rattler’s initial public offering during the year ended December 31, 2019, refer to Note 6—Rattler Midstream LP.

Stock Repurchase Program

In May 2019, the Company’s board of directors approved a stock repurchase program to acquire up to $2 billion of the Company’s outstanding common stock through December 31, 2020. Purchases under the repurchase program were made from time to time in open market or privately negotiated transactions, and were subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program did not require the Company to acquire any specific number of shares. During the years ended December 31, 2020 and 2019, the Company repurchased $98 million and $598 million, respectively, of its common stock under the repurchase program. The repurchase program was suspended beginning in the first quarter of 2020 and expired on December 31, 2020.

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, the per share earnings of Viper and Rattler are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiaries.

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


	Year Ended December 31,
	2020		2019		2018
	(In millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common stock	$	(4,517)	$	240	$	846
Weighted average common shares outstanding:
Basic weighted average common units outstanding	157,976		163,493		104,622
Effect of dilutive securities:
Potential common shares issuable(1)	—		350		307
Diluted weighted average common shares outstanding	157,976		163,843		104,929
Basic net income (loss) attributable to common stock	$	(28.59)	$	1.47	$	8.09
Diluted net income (loss) attributable to common stock	$	(28.59)	$	1.47	$	8.06

Change in Ownership of Consolidated Subsidiaries

The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period:


	Year Ended December 31,
	2020		2019		2018
	(in millions)
Net income (loss) attributable to the Company	$	(4,517)	$	240	$	846
Change in ownership of consolidated subsidiaries(1)	358		(33)		150
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest	$	(4,159)	$	207	$	996

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	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Noncontrolling Interest [Line Items]
Amount Repaid on Viper LLC’s Credit Facility			$ 1,478	$ 3,718	$ 1,242
Follow-on Public Offering
Noncontrolling Interest [Line Items]
Number of Units of Common Units Sold	10,925,000	10,080,000	0
Amount Repaid on Viper LLC’s Credit Facility	$ 314	$ 362
Follow-on Public Offering \| Viper Energy Partners LP
Noncontrolling Interest [Line Items]
Proceeds Received by Viper	$ 341	$ 303
Over-Allotment Option
Noncontrolling Interest [Line Items]
Number of Units of Common Units Sold	1,425,000	1,080,000

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	Dec. 31, 2020
Accounting Policies [Abstract]
Basis of Presentation	Basis of PresentationThe consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.
Reclassifications	Reclassifications Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.
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. Making accurate estimates and assumptions is particularly difficult as the oil and natural gas industry experiences challenges resulting from negative pricing pressure from the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets. Companies in the oil and natural gas industry have changed near term business plans in response to changing market conditions. The aforementioned circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities assumed, equity-based compensation, fair value estimates of derivative instruments 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.
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. The Company adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications to the rule on January 1, 2020. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for expected losses as estimated by the Company when 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 from joint interest owners or purchasers outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable 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 expected losses.
Derivative Instruments	Derivative InstrumentsThe 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.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $11.30, $13.54 and $12.62 for the years ended December 31, 2020, 2019 and 2018, respectively. Depletion expense for oil and natural gas properties was $1.2 billion, $1.4 billion and $595 million for the years ended December 31, 2020, 2019 and 2018, 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 write-down is required. For additional information regarding the Company’s impairments on proved oil and natural gas properties, see Note 8—Property and Equipment. 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 at least 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 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.
Other Property and Equipment	Other Property, Equipment and Land Other property, equipment and land 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. 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. 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.
Impairment or Long-Lived Assets	Impairment of Long-Lived Assets Other property and equipment used in operations and midstream assets are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset.
Capitalized Interest	Capitalized InterestThe 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.
Inventories	Inventories Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2020 and 2019. 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.
Debt Issuance Costs	Debt Issuance Costs Long-term debt includes capitalized costs related to the senior notes, net of accumulated amortization. The costs associated with the senior notes are netted against the senior notes balances and are amortized over the term of the senior notes using the effective interest method. See Note 11—Debt for further details. The costs associated with the Company’s credit facilities are included in other assets on the consolidated balance sheet and are 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.
Non-controlling Interest	Non-controlling Interests Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur. Because these changes in the ownership interests in Viper and Rattler do not result in a change of control, the transactions are accounted for as equity transactions under ASC Topic 810, “Consolidation”, which requires that any differences between the carrying value of the Company’s basis in Viper and Rattler and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 12—C apital Stock and Earnings Per Share for a discussion of changes of the Company’s ownership interest in consolidated subsidiaries during the year ended December 31, 2020.
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. 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. 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. Prior-period performance obligations The Company records revenue in the month production is delivered to the purchaser. However, purchaser and settlement statements for 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 years ended December 31, 2020, 2019 and 2018 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 An investment of less than 50% in an investee over which the Company exercises significant influence but does not have control is accounted for using the equity method. Additionally, an investment of greater than 50% in an investee over which the Company does not exercise significant influence or have control is also accounted for using the equity method. Under the equity method, the Company’s share of the investee’s earnings or loss is recognized in the consolidated statement of operations. Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions, material intercompany transactions and extent of ownership by an investor in relation to the concentration of other shareholdings. Additionally, an investment in a limited liability company that maintains a specific ownership account for each investor shall be viewed as similar to an investment in a limited partnership for purposes of determining whether a noncontrolling investment shall be accounted for using the cost method or the equity method. The Company has determined it has the ability to exercise significant influence over its investments which constitute less than a 20% ownership interest, and does not have the ability to exercise significant influence over its investments which constitute greater than a 50% ownership interest, and therefore accounts for all of its investments under the equity method. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision.
Accounting for Stock-based Compensation	Accounting for Equity-Based CompensationThe Company has granted various types of stock-based awards including stock options and restricted stock units. Viper and Rattler have granted various unit-based awards including unit options and phantom units to employees, officers and directors of Viper’s General Partner, Rattler’s General Partner and the Company who perform services for the respective entities. These plans and related accounting policies for material awards are defined and described more fully in Note 13—Equity-Based Compensation. Equity compensation awards are measured at fair value on the date of grant and are expensed over the required service period.
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 The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Recently Adopted Pronouncements In June 2016, the Financial Accounting Standards Board (FASB) issued 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. The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on the Company’s financial position, results of operations or liquidity since it does not have a history of credit losses. Accounting Pronouncements Not Yet Adopted In December 2019, the FASB issued 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. 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. The Company considers the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed.
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 in Note 2—Summary of Significant Accounting Policies.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

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.

Making accurate estimates and assumptions is particularly difficult as the oil and natural gas industry experiences challenges resulting from negative pricing pressure from the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets. Companies in the oil and natural gas industry have changed near term business plans in response to changing market conditions. The aforementioned circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.

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

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.

The Company adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications

to the rule on January 1, 2020. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for expected losses as estimated by the Company when 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 from joint interest owners or purchasers outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable 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 expected losses. At December 31, 2020 and 2019, the Company recorded immaterial allowances for credit losses related to joint interest receivables and credit losses related to sales of oil and natural gas production.

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. For additional information regarding the Company’s derivative instruments, see Note 15—Derivative s.

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. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $11.30, $13.54 and $12.62 for the years ended December 31, 2020, 2019 and 2018, respectively. Depletion expense for oil and natural gas properties was $1.2 billion, $1.4 billion and $595 million for the years ended December 31, 2020, 2019 and 2018, 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 write-down is required. For additional information regarding the Company’s impairments on proved oil and natural gas properties, see Note 8—Property and Equipment.

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 at least 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. For additional information regarding the Company’s real estate assets, see Note 7—Real Estate Assets.

Other Property, Equipment and Land

Other property, equipment and land 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

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.

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.

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. For additional information regarding the Company’s asset retirement obligations, see Note 9—Asset Retirement Obligations.

Impairment of Long-Lived Assets

Other property and equipment used in operations and midstream assets 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 significant impairment losses for the years ended December 31, 2020, 2019 and 2018.

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. See Note 11—Debt for further details.

Inventories

Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2020 and 2019. 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.

Debt Issuance Costs

Long-term debt includes capitalized costs related to the senior notes, net of accumulated amortization. The costs associated with the senior notes are netted against the senior notes balances and are amortized over the term of the senior notes using the effective interest method. See Note 11—Debt for further details. The costs associated with the Company’s credit facilities are included in other assets on the consolidated balance sheet and are amortized over the term of the facility.

