10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-35700

Diamondback Energy, Inc.

(Exact Name of Registrant As Specified in Its Charter)

DE		45-4502447
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification Number)
500 West Texas
Suite 1200
Midland,	TX	79701
(Address of principal executive offices)		(Zip code)

(432) 221-7400

(Registrant’s telephone number, including area code)

 Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock	FANG	The Nasdaq Stock Market LLC
		(NASDAQ Global Select Market)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check One):

Large Accelerated Filer	☒	Accelerated Filer	☐
Non-Accelerated Filer	☐	Smaller Reporting Company	☐
		Emerging Growth Company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐     No  ☒ 

As of October 30, 2020, the registrant had 157,972,650 shares of common stock outstanding.

DIAMONDBACK ENERGY, INC.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2020

TABLE OF CONTENTS

	Page
Glossary of Oil and Natural Gas Terms	ii
Glossary of Certain Other Terms	iv
Cautionary Statement Regarding Forward-Looking Statements	v
PART I. FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)	1
Condensed Consolidated Balance Sheets	1
Condensed Consolidated Statements of Operations	3
Condensed Consolidated Statements of Stockholders’ Equity	4
Condensed Consolidated Statements of Cash Flows	6
Condensed Notes to Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3. Quantitative and Qualitative Disclosures About Market Risk	49
Item 4. Controls and Procedures	50
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	51
Item 1A. Risk Factors	51
Item 6. Exhibits	52
Signatures	53

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a glossary of certain oil and natural gas industry terms that are used in this Quarterly Report on Form 10-Q (this “report”):

Basin	A large depression on the earth’s surface in which sediments accumulate.
Bbl or barrel	One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BOE	One barrel of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d	BOE per day.
British Thermal Unit or Btu	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion	The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Crude oil	Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Finding and development costs	Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
Gross acres or gross wells	The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.
Horizontal wells	Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
MBbl	One thousand barrels of crude oil and other liquid hydrocarbons.
MBOE/d	One thousand BOE per day.
Mcf	One thousand cubic feet of natural gas.
Mcf/d	One thousand cubic feet of natural gas per day.
Mineral interests	The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu	One million British Thermal Units.
Net acres or net wells	The sum of the fractional working interest owned in gross acres.
Oil and natural gas properties	Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Operator	The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Plugging and abandonment	Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Prospect	A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved reserves	The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Reserves	The estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

ii

Reservoir	A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Royalty interest	An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development, which may be subject to expiration.
Spacing	The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
Working interest	An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

iii

GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms that are used in this report.

ASU	Accounting Standards Update
Equity Plan	The Company’s Equity Incentive Plan.
Exchange Act	The Securities Exchange Act of 1934, as amended.
FASB	Financial Accounting Standards Board
GAAP	Accounting principles generally accepted in the United States.
2025 Indenture	The indenture relating to the 2025 Senior Notes (defined below), dated as of December 20, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
2025 Senior Notes	The Company’s 5.375% Senior Notes due 2025 in the aggregate principal amount of $800 million
December 2019 Notes	The Company’s 2.875% Senior Notes due 2024 in the aggregate principal amount of $1 billion, the Company’s 3.250% Senior Notes due 2026 in the aggregate principal amount of $800 million and the Company’s 3.500% Senior Notes due 2029 in the aggregate principal amount of $1.2 billion.
December 2019 Notes Indenture	The 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 and the second supplemental indenture dated as of May 26, 2020, relating to the December 2019 Notes (defined above) and the May 2020 Notes (defined below).
May 2020 Notes	The Company’s 4.750% Senior Notes due 2025 in the aggregate principal amount of $500.0 million issued on May 26, 2020 under the December 2019 Notes Indenture (defined above) and the related second supplemental indenture.
NYMEX	New York Mercantile Exchange.
Rattler	Rattler Midstream LP, a Delaware limited partnership.
Rattler’s General Partner	Rattler Midstream GP LLC, a Delaware limited liability company; the general partner of Rattler Midstream LP and a wholly-owned subsidiary of the Company.
Rattler LLC	Rattler Midstream Operating LLC, a Delaware limited liability company and a subsidiary of Rattler.
Rattler LTIP	Rattler Midstream LP Long-Term Incentive Plan.
Rattler Offering	Rattler’s initial public offering.
Rattler’s Partnership Agreement	The first amended and restated agreement of limited partnership, dated May 28, 2019.
SEC	United States Securities and Exchange Commission.
Securities Act	The Securities Act of 1933, as amended.
Senior Notes	The 2025 Senior Notes, the December 2019 Notes and the May 2020 Notes.
Viper	Viper Energy Partners LP, a Delaware limited partnership.
Viper’s General Partner	Viper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.
Viper LLC	Viper Energy Partners LLC, a Delaware limited liability company and a subsidiary of the Partnership.
Viper LTIP	Viper Energy Partners LP Long Term Incentive Plan.
Viper Offering	Viper’s initial public offering.
Viper’s Partnership Agreement	The second amended and restated agreement of limited partnership, dated May 9, 2018, as amended as of May 10, 2018.
Wells Fargo	Wells Fargo Bank, National Association.

iv

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this report and detailed under Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, 2019 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements. Unless the context requires otherwise, references to “we,” “us,” “our” or the “Company” are intended to mean the business and operations of the Company and its consolidated subsidiaries.

Forward-looking statements may include statements about:

•the volatility of realized oil and natural gas prices and the extent and duration of price reductions and increased production by the Organization of the Petroleum Exporting Counties, or OPEC, members and other oil exporting nations;

•the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the ongoing COVID-19 pandemic or any government responses to such threat, occurrence or pandemic;

•any impact of the ongoing COVID-19 pandemic on the health and safety of our employees;

•logistical challenges and the supply chain disruptions;

•changes in general economic, business or industry conditions;

•conditions in the capital, financial and credit markets and our ability to obtain capital needed for development and exploration operations on favorable terms or at all;

•conditions of the U.S. oil and natural gas industry and the effect of U.S. energy, monetary and trade policies;

•U.S. and global economic conditions and political and economic developments, including the outcome of the recent U.S. presidential election and resulting energy and environmental policies;

•our ability to execute our business and financial strategies;

•exploration and development drilling prospects, inventories, projects and programs;

•levels of production;

•the impact of reduced drilling activity;

•regional supply and demand factors, delays, curtailments or interruptions of production, and any governmental order, rule or regulation that may impose production limits;

•our ability to replace our oil and natural gas reserves;

•our ability to identify, complete and effectively integrate acquisitions of properties or businesses;

•competition in the oil and natural gas industry;

•title defects in our oil and natural gas properties;

•uncertainties with respect to identified drilling locations and estimates of reserves;

•the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel;

v

•restrictions on the use of water;

•the availability of transportation, pipeline and storage facilities;

•our ability to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

•federal and state legislative and regulatory initiatives relating to hydraulic fracturing;

•future operating results;

•impact of any impairment charges;

•lease operating expenses, general and administrative costs and finding and development costs;

•operating hazards;

•civil unrest, terrorist attacks and cyber threats;

•the effects of future litigation;

•our ability to keep up with technological advancements;

•capital expenditure plans;

•other plans, objectives, expectations and intentions; and

•certain other factors discussed elsewhere in this report.

All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

vi

PART I. FINANCIAL INFORMATION

ITEM 1.     CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(Unaudited)
	September 30,		December 31,
	2020		2019
	(In millions, except par values and share data)
Assets
Current assets:
Cash and cash equivalents	$	92	$	123
Restricted cash	7		5
Accounts receivable:
Joint interest and other, net	67		186
Oil and natural gas sales, net	224		429
Inventories	33		37
Derivative instruments	15		46
Income tax receivable	100		19
Prepaid expenses and other current assets	20		24
Total current assets	558		869
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($7,879 million and $9,207 million excluded from amortization at September 30, 2020 and December 31, 2019, respectively)	27,305		25,782
Midstream assets	1,026		931
Other property, equipment and land	135		125
Accumulated depletion, depreciation, amortization and impairment	(11,031)		(5,003)
Property and equipment, net	17,435		21,835
Equity method investments	532		479
Derivative instruments	—		7
Deferred tax assets, net	75		142
Investment in real estate, net	104		109
Other assets	56		90
Total assets	$	18,760	$	23,531

See accompanying notes to condensed consolidated financial statements.

1

Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets-(Continued)

(Unaudited)

	September 30,		December 31,
	2020		2019
	(In millions, except par values and share data)
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable - trade	$	95	$	179
Accrued capital expenditures	309		475
Current maturities of long-term debt	191		—
Other accrued liabilities	329		304
Revenues and royalties payable	219		278
Derivative instruments	86		27
Total current liabilities	1,229		1,263
Long-term debt	5,656		5,371
Derivative instruments	108		—
Asset retirement obligations	112		94
Deferred income taxes	978		1,886
Other long-term liabilities	8		11
Total liabilities	8,091		8,625
Commitments and contingencies (Note 17)
Stockholders’ equity:
Common stock, $0.01 par value; 200,000,000 shares authorized; 157,849,848 and 159,002,338 shares issued and outstanding at September 30, 2020 and December 31, 2019, respectively	2		2
Additional paid-in capital	12,615		12,357
Retained earnings (accumulated deficit)	(3,065)		890
Total Diamondback Energy, Inc. stockholders’ equity	9,552		13,249
Non-controlling interest	1,117		1,657
Total equity	10,669		14,906
Total liabilities and equity	$	18,760	$	23,531

See accompanying notes to condensed consolidated financial statements.

2

Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(In millions, except per share amounts, shares in thousands)
Revenues:
Oil sales	$	606	$	882	$	1,785	$	2,572
Natural gas sales	36		16		61		36
Natural gas liquid sales	65		58		156		190
Lease bonus	—		1		—		4
Midstream services	12		16		37		51
Other operating income	1		2		5		7
Total revenues	720		975		2,044		2,860
Costs and expenses:
Lease operating expenses	102		128		332		364
Production and ad valorem taxes	55		61		148		180
Gathering and transportation	33		25		105		54
Midstream services	26		26		81		60
Depreciation, depletion and amortization	286		365		1,036		1,046
Impairment of oil and natural gas properties	1,451		—		4,999		—
General and administrative expenses	20		19		64		68
Asset retirement obligation accretion	2		1		5		6
Other operating expense	1		1		4		3
Total costs and expenses	1,976		626		6,774		1,781
Income (loss) from operations	(1,256)		349		(4,730)		1,079
Other income (expense):
Interest expense, net	(53)		(38)		(147)		(133)
Other income, net	—		2		1		5
Gain (loss) on derivative instruments, net	(99)		177		82		3
Gain (loss) on revaluation of investment	(2)		—		(9)		4
Loss on extinguishment of debt	(2)		—		(5)		—
Income (loss) from equity investments	3		—		(10)		—
Total other income (expense), net	(153)		141		(88)		(121)
Income (loss) before income taxes	(1,409)		490		(4,818)		958
Provision for (benefit from) income taxes	(304)		102		(902)		171
Net income (loss)	(1,105)		388		(3,916)		787
Net income (loss) attributable to non-controlling interest	8		20		(138)		60
Net income (loss) attributable to Diamondback Energy, Inc.	$	(1,113)	$	368	$	(3,778)	$	727
Earnings (loss) per common share:
Basic	$	(7.05)	$	2.27	$	(23.91)	$	4.44
Diluted	$	(7.05)	$	2.26	$	(23.91)	$	4.42
Weighted average common shares outstanding:
Basic	157,833		162,543		157,984		164,070
Diluted	157,833		162,780		157,984		164,466
Dividends declared per share	$	0.375	$	0.1875	$	1.125	$	0.5625

See accompanying notes to condensed consolidated financial statements.

3

Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity

(Unaudited)

	Common Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Non-Controlling Interest		Total
	Shares	Amount
	($ in millions, shares in thousands)
Balance December 31, 2019	159,002	$	2	$	12,357	$	890	$	1,657	$	14,906
Unit-based compensation	—	—		—		—		5		5
Distribution equivalent rights payments	—	—		—		—		(1)		(1)
Stock-based compensation	—	—		10		—		—		10
Repurchased shares for tax withholding	(75)	—		(5)		—		—		(5)
Repurchased shares for share buyback program	(1,280)	—		(98)		—		—		(98)
Distribution to non-controlling interest	—	—		—		—		(43)		(43)
Dividend paid	—	—		—		(59)		—		(59)
Exercise of stock options and vesting of restricted stock units	168	—		1		—		—		1
Net income (loss)	—	—		—		(272)		(128)		(400)
Balance March 31, 2020	157,815	2		12,265		559		1,490		14,316
Distribution equivalent rights payments	—	—		—		—		(1)		(1)
Stock-based compensation	—	—		11		—		—		11
Repurchased shares for tax withholding	—	—		—		—		(2)		(2)
Distribution to non-controlling interest	—	—		—		—		(19)		(19)
Dividend paid	—	—		—		(59)		—		(59)
Exercise of stock options and vesting of restricted stock units	9	—		—		—		—		—
Change in ownership of consolidated subsidiaries, net	—	—		329		—		(329)		—
Net income (loss)	—	—		—		(2,393)		(18)		(2,411)
Balance June 30, 2020	157,824	2		12,605		(1,893)		1,121		11,835
Unit-based compensation	—	—		—		—		3		3
Stock-based compensation	—	—		10		—		—		10
Repurchased shares for tax withholding	(1)	—		—		—		—		—
Distribution to non-controlling interest	—	—		—		—		(15)		(15)
Dividend paid	—	—		—		(59)		—		(59)
Exercise of stock options and vesting of restricted stock units	27	—		—		—		—		—
Net income (loss)	—	—		—		(1,113)		8		(1,105)
Balance September 30, 2020	157,850	$	2	$	12,615	$	(3,065)	$	1,117	$	10,669

See accompanying notes to condensed consolidated financial statements.