Other Accrued Liabilities

Other accrued liabilities consist of the following:


	December 31,
	2020		2019
	(In millions)
Lease operating expenses payable	$	115	$	119
Ad valorem taxes payable	57		68
Interest payable	37		27
Derivative liability payable	30		3
Midstream operating expenses payable	18		22
Liability for drilling costs prepaid by joint interest partners	5		12
Other	40		53
Total other accrued liabilities	$	302	$	304

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.

Non-controlling Interests

Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur. Because these changes in the ownership interests in Viper and Rattler do not result in a change of control, the transactions are accounted for as equity transactions under ASC Topic 810, “Consolidation”, which requires that any differences between the carrying value of the Company’s basis in Viper and Rattler and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 12—C apital Stock and Earnings Per Share for a discussion of changes of the Company’s ownership interest in consolidated subsidiaries during the year ended December 31, 2020.

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.

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.

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.

Prior-period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, purchaser and settlement statements for 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 years ended December 31, 2020, 2019 and 2018 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

An investment of less than 50% in an investee over which the Company exercises significant influence but does not have control is accounted for using the equity method. Additionally, an investment of greater than 50% in an investee over which the Company does not exercise significant influence or have control is also accounted for using the equity method. Under the equity method, the Company’s share of the investee’s earnings or loss is recognized in the consolidated statement of operations.

Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions, material intercompany transactions and extent of ownership by an investor in relation to the concentration of other shareholdings. Additionally, an investment in a limited liability company that maintains a specific ownership account for each investor shall be viewed as similar to an investment in a limited partnership for purposes of determining whether a noncontrolling investment shall be accounted for using the cost method or the equity method. The Company has determined it has the ability to exercise significant influence over its investments which constitute less than a 20% ownership interest, and does not have the ability to exercise significant influence over its investments which constitute greater than a 50% ownership interest, and therefore accounts for all of its investments under the equity method.

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 were no material impairments for the Company’s equity investments for the years ended December 31, 2020, 2019 and 2018. For additional information on the Company’s investments, see Note 10—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 and Rattler have granted various unit-based awards including unit options and phantom units to employees, officers and directors of Viper’s General Partner, Rattler’s General Partner and the Company who perform services for the respective entities. These plans and related accounting policies for material awards are defined and described more fully in Note 13—Equity-Based Compensation. Equity compensation awards are measured at fair value on the date of grant and are expensed over the required service period. Forfeitures for these awards are recognized as they occur.

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

The Company 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. For additional information regarding income taxes, see Note 14—Income T axes.

Recent Accounting Pronouncements

Recently Adopted Pronouncements

In June 2016, the Financial Accounting Standards Board (FASB) issued 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. The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on the Company’s financial position, results of operations or liquidity since it does not have a history of credit losses.

Accounting Pronouncements Not Yet Adopted

In December 2019, the FASB issued 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. 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.

The Company considers the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed.

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Acquisition costs:
Proved properties	$ 13	$ 194	$ 5,665
Unproved properties	106	418	5,818
Development costs	381	956	493
Exploration costs	1,098	1,915	1,090
Total	$ 1,598	$ 3,483	$ 13,066

ACQUISITIONS AND DIVESTITURES

12 Months Ended

Dec. 31, 2020

Business Combinations [Abstract]

ACQUISITIONS AND DIVESTITURES

2020 Activity

Viper’s Acquisition of Certain Mineral and Royalty Interests

During the year ended December 31, 2020, Viper acquired, from unrelated third-party sellers, mineral and royalty interests representing 4,948 gross (417 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $64 million, subject to post-closing adjustments. Viper funded these acquisitions with cash on hand and borrowings under Viper LLC’s revolving credit facility.

Pending Acquisitions

See Note 18—Subsequent Events for acquisition agreements entered into in 2020 that are expected to close in 2021.

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 conventional and 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 not 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 not 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 million of Viper’s newly-issued Class B units, approximately 18 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, 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 11—Debt for information relating to this offering.

2018 Drop-down Transaction

On August 15, 2018, the Company completed a transaction to sell 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 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 11—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 revenues of $102 million and direct operating expenses of $17 million in its consolidated statements of operations 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.


	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

VIPER ENERGY PARTNERS LP - Narrative (Details) - USD ($)			1 Months Ended		12 Months Ended
	May 10, 2018	May 09, 2018	Mar. 31, 2019	Jul. 31, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Nov. 06, 2020	Oct. 29, 2020	May 31, 2019
Noncontrolling Interest [Line Items]
Stock repurchase program authorized amount										$ 2,000,000,000
Stock repurchase program amount repurchased					$ 98,000,000	$ 598,000,000
Viper Energy Partners LP \| Diamondback Energy, Inc.
Noncontrolling Interest [Line Items]
Cash distributions paid					$ 62,000,000	$ (133,000,000)	$ (155,000,000)
Common Stock
Noncontrolling Interest [Line Items]
Stock repurchase program authorized amount									$ 100,000,000
Follow-on Public Offering
Noncontrolling Interest [Line Items]
Number of Units of Common Units Sold			10,925,000	10,080,000	0
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
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
Stock repurchase program authorized amount								$ 100,000,000
Stock repurchase program amount repurchased					$ 24,000,000
Stock repurchase remaining authorized amount					$ 76,000,000

INCOME TAXES - Reconciliation of Statutory Federal Income Tax (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income tax expense at the federal statutory rate	$ (1,213)	$ 76	$ 234
Impact of nontaxable noncontrolling interest	0	0	(5)
Income tax benefit relating to net operating loss carryback	(25)	0	0
State income tax expense, net of federal tax effect	(30)	6	8
Non-deductible compensation	6	4	5
Change in valuation allowance	153	0	0
Deferred taxes related to change in Viper LP's tax status	0	(42)	(73)
Other, net	5	3	(1)
Provision for (benefit from) income taxes	$ (1,104)	$ 47	$ 168

SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2020

Segment Reporting [Abstract]

Schedule of results of the company business segments

The following tables summarize the results of the Company's operating segments during the periods presented:


	Upstream		Midstream Operations		Eliminations		Total
	(in millions)
Year Ended December 31, 2020:
Third-party revenues	$	2,756	$	57	$	—	$	2,813
Intersegment revenues	—		367		(367)		—
Total revenues	$	2,756	$	424	$	(367)	$	2,813
Lease operating expenses	$	425	$	—	$	—	$	425
Depreciation, depletion and amortization	$	1,251	$	53	$	—	$	1,304
Impairment of oil and natural gas properties	$	6,021	$	—	$	—	$	6,021
Income (loss) from operations	$	(5,562)	$	182	$	(96)	$	(5,476)
Interest expense, net	$	(180)	$	(17)	$	—	$	(197)
Other income (expense)	$	(87)	$	(10)	$	(6)	$	(103)
Provision for (benefit from) income taxes	$	(1,114)	$	10	$	—	$	(1,104)
Net income (loss) attributable to non-controlling interest	$	(190)	$	35	$	—	$	(155)
Net income (loss) attributable to Diamondback Energy, Inc.	$	(4,525)	$	110	$	(102)	$	(4,517)
Total assets	$	16,128	$	1,809	$	(318)	$	17,619


	Upstream		Midstream Operations		Eliminations		Total
	(in millions)
Year Ended December 31, 2019:
Third-party revenues	$	3,891	$	73	$	—	$	3,964
Intersegment revenues	—		375		(375)		—
Total revenues	$	3,891	$	448	$	(375)	$	3,964
Lease operating expenses	$	490	$	—	$	—	$	490
Depreciation, depletion and amortization	$	1,405	$	42	$	—	$	1,447
Impairment of oil and natural gas properties	$	790	$	—	$	—	$	790
Income (loss) from operations	$	790	$	219	$	(314)	$	695
Interest expense, net	$	(171)	$	(1)	$	—	$	(172)
Other income (expense)	$	(149)	$	(6)	$	(6)	$	(161)
Provision for (benefit from) income taxes	$	21	$	26	$	—	$	47
Net income (loss) attributable to non-controlling interest	$	75	$	91	$	(91)	$	75
Net income (loss) attributable to Diamondback Energy, Inc.	$	374	$	95	$	(229)	$	240
Total assets	$	22,125	$	1,636	$	(230)	$	23,531