4

Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity

(Unaudited)

	Common Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Non-Controlling Interest		Total
	Shares	Amount
	($ in millions, shares in thousands)
Balance December 31, 2018	164,273	$	2	$	12,936	$	762	$	467	$	14,167
Net proceeds from issuance of common units - Viper Energy Partners LP	—	—		—		—		341		341
Stock-based compensation	—	—		19		—		—		19
Repurchased shares for tax withholding	(125)	—		(13)		—		—		(13)
Distribution to non-controlling interest	—	—		—		—		(26)		(26)
Dividend paid	—	—		—		(20)		—		(20)
Exercise of stock options and vesting of restricted stock units	468	—		—		—		—		—
Change in ownership of consolidated subsidiaries, net	—	—		77		—		(74)		3
Net income (loss)	—	—		—		10		33		43
Balance March 31, 2019	164,616	2		13,019		752		741		14,514
Net proceeds from issuance of common units - Viper Energy Partners LP	—	—		—		—		720		720
Unit-based compensation	—	—		—		—		2		2
Stock-based compensation	—	—		12		—		—		12
Repurchased shares for share buyback program	(1,016)	—		(104)		—		—		(104)
Distribution to non-controlling interest	—	—		—		—		(24)		(24)
Dividend paid	—	—		—		(32)		—		(32)
Exercise of stock options and vesting of restricted stock units	349	—		6		—		—		6
Net income (loss)	—	—		—		349		7		356
Balance June 30, 2019	163,949	2		12,933		1,069		1,446		15,450
Unit-based compensation	—	—		—		—		2		2
Stock-based compensation	—	—		1		—		—		1
Repurchased shares for share buyback program	(2,954)	—		(296)		—		—		(296)
Distribution to non-controlling interest	—	—		—		—		(29)		(29)
Dividend paid	—	—		—		(30)		—		(30)
Exercise of stock options and vesting of restricted stock units	147	—		3		—		—		3
Net income (loss)	—	—		—		368		20		388
Balance September 30, 2019	161,142	$	2	$	12,641	$	1,407	$	1,439	$	15,489

See accompanying notes to condensed consolidated financial statements.

5

Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended September 30,
	2020		2019
	(In millions)
Cash flows from operating activities:
Net income (loss)	$	(3,916)	$	787
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes	(902)		171
Impairment of oil and natural gas properties	4,999		—
Depreciation, depletion and amortization	1,036		1,046
(Gain) loss on derivative instruments, net	(82)		(3)
Cash received on settlement of derivative instruments	288		33
Other	68		34
Changes in operating assets and liabilities:
Accounts receivable	265		(116)
Accounts payable and accrued liabilities	(18)		(136)
Accrued interest	34		(29)
Revenues and royalties payable	(59)		64
Other	2		1
Net cash provided by (used in) operating activities	1,715		1,852
Cash flows from investing activities:
Drilling, completions and non-operated additions to oil and natural gas properties	(1,404)		(1,883)
Infrastructure additions to oil and natural gas properties	(96)		(104)
Additions to midstream assets	(133)		(186)
Acquisitions of leasehold interests	(89)		(311)
Acquisitions of mineral interests	(65)		(320)
Proceeds from sale of assets	2		301
Contributions to equity method investments	(90)		(225)
Distributions from equity method investments	27		—
Other	(7)		(16)
Net cash provided by (used in) investing activities	(1,855)		(2,744)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	917		1,409
Repayments under credit facility	(1,238)		(1,168)
Proceeds from senior notes	997		—
Repayment of senior notes	(239)		—
Proceeds from joint venture	47		42
Public offering costs	—		(40)
Proceeds from public offerings	—		1,106
Repurchased shares as part of share buyback	(98)		(400)
Dividends to stockholders	(177)		(82)
Distributions to non-controlling interest	(77)		(79)
Other	(21)		(11)
Net cash provided by (used in) financing activities	111		777
Net increase (decrease) in cash and cash equivalents	(29)		(115)
Cash, cash equivalents and restricted cash at beginning of period	128		215
Cash, cash equivalents and restricted cash at end of period	$	99	$	100
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	100	$	115
Accrued capital expenditures	$	352	$	560

See accompanying notes to condensed consolidated financial statements.

6

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements

(Unaudited)

1.    DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Organization and Description of the Business

Diamondback Energy, Inc., together with its subsidiaries (collectively referred to as “Diamondback” or the “Company” unless the context otherwise requires), is an independent oil and gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on December 30, 2011.

The wholly-owned subsidiaries of Diamondback, as of September 30, 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, Rattler Midstream GP LLC, a Delaware limited liability company, 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’s subsidiary Viper Energy Partners LLC, a Delaware limited liability company, Rattler Midstream LP, a Delaware limited partnership, Rattler Midstream Operating LLC, a Delaware limited liability company, 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, and Energen’s wholly-owned subsidiaries Energen Resources Corporation, an Alabama corporation, and EGN Services, Inc., an Alabama corporation.

Basis of Presentation

The condensed 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 September 30, 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 September 30, 2020, the Company owned approximately 71% 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.

These condensed consolidated financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to SEC rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2019, which contains a summary of the Company’s significant accounting policies and other disclosures.

2.    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.

7

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 gas markets. Companies in the oil and 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.

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 deemed 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. The adoption of ASU 2016-13 did not result in a material change to the Company’s allowance. At September 30, 2020 and December 31, 2019, the Company recorded an immaterial allowance for expected losses.

Non-controlling Interest

Non-controlling interest in the accompanying condensed consolidated financial statements represents minority interest ownership in Viper and Rattler. 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.

In the second quarter of 2020, the Company recorded 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. See Note 11—Capital Stock and Earnings Per Share for a presentation of the change in ownership.

8

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Recent Accounting Pronouncements

The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Company’s analysis of the effects on its financial statements:

Standard	Description	Date of Adoption	Effect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 2016-13, “Financial Instruments - Credit Losses”	This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash.	Q1 2020	The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”	This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.	Q1 2021	This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company does not believe that the adoption of this update will have an impact on its financial position, results of operations or liquidity.

3.    REVENUE FROM CONTRACTS WITH CUSTOMERS

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

	Three Months Ended September 30, 2020								Three Months Ended September 30, 2019
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	348	$	257	$	1	$	606	$	529	$	350	$	3	$	882
Natural gas sales	19		17		—		36		7		8		1		16
Natural gas liquid sales	36		28		1		65		33		25		—		58
Total	$	403	$	302	$	2	$	707	$	569	$	383	$	4	$	956

9

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

	Nine Months Ended September 30, 2020								Nine Months Ended September 30, 2019
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	1,030	$	750	$	5	$	1,785	$	1,561	$	951	$	60	$	2,572
Natural gas sales	32		29		—		61		17		18		1		36
Natural gas liquid sales	88		67		1		156		110		78		2		190
Total	$	1,150	$	846	$	6	$	2,002	$	1,688	$	1,047	$	63	$	2,798

4.    DIVESTITURES

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, 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, 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 18.3 million of Viper’s newly-issued Class B units, approximately 18.3 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits (the “Drop-Down”). The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by the Company, and have an average net royalty interest of approximately 3.2% (the “Drop-Down Assets”). The Drop-Down closed on October 1, 2019 and was effective as of July 1, 2019. Viper funded the cash portion of the purchase price of the Drop-Down Assets through a combination of cash on hand and borrowings under Viper LLC’s revolving credit facility.

5.    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 September 30, 2020, Diamondback owned approximately 71% of Rattler’s total units outstanding.

Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May 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 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. Diamondback, as the holder of the Class B units, and Rattler’s General Partner, as the holder of the general partner interest, are

10

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1 million capital contributions, payable quarterly.

6.    REAL ESTATE ASSETS    

The following schedule presents the cost and related accumulated depreciation of the Company’s real estate assets. The Company’s intangible lease assets and related accumulated amortization were immaterial as of September 30, 2020 and December 31, 2019.

	Estimated Useful Lives	September 30, 2020		December 31, 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		(12)		(9)
Total investment in land and buildings, net		$	98	$	101

7.    PROPERTY AND EQUIPMENT

Property and equipment includes the following as of the dates indicated:

	September 30,		December 31,
	2020		2019
	(in millions)
Oil and natural gas properties:
Subject to depletion	$	19,426	$	16,575
Not subject to depletion	7,879		9,207
Gross oil and natural gas properties	27,305		25,782
Accumulated depletion	(3,988)		(2,995)
Accumulated impairment	(6,933)		(1,934)
Oil and natural gas properties, net	16,384		20,853
Midstream assets	1,026		931
Other property, equipment and land	135		125
Accumulated depreciation	(110)		(74)
Total property and equipment, net	$	17,435	$	21,835

Under the full cost 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 proved oil and natural gas properties. As a result of the sharp decline in commodity prices which began during the first quarter of 2020 and continued for most of the second and third quarters of 2020, the Company recorded non-cash ceiling test impairments for the three months and nine months ended September 30, 2020 of $1.5 billion and $5.0 billion, respectively, which were included in accumulated depletion. The impairment charge affected the Company’s results of operations 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. No impairment on proved oil and natural gas properties was recorded for the three months or nine months ended September 30, 2019. Given the rate of change impacting the oil and 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.

11

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Capitalized internal costs were approximately $14 million and $8 million for the three months ended September 30, 2020 and 2019, respectively, and $42 million and $32 million for the nine months ended September 30, 2020 and 2019, 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. Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any of the acreage, associated with acquisition costs not currently being amortized, expire based on current drilling plans.

8.    ASSET RETIREMENT OBLIGATIONS

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

	Nine Months Ended September 30,
	2020		2019
	(in millions)
Asset retirement obligations, beginning of period	$	94	$	136
Additional liabilities incurred	12		6
Liabilities acquired	3		3
Liabilities settled	(1)		(61)
Accretion expense	5		6
Asset retirement obligations, end of period	113		90
Less current portion(1)	1		—
Asset retirement obligations - long-term	$	112	$	90

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

9.    EQUITY METHOD INVESTMENTS

The following table presents the carrying values of Rattler’s equity method investments as of the dates indicated:

	Ownership Interest		September 30, 2020		December 31, 2019
			(in millions)
EPIC Crude Holdings, LP	10	%	$	123	$	110
Gray Oak Pipeline, LLC	10	%	135		115
Wink to Webster Pipeline LLC	4	%	75		34
OMOG JV LLC	60	%	195		219
Amarillo Rattler, LLC	50	%	4		1
Total			$	532	$	479

12

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The following table presents income (loss) from Rattler’s equity method investees reflected in the Condensed Consolidated Statement of Operations for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
EPIC Crude Holdings, LP	$	(2)	$	—	$	(5)	$	—
Gray Oak Pipeline, LLC	4		—		6		—
OMOG JV LLC	1		—		(11)		—
Total	$	3	$	—	$	(10)	$	—

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 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 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 2.52% interest rate with a maturity date of March 31, 2022. The short-term promissory note was repaid on May 31, 2019.

On June 4, 2019, Rattler entered into an equity contribution agreement with respect to Gray Oak. The equity contribution agreement required Rattler to contribute equity or make loans to Gray Oak so that Gray Oak can, to the extent necessary, cure payment defaults under Gray Oak’s credit agreement and, in certain instances, repay Gray Oak’s credit agreement in full. Rattler’s obligations under the equity contribution agreement were limited to its proportionate ownership interest in Gray Oak, and such obligations were guaranteed by Rattler LLC, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. The equity contribution agreement and Rattler’s obligations under the agreement were terminated in September 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 for delivery to multiple Houston area locations (the “Wink to Webster pipeline”). The Wink to Webster pipeline is expected to begin service in the first half of 2021.

On October 1, 2019, Rattler LLC acquired a 60% equity interest in OMOG JV LLC (“OMOG”). On November 7, 2019, OMOG acquired 100% of Reliance Gathering, LLC which owns and operates a crude oil gathering system in the Permian Basin, and was renamed as Oryx Midland Oil Gathering LLC following the acquisition.

On December 20, 2019, Rattler LLC acquired a 50% equity interest in Amarillo Rattler, LLC (“Amarillo Rattler”), 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. Amarillo Rattler 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 Amarillo Rattler in exchange for the Company’s dedication of certain leasehold interests to that agreement.

13

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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. During the nine months ended September 30, 2020, Rattler’s loss from equity method investments includes a proportional charge of $16 million representing impairment recorded by the investee associated with its goodwill. During the three months and nine months ended September 30, 2020, Rattler’s loss from equity method investment includes an immaterial abandonment charge related to a project that is no longer expected to be completed. No other impairments were recorded for Rattler’s equity method investments for the three or nine months ended September 30, 2020 or 2019. Rattler’s investees all serve customers in the oil and gas industry, which has begun to experience 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.

10.    DEBT

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

	September 30,		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	86		39
Unamortized debt issuance costs	(30)		(19)
Unamortized discount costs	(28)		(31)
Unamortized premium costs	16		9
Revolving credit facility(1)	—		13
Viper revolving credit facility(1)	127		97
Viper 5.375% Senior Notes due 2027	480		500
Rattler revolving credit facility(2)	85		424
Rattler 5.625% Senior Notes due 2025	500		—
Total debt, net	5,847		5,371
Less: current maturities of long-term debt	(191)		—
Total long-term debt	$	5,656	$	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.

References in this section to the Company shall mean Diamondback Energy, Inc. and Diamondback O&G LLC, collectively, unless otherwise specified.

14

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

May 2020 Senior Notes

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.

Second Amended and Restated Credit Facility

Diamondback O&G LLC, as borrower, and Diamondback Energy, Inc., as parent guarantor, 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 the Company’s unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied, which changes became effective on November 20, 2019. As of September 30, 2020, the maximum credit amount available under the credit agreement was $2 billion. As of September 30, 2020, the Company had no outstanding borrowings under its revolving credit facility and $2.0 billion available for future borrowings under the revolving credit facility. As of September 30, 2020, there was an aggregate of $3 million in outstanding letters of credit, which reduce the amount available under the credit agreement on a dollar-for-dollar basis. The weighted average interest rate on the credit facility was 1.83% and 2.27% for the three months and nine months ended September 30, 2020, respectively.

As of September 30, 2020, the Company was in compliance with all financial maintenance covenants under the revolving credit facility.

Energen’s Notes

Energen became a wholly owned subsidiary of the Company at the effective time of the merger and remained the issuer of an aggregate principal amount of $530 million in notes (the “Energen Notes”). As of September 30, 2020, the Energen Notes consist 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 7.350% 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.

15

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined semi-annually in May and November. 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 reduced from $775 million to $580 million during the regularly scheduled (semi-annual) spring 2020 redetermination in the second quarter of 2020, and is expected to be reaffirmed at $580 million by the lenders during the regularly scheduled (semi-annual) fall 2020 redetermination in November 2020. As of September 30, 2020, Viper LLC had $127 million of outstanding borrowings and $453 million available for future borrowings under the Viper credit agreement. The weighted average interest rate on the credit facility was 2.14% and 2.66% for the three months and nine months ended September 30, 2020, respectively. The revolving credit facility will mature on November 1, 2022.

As of September 30, 2020, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement.

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 net proceeds of approximately $490 million from the offering of the Viper Notes. Viper loaned the gross proceeds to Viper LLC. Viper LLC used the proceeds from the notes offering to pay down borrowings under its revolving credit facility. During the three months and nine months ended September 30, 2020, Viper repurchased $6 million and $20 million, respectively of the outstanding principal amount of Viper Notes in open market purchases 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. The repurchase brought the total outstanding principal amount of Viper Notes down to $480 million as of September 30, 2020.

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, which is expandable to $1 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of September 30, 2020, Rattler LLC had $85 million of outstanding borrowings and $515 million available for future borrowings under the Rattler credit agreement. The weighted average interest rate on the credit facility was 1.46% and 2.18% for the three months and nine months ended September 30, 2020, respectively.

As of September 30, 2020, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

See Note 18—Subsequent Events for a description of the amendment to the Rattler credit agreement which occurred subsequent to September 30, 2020.

Rattler’s Notes

On July 14, 2020, Rattler completed an offering (the “Notes Offering”) of $500 million in aggregate principal amount of its 5.625% Senior Notes due 2025 (the “Rattler Notes”). Interest on the Rattler Notes is payable on January 15 and July 15 of each year, beginning on January 15, 2021. The Rattler Notes mature on July 15, 2025. Rattler received net proceeds of approximately $490 million from the Notes Offering. Rattler loaned the gross proceeds to Rattler LLC, which Rattler LLC used 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 it may incur 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

16

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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.

Alliance with Obsidian Resources, L.L.C.

Diamondback O&G LLC 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 September 30, 2020 and December 31, 2019, CEMOF’s return related to this alliance was $86 million and $39 million, respectively. As of September 30, 2020, 15 joint wells have been drilled and completed.

11.    CAPITAL STOCK AND EARNINGS PER SHARE

Diamondback did not complete any equity offerings during the nine months ended September 30, 2020 and September 30, 2019.

Rattler’s Initial Public Offering

Please see Note 5—Rattler Midstream LP for information regarding the Rattler Offering.

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 may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the three months ended September 30, 2020, the Company repurchased no common stock under this repurchase program. During the nine months ended September 30, 2020, the Company repurchased approximately $98 million of common stock under this repurchase program. As of September 30, 2020, $1.3 billion remained available for use to repurchase shares under the Company's common stock repurchase program, although the Company has suspended this program to preserve liquidity.

Earnings (Loss) Per Share

The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the diluted earnings per share computation, the per share earnings of Viper and Rattler are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiary.

17

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	($ in millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common stock	$	(1,113)	$	368	$	(3,778)	$	727
Weighted average common shares outstanding:
Basic weighted average common units outstanding	157,833		162,543		157,984		164,070
Effect of dilutive securities:
Potential common shares issuable(1)	—		237		—		396
Diluted weighted average common shares outstanding	157,833		162,780		157,984		164,466
Basic net income (loss) attributable to common stock	$	(7.05)	$	2.27	$	(23.91)	$	4.44
Diluted net income (loss) attributable to common stock	$	(7.05)	$	2.26	$	(23.91)	$	4.42

(1)    For the three and nine months ended September 30, 2020, no potential common units were included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive. For the three months and nine months ended September 30, 2019, there were 50,814 and 40,291 potential common units excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive under the treasury stock method.

Change in Ownership of Consolidated Subsidiaries

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Net income (loss) attributable to the Company	$	(1,113)	$	368	$	(3,778)	$	727
Change in ownership of consolidated subsidiaries	—		—		329		77
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest	$	(1,113)	$	368	$	(3,449)	$	804

12.    EQUITY-BASED COMPENSATION

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
General and administrative expenses	$	9	$	4	$	27	$	27
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	4		(1)		12		9

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Restricted Stock Units

The following table presents the Company’s restricted stock units activity under the Equity Plan during the nine months ended September 30, 2020:

	Restricted Stock Awards & Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	505,867	$	96.01
Granted	183,102	$	60.72
Vested	(139,355)	$	85.21
Forfeited	(19,228)	$	99.01
Unvested at September 30, 2020	530,386	$	86.55

The aggregate fair value of restricted stock units that vested during the nine months ended September 30, 2020 and 2019 was $12 million and $4 million, respectively. As of September 30, 2020, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $27 million, which is expected to be recognized over a weighted-average period of 1.7 years.

During the nine months ended September 30, 2020, the Company modified an insignificant amount of restricted stock units to include dividend equivalent rights during the vesting period which resulted in no incremental compensation costs to be recognized.

Performance Based Restricted Stock Units

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 measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during the performance period of January 1, 2018 to December 31, 2020 and cliff vest at December 31, 2020 subject to continued employment.

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 for the March 2020 awards.

	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		%

19

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the nine months ended September 30, 2020:

	Performance Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	271,819	$	147.07
Granted	272,601	$	85.73
Vested	(47,554)	$	89.27
Forfeited	(8,396)	$	170.45
Unvested at September 30, 2020(1)	488,470	$	110.33

(1)A maximum of 1,089,464 units could be awarded based upon the Company’s final TSR ranking.

As of September 30, 2020, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $26 million, which is expected to be recognized over a weighted-average period of 2.0 years.

Rattler Long-Term Incentive Plan

On May 22, 2019, the board of directors of Rattler’s General Partner adopted the Rattler Midstream LP Long Term Incentive Plan (“Rattler LTIP”), for employees, consultants and directors of Rattler’s General Partner and any of its affiliates, including Diamondback, who perform services for Rattler. The Rattler LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards.

Under the Rattler LTIP, the board of directors of Rattler’s General Partner is authorized to issue phantom units to eligible employees and non-employee directors. Rattler estimates the fair value of phantom units as the closing price of Rattler’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting, the phantom units entitle the recipient to one common unit of Rattler for each phantom unit. The recipients are also entitled to distribution equivalent rights, which represent the right to receive a cash payment equal to the value of the distributions paid on one phantom unit between the grant date and the vesting date.

The following table presents the phantom unit activity under the Rattler LTIP for the nine months ended September 30, 2020:

	Phantom Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	2,226,895	$	19.14
Granted	53,943	$	10.41
Vested	(449,633)	$	19.14
Forfeited	(23,442)	$	18.23
Unvested at September 30, 2020	1,807,763	$	18.89

The aggregate fair value of phantom units that vested during the nine months ended September 30, 2020 was $9 million. As of September 30, 2020, the unrecognized compensation cost related to unvested phantom units was $31 million. Such cost is expected to be recognized over a weighted-average period of 3.6 years.

20

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

13.    INCOME TAXES

The Company’s effective income tax rates were 21.6% and 20.8% for the three months ended September 30, 2020 and 2019, respectively, and 18.7% and 17.9% for the nine months ended September 30, 2020 and 2019, respectively. Total income tax benefit from continuing operations for the three and nine months ended September 30, 2020 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss primarily due to (i) the impact of recording a valuation allowance on Viper’s deferred tax assets, (ii) state income taxes and (iii) the impact of permanent differences between book and taxable income, partially offset by tax benefit in the first quarter resulting from the carryback of federal net operating losses.

For the nine months ended September 30, 2020, the Company recorded a discrete income tax expense of $143 million related to application in the first quarter of a valuation allowance on Viper’s beginning-of-year deferred tax assets, which consist primarily of its investment in Viper LLC and federal net operating loss carryforwards. A valuation allowance was also applied against the year-to-date tax benefit resulting from Viper’s pre-tax loss for 2020. The determination to record a valuation allowance was based on assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets. In light of those criteria for recognizing the tax benefit of deferred tax assets, Viper’s assessment resulted in application of a valuation allowance against Viper’s deferred tax assets as of March 31, 2020, June 30, 2020, and September 30, 2020. In addition, for the nine months ended September 30, 2020, the Company recorded a discrete income tax benefit of $25 million related to the available carryback of certain federal net operating losses to tax year(s) in which the corporate income tax rate was 35%. Prior to the enactment of the Coronavirus Aid, Relief, and Economic Security Act (“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 benefit associated with federal net operating loss carryforwards at the statutory 21% corporate income tax rate.

Total income tax expense for the three and nine months ended September 30, 2019 differed from amounts computed by applying the federal statutory rate to pre-tax income primarily due to (i) state income taxes, (ii) the impact of permanent differences between book and taxable income and (iii) the revision of estimated deferred taxes recognized by Viper as a result of its change in tax status. For the nine months ended September 30, 2019, the Company recorded a discrete income tax expense of less than $1 million related to equity-based compensation and a discrete benefit of approximately $42 million related to the revision of estimated deferred taxes on Viper’s investment in Viper LLC arising from the change in Viper’s tax status. Based on information available regarding unitholders’ tax basis, Viper revised its estimate of deferred taxes on Viper’s investment in Viper LLC on the date of the tax status change, resulting in discrete deferred tax benefit of $42 million for the nine months ended September 30, 2019.

During the three months ended June 30, 2020, the Company recorded an increase through stockholders’ equity to the carrying value of its investment in Rattler LLC, resulting in an increase in the Company’s deferred tax liability related to 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. As a result of Rattler’s assessment each period, including consideration of all available positive and negative evidence, Rattler continued to determine that it is more likely than not that Rattler will realize its deferred tax assets as of September 30, 2020.

The 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 has considered the impact of this legislation in the period of enactment, resulting in discrete income tax benefit for the three months ended March 31, 2020 related to the anticipated carryback of approximately $179 million of the Company’s federal net operating losses as noted above. 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 total approximately $100 million as of March 31, 2020, June 30, 2020 and September 30, 2020.

As discussed further in Note 5, 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.

21

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

14.    DERIVATIVES

All derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the condensed 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 only entered into derivative instruments with counterparties that are also lenders under its credit facility and have been deemed an acceptable credit risk.

22

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

As of September 30, 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
Oct. - Dec.	2020	Swaps	11,000	WTI Cushing	$—	$43.47	$—	$—
Oct. - Dec.	2020	Swaps	4,000	WTI Magellan	$—	$61.95	$—	$—
Oct. - Dec.	2020	Swaps	24,200	Brent	$—	$47.62	$—	$—
Oct. - Dec.	2020	Basis Swaps	45,087	WTI Cushing(1)	$(1.33)	$—	$—	$—
Oct. - Dec.	2020	Basis Swaps	8,000	WTL Cushing(1)	$(1.31)	$—	$—	$—
Oct. - Dec.	2020	Rolling Hedge(2)	120,000	WTI Cushing	$(1.05)	$—	$—	$—
Oct. - Dec.	2020	Costless Collar	45,779	WTI Cushing	$—	$—	$35.92	$42.29
Oct. - Dec.	2020	Costless Collar	4,000	WTI Magellan	$—	$—	$39.00	$49.00
Oct. - Dec.	2020	Costless Collar	64,710	Brent	$—	$—	$37.59	$45.63
Jan. - Dec.	2021	Swaps	5,000	WTI Magellan	$—	$37.78	$—	$—
Jan. - Dec.	2021	Swaps	7,500	Brent	$—	$41.58	$—	$—
Jan. - Dec.	2021	Costless Collar	65,000	Brent	$—	$—	$39.25	$48.36
July - Dec.	2021	Swaption	5,000	Brent	$—	$51.00	$—	$—
Jan. - Dec.	2021	Costless Collar	10,000	WTI Cushing	$—	$—	$30.00	$43.05
NATURAL GAS
Oct. - Dec.	2020	Swaps	60,000	Henry Hub	$—	$2.48	$—	$—
Oct. - Dec.	2020	Swaps	60,000	Waha Hub	$—	$1.51	$—	$—
Oct. - Dec.	2020	Basis Swaps	145,000	Waha Hub(1)	$(1.57)	$—	$—	$—
Jan. - Dec.	2021	Swaps	190,000	Henry Hub	$—	$2.62	$—	$—
Jan. - Dec.	2021	Basis Swaps	230,000	Waha Hub(1)	$(0.69)	$—	$—	$—
Jan. - Dec.	2022	Basis Swaps	80,000	Waha Hub(1)	$(0.45)	$—	$—	$—
NATURAL GAS LIQUIDS
Oct. - Dec.	2020	Swaps	7,000	Mont Belvieu Ethane	$—	$8.43	$—	$—
Oct. - Dec.	2020	Swaps	5,000	Mont Belvieu Propane	$—	$21.76	$—	$—
DIESEL
Oct. - Dec.	2021	Swaps	1,000,000	Gulf Cost Ultra Low Sulfur	$—	$1.60	$—	$—

(1) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price or the Midland Argus WTL 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.

23

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Settlement Month	Settlement Year	Type of Contract	Bbls/Mcf Per Day	Index	Strike Price	Swap Price	Put Price	Long Put Price	Option Price
OIL
Oct. - Dec.	2020	Calls(1)	8,000	WTI Magellan	$45.00	$—	$—	$—	$—
Oct. - Dec.	2020	Option	4,700	WTI Cushing	$—	$—	$—	$46.51	$—
Oct. - Dec.	2020	Put Spread	3,800	WTI Magellan	$—	$—	$25.00	$50.00	$—
Oct. - Dec.	2022	Option	5,000	WTI Cushing	$—	$—	$35.00	$—	$—
NATURAL GAS
Oct. - Dec.	2020	Swap Double-Up	30,000	Waha Hub	$—	$1.70	$—	$—	$1.70

(1) Includes a deferred premium at a weighted-average price of $(1.89)/Bbl and a strike price of $45.00/Bbl

Interest Rate Swaps and Treasury Locks

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

The following table summarizes the Company’s interest rate swaps and treasury locks as of September 30, 2020:

Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.551	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.5575	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.297	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.195	%

See Note 18—Subsequent Events for discussion of derivative transactions which occurred subsequent to September 30, 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 15—Fair Value Measurements for further details.

24

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Gains and Losses on Derivative Instruments

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Gain (loss) on derivative instruments, net
Commodity contracts	$	(104)	$	157	$	147	$	(17)
Interest rate swaps	5		20		(65)		20
Total	$	(99)	$	177	$	82	$	3
Net cash received (paid) on settlements
Commodity contracts(1)	(9)		11		288		33
Total	$	(9)	$	11	$	288	$	33

(1)The three and nine months ended September 30, 2020 include cash received on contracts terminated prior to their contractual maturity of $6 million and $17 million, respectively.