	Upstream		Midstream Operations		Eliminations		Total
	(in millions)
Year Ended December 31, 2018:
Third-party revenues	$	2,132	$	44	$	—	$	2,176
Intersegment revenues	—		140		(140)		—
Total revenues	$	2,132	$	184	$	(140)	$	2,176
Lease operating expenses	$	205	$	—	$	—	$	205
Depreciation, depletion and amortization	$	598	$	25	$	—	$	623
Income (loss) from operations	$	1,071	$	80	$	(140)	$	1,011
Interest expense, net	$	(87)	$	—	$	—	$	(87)
Other income (expense)	$	189	$	—	$	—	$	189
Provision for (benefit from) income taxes	$	151	$	17	$	—	$	168
Net income (loss) attributable to non-controlling interest	$	99	$	—	$	—	$	99
Net income (loss) attributable to Diamondback Energy, Inc.	$	923	$	63	$	(140)	$	846
Total assets	$	21,096	$	604	$	(104)	$	21,596

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2020

Accounting Policies [Abstract]

Schedule of other accrued liabilities

Other accrued liabilities consist of the following:


	December 31,
	2020		2019
	(In millions)
Lease operating expenses payable	$	115	$	119
Ad valorem taxes payable	57		68
Interest payable	37		27
Derivative liability payable	30		3
Midstream operating expenses payable	18		22
Liability for drilling costs prepaid by joint interest partners	5		12
Other	40		53
Total other accrued liabilities	$	302	$	304

SEGMENT INFORMATION - Summary of Business Segments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Revenues	$ 2,813	$ 3,964	$ 2,176
Lease operating expenses	425	490	205
Depreciation, depletion and amortization	1,304	1,447	623
Impairment of oil and natural gas properties	6,021	790	0
Income (loss) from operations	(5,476)	695	1,011
Interest expense, net	(197)	(172)	(87)
Other income (expense)	(103)	(161)	189
Provision for (benefit from) income taxes	(1,104)	47	168
Net income (loss) attributable to non-controlling interest	(155)	75	99
Net income (loss) attributable to Diamondback Energy, Inc.	(4,517)	240	846
Total assets	17,619	23,531	21,596
Upstream
Segment Reporting Information [Line Items]
Revenues	2,756	3,891	2,132
Midstream Operations
Segment Reporting Information [Line Items]
Revenues	424	448	184
Operating Segments \| Upstream
Segment Reporting Information [Line Items]
Revenues	2,756	3,891	2,132
Lease operating expenses	425	490	205
Depreciation, depletion and amortization	1,251	1,405	598
Impairment of oil and natural gas properties	6,021	790
Income (loss) from operations	(5,562)	790	1,071
Interest expense, net	(180)	(171)	(87)
Other income (expense)	(87)	(149)	189
Provision for (benefit from) income taxes	(1,114)	21	151
Net income (loss) attributable to non-controlling interest	(190)	75	99
Net income (loss) attributable to Diamondback Energy, Inc.	(4,525)	374	923
Total assets	16,128	22,125	21,096
Operating Segments \| Midstream Operations
Segment Reporting Information [Line Items]
Revenues	57	73	44
Lease operating expenses	0	0	0
Depreciation, depletion and amortization	53	42	25
Impairment of oil and natural gas properties	0	0
Income (loss) from operations	182	219	80
Interest expense, net	(17)	(1)	0
Other income (expense)	(10)	(6)	0
Provision for (benefit from) income taxes	10	26	17
Net income (loss) attributable to non-controlling interest	35	91	0
Net income (loss) attributable to Diamondback Energy, Inc.	110	95	63
Total assets	1,809	1,636	604
Eliminations
Segment Reporting Information [Line Items]
Revenues	(367)	(375)	(140)
Lease operating expenses	0	0	0
Depreciation, depletion and amortization	0	0	0
Impairment of oil and natural gas properties	0	0
Income (loss) from operations	(96)	(314)	(140)
Interest expense, net	0	0	0
Other income (expense)	(6)	(6)	0
Provision for (benefit from) income taxes	0	0	0
Net income (loss) attributable to non-controlling interest	0	(91)	0
Net income (loss) attributable to Diamondback Energy, Inc.	(102)	(229)	(140)
Total assets	$ (318)	$ (230)	$ (104)

ACQUISITIONS AND DIVESTITURES - Estimated Fair Values of Assets Acquired and Liabilities Assumed (Details) - Energen - USD ($) $ in Millions	Nov. 29, 2018	Dec. 31, 2019
Business Acquisition [Line Items]
Consideration	$ 7,136
Fair value of liabilities assumed:
Current liabilities	388
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Asset Retirement Obligation	(105)
Long-term debt	1,099
Noncurrent derivative instruments	17
Business acquisition, deferred tax liabilities	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
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, 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

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

12 Months Ended

Dec. 31, 2020

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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,
	2020		2019
	(In millions)
Oil and natural gas properties:
Proved properties	$	19,884	$	16,575
Unproved properties	7,493		9,207
Total oil and natural gas properties	27,377		25,782
Accumulated depletion	(4,237)		(2,995)
Accumulated impairment	(7,954)		(1,934)
Net oil and natural gas properties capitalized	$	15,186	$	20,853

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,
	2020		2019		2018
	(In millions)
Acquisition costs:
Proved properties	$	13	$	194	$	5,665
Unproved properties	106		418		5,818
Development costs	381		956		493
Exploration costs	1,098		1,915		1,090

Total	$	1,598	$	3,483	$	13,066

Results of Operations from Oil and Natural Gas Producing Activities

For revenues and expenses related to the production and sale of oil, natural gas and natural gas liquids, see the results of the Company's upstream business segment in Note 19—Segment Information.

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2020, 2019 and 2018 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

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

The changes in estimated proved reserves are as follows:


	Oil (MBbls)	Natural Gas Liquids (MBbls)	Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves:
As of 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
Extensions and discoveries	191,009	58,410	316,035
Revisions of previous estimates	(78,244)	21,927	300,160
Purchase of reserves in place	2,124	778	3,512
Divestitures	(209)	(141)	(905)
Production	(66,182)	(21,981)	(130,549)
As of December 31, 2020	759,401	289,196	1,607,064

Proved Developed Reserves:
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
December 31, 2020	443,464	192,495	1,085,035

Proved Undeveloped Reserves:
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
December 31, 2020	315,937	96,701	522,029

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, 2020, the Company’s extensions and discoveries of 302,092 MBOE resulted primarily from the drilling of 682 new wells and from 298 new proved undeveloped locations added. Viper royalty interests accounted for 8% of the extension volumes. The Company’s downward revisions of previous estimates of 6,290 MBOE were the result of negative revisions due to lower product pricing of 54,645 MBOE, which were partially offset by positive revisions of 23,066 MBOE associated with a reduction in lease operating expenses, resulting in a total negative pricing revision of 31,579 MBOE. Downgrades of 31,074 MBOE are primarily from changes in the corporate development plan. These revisions were offset by positive performance revisions of 56,362 MBOE associated with less gas flaring and a corresponding increase in natural gas liquid recoveries.

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. 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 MBOE of working interest purchases, primarily attributable to Energen, and 9,306 MBOE of Viper royalty purchases.

At December 31, 2020, the Company’s estimated PUD reserves were approximately 499,643 MBOE, a 131,784 MBOE increase over the reserve estimate at December 31, 2019 of 367,859 MBOE. The following table includes the changes in PUD reserves for 2020 (MBOE):


Beginning proved undeveloped reserves at December 31, 2019			367,859
Undeveloped reserves transferred to developed			(89,133)
Revisions			(15,742)
Purchases			964
Divestitures			(14)
Extensions and discoveries			235,709
Ending proved undeveloped reserves at December 31, 2020			499,643

The increase in proved undeveloped reserves was primarily attributable to extensions of 220,023 MBOE from 277 gross (236 net) wells in which the Company has a working interest and 15,686 MBOE from 299 gross wells in which Viper owns royalty interests. Of the 277 gross working interest wells, 98 were in the Delaware Basin. Transfers of 89,133 MBOE were the result of drilling or participating in 102 gross (94 net) horizontal wells in which the Company has a working interest and 82 gross wells in which the Company has a royalty interest or mineral interest through Viper. The Company owns a working interest in 78 of the 82 gross Viper wells. Downward revisions of 15,742 MBOE were the result of (i) negative revisions of 4,226 MBOE due to lower product pricing, which were partially offset by positive revisions of 1,494 MBOE associated with a reduction in lease operating expenses, resulting in a total negative pricing revision of 2,732 MBOE, and (ii) PUD downgrades of 26,329 MBOE primarily from changes in the corporate development plan. These revisions were offset with positive performance revisions of 13,319 MBOE associated with less gas flaring and a corresponding increase in shrunk gas and natural gas liquid recoveries.