25

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

15.    FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

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

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

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

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

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

The Company estimates the fair values of proved oil and natural gas properties assumed in business combinations using discounted cash flow techniques and based on market assumptions as to the future commodity prices, internal estimates of future quantities of oil and natural gas reserves, future estimated rates of production, expected recovery rates and risk-adjustment discounts. The estimated fair values of unevaluated oil and natural gas properties were based on the location, engineering and geological studies, historical well performance, and applicable mineral lease terms. Given the unobservable nature of the inputs, the estimated fair values of oil and natural gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of business combinations are estimated using the same assumptions and methodology as described below.

The Company estimates asset retirement obligations pursuant to the provisions of the FASB issued ASC Topic 410, “Asset Retirement and Environmental Obligations.” The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with the future plugging and abandonment of wells and related facilities. Given the unobservable nature of the inputs, including plugging costs and useful lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 8—Asset Retirement Obligations for further discussion of the Company’s asset retirement obligations.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments and Viper’s investment. Viper measures its investment utilizing the fair value option, and as such the investment is 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.

26

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 condensed consolidated balance sheets as of September 30, 2020 and December 31, 2019. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.

	As of September 30, 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	$	—	$	107	$	—	$	107	$	(92)	$	15
Non-current:
Investment	$	5	$	—	$	—	$	5	$	—	$	5
Derivative Instruments	$	—	$	65	$	—	$	65	$	(65)	$	—
Liabilities:
Current:
Derivative Instruments	$	—	$	178	$	—	$	178	$	(92)	$	86
Non-current:
Derivative Instruments	$	—	$	173	$	—	$	173	$	(65)	$	108

	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

27

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 condensed consolidated balance sheets:

	September 30, 2020				December 31, 2019
	Carrying				Carrying
	Value(1)		Fair Value		Value(1)		Fair Value
	(in millions)
Debt:
Revolving credit facility	$	—	$	—	$	13	$	13
4.625% Notes due 2021	$	191	$	194	$	399	$	411
7.320% Medium-term Notes, Series A, due 2022	$	21	$	22	$	21	$	22
2.875% Senior Notes due 2024	$	993	$	1,014	$	992	$	1,012
4.750% Senior Notes due 2025	$	496	$	541	$	—	$	—
5.375% Senior Notes due 2025	$	800	$	830	$	799	$	840
3.250% Senior Notes due 2026	$	793	$	803	$	792	$	812
7.350% Medium-term Notes, Series A, due 2027	$	—	$	—	$	11	$	12
7.125% Medium-term Notes, Series B, due 2028	$	107	$	113	$	108	$	116
3.500% Senior Notes due 2029	$	1,187	$	1,158	$	1,186	$	1,226
Viper revolving credit facility	$	127	$	127	$	97	$	97
Viper's 5.375% Senior Notes due 2027	$	471	$	477	$	490	$	521
Rattler revolving credit facility	$	85	$	85	$	424	$	424
Rattler’s 5.625% Senior Notes due 2025	$	490	505		$	—	$	—
DrillCo Agreement	$	86	$	86	$	39	$	39

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

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 September 30, 2020 quoted market price, a Level 1 classification in the fair value hierarchy.

Fair Value of Financial Assets

The carrying amount of cash and cash equivalents, receivables, prepaid expenses and other current assets, payables and other accrued liabilities approximate their fair value because of the short-term nature of the instruments.

16.    LEASES

The Company leases certain drilling rigs, facilities, compression and other equipment.

The following table summarizes operating lease costs for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Operating lease costs	$	4	$	7	$	13	$	19

28

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

For the nine months ended September 30, 2020 and 2019, cash paid for operating lease liabilities, as reported in cash flows provided by operating activities on the Company’s condensed consolidated statements of cash flows, was $13 million and $19 million, respectively. During the nine months ended September 30, 2020 and 2019, the Company recorded an additional $10 million and $15 million of right-of-use assets in exchange for new lease liabilities, respectively. There were no significant right-of-use assets recorded during the three months ended September 30, 2020 and 2019.

As of September 30, 2020, the Condensed Consolidated Balance Sheet includes operating right-of-use assets of $13 million in other assets, current operating lease liabilities of $9 million in other accrued liabilities , and long-term operating lease liabilities of $4 million in other long-term liabilities. As of September 30, 2020, the weighted average remaining lease term was 1.5 years and the weighted average discount rate was 9.2%.

Schedule of Operating Lease Liability Maturities. The following table summarizes undiscounted cash flows owed by the Company to lessors pursuant to contractual agreements in effect as of September 30, 2020:

	As of September 30, 2020
	(in millions)
2020 (October - December)	$	4
2021	7
2022	3
2023	—
2024	—
Thereafter	—
Total lease payments	14
Less: interest	1
Present value of lease liabilities	$	13

17.    COMMITMENTS AND CONTINGENCIES

The Company is a party to various routine legal proceedings, disputes and claims arising in the ordinary course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. 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.

18.    SUBSEQUENT EVENTS

Third Quarter 2020 Dividend Declaration

On October 29, 2020, the Board of Directors of the Company declared a cash dividend for the third quarter of 2020 of $0.375 per share of common stock, payable on November 19, 2020 to its stockholders of record at the close of business on November 12, 2020.

Amendment to the Rattler Credit Agreement in Connection with Initiation of Rattler’s Common Unit Repurchase Program

On November 2, 2020, Rattler and Rattler LLC entered into a second amendment (the “Second Amendment”) to the Rattler Credit Agreement with Wells Fargo, as the administrative agent, and the lenders party thereto. The Second Amendment permits Rattler to conduct common unit repurchases in connection with the common unit repurchase program approved by the board of directors of Rattler’s General Partner on October 29, 2020.

29

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Under Rattler’s common unit repurchase program to be conducted under Rule 10b-18 of the Exchange Act, Rattler is authorized to acquire up to $100 million of Rattler’s outstanding common units in open market or privately negotiated transactions with cash on hand and free cash flow from operations. The common unit repurchase program is authorized to extend through December 31, 2021, may be suspended from time to time or modified, extended or discontinued by the board of directors of Rattler’s General Partner at any time, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors.

Commodity Contracts

Subsequent to September 30, 2020, the Company entered into new fixed price swaps and basis swaps. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges noted in the table below.

The following tables present the derivative contracts entered into by the Company between October 1, 2020 and November 2, 2020. When aggregating multiple contracts, the weighted average contract price is disclosed.

					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
Jan. - Mar.	2021	Costless Collar	3,000	WTI Cushing	$—	$—	$37.00	$44.19
Mar. - June	2021	Costless Collar	1,000	WTI Cushing	$—	$—	$37.00	$47.00
Jan. - June	2021	Costless Collar	6,000	Brent	$—	$—	$37.50	$45.50
NATURAL GAS
Jan. - Dec.	2021	Swaps	10,000	Henry Hub	$—	$3.05	$—	$—
Jan. - Dec.	2022	Basis Swap	20,000	Waha Hub	$(0.31)	$—	$—	$—

Interest Rate Swaps

Subsequent to September 30, 2020, the Company entered into new interest rate swaps and terminated existing interest rate swaps.

The following table presents the interest rate swaps entered into by the Company subsequent to September 30, 2020.

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	%

The following table presents the interest rate swap contracts terminated by the Company subsequent to September 30, 2020.

Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.551	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.5575	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.297	%

30

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

19.    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 in the Permian Basin in West Texas and (ii) the midstream operations segment includes midstream services and real estate. All of Rattler’s equity method investments are included in the midstream segment.

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

	Upstream		Midstream Services		Eliminations		Total
Three Months Ended September 30, 2020:	(in millions)
Third-party revenues	$	706	$	14	$	—	$	720
Intersegment revenues	—		83		(83)		—
Total revenues	706		97		(83)		720
Depreciation, depletion and amortization	275		11		—		286
Impairment of oil and natural gas properties	1,451		—		—		1,451
Income (loss) from operations	(1,282)		44		(18)		(1,256)
Interest expense, net	(47)		(6)		—		(53)
Other income (expense)	(103)		4		(1)		(100)
Provision for (benefit from) income taxes	(307)		3		—		(304)
Net income (loss) attributable to non-controlling interest	(1)		9		—		8
Net income (loss) attributable to Diamondback Energy, Inc.	(1,124)		30		(19)		(1,113)
As of September 30, 2020:
Total assets	$	17,245	$	1,812	$	(297)	$	18,760

	Upstream		Midstream Services		Eliminations		Total
Three Months Ended September 30, 2019:	(in millions)
Third-party revenues	$	957	$	18	$	—	$	975
Intersegment revenues	—		97		(97)		—
Total revenues	957		115		(97)		975
Depreciation, depletion and amortization	353		12		—		365
Income (loss) from operations	321		52		(24)		349
Interest expense, net	(37)		(1)		—		(38)
Other income (expense)	181		(1)		(1)		179
Provision for (benefit from) income taxes	99		3		—		102
Net income (loss) attributable to non-controlling interest	20		37		(37)		20
Net income (loss) attributable to Diamondback Energy, Inc.	346		10		12		368
As of December 31, 2019:
Total assets	$	22,125	$	1,636	$	(230)	$	23,531

31

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

	Upstream		Midstream Services		Eliminations		Total
Nine Months Ended September 30, 2020:	(in millions)
Third-party revenues	$	2,002	$	42	$	—	$	2,044
Intersegment revenues	—		273		(273)		—
Total revenues	2,002		315		(273)		2,044
Depreciation, depletion and amortization	1,001		35		—		1,036
Impairment of oil and natural gas properties	4,999		—		—		4,999
Income (loss) from operations	(4,787)		134		(77)		(4,730)
Interest expense, net	(137)		(10)		—		(147)
Other income (expense)	73		(10)		(4)		59
Provision for (benefit from) income taxes	(910)		8		—		(902)
Net income (loss) attributable to non-controlling interest	(163)		25		—		(138)
Net income (loss) attributable to Diamondback Energy, Inc.	(3,778)		81		(81)		(3,778)
As of September 30, 2020:
Total assets	$	17,245	$	1,812	$	(297)	$	18,760

	Upstream		Midstream Services		Eliminations		Total
Nine Months Ended September 30, 2019:	(in millions)
Third-party revenues	$	2,802	$	58	$	—	$	2,860
Intersegment revenues	—		264		(264)		—
Total revenues	2,802		322		(264)		2,860
Depreciation, depletion and amortization	1,014		32		—		1,046
Income (loss) from operations	1,004		159		(84)		1,079
Interest expense, net	(132)		(1)		—		(133)
Other income (expense)	16		(1)		(3)		12
Provision for (benefit from) income taxes	167		4		—		171
Net income (loss) attributable to non-controlling interest	60		52		(52)		60
Net income (loss) attributable to Diamondback Energy, Inc.	$	661	$	101	$	(35)	727
As of December 31, 2019:
Total assets	$	22,125	$	1,636	$	(230)	$	23,531

32

ITEM 2.         MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this report as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We operate in two business segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas and (ii) through our publicly-traded subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.

2020 Recent Developments

COVID-19 and Collapse in Commodity Prices

On March 11, 2020, the World Health Organization characterized the global outbreak of the novel strain of coronavirus, COVID-19, as a “pandemic.” To limit the spread of COVID-19, governments have taken various actions including the issuance of stay-at-home orders and social distancing guidelines, causing some businesses to suspend operations and a reduction in demand for many products from direct or ultimate customers. Although many stay-at-home orders have expired and certain restrictions on conducting business have been lifted, the COVID-19 pandemic resulted in a widespread health crisis and a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused significant volatility and disruption of the financial markets.

In early March 2020, oil prices dropped sharply, and then continued to decline reaching a closing NYMEX price low of negative $37.63 per barrel in April 2020. For the first nine months of 2020, the average NYMEX WTI and Henry Hub futures contracts prices for crude oil and condensate and natural gas were $38.21 per barrel and $1.92 per million British thermal units (MMBtu), respectively, representing decreases of 33% and 25%, respectively, from the average WTI futures prices for the same period in 2019. This was a result of multiple factors affecting supply and demand in global oil and natural gas markets, including actions taken by OPEC members and other exporting nations impacting commodity price and production levels and the ongoing COVID-19 pandemic. While OPEC members and certain other nations agreed in April 2020 to cut production, which helped to reduce a portion of the excess supply in the market and improve oil prices, there is no assurance that this agreement will continue or be observed by its parties, and downward pressure on commodity prices has continued and could continue for the foreseeable future. The Company cannot predict if or when commodity prices will stabilize and at what levels.

As a result of the reduction in crude oil demand caused by factors mentioned above, in March 2020, we announced reductions to our capital plans for 2020 and have recently indicated that we expect our budget to remain in this lower range for the rest of 2020. We also lowered our total commodity production and oil production guidance for 2020 and, as of August 3, 2020, were targeting slightly lower oil production volumes in 2020 as compared to full year 2019, and took other actions discussed below. We continued our trend of cost reductions in the third quarter of 2020, with our lease operating and general and administrative expenses remaining near all-time lows and capital costs per lateral foot continuing to decline. Our drilling and completion operations continue to become more efficient, and we are beginning to see the benefits from high-grading our development program after the downturn began earlier in 2020. We remain on track to meet our fourth quarter 2020 average production target of between 170,000 and 175,000 barrels of oil per day, and expect this to be the baseline for our development plan in 2021. We expect to execute on this maintenance plan with 25% to 35% less capital than in 2020, which implies a reinvestment ratio of approximately 70% at $40 per barrel WTI. Our investment framework and capital allocation philosophy at current depressed commodity prices remain focused on protecting our common stock dividend, spending maintenance capital on holding production flat and using excess free cash flow to pay down debt. We believe that we have the size, scale, balance sheet, asset quality and cost structure to weather a prolonged downturn in our industry and succeed in the subsequent upcycle.

33

In addition, as a result of the sharp decline in commodity prices in early March 2020, and the continued depressed oil pricing throughout the second and third quarters of 2020, we recorded non-cash ceiling test impairments for the nine months ended September 30, 2020 of approximately $5.0 billion, of which approximately $1.5 billion was recorded for the three months ended September 30, 2020 and approximately $3.5 billion was recorded for the six months ended June 30, 2020. These impairment charges adversely affected our results of operations but did not reduce our cash flows. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will have material write downs in subsequent quarters. Our production, proved reserves and cash flows will also be adversely impacted. Our results of operations may be further adversely impacted by any government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin where we operate.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic, the depressed commodity prices and the adverse macroeconomic will persist, the full extent of the impact they will have on our industry and our business, financial condition, results of operations or cash flows, or the pace or extent of any subsequent recovery.

Our Response to the Commodity Price Volatility and Impact of COVID-19

•We have taken swift and decisive actions to protect the health and safety of our employees and preserve the strength of our organization during the COVID-19 pandemic and the depressed commodity price markets.

•We also curtailed 5% of our oil production during the second quarter of 2020. This curtailed production has been restored and is now receiving significantly higher realized prices than it would have received when the decision was made to curtail. We currently have three completion crews working to stem production declines to meet our fourth quarter 2020 average production target of between 170,000 and 175,000 barrels of oil per day.

•Our operated rig count declined rapidly beginning in the second quarter of 2020, from 20 rigs on March 31, 2020 to five rigs currently, building a significant inventory of drilled but uncompleted wells.

•Assuming a continuation of current market conditions, we plan to operate between five and six operated drilling rigs and between three and four completion crews for the remainder of 2020.

•Based on current forward commodity prices, we expect to generate significant free cash flow in the remainder of 2020 and in 2021. Under a maintenance capital scenario in 2021 should that become the base case operating plan, we anticipate that we will be able to hold expected fourth quarter 2020 oil production flat while spending 25% to 35% less than our 2020 capital budget, including lower midstream and infrastructure budgets.

•We intend to remain focused on returning capital to our stockholders through our quarterly dividend while protecting our balance sheet, and intend to continue to drill, complete and produce hydrocarbons with the highest margins at the lowest capital and operating costs in the industry.

•We have hedged approximately 100% of our remaining expected 2020 oil production, including basis differentials and a majority of WTI contract exposure and removed all three-way collar hedge exposure to maximize downside protection.

•We have hedged approximately 50% of our expected 2021 oil production in the form of swaps and two-way collars.

Third Quarter 2020 and Other Recent Developments

•We recorded a net loss of $1.1 billion for the third quarter ended September 30, 2020, which reflected an impairment of oil and natural gas properties of approximately $1.5 billion as a result of lower average trailing 12-month commodity pricing.

•Our average production was 287.3 MBOE/d during the third quarter of 2020.

•During the third quarter of 2020, we drilled 22 gross horizontal wells in the Midland Basin and ten gross horizontal wells in the Delaware Basin.

•We turned 41 gross operated horizontal wells (25 in the Midland Basin and 16 in the Delaware Basin) to production and had capital expenditures of $281 million during the third quarter of 2020.

34

•The average lateral length for the wells completed during the third quarter of 2020 was 9,881 feet.

•As of September 30, 2020, we had $2.0 billion of availability for future borrowings under our revolving credit facility and approximately $92 million of cash on hand.

•We retired all of the outstanding Energen’s 7.350% Medium-term notes due 2027 in the aggregate principal amount of $10 million.

•Our cash operating costs for the third quarter ended September 30, 2020 were $7.61 per BOE, including lease operating expenses of $3.86 per BOE, cash general and administrative expenses of $0.42 per BOE and production and ad valorem taxes and gathering and transportation expenses of $3.33 per BOE.

•Our current drilling and completion costs in the Midland Basin are approximately $450 per lateral foot, with an estimated additional $60 to $80 of equip costs per lateral foot.

•Our current drilling and completion costs in the Delaware Basin are between $600 and $700 per lateral foot, with an estimated additional $100 to $150 of equip costs per lateral foot.

•We completed an average of over 3,300 lateral feet per day per completion crew in the Midland Basin using Simulfrac technology during the third quarter of 2020.

•We continued our commitment to environmental stewardship during the third quarter of 2020, flaring 0.5% of net production, down 74% from 2019. During the nine months ended September 30, 2020, we flared 0.9% of net production, down 54% from 2019.

•We recycled 25.1% of water used for completion operations in the third quarter of 2020, up 24% from 2019. During the nine months ended September 30, 2020, we recycled 21.4% of water used for completion operations, up 53% from 2019.

•On October 29, 2020, our board of directors declared a cash dividend for the third quarter of 2020 of $0.375 per share of common stock, payable on November 19, 2020 to our stockholders of record at the close of business of November 12, 2020.

•In July 2020, Rattler completed a notes offering of $500 million in aggregate principal amount of its 5.625% Senior Notes due 2025, or the Rattler Notes, under Rule 144A and Regulation S under the Securities Act, resulting in net proceeds of approximately $490 million. The proceeds from the offering of the Rattler Notes were used to repay outstanding borrowings under its revolving credit facility.

•On October 29, 2020, Rattler implemented a common unit repurchase program under Rule 10b-18 of the Exchange Act to acquire up to $100 million of Rattler’s outstanding common units in open market or privately negotiated transactions with cash on hand and free cash flow from operations. The common unit repurchase program is authorized to extend through December 31, 2021, may be suspended from time to time or modified, extended or discontinued by the board of directors of Rattler’s General Partner at any time, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors. In connection with the common unit repurchase program, Rattler entered into an amendment to the Rattler credit agreement permitting such program.

Upstream Segment

In our upstream segment, our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Also, in our upstream segment, our publicly-traded subsidiary, Viper, is focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties in the Permian Basin and the Eagle Ford Shale and derives royalty income and lease bonus income from such interests.

As of September 30, 2020, we had approximately 378,961 net acres, which primarily consisted of approximately 199,254 net acres in the Midland Basin and approximately 152,743 net acres in the Delaware Basin. As of December 31, 2019, we had an estimated 12,310 gross horizontal locations that we believe to be economic at $60 per barrel WTI.

35

The following table sets forth the total number of operated horizontal wells drilled and completed during the three months and nine months ended September 30, 2020:

	Three Months Ended September 30, 2020				Nine Months Ended September 30, 2020
	Drilled		Completed(1)		Drilled		Completed(2)
Area	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Midland Basin	22	20	25	25	114	108	69	61
Delaware Basin	10	10	16	16	69	65	67	63
Total	32	30	41	41	183	173	136	124

(1)The average lateral length for the wells completed during the third quarter of 2020 was 9,881 feet. Operated completions during the third quarter of 2020 consisted of 16 Wolfcamp A wells, five Wolfcamp B wells, six Lower Spraberry wells, nine Middle Spraberry wells and five Second Bone Springs wells.

(2)The average lateral length for the wells completed during the first nine months of 2020 was 9,955 feet. Operated completions during the first nine months of 2020 consisted of 67 Wolfcamp A wells, 16 Wolfcamp B wells, 17 Lower Spraberry wells, 17 Middle Spraberry wells, three Jo Mill wells, 11 Second Bone Springs wells and five Third Bone Springs wells.

As of September 30, 2020, we operated the following wells:

	Vertical Wells		Horizontal Wells		Total
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	1,400	1,313	1,072	976	2,472	2,289
Delaware Basin	25	22	569	535	594	557
Total	1,425	1,335	1,641	1,511	3,066	2,846

As of September 30, 2020, we held interests in 3,588 gross (2,941 net) wells, including wells that we do not operate.

Our development program is focused entirely within the Permian Basin, where we continue to focus on long-lateral multi-well pad development. Our horizontal development consists of multiple targeted intervals, primarily within the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Springs formations in the Delaware Basin.

Midstream Operations

In our midstream operations segment, Rattler’s crude oil infrastructure assets consist of gathering pipelines and metering facilities, which collectively gather crude oil for its customers. Rattler’s facilities gather crude oil from horizontal and vertical wells in our ReWard, Spanish Trail, Pecos and Glasscock areas within the Permian Basin. Rattler’s natural gas gathering and compression system consists of gathering pipelines, compression and metering facilities, which collectively service the production from our Pecos area assets within the Permian Basin. Rattler’s water sourcing and distribution assets consists of water wells, hydraulic fracturing pits, pipelines and water treatment facilities, which collectively gather and distribute water from Permian Basin aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Rattler’s produced water gathering and disposal system spans approximately 508 miles and consists of gathering pipelines along with produced water disposal wells and facilities which collectively gather and dispose of produced water from operations throughout our Permian Basin acreage.

We have entered into multiple fee-based commercial agreements with Rattler, each with an initial term ending in 2034, utilizing Rattler’s infrastructure assets or its planned infrastructure assets to provide an array of essential services critical to our upstream operations in the Delaware and Midland Basins. Our agreements with Rattler include substantial acreage dedications. On May 5, 2020, we amended our commercial agreements with Rattler to, among other things, in certain cases add certain new areas to our dedication and commitment and revise the threshold for permitting releases of dedications in connection with transfers or swaps by us or our affiliates.

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Results of Operations

The following table sets forth selected operating data for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Revenues (in millions):
Oil sales	$	606	$	882	$	1,785	$	2,572
Natural gas sales	36		16		61		36
Natural gas liquid sales	65		58		156		190
Total oil, natural gas and natural gas liquid revenues	$	707	$	956	$	2,002	$	2,798
Production Data (in thousands):
Oil (MBbls)	15,639		17,064		50,009		50,581
Natural gas (MMcf)	32,505		26,271		96,482		69,394
Natural gas liquids (MBbls)	5,377		4,974		16,326		13,420
Combined volumes (MBOE)	26,433		26,417		82,415		75,567
Daily combined volumes (BOE/d)	287,315		287,138		300,785		276,802
Daily oil volumes (BO/d)	169,989		185,478		182,515		185,278
Average Prices:
Oil ($ per Bbl)	$	38.75	$	51.71	$	35.69	$	50.86
Natural gas ($ per Mcf)	$	1.11	$	0.62	$	0.63	$	0.52
Natural gas liquids ($ per Bbl)	$	12.09	$	11.61	$	9.56	$	14.14
Combined ($ per BOE)	$	26.75	$	36.20	$	24.29	$	37.03
Oil, hedged ($ per Bbl)(1)	$	38.17	$	51.84	$	41.31	$	50.99
Natural gas, hedged ($ per MMbtu)(1)	$	0.95	$	0.69	$	0.57	$	0.74
Natural gas liquids, hedged ($ per Bbl)(1)	$	12.09	$	12.83	$	9.56	$	14.93
Average price, hedged ($ per BOE)(1)	$	26.22	$	36.59	$	27.63	$	37.46

(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects includes gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.

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Production Data

Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. The following tables set forth our production data for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Oil (MBbls)	59	%	65	%	61	%	67	%
Natural gas (MMcf)	21	%	17	%	19	%	15	%
Natural gas liquids (MBbls)	20	%	18	%	20	%	18	%
	100	%	100	%	100	%	100	%

	Three Months Ended September 30, 2020				Three Months Ended September 30, 2019
	Midland Basin	Delaware Basin	Other(1)	Total	Midland Basin	Delaware Basin	Other(2)	Total
	(in thousands)
Production Data:
Oil (MBbls)	8,971	6,627	41	15,639	10,105	6,881	78	17,064
Natural gas (MMcf)	17,403	15,003	99	32,505	12,839	13,224	208	26,271
Natural gas liquids (MBbls)	3,087	2,268	22	5,377	2,748	2,179	47	4,974
Total (MBoe)	14,958	11,395	80	26,433	14,993	11,264	160	26,417

	Nine Months Ended September 30, 2020				Nine Months Ended September 30, 2019
	Midland Basin	Delaware Basin	Other(1)	Total	Midland Basin	Delaware Basin	Other(2)	Total
	(in thousands)
Production Data:
Oil (MBbls)	28,864	21,013	132	50,009	30,411	18,810	1,360	50,581
Natural gas (MMcf)	50,285	45,871	326	96,482	33,605	34,846	943	69,394
Natural gas liquids (MBbls)	9,281	6,975	70	16,326	7,533	5,721	166	13,420
Total (MBoe)	46,525	35,633	257	82,415	43,545	30,339	1,683	75,567

(1)Includes the Central Basin Platform, the Eagle Ford Shale and the Rockies.

(2)Includes the Eagle Ford Shale.

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Comparison of the Three Months Ended September 30, 2020 and 2019 and Nine Months Ended September 30, 2020 and 2019

Oil, Natural Gas and Natural Gas Liquids Revenues. Our oil, natural gas and natural gas liquids revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.

The net dollar effect of the change in prices (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas and natural gas liquids) and the net dollar effect of the change in production (calculated as the change in period-to-period volumes for oil, natural gas and natural gas liquids multiplied by the prior period average prices) are shown below:

	Three Months Ended September 30, 2020 Compared to 2019						Nine Months Ended September 30, 2020 Compared to 2019
	Change in prices		Production volumes(1)		Total net dollar effect of change		Change in prices		Production volumes(1)		Total net dollar effect of change
	(in millions)
Effect of changes in price:
Oil	$	(12.96)	15,639		$	(203)	$	(15.17)	50,009		$	(758)
Natural gas	$	0.49	32,505		16		$	0.11	96,482		11
Natural gas liquids	$	0.48	5,377		3		$	(4.58)	16,326		(75)
Total revenues due to change in price					$	(184)					$	(822)
	Change in production volumes(1)		Prior period Average Prices		Total net dollar effect of change		Change in production volumes(1)		Prior period Average Prices		Total net dollar effect of change
	(in millions)
Effect of changes in production volumes:
Oil	(1,426)		$	51.71	$	(74)	(572)		$	50.86	$	(29)
Natural gas	6,235		$	0.62	4		27,088		$	0.52	14
Natural gas liquids	403		$	11.61	5		2,905		$	14.14	41
Total revenues due to change in production volumes					(65)						26
Total change in revenues					$	(249)					$	(796)

(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Our oil, natural gas and natural gas liquids revenues for the third quarter of 2020 decreased by $249 million, or 26%, to $707 million from $956 million during the third quarter of 2019, and our total revenues for the nine months ended September 30, 2020 decreased by $796 million, or 28%, to $2.0 billion from $2.8 billion during the same period in 2019. These declines were primarily driven by the sudden drop in demand and prices for oil stemming from the COVID-19 pandemic, which resulted in temporarily curtailing a portion of our oil production volumes in the second quarter of 2020 and reducing our total capital budget and drilling and completion plan for 2020.

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Midstream Services Revenue. The following table shows midstream services revenue for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Midstream services revenue	$	12	$	16	$	37	$	51

Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. Midstream services revenue decreased by $4 million for the three months ended September 30, 2020 and $14 million for the nine months ended September 30, 2020 compared to the same periods in 2019 primarily due to a reduction in sourced water volumes due to the lower level of drilling and completion activity in 2020.