As of December 31, 2020, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2020, approximately $381 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, 2020, 2019 and 2018.


	December 31,
	2020		2019		2018
	(In millions)
Future cash inflows	$	32,173	$	40,681	$	43,578
Future development costs	(3,585)		(3,809)		(3,560)
Future production costs	(10,763)		(9,319)		(7,727)
Future production taxes	(2,354)		(2,905)		(2,935)
Future income tax expenses	(727)		(2,635)		(3,913)
Future net cash flows	14,744		22,013		25,443
10% discount to reflect timing of cash flows	(7,986)		(11,829)		(13,767)
Standardized measure of discounted future net cash flows(1)	$	6,758	$	10,184	$	11,676

The table below presents the unweighted arithmetic average first-day-of–the-month price for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows.


	December 31,
	2020		2019		2018


Oil (per Bbl)	$	38.06	$	51.88	$	59.63
Natural gas (per Mcf)	$	0.09	$	0.18	$	1.47
Natural gas liquids (per Bbl)	$	10.83	$	15.65	$	24.43

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,
	2020		2019		2018
	(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period	$	10,184	$	11,676	$	3,757
Sales of oil and natural gas, net of production costs	(2,225)		(3,334)		(1,786)
Acquisitions of reserves	30		309		5,520
Divestitures of reserves	(4)		(500)		(2)
Extensions and discoveries, net of future development costs	1,514		4,004		3,287
Previously estimated development costs incurred during the period	704		120		535
Net changes in prices and production costs	(5,273)		831		1,805
Changes in estimated future development costs	526		(3,190)		(81)
Revisions of previous quantity estimates	(462)		(1,242)		271
Accretion of discount	1,126		1,344		380
Net change in income taxes	807		693		(1,728)
Net changes in timing of production and other	(169)		(527)		(282)
Standardized measure of discounted future net cash flows at the end of the period	$	6,758	$	10,184	$	11,676

DERIVATIVES - Interest rate swaps and treasury locks (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Offsetting Assets [Line Items]
Net cash received (paid) on settlements	$ 250	$ 80	$ (121)
Interest Rate Swap One
Offsetting Assets [Line Items]
Notional Amount	$ 250
Interest Rate	1.692%
Interest Rate Swap Two
Offsetting Assets [Line Items]
Notional Amount	$ 250
Interest Rate	1.8361%
Interest Rate Swap Three
Offsetting Assets [Line Items]
Notional Amount	$ 250
Interest Rate	1.852%
Interest Rate Swap Four
Offsetting Assets [Line Items]
Notional Amount	$ 250
Interest Rate	1.722%

Consolidated Statements of Cash Flows - USD ($)
shares in Millions, $ in Millions

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Cash flows from operating activities:

Net income (loss)

$ (4,672)

$ 315

$ 945

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:

Provision for (benefit from) deferred income taxes

(1,042)

168

Impairment of oil and natural gas properties

6,021

790

Depreciation, depletion and amortization

1,304

1,447

623

Loss on early extinguishment of debt

(Gain) loss on derivative instruments, net

108

(101)

Cash received (paid) on settlement of derivative instruments

250

(121)

Equity-based compensation expense

Other

Changes in operating assets and liabilities:

Accounts receivable

217

(187)

Income tax receivable

(62)

Prepaid expenses and other

Accounts payable and accrued liabilities

(20)

(129)

(7)

Revenues and royalties payable

(41)

135

Other

(1)

Net cash (used in) provided by operating activities

2,118

2,739

1,565

Cash flows from investing activities:

Drilling, completions and non-operated additions to oil and natural gas properties

(1,611)

(2,557)

(1,359)

Infrastructure additions to oil and natural gas properties

(108)

(120)

(102)

Additions to midstream assets

(140)

(244)

(204)

Acquisitions of leasehold interests

(119)

(443)

(1,371)

Acquisitions of mineral interests

(66)

(333)

(440)

Funds held in escrow

(51)

Proceeds from sale of assets

300

Investment in real estate

(1)

(111)

Contributions to equity method investments

(102)

(485)

Other

(5)

(7)

Net cash provided by (used in) investing activities

(2,101)

(3,888)

(3,503)

Cash flows from financing activities:

Proceeds from borrowings under credit facilities

1,130

2,350

2,652

Repayments under credit facilities

(1,478)

(3,718)

(1,242)

Repayment on Energen's credit facility

(559)

Proceeds from senior notes

997

3,469

1,062

Repayment of senior notes

(239)

(1,250)

Proceeds from joint venture

Premium on extinguishment of debt

(2)

(44)

Debt issuance costs

(11)

(18)

(25)

Public offering costs

(41)

(3)

Proceeds from public offerings

1,106

305

Repurchased shares under buyback program

(98)

(593)

Repurchased units under buyback program

(39)

Dividends to stockholders

(236)

(112)

(37)

Distributions to non-controlling interest

(93)

(122)

(98)

Other

(8)

(4)

(14)

Net cash (used in) provided by financing activities

(37)

1,062

2,041

Net increase (decrease) in cash and cash equivalents

(20)

(87)

103

Cash, cash equivalents and restricted cash at beginning of period

128

215

112

Cash, cash equivalents and restricted cash at end of period

108

128

215

Supplemental disclosure of cash flow information:

Interest paid, net of capitalized interest

235

237

114

Supplemental disclosure of non-cash transactions:

Accrued capital expenditures

$ 213

$ 553

$ 437

Common stock issued

^[1]

7,136

Asset retirement obligations acquired

$ 2

$ 4

$ 111

Ajax Acquisition

Supplemental disclosure of non-cash transactions:

Common stock issued

340

[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.

INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020, 2019 and 2018 are as follows:


	Year Ended December 31,
	2020		2019		2018
	(In millions)
Current income tax provision (benefit):
Federal	$	(62)	$	—	$	—
State	—		—		—
Total current income tax provision (benefit)	(62)		—		—
Deferred income tax provision (benefit):
Federal	(1,010)		40		160
State	(32)		7		8
Total deferred income tax provision (benefit)	(1,042)		47		168
Total provision for (benefit from) income taxes	$	(1,104)	$	47	$	168

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,
	2020		2019		2018
	(In millions)
Income tax expense at the federal statutory rate (21%)	$	(1,213)	$	76	$	234
Impact of nontaxable noncontrolling interest	—		—		(5)
Income tax benefit relating to net operating loss carryback	(25)		—		—
State income tax expense, net of federal tax effect	(30)		6		8
Non-deductible compensation	6		4		5
Change in valuation allowance	153		—		—
Deferred taxes related to change in Viper LP's tax status	—		(42)		(73)
Other, net	5		3		(1)
Provision for (benefit from) income taxes	$	(1,104)	$	47	$	168

Schedule of deferred tax assets and liabilities

The components of the Company’s deferred tax assets and liabilities as of December 31, 2020 and 2019 are as follows:


	December 31,
	2020		2019
	(In millions)












Deferred tax assets:
Net operating loss and other carryforwards	$	524	$	453
Derivative instruments	60		—
Stock based compensation	7		7

Viper's investment in Viper LLC	150		134
Rattler's investment in Rattler LLC	58		—
Other	8		11
Deferred tax assets	807		605
Valuation allowance	(166)		(7)
Deferred tax assets, net of valuation allowance	641		598
Deferred tax liabilities:
Oil and natural gas properties and equipment	1,156		2,275
Midstream investments	192		50
Derivative instruments	—		6
Rattler's investment in Rattler LLC	—		8
Other	3		3
Total deferred tax liabilities	1,351		2,342
Net deferred tax liabilities	$	710	$	1,744