Lease Operating Expenses. The following table shows lease operating expenses for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2020				2019				2020				2019
	Amount		Per BOE		Amount		Per BOE		Amount		Per BOE		Amount		Per BOE
	(in millions, except per BOE amounts)
Lease operating expenses	$	102	$	3.86	$	128	$	4.85	$	332	$	4.03	$	364	$	4.82

Lease operating expenses for the three months ended September 30, 2020 as compared to the three months ended September 30, 2019 decreased by $26 million, or $0.99 per BOE. Lease operating expenses for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019 decreased by $32 million, or $0.79 per BOE. In both cases, the decrease in lease operating expenses was primarily associated with a reduction in well maintenance activity related to overall efficiencies gained, as well as improvements in infrastructure which reduced power generation costs and trucking fees.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,										Nine Months Ended September 30,
	2020					2019					2020					2019
	Amount			Per BOE		Amount			Per BOE		Amount			Per BOE		Amount			Per BOE
	(in millions, except per BOE amounts)
Production taxes	$	36		$	1.36	$	45		$	1.69	$	97		$	1.18	$	132		$	1.75
Ad valorem taxes	19			0.72		16			0.62		51			0.62		48			0.63
Total production and ad valorem expense	$	55		$	2.08	$	61		$	2.31	$	148		$	1.80	$	180		$	2.38
Production taxes as a % of oil, natural gas, and natural gas liquids revenue	5.1		%			4.7		%			4.8		%			4.7		%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of production revenues remained consistent for the three and nine month periods ended September 30, 2020 compared to the same periods in 2019.

Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes for the three months ended September 30, 2020 as compared to the three months ended September 30, 2019 increased by $3 million primarily due to higher overall valuations resulting from an increase in revenues between valuation periods.

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Ad valorem taxes for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019 remained relatively flat.

Gathering and Transportation Expense. The following table shows gathering and transportation expense for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2020				2019				2020				2019
	Amount		Per BOE		Amount		Per BOE		Amount		Per BOE		Amount		Per BOE
	(in millions, except per BOE amounts)
Gathering and transportation expense	$	33	$	1.25	$	25	$	0.95	$	105	$	1.27	$	54	$	0.71

For the three months and nine months ended September 30, 2020, the per BOE increases for gathering and transportation expenses are primarily attributable to recording minimum volume commitment fees in 2020, as well as an increase in fees for our gas production and an overall change in our product mix, with gas and natural gas liquids production becoming a greater percentage of overall production.

Midstream Services Expense. The following table shows midstream services expense for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Midstream services expense	$	26	$	26	$	81	$	60

Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities. Midstream services expense increased for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019 primarily due to increased oil, gas and produced water volumes largely attributable to the continued build out of our midstream assets. In addition, we incurred certain asset maintenance and workover charges related to our produced water wells to increase their capacity.

Depreciation, Depletion and Amortization. The following table provides the components of our depreciation, depletion and amortization expense for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions, except BOE amounts)
Depletion of proved oil and natural gas properties	$	273	$	353	$	995	$	1,009
Depreciation of midstream assets	9		9		29		25
Depreciation of other property and equipment	4		3		12		12
Depreciation, depletion and amortization expense	$	286	$	365	$	1,036	$	1,046
Oil and natural gas properties depletion rate per BOE	$	10.33	$	13.33	$	12.07	$	13.34

The decrease in depletion of proved oil and natural gas properties of $80 million for the three months ended September 30, 2020 as compared to the three months ended September 30, 2019 resulted primarily from a reduction in the average depletion rate for our oil and natural gas properties in 2020, which stemmed from a decrease in the net book value of our properties due to the full cost ceiling impairments recorded in the first and second quarters of 2020 and fourth quarter of 2019. The decrease in depletion of proved oil and natural gas properties of $14 million for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019 resulted primarily from lower production levels and as well as the decrease in the net book value of our properties due to the full cost ceiling impairments recorded in 2020.

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Impairment of Oil and Natural Gas Properties. As a result of the sharp decline in commodity prices during 2020, we recorded non-cash ceiling test impairments for the three months and nine months ended September 30, 2020 of $1.5 billion and $5.0 billion, respectively, which is included in accumulated depletion. The impairment charge affected our results of operations but did not reduce cash flow. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our 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, we will continue to have material write downs in subsequent quarters. No impairment on proved oil and natural gas properties was recorded for the nine months ended September 30, 2019.

General and Administrative Expenses. The following table shows general and administrative expenses for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2020				2019				2020				2019
	Amount		Per BOE		Amount		Per BOE		Amount		Per BOE		Amount		Per BOE
	(in millions, except per BOE amounts)
General and administrative expenses	$	11	$	0.42	$	15	$	0.59	$	37	$	0.45	$	41	$	0.55
Non-cash stock-based compensation	9		0.34		4		0.16		27		0.33		27		0.36
Total general and administrative expenses	$	20	$	0.76	$	19	$	0.75	$	64	$	0.78	$	68	$	0.91

Total general and administrative expenses for the three months ended September 30, 2020 as compared to the three months ended September 30, 2019 increased by $1 million primarily due to an increase in non-cash stock-based compensation, partially offset by decreases in contract labor, rent, legal expense and penalties. General and administrative expenses for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019 decreased by $4 million primarily due to decreases in rent, contract labor expense and penalties.

Net Interest Expense. The following table shows net interest expense for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Net interest expense	$	53	$	38	$	147	$	133

Net interest expense increased by $15 million and $14 million, respectively, for the three months and nine months ended September 30, 2020 compared to the same periods in 2019. In both cases, the increases were primarily due to an increase in borrowings as well as the issuance of the May 2020 Notes.

Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on settlements of derivative instruments for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Gain (loss) on derivative instruments, net	$	(99)	$	177	$	82	$	3
Net cash received (paid) on settlements	$	(9)	$	11	$	288	$	33

We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our condensed consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.”

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Net cash received (paid) on settlements of derivative instruments for the three and nine months ended September 30, 2020 include cash received on contracts terminated prior to their contractual maturity of $6 million and $17 million, respectively.

Provision for (Benefit from) Income Taxes. The following table shows provision for (benefit from) income taxes for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Provision for (benefit from) income taxes	$	(304)	$	102	$	(902)	$	171

The change in our income tax provision for the third quarter of 2020 compared to the same period in 2019 was primarily due to the pre-tax loss for the three months ended September 30, 2020, compared to pre-tax income for the three months ended September 30, 2019.

The change in our income tax provision for the first nine months of 2020 compared to the same period in 2019 was primarily due to the pre-tax loss for the nine months ended September 30, 2020, partially offset by discrete tax expense resulting from application of a valuation allowance on Viper’s deferred tax assets, compared to pre-tax income for the nine months ended September 30, 2019, partially offset by a discrete income tax benefit resulting from estimated deferred taxes recognized as a result of Viper’s change in tax status.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of our senior notes and cash flows from operations. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties.

As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the depressed commodity markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Liquidity and Cash Flow

Our cash flows for the nine months ended September 30, 2020 and 2019 are presented below:

	Nine Months Ended September 30,
	2020		2019
	(in millions)
Net cash provided by (used in) operating activities	$	1,715	$	1,852
Net cash provided by (used in) investing activities	(1,855)		(2,744)
Net cash provided by (used in) financing activities	111		777
Net increase (decrease) in cash	$	(29)	$	(115)

Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

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The decrease in operating cash flows for the nine months ended September 30, 2020 compared to the same period in 2019 primarily resulted from the decline in our oil and natural gas revenues and a reduction in our accounts payable and other current liabilities payable during 2020 compared to an increase in payable balances during 2019. These reductions in operating cash flow were partially offset by an increase in collections on our accounts receivable during 2020 compared to 2019 and other working capital changes.

Investing Activities

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. Net cash used in investing activities was $1.9 billion and $2.7 billion during the nine months ended September 30, 2020 and 2019, respectively.

Capital Expenditure Activities

Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:

	Nine Months Ended September 30,
	2020		2019
	(in millions)
Drilling, completions and non-operated additions to oil and natural gas properties(1)(2)	$	1,404	$	1,883
Infrastructure additions to oil and natural gas properties	96		104
Additions to midstream assets	133		186
Total	$	1,633	$	2,173

(1)During the nine months ended September 30, 2020, in conjunction with our development program, we drilled 183 gross (173 net) operated horizontal wells, of which 69 gross (65 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 136 gross (124 net) operated horizontal wells to production, of which 67 gross (63 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin.

(2)During the nine months ended September 30, 2019, in conjunction with our development program, we drilled 255 gross (231 net) operated horizontal wells, of which 122 gross (110 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 239 gross (219 net) operated horizontal wells to production, of which 105 gross (96 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin.

Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2020 and 2019 was $111 million and $777 million, respectively. During the nine months ended September 30, 2020, the amount provided by financing activities was primarily attributable to $758 million in proceeds from the May Notes Offering and Rattler Notes Offering, net of repayments on Energen’s 4.625% senior notes and 7.350% medium-term notes, as well as $47 million in proceeds from our joint venture. These net increases in cash flows from financing activities were largely offset by $321 million of payments, net of borrowings on our credit facility, $177 million of dividends to stockholders, $98 million of share repurchases as part of our stock repurchase program and $77 million in distributions to non-controlling interest.

The 2019 amount provided by financing activities was primarily attributable to $341 million in net proceeds from Viper’s public offering completed on March 1, 2019, $720 million in net proceeds from the Rattler Offering, $241 million of borrowings, net of repayments under our credit facility, and $42 million in proceeds from our joint venture, partially offset by $400 million of share repurchases as part of our stock repurchase program, $82 million of dividends to stockholders and $79 million in distributions to non-controlling interest.

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Indebtedness

Second Amended and Restated Credit Facility

As of September 30, 2020, the maximum credit amount available under our credit agreement was $2 billion, and we had no outstanding borrowings under our credit agreement and $2 billion available for future borrowings. As of September 30, 2020, there was an aggregate of $3 million in letters of credit outstanding under our credit agreement. The weighted average interest rate on the credit facility was 1.83% and 2.27% for the three months and nine months ended September 30, 2020, respectively. The credit agreement matures on November 1, 2022.

As of September 30, 2020, we were in compliance with all financial maintenance covenants under our credit agreement.

The May 2020 Notes and Tender Offer for Energen’s 4.625% Senior Notes and Repurchase of Energen’s 7.35% Medium-term Notes

On May 26, 2020, we completed a registered offering of $500 million in aggregate principal amount of our 4.750% Senior Notes due 2025. 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. We received net proceeds of approximately $496 million from the offering.

We used the net proceeds, among other things, to make an equity contribution to Energen to purchase $209 million in aggregate principal amount of Energen’s 4.625% senior notes pursuant to a tender offer. As of September 30, 2020, $191 million in aggregate principal amount of Energen’s 4.625% senior notes remained outstanding.

During the third quarter of 2020, we repurchased all $10 million in principal amount of Energen’s outstanding 7.350% medium-term notes due on July 28, 2027 at a price of 120% of the aggregate principal amount.

Viper’s Credit Agreement

The Viper credit agreement, as amended, or the Viper credit agreement, provides for a revolving credit facility in the maximum credit amount of $2 billion, a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) and a maturity date of November 1, 2022. The borrowing base is scheduled to be re-determined semi-annually in May and November. In addition, Viper LLC and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. Viper LLC’s borrowing base was reduced from $775 million to $580 million during the regularly scheduled (semi-annual) spring 2020 redetermination in the second quarter of 2020, and is expected to be reaffirmed at $580 million by the lenders during the regularly scheduled (semi-annual) fall 2020 redetermination in November 2020. As of September 30, 2020, Viper LLC had $127 million of outstanding borrowings and $453 million available for future borrowings under the Viper credit agreement. Amounts borrowed under the Viper credit agreement bore interest at a weighted average rate of 2.14% and 2.66% for the three months and nine months ended September 30, 2020, respectively.

As of September 30, 2020, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement.

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, or the Viper Notes. Viper received net proceeds of approximately $490 million from the notes offering and loaned the gross proceeds to Viper LLC to pay down borrowings under the Viper credit agreement. 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.

As of September 30, 2020, Viper repurchased $20 million in principal amount of the outstanding Viper Notes in open market purchases 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. As of September 30, 2020, $480 million in aggregate principal amount of the Viper Notes remained outstanding.

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Rattler’s Credit Agreement

The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of September 30, 2020, Rattler LLC had $85 million of outstanding borrowings and $515 million available for future borrowings under the Rattler credit agreement. The weighted average interest rate on the credit facility was 1.46% and 2.18% for the three months and nine months ended September 30, 2020, respectively. The Rattler credit agreement has a maturity date of May 28, 2024. In connection with the offering of the Rattler Notes described below completed on July 14, 2020, Rattler LLC used the proceeds of the offering to repay a portion of the outstanding borrowings under the Rattler credit agreement.

As of September 30, 2020, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

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, or the Notes Offering. Interest on the Rattler Notes is payable on January 15 and July 15 of each year, beginning on January 15, 2021. The Rattler Notes mature on July 15, 2025. Rattler received net proceeds of approximately $490 million from the Notes Offering. Rattler loaned the gross proceeds to Rattler LLC under the terms of a subordinated promissory note, dated as of July 14, 2020. The promissory note requires Rattler LLC to repay the intercompany loan to Rattler on the same terms and in the same amounts as the Rattler Notes and has the same maturity date, interest rate, change of control repurchase and redemption provisions. Rattler LLC used the proceeds from the Notes Offering to repay a portion of the outstanding borrowings under the Rattler credit agreement.

For additional information regarding our indebtedness, see Note 10—Debt included in Notes to the Condensed Consolidated Financial Statements included elsewhere in this report.

Capital Requirements and Sources of Liquidity

Our board of directors approved a 2020 capital budget for drilling and completion, midstream and infrastructure of approximately $2.8 billion to $3.0 billion. In response to the current commodity price environment, in the third quarter of 2020 we updated our 2020 capital budget to narrow our anticipated capital expenditures for 2020 to approximately $1.8 billion to $1.9 billion, representing a decrease of 36% over our 2019 capital budget. We estimate that, of these expenditures, approximately:

•$1.565 billion to $1.630 billion will be spent on drilling and completing 170 to 200 gross (153 to 180 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 10,000 feet;

•$125 million to $150 million will be spent on midstream infrastructure, excluding joint venture investments; and

•$110 million to $120 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

    We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

During the third quarter of 2020, we spent $219 million on drilling and completion, $39 million on midstream, $7 million on non-operated properties and $16 million on infrastructure, for total capital expenditures of $281 million. During the nine months ended September 30, 2020, we spent $1.3 billion on drilling and completion, $133 million on midstream, $96 million on infrastructure and $57 million on non-operated properties, for total capital expenditures of $1.6 billion.

In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. Under this program, we did not repurchase any of our common stock during the third quarter of 2020, but repurchased approximately $98 million of common stock during the nine months ended September 30, 2020. Although we have approximately $1.3 billion remaining available for future repurchases under this program, we have suspended the program to preserve liquidity.

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The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We are currently operating six drilling rigs and three completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

Based upon current oil and natural gas prices and production expectations for 2020, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through the 12-month period following the filing of this report. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2020 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. If there is a decline in commodity prices, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.

Guarantor Financial Information

As of September 30, 2020, Diamondback O&G LLC is the sole guarantor under the December 2019 Notes Indenture governing the December 2019 Notes and the May 2020 Notes and the 2025 Indenture governing the 2025 Senior Notes. In connection with the satisfaction and discharge of the indenture, dated as of October 28, 2016, as subsequently supplemented, among Diamondback Energy, Inc., the guarantor subsidiaries party thereto and Wells Fargo, as trustee, governing Diamondback Energy, Inc.’s then outstanding 4.750% Senior Notes due 2024, or the 4.750% senior notes, Diamondback E&P LLC and Energen Corporation and its subsidiaries were released as guarantors under the 4.750% senior notes, the 2025 Senior Notes and Diamondback O&G LLC’s revolving credit facility. Rattler LLC was released as a guarantor under Diamondback O&G LLC’s credit agreement on May 28, 2019. Viper, Viper’s General Partner, Viper LLC, Rattler, Rattler’s General Partner and Rattler’s subsidiaries remain non-guarantor subsidiaries.

Diamondback O&G LLC’s guarantees of the December 2019 Notes, the May 2020 Notes and the 2025 Senior Notes are “full and unconditional,” as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the December 2019 Notes Indenture and the 2025 Indenture, such as, with certain exceptions, (1) in the event Diamondback O&G LLC (or all or substantially all of its assets) is sold or disposed of, (2) in the event Diamondback O&G LLC ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (3) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.

Diamondback O&G LLC’s guarantees of the December 2019 Notes, the May 2020 Notes and the 2025 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The rights of holders of the Senior Notes against Diamondback O&G LLC may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback O&G LLC’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of Diamondback O&G LLC. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

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The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and Diamondback O&G LLC, as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiary operated as an independent entity.

	September 30, 2020		December 31, 2019
Summarized Balance Sheets	(in millions)
Assets
Current assets	$	303	$	396
Property and equipment, net	7,923		10,109
Other noncurrent assets	7		17
Liabilities
Current liabilities	$	214	$	167
Intercompany accounts payable, non-guarantor subsidiary	386		600
Long-term debt	4,268		3,782
Other noncurrent liabilities	1,124		504

	Nine Months Ended September 30, 2020
Summarized Statement of Operations	(in millions)
Revenues	$	1,185
Income (loss) from operations	(2,627)
Net income (loss)	(1,535)

Contractual Obligations

Other than the changes in debt discussed in Note 10—Debt included in Notes to the Condensed Consolidated Financial Statements included elsewhere in this report, there were no material changes to our contractual obligations and other commitments, from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019.

Critical Accounting Policies

There have been no changes in our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019.

Off-Balance Sheet Arrangements

We had no material off-balance sheet arrangements as of September 30, 2020. Please read Note 17 included in Notes to the Condensed Consolidated Financial Statements set forth in Part I, Item 1 of this report, for a discussion of our commitments and contingencies, which are not recognized in the balance sheets under GAAP.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our major market risk exposure in our exploration and production business is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. Oil prices dropped sharply in early March 2020, and then continued to decline reaching negative levels. This was a result of multiple factors affecting supply and demand in global oil and gas markets, including actions taken by OPEC members and other oil exporting nations impacting commodity price and production levels and a significant decrease in demand due to the ongoing COVID-19 pandemic, which resulted in a widespread health and economic crisis. While OPEC members and certain other nations agreed in April of 2020 to cut production, which helped to reduce a portion of the excess supply in the market and improve oil prices, there is no assurance that this agreement will continue or be observed by its parties, and downward pressure on commodity prices has continued and could continue for the foreseeable future. We cannot predict if or when commodity prices will stabilize and at what levels.

We use derivatives, including swaps, basis swaps, double-up swaps, put spreads, interest rate swaps, swaptions, rolling hedges, calls, options, costless collars and three-way collars, to reduce price volatility associated with certain of our oil and natural gas sales. Please read Note 14 included in Notes to the Condensed Consolidated Financial Statements set forth in Part I, Item 1 of this report, for a discussion of our derivatives.

At September 30, 2020, we had a net liability derivative position related to our commodity price derivatives of $115 million, related to our price swap, price basis swap derivatives and costless collars. Utilizing actual derivative contractual volumes under our commodity price derivatives as of September 30, 2020, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to $151 million, an increase of $36 million, while a 10% decrease in forward curves associated with the underlying commodity would have converted the net liability position to a net asset derivative position of $78 million, a change of $37 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

In our midstream operations business, we have indirect exposure to commodity price risk in that persistent low commodity prices may cause us or Rattler’s other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets. If we or Rattler’s other customers delay drilling or temporarily shuts in production due to persistently low commodity prices or for any other reason, our revenue in the midstream operations segment could decrease, as Rattler’s commercial agreements do not contain minimum volume commitments.

For additional information on our open commodity derivative instruments at September 30, 2020, see Note 14—Derivatives included in Notes to the Condensed Consolidated Financial Statements elsewhere in this report.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $67 million at September 30, 2020) and receivables from the sale of our oil and natural gas production (approximately $224 million at September 30, 2020).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with a limited number of significant customers. We do not require our customers to post collateral, and the failure or inability of our significant customers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

The ongoing COVID-19 pandemic, depressed commodity pricing environment and adverse macroeconomic conditions may enhance our customer credit risk.

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Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We have used interest rate swaps and treasury locks to reduce our exposure to variable rate interest payments associated with our revolving credit facility.

The following table summarizes the Company’s interest rate swaps and treasury locks as of September 30, 2020:

Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.551	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.5575	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.297	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.195	%

For additional information on our variable interest rate debt at September 30, 2020, see Note 10—Debt included in Notes to the Condensed Consolidated Financial Statements elsewhere in this report. See Note 18—Subsequent Events for discussion of derivative transactions which occurred subsequent to September 30, 2020.

ITEM 4.          CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures

Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of September 30, 2020, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of September 30, 2020, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2020 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

We are a party to various routine legal proceedings, disputes and claims arising in the ordinary course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, results of operations or cash flows.

ITEM 1A. RISK FACTORS

Our business faces many risks. Any of the risks discussed in this report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially impair our business operations, financial condition or future results.

As of the date of this filing, we continue to be subject to the risk factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 27, 2020, and in Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, filed with the SEC on May 8, 2020. Depending on the duration of the COVID-19 pandemic and its severity and related economic repercussions, however, the negative impact of many of the risks discussed in such reports may be heightened or exacerbated. For a discussion of the recent trends and uncertainties impacting our business, see also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—2020 Recent Developments—COVID-19 and Collapse in Commodity Prices” and “—Our Response to the Commodity Price Volatility and Impact of COVID.”

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ITEM 6.    EXHIBITS

EXHIBIT INDEX

Exhibit Number	Description
3.1	Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
3.2	Certificate of Amendment No. 1 of the Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 12, 2016).
3.3	Second Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 19, 2019).
4.1	Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
4.2	Indenture, dated as of July 14, 2020, among Rattler Midstream LP, as issuer, Rattler Midstream Operating LLC, Tall City Towers LLC, Rattler Ajax Processing LLC, and Rattler OMOG LLC, as guarantors, and Wells Fargo Bank, National Association, as trustee (including the form of Rattler Midstream LP’s 5.625% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-38919, filed by Rattler Midstream LP with the SEC on July 14, 2020).
10.1*	Second Amendment, dated as of November 2, 2020, to the Credit Agreement, dated May 28, 2019, as amended on October 23, 2019, by and among Rattler Midstream Operating LLC, as borrower, Rattler Midstream LP, as parent, Wells Fargo Bank, National Association, as the administrative agent, and certain lenders from time to time party thereto.
22.1	List of Issuers and Guarantor Subsidiaries (incorporated by reference to Exhibit 22.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on May 7, 2020).
31.1*	Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*	Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1**	Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2**	Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101	The following financial information from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, formatted in Inline XBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statement of Changes in Stockholders’ Equity, (iv) Condensed Consolidated Statements of Cash Flows and (v) Condensed Notes to Consolidated Financial Statements.
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

______________

*	Filed herewith.
**	The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Quarterly Report on Form 10-Q pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		DIAMONDBACK ENERGY, INC.
Date:	November 5, 2020	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer
		(Principal Executive Officer)
Date:	November 5, 2020	/s/ Kaes Van’t Hof
		Kaes Van’t Hof
		Chief Financial Officer
		(Principal Financial Officer)

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EX-10.1

Exhibit 10.1

SECOND AMENDMENT TO

CREDIT AGREEMENT

DATED AS OF

NOVEMBER 2, 2020

AMONG

RATTLER MIDSTREAM LP,

AS PARENT,

RATTLER MIDSTREAM OPERATING LLC,

AS BORROWER,

WELLS FARGO BANK, NATIONAL ASSOCIATION,

AS ADMINISTRATIVE AGENT,

THE LENDERS PARTY HERETO, AND

WELLS FARGO SECURITIES, LLC,

CREDIT SUISSE SECURITIES (USA) LLC,

JPMORGAN CHASE BANK, N.A., AND

MERRILL LYNCH, PIERCE, FENNER & SMITH INCORPORATED,

AS JOINT LEAD ARRANGERS AND JOINT BOOKRUNNERS

This SECOND AMENDMENT TO CREDIT AGREEMENT (this “Amendment”), dated as of November 2, 2020, is among: Rattler Midstream LP, a Delaware limited partnership (the “Parent”); Rattler Midstream Operating LLC, a Delaware limited liability company (the “Borrower”); each of the undersigned guarantors (together with the Parent, the “Guarantors”); each of the Lenders (as such term is defined in the Credit Agreement referred to below) party hereto; and Wells Fargo Bank, National Association, as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”).

R E C I T A L S

A.    The Parent, the Borrower, the Administrative Agent, and the Lenders are parties to that certain Credit Agreement, dated as of May 28, 2019 (as amended and supplemented prior to the date hereof, the “Credit Agreement”), pursuant to which the Lenders have made certain credit available to and on behalf of the Borrower.

B.    The Borrower has requested and the Lenders signatory hereto have agreed to amend certain provisions of the Credit Agreement as set forth herein.

C.    Now, therefore, to induce the Administrative Agent and the Lenders to enter into this Amendment and in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.    Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement as amended by this Amendment. Unless otherwise indicated, all section references in this Amendment refer to sections of the Credit Agreement.

Section 2.    Amendments to Credit Agreement. In reliance on the representations, warranties, covenants, and agreements contained in this Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, the Credit Agreement is hereby amended, effective as of the Amendment Effective Date (as defined below), as follows:

2.1    Amendments to Section 1.02.

(a)    The following definitions are hereby amended and restated in their entirety to read as follows:

“Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable Resolution Authority in respect of any liability of an Affected Financial Institution.

“Bail-In Legislation” means (a) with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law, regulation, rule or requirement for such EEA Member Country from time to time which is

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described in the EU Bail-In Legislation Schedule and (b) with respect to the United Kingdom, Part I of the United Kingdom Banking Act 2009 (as amended from time to time) and any other law, regulation or rule applicable in the United Kingdom relating to the resolution of unsound or failing banks, investment firms or other financial institutions or their affiliates (other than through liquidation, administration or other insolvency proceedings).

“EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“Loan Documents” means this Agreement, the First Amendment, the Second Amendment, the Notes, the Letter of Credit Agreements, the Letters of Credit, and the Security Instruments.

“Write-Down and Conversion Powers” means, (a) with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule, and (b) with respect to the United Kingdom, any powers of the applicable Resolution Authority under the Bail-In Legislation to cancel, reduce, modify or change the form of a liability of any UK Financial Institution or any contract or instrument under which that liability arises, to convert all or part of that liability into shares, securities or obligations of that person or any other person, to provide that any such contract or instrument is to have effect as if a right had been exercised under it or to suspend any obligation in respect of that liability or any of the powers under that Bail-In Legislation that are related to or ancillary to any of those powers.

(b)    The following definitions are hereby added where alphabetically appropriate to read as follows:

“Affected Financial Institution” means (a) any EEA Financial Institution or (b) any UK Financial Institution.

“Resolution Authority” means an EEA Resolution Authority or, with respect to any UK Financial Institution, a UK Resolution Authority.

“Second Amendment” means that certain Second Amendment to Credit Agreement, dated as of the Second Amendment Effective Date, by and among the Parent, the Borrower, the other Guarantors party thereto, the Administrative Agent, and the Lenders party thereto.

“Second Amendment Effective Date” means November 2, 2020.

2

“UK Financial Institution” means any BRRD Undertaking (as such term is defined under the PRA Rulebook (as amended form time to time) promulgated by the United Kingdom Prudential Regulation Authority) or any person falling within IFPRU 11.6 of the FCA Handbook (as amended from time to time) promulgated by the United Kingdom Financial Conduct Authority, which includes certain credit institutions and investment firms, and certain affiliates of such credit institutions or investment firms.

“UK Resolution Authority” means the Bank of England or any other public administrative authority having responsibility for the resolution of any UK Financial Institution.

2.2    Amendments to Section 9.04(a). Section 9.04(a) of the Credit Agreement is

hereby amended by (a) deleting the reference to “and” at the end of clause (viii) therein, (b) replacing the reference to “.” with “; and” at the end of clause (ix) therein and (c) adding a new clause (x) thereto immediately following clause (ix) thereof to read as follows:

(x)    commencing on the Second Amendment Effective Date, (1) the Parent may make Restricted Payments other than dividends and distributions in an aggregate amount not to exceed $200,000,000; provided that both prior to and after giving pro forma effect thereto (including any Borrowings made in connection with any such Restricted Payment), (A) no Default or Event of Default has occurred and is continuing, (B) the Consolidated Total Leverage Ratio does not exceed 3.00 to 1.00, and (C) Availability is equal to or greater than $400,000,000 and (2) the Borrower may make Restricted Payments to the Parent.

2.3    Amendment to Section 12.17. Section 12.17 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

Section 12.17    Acknowledgement and Consent to Bail-In of Affected Financial Institutions. Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Affected Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the write-down and conversion powers of the applicable Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)    the application of any Write-Down and Conversion Powers by the applicable Resolution Authority to any such liabilities arising hereunder which may be payable to it by any party hereto that is an Affected Financial Institution; and

(b)    the effects of any Bail-in Action on any such liability, including, if applicable:

(i)    a reduction in full or in part or cancellation of any such liability;

3

(ii)    a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such Affected Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

(iii)    the variation of the terms of such liability in connection with the exercise of the write-down and conversion powers of the applicable Resolution Authority.