Schedule of unrecognized tax benefits

The following table sets forth changes in the Company’s unrecognized tax benefits:


	December 31,
	2020		2019
	(in millions)
Balance at beginning of year	$	7	$	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

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Narrative (Details) MBoe in Thousands, Boe in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($) Boe MBoe sWDWell well	Dec. 31, 2019 USD ($) Boe MBoe sWDWell	Dec. 31, 2018 USD ($) Boe MBoe sWDWell
Oil and Gas, Delivery Commitment [Line Items]
Extensions and discoveries (in MBOE)	302,092	376,287	202,089
Oil and gas development well drilled net productive \| sWDWell	682	283	135
Proved undeveloped reserves number of wells added \| sWDWell	298	291	138
Percentage of extension volumes attributable to subsidiary	8.00%	5.00%	10.00%
Revision of previous estimate as result of positive technical and performance revisions (in MBOE)		(117,898)	14,218
Revisions due to higher pricing (in MBOE) \| MBoe			6,032
Revisions from PUD reclassifications due to timing	(6,290)		(4,815)
Lower product pricing	54,645
Reduction in LOE	23,066
Total negative pricing revision	31,579
Change in corporate plan	31,074
Performance revisions	56,362
Increase due to purchase of reserves \| MBoe		21,092	486,992
Purchase of working interest in Reserves		10,939	477,686
Proved undeveloped reserves (energy)	499,643	367,859
Proved undeveloped reserves, increase (energy)	131,784
Extensions and discoveries, working interest (in MBOE) \| MBoe	220,023
Number of horizontal wells developed, working interest gross \| well	277
Number of horizontal wells developed, working interest \| well	236
Proved undeveloped reserves extensions and discoveries mineral interest \| MBoe	15,686
Number of horizontal wells developed, mineral interest \| well	299
Undeveloped reserves transferred to developed	89,133
Number of horizontal wells developed working interest gross \| well	102
Number of horizontal wells developed working interest net \| well	94
Number of horizontal wells developed mineral interest gross \| well	82
Number of horizontal wells developed working and mineral interest \| well	78
Revisions	(15,742)
Revisions from PUD reclassifications due to lower benchmark commodity prices	4,226
Lease operating expenses	1,494
Pricing revision	2,732
Change in corporate plan	26,329
Revisions from PUD reclassifications due to refinement	13,319
Proved undeveloped reserves, planned development period	5 years
Capital expenditures towards development of proved undeveloped reserves \| $	$ 381	$ 956	$ 493
Delaware Basin
Oil and Gas, Delivery Commitment [Line Items]
Number of horizontal wells developed working interest \| well	98
Viper Energy Partners LP
Oil and Gas, Delivery Commitment [Line Items]
Royalty purchases		10,153	9,306

VIPER ENERGY PARTNERS LP (Tables)

12 Months Ended

Dec. 31, 2020

Noncontrolling Interest [Abstract]

Schedule of sale of stock

Viper completed the following equity offerings during the years ended December 31, 2019 and 2018:


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)
July 2018	10,080,000	1,080,000	$	303	$	362
March 2019	10,925,000	1,425,000	$	341	$	314

There were no equity offerings during the year ended December 31, 2020.

SEGMENT INFORMATION - Additional Information (Details)	12 Months Ended
SEGMENT INFORMATION - Additional Information (Details)	Dec. 31, 2020 segment
Segment Reporting [Abstract]
Number of business segments	2

EQUITY-BASED COMPENSATION - Restricted Stock Units (Narratives) (Details) - Restricted Stock Units (RSUs) - Equity Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregated fair value of restricted stock	$ 25	$ 45	$ 19
Share based award not recognized	$ 41
Unrecognized compensation cost, expected period of recognition	2 years 3 months 18 days

FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2020

Fair Value Disclosures [Abstract]

Schedule of fair value measurement information for financial instruments measured on a recurring basis


	As of December 31, 2020
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(in millions)
Assets:
Current:

Derivative Instruments	$	—	$	43	$	—	$	43	$	(42)	$	1

Non-current:

Derivative Instruments	$	—	$	187	$	—	$	187	$	(187)	$	—

Liabilities:
Current:
Derivative Instruments	$	—	$	291	$	—	$	291	$	(42)	$	249

Non-current:
Derivative Instruments	$	—	$	244	$	—	$	244	$	(187)	$	57


	As of December 31, 2019
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(in millions)
Assets:
Current:

Derivative Instruments	$	—	$	64	$	—	$	64	$	(18)	$	46

Non-current:
Investment	$	19	$	—	$	—	$	19	$	—	$	19
Derivative Instruments	$	—	$	7	$	—	$	7	$	—	$	7

Liabilities:
Current:
Derivative Instruments	$	—	$	45	$	—	$	45	$	(18)	$	27

Offsetting Assets


	As of December 31, 2020
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(in millions)
Assets:
Current:

Derivative Instruments	$	—	$	43	$	—	$	43	$	(42)	$	1

Non-current:

Derivative Instruments	$	—	$	187	$	—	$	187	$	(187)	$	—

Liabilities:
Current:
Derivative Instruments	$	—	$	291	$	—	$	291	$	(42)	$	249

Non-current:
Derivative Instruments	$	—	$	244	$	—	$	244	$	(187)	$	57


	As of December 31, 2019
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(in millions)
Assets:
Current:

Derivative Instruments	$	—	$	64	$	—	$	64	$	(18)	$	46

Non-current:
Investment	$	19	$	—	$	—	$	19	$	—	$	19
Derivative Instruments	$	—	$	7	$	—	$	7	$	—	$	7

Liabilities:
Current:
Derivative Instruments	$	—	$	45	$	—	$	45	$	(18)	$	27

Offsetting Liabilities


	As of December 31, 2020
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(in millions)
Assets:
Current:

Derivative Instruments	$	—	$	43	$	—	$	43	$	(42)	$	1

Non-current:

Derivative Instruments	$	—	$	187	$	—	$	187	$	(187)	$	—

Liabilities:
Current:
Derivative Instruments	$	—	$	291	$	—	$	291	$	(42)	$	249

Non-current:
Derivative Instruments	$	—	$	244	$	—	$	244	$	(187)	$	57


	As of December 31, 2019
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(in millions)
Assets:
Current:

Derivative Instruments	$	—	$	64	$	—	$	64	$	(18)	$	46

Non-current:
Investment	$	19	$	—	$	—	$	19	$	—	$	19
Derivative Instruments	$	—	$	7	$	—	$	7	$	—	$	7

Liabilities:
Current:
Derivative Instruments	$	—	$	45	$	—	$	45	$	(18)	$	27

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, 2020				December 31, 2019
	Carrying				Carrying
	Value(1)		Fair Value		Value(1)		Fair Value
	(in millions)
Debt:
Revolving credit facility	$	23	$	23	$	13	$	13
4.625% Notes due 2021	$	191	$	193	$	399	$	411
7.320% Medium-term Notes, Series A, due 2022	$	21	$	22	$	21	$	22
2.875% Senior Notes due 2024	$	993	$	1,053	$	992	$	1,012
4.750% Senior Notes due 2025	$	496	$	565	$	—	$	—
5.375% Senior Notes due 2025	$	799	$	824	$	799	$	840
3.250% Senior Notes due 2026	$	793	$	857	$	792	$	812
7.350% Medium-term Notes, Series A, due 2027	$	—	$	—	$	11	$	12
7.125% Medium-term Notes, Series B, due 2028	$	107	$	119	$	108	$	116
3.500% Senior Notes due 2029	$	1,187	$	1,286	$	1,186	$	1,226
Viper revolving credit facility	$	84	$	84	$	97	$	97
Viper's 5.375% Senior Notes due 2027	$	472	$	501	$	490	$	521
Rattler revolving credit facility	$	79	$	79	$	424	$	424
Rattler’s 5.625% Senior Notes due 2025	$	491	$	528	$	—	$	—
DrillCo Agreement	$	79	$	79	$	39	$	39

(1)The carrying value includes associated deferred loan costs and any remaining discount or premium.

DEBT - Interest Expense (Details) - USD ($) $ in Millions	12 Months Ended
DEBT - Interest Expense (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
Interest expense	$ 250	$ 235	$ 110
Other fees and expenses	6	4	10
Less: interest income	4	1	1
Less: capitalized interest	55	66	32
Interest expense, net	$ 197	$ 172	$ 87

DERIVATIVES - Open Derivative Positions (Details)	12 Months Ended
DERIVATIVES - Open Derivative Positions (Details)	Dec. 31, 2020 MMBTU $ / bbl $ / MMBTU bbl
OIL \| Jan. - Mar. \| Costless Collars \| WTI Cushing
Derivative [Line Items]
Volume (Bbls) \| bbl	37,000
Derivative, Floor Price	34.95
Derivative, Cap Price	45.17
OIL \| Jan. - Mar. \| Costless Collars \| Brent
Derivative [Line Items]
Volume (Bbls) \| bbl	82,000
Derivative, Floor Price	39.04
Derivative, Cap Price	48.51
OIL \| Jan. - Mar. \| Swaps \| WTI
Derivative [Line Items]
Volume (Bbls) \| bbl	5,000
Weighted Average Differential	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	45.46
OIL \| Jan. - June \| Rolling Hedge \| WTI
Derivative [Line Items]
Volume (Bbls) \| bbl	12,000
Weighted Average Differential	(0.07)
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	0
OIL \| Jan. - June \| Basis Swap \| WTI
Derivative [Line Items]
Volume (Bbls) \| bbl	8,000
Weighted Average Differential	0.52
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	0
OIL \| Jan. - Dec. \| Swaps \| WTI Houston Argus
Derivative [Line Items]
Volume (Bbls) \| bbl	5,000
Weighted Average Differential	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	37.78
OIL \| Jan. - Dec. \| Swaps \| Brent
Derivative [Line Items]
Volume (Bbls) \| bbl	5,000
Weighted Average Differential	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	41.62
OIL \| Apr. - June \| Costless Collars \| WTI Cushing
Derivative [Line Items]
Volume (Bbls) \| bbl	15,000
Derivative, Floor Price	33.00
Derivative, Cap Price	45.33
OIL \| Apr. - June \| Costless Collars \| Brent
Derivative [Line Items]
Volume (Bbls) \| bbl	80,000
Derivative, Floor Price	39.26
Derivative, Cap Price	48.62
OIL \| Apr. - June \| Swaps \| WTI
Derivative [Line Items]
Volume (Bbls) \| bbl	2,000
Weighted Average Differential	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	47.35
OIL \| July - Dec. \| Costless Collars \| WTI Cushing
Derivative [Line Items]
Volume (Bbls) \| bbl	10,000
Derivative, Floor Price	30.00
Derivative, Cap Price	43.05
OIL \| July - Dec. \| Costless Collars \| Brent
Derivative [Line Items]
Volume (Bbls) \| bbl	60,000
Derivative, Floor Price	39.43
Derivative, Cap Price	48.12
OIL \| July - Dec. \| Swaptions \| Brent
Derivative [Line Items]
Volume (Bbls) \| bbl	5,000
Weighted Average Differential	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	51.00
OIL \| Jan -Dec 2022 \| Option \| Brent
Derivative [Line Items]
Volume (Bbls) \| bbl	5,000
Derivative, Put Price	35.00
NATURAL GAS \| Jan. - Dec. \| Swaps \| Henry Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) \| MMBTU	200,000
Weighted Average Differential \| $ / MMBTU	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) \| $ / MMBTU	2.65
NATURAL GAS \| Jan. - Dec. \| Basis Swap \| Waha Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) \| MMBTU	230,000
Weighted Average Differential \| $ / MMBTU	(0.69)
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) \| $ / MMBTU	0
NATURAL GAS \| Jan -Dec 2022 \| Basis Swap \| Waha Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) \| MMBTU	100,000
Weighted Average Differential \| $ / MMBTU	(0.42)
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) \| $ / MMBTU	0

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Changes in ARO liability
Asset retirement obligations, beginning of period	$ 94	$ 136
Additional liabilities incurred	13	8
Liabilities acquired	2	4	$ 111
Liabilities settled and divested	(8)	(61)
Accretion expense	7	7	2
Revisions in estimated liabilities	1	0
Asset retirement obligations, end of period	109	94	$ 136
Less: current portion(1)	1	0
Asset retirement obligations - long-term	$ 108	$ 94

DERIVATIVES - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments, net	$ (81)	$ (108)	$ 101
Net cash received (paid) on settlements	250	80	(121)
Cash received on contract	17
Commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments, net	(32)	(151)	101
Net cash received (paid) on settlements	250	37	(121)
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments, net	(49)	43	0
Net cash received (paid) on settlements	$ 0	$ 43	$ 0

EQUITY METHOD INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2020

Equity Method Investments and Joint Ventures [Abstract]

Equity method investments

At December 31, 2020 and 2019, Rattler had the following investments:


	Ownership Interest		December 31, 2020		December 31, 2019
			(in millions)
EPIC Crude Holdings, LP	10	%	$	121	$	110
Gray Oak Pipeline, LLC	10	%	130		115
Wink to Webster Pipeline LLC	4	%	83		34
OMOG JV LLC	60	%	194		219
Amarillo Rattler, LLC	50	%	5		1
Total			$	533	$	479

The following summarizes the income (loss) of equity method investees for the periods presented:


	Year Ended December 31,
	2020		2019
	(in millions)
EPIC Crude Holdings, LP	$	(9)	$	(6)
Gray Oak Pipeline, LLC	10		1
Wink to Webster Pipeline LLC	(2)		(1)
OMOG JV LLC	(9)		—

Total	$	(10)	$	(6)

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Lease operating expenses payable	$ 115	$ 119
Ad valorem taxes payable	57	68
Interest payable	37	27
Derivative liability payable	30	3
Midstream operating expenses payable	18	22
Liability for drilling costs prepaid by joint interest partners	5	12
Other	40	53
Total other accrued liabilities	$ 302	$ 304

RATTLER MIDSTREAM LP (Details) - USD ($)		12 Months Ended
RATTLER MIDSTREAM LP (Details) - USD ($)	May 28, 2019	Dec. 31, 2020	Dec. 31, 2019	Oct. 29, 2020	May 31, 2019
Noncontrolling Interest [Line Items]
Limited partners capital contribution	$ 1,000,000
Stock repurchase program authorized amount					$ 2,000,000,000
Stock repurchase program amount repurchased		$ 98,000,000	$ 598,000,000
Common Stock
Noncontrolling Interest [Line Items]
Stock repurchase program authorized amount				$ 100,000,000
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
Rattler MIdstream LP \| Class B Units
Noncontrolling Interest [Line Items]
Limited partners' capital account, units issued (in Shares)	107,815,152
Rattler MIdstream LP \| Common Stock
Noncontrolling Interest [Line Items]
Stock repurchase program amount repurchased		15,000,000
Stock repurchase remaining authorized amount		$ 85,000,000
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
Noncontrolling Interest [Line Items]
Ownership percentage	29.00%	72.00%
Limited partners ownership percentage	71.00%

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) - Proved Undeveloped Reserves (Details) Boe in Thousands	12 Months Ended
	Dec. 31, 2020 Boe
Proved Undeveloped Reserves (Energy)
Beginning proved undeveloped reserves at December 31, 2019	367,859
Undeveloped reserves transferred to developed	(89,133)
Revisions	(15,742)
Purchases	964
Divestitures	(14)
Extensions and discoveries	235,709
Ending proved undeveloped reserves at December 31, 2020	499,643

REVENUE FROM CONTRACTS WITH CUSTOMERS

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

REVENUE FROM CONTRACTS WITH CUSTOMERS

Disaggregation of Revenue

The following tables present the Company’s revenue from contracts with customers disaggregated by product type and basin:


	Year Ended December 31, 2020
	Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	1,393	$	1,011	$	6	$	2,410
Natural gas sales	56		50		1		107
Natural gas liquid sales	138		100		1		239

Total	$	1,587	$	1,161	$	8	$	2,756


	Year Ended December 31, 2019
	Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	2,139	$	1,351	$	64	$	3,554
Natural gas sales	32		33		1		66
Natural gas liquid sales	154		110		3		267

Total	$	2,325	$	1,494	$	68	$	3,887


	Year Ended December 31, 2018
	Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	1,350	$	508	$	21	$	1,879
Natural gas sales	38		22		1		61
Natural gas liquid sales	140		47		3		190

Total	$	1,528	$	577	$	25	$	2,130

Customers

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, 2020, four purchasers each accounted for more than 10% of our revenue: Vitol Inc. (“Vitol”) (26%); Shell Trading (USA) Company (“Shell”) (22%); Plains Marketing LP (“Plains”) (20%); and Trafigura Trading LLC (11%). For the year ended December 31, 2019, three purchasers each accounted for more than 10% of the Company’s 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 Supply & Trading LP (15%); and Occidental Energy Marketing Inc. (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.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI http://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130550-203045

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (e)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (c)
-URI http://asc.fasb.org/extlink&oid=121604090&loc=SL49130554-203045

+ Details

DEBT (Tables)

12 Months Ended

Dec. 31, 2020

Debt Disclosure [Abstract]

Schedule of long-term debt

The Company’s debt consisted of the following as of the dates indicated:


	December 31,
	2020		2019
	(in millions)
4.625% Notes due 2021	$	191	$	399
7.320% Medium-term Notes, Series A, due 2022	20		21
2.875% Senior Notes due 2024	1,000		1,000
4.750% Senior Notes due 2025	500		—
5.375% Senior Notes due 2025	800		800
3.250% Senior Notes due 2026	800		800

7.350% Medium-term Notes, Series A, due 2027	—		11
7.125% Medium-term Notes, Series B, due 2028	100		108
3.500% Senior Notes due 2029	1,200		1,200
DrillCo Agreement	79		39
Unamortized debt issuance costs	(29)		(19)
Unamortized discount costs	(27)		(31)
Unamortized premium costs	15		9
Revolving credit facility(1)	23		13
Viper revolving credit facility(1)	84		97
Viper 5.375% Senior Notes due 2027	480		500
Rattler revolving credit facility(2)	79		424
Rattler 5.625% Senior Notes due 2025	500		—
Total debt, net	5,815		5,371
Less: current maturities of long-term debt	(191)		—
Total long-term debt	$	5,624	$	5,371

(1) Each of these revolving credit facilities matures on November 1, 2022.

(2) The Rattler revolving credit facility matures on May 28, 2024.

Schedule of maturities of long-term debt

Debt maturities as of December 31, 2020, excluding debt issuance costs, premiums and discounts, are as follows:


Year Ending December 31,	Total
	(in millions)
2021	$	191
2022	127
2023	—
2024	1,079
2025	1,800
Thereafter	2,659
Total	$	5,856

Financial covenants


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 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

Schedule of interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2020, 2019 and 2018:


	Year Ended December 31,
	2020		2019		2018
	(in millions)
Interest expense	$	250	$	235	$	110
Other fees and expenses	6		4		10
Less: interest income	4		1		1
Less: capitalized interest	55		66		32
Interest expense, net	$	197	$	172	$	87

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=120391452&loc=d3e13212-122682

Reference 2: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=119993939&loc=d3e28541-108399

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21506-112644

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=120395691&loc=d3e23780-122690

Reference 5: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=119993939&loc=d3e28551-108399

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21521-112644

Reference 7: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21538-112644

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=75038535&loc=d3e64711-112823

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=114775985&loc=d3e28878-108400

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=109259400&loc=d3e21475-112644

+ Details

DEBT - Schedule of Long-term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2019	Dec. 05, 2019
Debt Instrument [Line Items]
Long-term debt, gross	$ 5,815		$ 5,371
Unamortized debt issuance costs	(29)		(19)
Unamortized discount costs	(27)		(31)
Unamortized premium costs	15		9
Less: current maturities of long-term debt	(191)		0
Total debt, net	5,624		5,371
4.625% Notes due 2021
Debt Instrument [Line Items]
Long-term debt, gross	$ 191		399
Stated interest rate	4.625%
7.320% Medium-term Notes, Series A, due 2022
Debt Instrument [Line Items]
Long-term debt, gross	$ 20		21
Stated interest rate	7.32%
2.875% Senior Notes due 2024
Debt Instrument [Line Items]
Long-term debt, gross	$ 1,000		1,000
Stated interest rate	2.875%			2.875%
4.750% Senior Notes due 2025
Debt Instrument [Line Items]
Long-term debt, gross	$ 500		0
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		800
Stated interest rate	3.25%			3.25%
7.350% Medium-term Notes, Series A, due 2027
Debt Instrument [Line Items]
Long-term debt, gross	$ 0		11
Stated interest rate	7.35%	7.35%
7.125% Medium-term Notes, Series B, due 2028
Debt Instrument [Line Items]
Long-term debt, gross	$ 100		108
Stated interest rate	7.125%
3.500% Senior Notes due 2029
Debt Instrument [Line Items]
Long-term debt, gross	$ 1,200		1,200
Stated interest rate	3.50%			3.50%
DrillCo Agreement
Debt Instrument [Line Items]
Long-term debt, gross	$ 79		39
Revolving credit facility(1)
Debt Instrument [Line Items]
Long-term debt, gross	23		13
Viper revolving credit facility(1) \| Viper Energy Partners LP
Debt Instrument [Line Items]
Long-term debt, gross	$ 84		97
Viper 5.375% Senior Notes due 2027
Debt Instrument [Line Items]
Stated interest rate	5.375%
Viper 5.375% Senior Notes due 2027 \| Viper Energy Partners LP
Debt Instrument [Line Items]
Long-term debt, gross	$ 480		500
Rattler revolving credit facility(2)
Debt Instrument [Line Items]
Long-term debt, gross	$ 79		424
Rattler 5.625% Senior Notes due 2025
Debt Instrument [Line Items]
Stated interest rate	5.625%
Rattler 5.625% Senior Notes due 2025 \| Rattler LLC
Debt Instrument [Line Items]
Long-term debt, gross	$ 500		$ 0

PROPERTY AND EQUIPMENT (Details) - USD ($) $ in Millions	12 Months Ended
PROPERTY AND EQUIPMENT (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and natural gas properties:
Subject to depletion	$ 19,884	$ 16,575
Not subject to depletion	7,493	9,207
Gross oil and natural gas properties	27,377	25,782
Accumulated depletion and depreciation	(12,314)	(5,003)
Accumulated impairment	(7,954)	(1,934)
Oil and natural gas properties, net	15,186	20,853
Midstream assets	1,013	931
Other property, equipment and land	138	125
Total property and equipment, net	16,214	21,835
Capitalized internal costs	$ 53	49	$ 29
Timing of inclusion of costs in amortization calculation	5 years
Impairment of oil and natural gas properties	$ 6,021	790	0
Exploration costs or development costs not subject to depletion	85	228
Capitalized interest not subject to depletion	51	118
Oil and Gas Properties
Oil and natural gas properties:
Subject to depletion	19,884	16,575
Not subject to depletion	7,493	9,207
Gross oil and natural gas properties	27,377	25,782
Accumulated depletion and depreciation	(4,237)	(2,995)
Accumulated impairment	(7,954)	(1,934)
Oil and natural gas properties, net	15,186	20,853
Balance of costs not subject to depletion	71	421	$ 5,090	$ 1,682	$ 229
Other Property and Equipment, Net
Oil and natural gas properties:
Accumulated depletion and depreciation	(123)	(74)
Other property, equipment and land	$ 138	$ 125

REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)

12 Months Ended

Dec. 31, 2020

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following tables present the Company’s revenue from contracts with customers disaggregated by product type and basin:


	Year Ended December 31, 2020
	Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	1,393	$	1,011	$	6	$	2,410
Natural gas sales	56		50		1		107
Natural gas liquid sales	138		100		1		239

Total	$	1,587	$	1,161	$	8	$	2,756


	Year Ended December 31, 2019
	Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	2,139	$	1,351	$	64	$	3,554
Natural gas sales	32		33		1		66
Natural gas liquid sales	154		110		3		267

Total	$	2,325	$	1,494	$	68	$	3,887


	Year Ended December 31, 2018
	Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	1,350	$	508	$	21	$	1,879
Natural gas sales	38		22		1		61
Natural gas liquid sales	140		47		3		190

Total	$	1,528	$	577	$	25	$	2,130

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, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Future cash inflows	$ 32,173	$ 40,681	$ 43,578
Future development costs	(3,585)	(3,809)	(3,560)
Future production costs	(10,763)	(9,319)	(7,727)
Future production taxes	(2,354)	(2,905)	(2,935)
Future income tax expenses	(727)	(2,635)	(3,913)
Future net cash flows	14,744	22,013	25,443
10% discount to reflect timing of cash flows	(7,986)	(11,829)	(13,767)
Standardized measure of discounted future net cash flows(1)	6,758	10,184	11,676	$ 3,757
Oil and Gas, Delivery Commitment [Line Items]
Standardized measure of discounted future net cash flows(1)	$ 6,758	10,184	11,676	$ 3,757
Viper Energy Partners LP
Oil and Gas, Delivery Commitment [Line Items]
Noncontrolling interest, ownership percentage	42.00%
Viper Energy Partners LP
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]
Standardized measure of discounted future net cash flows(1)	$ 1,000	1,300	1,100
Oil and Gas, Delivery Commitment [Line Items]
Standardized measure of discounted future net cash flows(1)	$ 1,000	$ 1,300	$ 1,100

VIPER ENERGY PARTNERS LP

12 Months Ended

Dec. 31, 2020

Noncontrolling Interest [Abstract]

VIPER ENERGY PARTNERS LP

Viper completed the following equity offerings during the years ended December 31, 2019 and 2018:


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)
July 2018	10,080,000	1,080,000	$	303	$	362
March 2019	10,925,000	1,425,000	$	341	$	314

There were no equity offerings during the year ended December 31, 2020.

Recapitalization, Tax Status Election and Related Transactions by Viper

Implementation of Viper’s Common Unit Repurchase Program

Viper LLC’s Revolving Credit Facility

RATTLER MIDSTREAM LP

Implementation of Rattler’s Common Unit Repurchase Program

Rattler LLC’s Revolving Credit Facility

COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2020

Commitments and Contingencies Disclosure [Abstract]

Future Minimum 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, 2020:


Year Ending December 31,	Transportation Commitments(1)		Sand Supply Agreement(2)		Produced Water Disposal Commitments(3)
	(in millions)
2021	$	60	$	18	$	5
2022	60		18		5
2023	51		18		5
2024	48		18		5
2025	47		18		5
Thereafter	133		5		31
Total	$	399	$	95	$	56

(3)Rattler entered into a minimum volume commitment to purchase produced water disposal services under a 14 year agreement beginning in 2021.

Delivery Commitment

At December 31, 2020, the Company’s delivery commitments covered the following gross volumes of oil:


Year Ending December 31,			Oil Volume Commitments (Bbl/d)
2021			175,000
2022			175,000
2023			175,000
2024			125,000
2025			125,000
Thereafter			400,000
Total			1,175,000

INCOME TAXES - Components of Income Tax Provision (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current income tax provision (benefit):
Federal	$ (62)	$ 0	$ 0
State	0	0	0
Total current income tax provision (benefit)	(62)	0	0
Deferred income tax provision (benefit):
Federal	(1,010)	40	160
State	(32)	7	8
Total deferred income tax provision (benefit)	(1,042)	47	168
Provision for (benefit from) income taxes	$ (1,104)	$ 47	$ 168

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

DEBT - Financial Covenant Table (Details)	12 Months Ended
DEBT - Financial Covenant Table (Details)	Dec. 31, 2020
Maximum \| Rattler revolving credit facility(2)
Line of Credit Facility [Line Items]
Line of credit, covenant terms, consolidated total leverage ratio	5.00
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	3.50
Maximum \| Viper revolving credit facility(1)
Line of Credit Facility [Line Items]
Ratio of total net debt to EBITDAX, as defined in the credit agreement	4.0
Minimum \| Rattler revolving credit facility(2)
Line of Credit Facility [Line Items]
Line of credit facility, covenant terms ratio of consolidated interest coverage	2.50
Minimum \| Viper revolving credit facility(1)
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement	1.0

EQUITY-BASED COMPENSATION - Rattler Long-Term Incentive Plan (Details) - Phantom Share Units (PSUs) - Rattler Midstream LP Long-Term Incentive Plan	12 Months Ended
	Dec. 31, 2020 $ / shares shares
Restricted Stock Awards & Units
Unvested, beginning balance (in shares) \| shares	2,226,895
Granted (in shares) \| shares	348,379
Vested (in shares) \| shares	(460,781)
Forfeited (in shares) \| shares	(24,825)
Unvested, ending balance (in shares) \| shares	2,089,668
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Unvested, beginning balance (in dollars per share) \| $ / shares	$ 19.14
Granted (in dollars per share) \| $ / shares	6.51
Vested (in dollars per share) \| $ / shares	19.06
Forfeited (in dollars per share) \| $ / shares	17.54
Unvested, ending balance (in dollars per share) \| $ / shares	$ 17.07

DEBT - Second Amended and Restated Credit Facility (Details)	12 Months Ended
	Dec. 31, 2020 USD ($) letter	Dec. 31, 2019 USD ($)	Dec. 31, 2018
Line of Credit Facility [Line Items]
Outstanding borrowings	$ 5,815,000,000	$ 5,371,000,000
Revolving credit facility(1)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	2,000,000,000.0
Outstanding borrowings	23,000,000	$ 13,000,000
Remaining borrowing capacity	$ 1,980,000,000
Number of letters of credit outstanding \| letter	3,000,000
Weighted average interest rate	2.02%	4.10%	3.75%
Debt covenant, total net debt to capitalization ratio	65.00%
Debt covenant, debt principal amount as percentage of net tangible assets	15.00%
Revolving credit facility(1) \| Federal Funds Rate
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.50%
Revolving credit facility(1) \| LIBOR
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Revolving credit facility(1) \| Investment Grade Annually \| Minimum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.125%
Revolving credit facility(1) \| Investment Grade Annually \| Maximum
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.35%
Revolving credit facility(1) \| Investment Grade Annually \| Base Rate \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	0.125%
Revolving credit facility(1) \| Investment Grade Annually \| Base Rate \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.00%
Revolving credit facility(1) \| Investment Grade Annually \| LIBOR \| Minimum
Line of Credit Facility [Line Items]
Basis spread on variable rate	1.125%
Revolving credit facility(1) \| Investment Grade Annually \| LIBOR \| Maximum
Line of Credit Facility [Line Items]
Basis spread on variable rate	2.00%

FAIR VALUE MEASUREMENTS - Nonrecurring Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2019	Dec. 05, 2019
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 2025
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%	7.35%
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%
Rattler 5.625% Senior Notes due 2025
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Stated interest rate	5.625%
Reported Value Measurement \| Revolving credit facility(1) \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	$ 23		$ 13
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	191		399
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		21
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	993		992
Reported Value Measurement \| 4.750% Senior Notes due 2025 \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	496		0
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	793		792
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	0		11
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	107		108
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	1,187		1,186
Reported Value Measurement \| Viper revolving credit facility(1) \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	84		97
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	472		490
Reported Value Measurement \| Rattler revolving credit facility(2) \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	79		424
Reported Value Measurement \| Rattler 5.625% Senior Notes due 2025 \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	491		0
Reported Value Measurement \| DrillCo Agreement \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt, fair value	79		39
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	193		411
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		22
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	0		12
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	119		116
Estimate of Fair Value Measurement \| Rattler 5.625% Senior Notes due 2025 \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	528		0
Estimate of Fair Value Measurement \| DrillCo Agreement \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt, fair value	79		39
Level 1 \| Estimate of Fair 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	1,053		1,012
Level 1 \| Estimate of Fair Value Measurement \| 4.750% Senior Notes due 2025 \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	565		0
Level 1 \| Estimate of Fair 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	824		840
Level 1 \| Estimate of Fair 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	857		812
Level 1 \| Estimate of Fair 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	1,286		1,226
Level 1 \| Estimate of Fair 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	501		521
Level 2 \| Estimate of Fair Value Measurement \| Revolving credit facility(1) \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	23		13
Level 2 \| Estimate of Fair Value Measurement \| Viper revolving credit facility(1) \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	84		97
Level 2 \| Estimate of Fair Value Measurement \| Rattler revolving credit facility(2) \| Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	$ 79		$ 424