Section 3.    Conditions Precedent. This Amendment shall become effective on the date (such date, the “Amendment Effective Date”) when each of the following conditions is satisfied (or waived in accordance with Section 12.02 of the Credit Agreement):

3.1    The Administrative Agent shall have received from Lenders constituting Majority Lenders, the Guarantors, and the Borrower, counterparts (in such number as may be requested by the Administrative Agent) of this Amendment signed on behalf of such Person.

3.2    The Administrative Agent and the Lenders shall have received all fees and other amounts due and payable on or prior to the date hereof, including, to the extent invoiced, reimbursement or payment of all documented out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Credit Agreement.

3.3    No Default shall have occurred and be continuing as of the date hereof, after giving effect to the terms of this Amendment.

The Administrative Agent is hereby authorized and directed to declare this Amendment to be effective when it has received documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 3 or the waiver of such conditions as permitted in Section 12.02 of the Credit Agreement. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for all purposes.

Section 4.    Miscellaneous.

4.1    Confirmation. The provisions of the Credit Agreement (as amended by this Amendment) shall remain in full force and effect following the effectiveness of this Amendment.

4.2    Ratification and Affirmation; Representations and Warranties. Each of the Guarantors and the Borrower hereby (a) ratifies and affirms its obligations under, and acknowledges its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to which it is a party remains in full force and effect as expressly amended hereby and (b) represents and warrants to the Lenders that as of the date hereof, after giving effect to the terms of this Amendment:

4

(i)    all of the representations and warranties contained in each Loan Document to which it is a party are true and correct in all material respects (or, if already qualified by materiality, Material Adverse Effect or a similar qualification, true and correct in all respects), except to the extent any such representations and warranties are expressly limited to an earlier date, in which case such representations and warranties shall be true and correct in all material respects (or, if already qualified by materiality, Material Adverse Effect or a similar qualification, true and correct in all respects) as of such specified earlier date;

(ii)    no Default or Event of Default has occurred and is continuing; and

(iii)    no event or events have occurred which individually or in the aggregate could reasonably be expected to have a Material Adverse Effect.

4.3    Counterparts. This Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Amendment by facsimile or electronic transmission shall be effective as delivery of a manually executed counterpart hereof.

4.4    NO ORAL AGREEMENT. THIS AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT UNWRITTEN ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

4.5    GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

4.6    Payment of Expenses. To the extent required pursuant to Section 12.03 of the Credit Agreement, the Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonable out-of-pocket expenses incurred in connection with this Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees, charges and disbursements of counsel to the Administrative Agent.

4.7    Severability. Any provision of this Amendment that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

5

4.8    Successors and Assigns. This Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

4.9    Loan Document. This Amendment is a Loan Document.

[SIGNATURES BEGIN NEXT PAGE]

6

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed as of the date first written above.

BORROWER:	RATTLER MIDSTREAM OPERATING LLC
	By:	/s/ Teresa L. Dick
	Name:	Teresa L. Dick
	Title:	Chief Financial Officer, Executive Vice President and Assistant Secretary
GUARANTORS:	RATTLER MIDSTREAM LP
	By:	Rattler Midstream GP LLC, its General Partner
	By:	/s/ Teresa L. Dick
	Name:	Teresa L. Dick
	Title:	Chief Financial Officer, Executive Vice President and Assistant Secretary
	TALL CITY TOWERS LLC
	By:	/s/ Teresa L. Dick
	Name:	Teresa L. Dick
	Title:	Chief Financial Officer, Executive Vice President and Assistant Secretary
	RATTLER OMOG LLC
	By:	Rattler Midstream Operating LLC, its sole member
	By:	/s/ Teresa L. Dick
	Name:	Teresa L. Dick
	Title:	Chief Financial Officer, Executive Vice President and Assistant Secretary

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

RATTLER AJAX PROCESSING LLC
By:	Rattler Midstream Operating LLC, its sole member
By:	/s/ Teresa L. Dick
Name:	Teresa L. Dick
Title:	Chief Financial Officer, Executive Vice President and Assistant Secretary

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

ADMINISTRATIVE AGENT,	WELLS FARGO BANK, NATIONAL
ISSUING BANK AND LENDER:	ASSOCATION, as Administrative Agent, Issuing
	Bank and as a Lender
	By:	/s/ Andrew Ostrov
	Name:	Andrew Ostrov
	Title:	Director

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

LENDERS:	BANK OF AMERICA, N.A.
	By:	/s/ Ronald E. McKaig
	Name:	Ronald E. McKaig
	Title:	Managing Director

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

LENDERS:	CREDIT SUISSE AG, CAYMAN ISLANDS
	BRANCH
	By:	/s/ Nupur Kumar
	Name:	Nupur Kumar
	Title:	Authorized Signatory
	By:	/s/ Andrew Griffin
	Name:	Andrew Griffin
	Title:	Authorized Signatory

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

LENDERS:	JPMORGAN CHASE BANK, N.A.
	By:	/s/ Michael A. Kamauf
	Name:	Michael A. Kamauf
	Title:	Authorized Officer

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

LENDERS:	CITIBANK, N.A.
	By:	/s/ Jeff Ard
	Name:	Jeff Ard
	Title:	Vice President

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

LENDERS:	PNC BANK, NATIONAL ASSOCIATION
	By:	/s/ John Engel
	Name:	John Engel
	Title:	Vice President

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

LENDERS:	BARCLAYS BANK PLC
	By:	/s/ Sydney G. Dennis
	Name:	Sydney G. Dennis
	Title:	Director

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

LENDERS:	CAPITAL ONE, NATIONAL ASSOCIATION
	By:	/s/ Christopher Kuna
	Name:	Christopher Kuna
	Title:	Senior Director

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

LENDERS:	TRUIST BANK, successor by merger to SunTrust
	Bank, as a Lender
	By:	/s/ Samantha Sanford
	Name:	Samantha Sanford
	Title:	Vice President

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

LENDERS:	THE BANK OF NOVA SCOTIA, HOUSTON
	BRANCH
	By:	/s/ Scott Nickel
	Name:	Scott Nickel
	Title:	Director

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

LENDERS:	U.S. BANK NATIONAL ASSOCIATION
	By:	/s/ Bruce E. Hernandez
	Name:	Bruce E. Hernandez
	Title:	Senior Vice President

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

LENDERS:	GOLDMAN SACHS BANK USA
	By:	/s/ Mahesh Mohan
	Name:	Mahesh Mohan
	Title:	Authorized Signatory

SIGNATURE PAGE

SECOND AMENDMENT TO CREDIT AGREEMENT

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Travis D. Stice, certify that:

1.    I have reviewed this Quarterly Report on Form 10-Q of Diamondback Energy, Inc.

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)    Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)    Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 5, 2020	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Kaes Van't Hof, certify that:

1.    I have reviewed this Quarterly Report on Form 10-Q of Diamondback Energy, Inc.

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)    Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)    Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)    Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.    The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)    All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)    Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 5, 2020	/s/ Kaes Van't Hof
		Kaes Van't Hof
		Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PERIOD REPORT

In connection with the Quarterly Report on Form 10-Q of Diamondback Energy, Inc. (the "Company"), as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, Travis D. Stice, Chief Executive Officer of Diamondback Energy, Inc., certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 5, 2020	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF PERIOD REPORT

In connection with the Quarterly Report on Form 10-Q of Diamondback Energy, Inc. (the "Company"), as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, Kaes Van't Hof, Chief Financial Officer of Diamondback Energy, Inc., certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 5, 2020	/s/ Kaes Van't Hof
		Kaes Van't Hof
		Chief Financial Officer

XML

Cover - shares	9 Months Ended
	Sep. 30, 2020	Oct. 30, 2020
Cover [Abstract]
Document type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 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
Trading Symbol	FANG
Security Exchange Name	NASDAQ
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		157,972,650
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q3
Entity Central Index Key	0001539838
Current Fiscal Year End Date	--12-31

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 92	$ 123
Restricted cash	7	5
Accounts receivable:
Joint interest and other, net	67	186
Oil and natural gas sales, net	224	429
Inventories	33	37
Derivative instruments	15	46
Income tax receivable	100	19
Prepaid expenses and other current assets	20	24
Total current assets	558	869
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($7,879 million and $9,207 million excluded from amortization at September 30, 2020 and December 31, 2019, respectively)	27,305	25,782
Midstream assets	1,026	931
Other property, equipment and land	135	125
Accumulated depletion, depreciation, amortization and impairment	(11,031)	(5,003)
Property and equipment, net	17,435	21,835
Equity method investments	532	479
Derivative instruments	0	7
Deferred tax assets, net	75	142
Investment in real estate, net	104	109
Other assets	56	90
Total assets	18,760	23,531
Current liabilities:
Accounts payable - trade	95	179
Accrued capital expenditures	309	475
Current maturities of long-term debt	191	0
Other accrued liabilities	329	304
Revenues and royalties payable	219	278
Derivative instruments	86	27
Total current liabilities	1,229	1,263
Long-term debt	5,656	5,371
Derivative instruments	108	0
Asset retirement obligations	112	94
Deferred income taxes	978	1,886
Other long-term liabilities	8	11
Total liabilities	8,091	8,625
Commitments and contingencies (Note 17)
Stockholders’ equity:
Common stock, $0.01 par value; 200,000,000 shares authorized; 157,849,848 and 159,002,338 shares issued and outstanding at September 30, 2020 and December 31, 2019, respectively	2	2
Additional paid-in capital	12,615	12,357
Retained earnings (accumulated deficit)	(3,065)	890
Total Diamondback Energy, Inc. stockholders’ equity	9,552	13,249
Non-controlling interest	1,117	1,657
Total equity	10,669	14,906
Total liabilities and equity	$ 18,760	$ 23,531

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parentheticals) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Oil and natural gas properties, amortization excluded	$ 7,879	$ 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)	157,849,848	159,002,338
Shares Outstanding (in Shares)	157,849,848	159,002,338

XML

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Revenues:
Revenue	$ 707	$ 956	$ 2,002	$ 2,798
Lease bonus	0	1	0	4
Other operating income	1	2	5	7
Total revenues	720	975	2,044	2,860
Costs and expenses:
Lease operating expenses	102	128	332	364
Production and ad valorem taxes	55	61	148	180
Depreciation, depletion and amortization	286	365	1,036	1,046
Impairment of oil and natural gas properties	1,451	0	4,999	0
General and administrative expenses	20	19	64	68
Asset retirement obligation accretion	2	1	5	6
Other operating expense	1	1	4	3
Total costs and expenses	1,976	626	6,774	1,781
Income (loss) from operations	(1,256)	349	(4,730)	1,079
Other income (expense):
Interest expense, net	(53)	(38)	(147)	(133)
Other income, net	0	2	1	5
Gain (loss) on derivative instruments, net	(99)	177	82	3
Gain (loss) on revaluation of investment	(2)	0	(9)	4
Loss on early extinguishment of debt	(2)	0	(5)	0
(Income) loss from equity investment	3	0	(10)	0
Total other income (expense), net	(153)	141	(88)	(121)
Income (loss) before income taxes	(1,409)	490	(4,818)	958
Provision for (benefit from) income taxes	(304)	102	(902)	171
Net income (loss)	(1,105)	388	(3,916)	787
Net income (loss) attributable to non-controlling interest	8	20	(138)	60
Net income (loss) attributable to Diamondback Energy, Inc.	$ (1,113)	$ 368	$ (3,778)	$ 727
Earnings (loss) per common share:
Basic (in USD per share)	$ (7.05)	$ 2.27	$ (23.91)	$ 4.44
Diluted (in USD per share)	$ (7.05)	$ 2.26	$ (23.91)	$ 4.42
Weighted average common shares outstanding:
Basic (in shares)	157,833	162,543	157,984	164,070
Diluted (in shares)	157,833	162,780	157,984	164,466
Dividends declared per share (in USD per share)	$ 0.375	$ 0.1875	$ 1.125	$ 0.5625
Oil sales
Revenues:
Revenue	$ 606	$ 882	$ 1,785	$ 2,572
Natural gas sales
Revenues:
Revenue	36	16	61	36
Natural gas liquid sales
Revenues:
Revenue	65	58	156	190
Midstream services
Revenues:
Revenue	12	16	37	51
Costs and expenses:
Cost of goods and services sold	26	26	81	60
Gathering and transportation
Costs and expenses:
Cost of goods and services sold	$ 33	$ 25	$ 105	$ 54

XML

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited) - USD ($) $ in Millions	Total	Viper Energy Partners LP	Common Stock	Additional Paid-in Capital	Retained Earnings (Accumulated Deficit)	Non-Controlling Interest	Non-Controlling Interest Viper Energy Partners LP
Balance at beginning of period at Dec. 31, 2018	$ 14,167		$ 2	$ 12,936	$ 762	$ 467
Balance at beginning of period (in Shares) at Dec. 31, 2018			164,273,000
Increase (Decrease) in Stockholders' Equity
Net proceeds from issuance of common units		$ 341					$ 341
Stock-based compensation	19			19
Repurchased shares for share buyback program	(13)			(13)
Repurchased shares for share buyback program (in Shares)			(125,000)
Distribution to non-controlling interest	(26)					(26)
Dividend paid	(20)				(20)
Exercise of stock options and vesting of restricted stock units	0			0
Exercise of stock and unit options and awards of restricted stock (in Shares)			468,000
Change in ownership of consolidated subsidiaries, net	3			77		(74)
Net income (loss)	43				10	33
Balance at end of period at Mar. 31, 2019	14,514		$ 2	13,019	752	741
Balance at end of period (in Shares) at Mar. 31, 2019			164,616,000
Balance at beginning of period at Dec. 31, 2018	14,167		$ 2	12,936	762	467
Balance at beginning of period (in Shares) at Dec. 31, 2018			164,273,000
Increase (Decrease) in Stockholders' Equity
Net income (loss)	787
Balance at end of period at Sep. 30, 2019	15,489		$ 2	12,641	1,407	1,439
Balance at end of period (in Shares) at Sep. 30, 2019			161,142,000
Balance at beginning of period at Mar. 31, 2019	14,514		$ 2	13,019	752	741
Balance at beginning of period (in Shares) at Mar. 31, 2019			164,616,000
Increase (Decrease) in Stockholders' Equity
Net proceeds from issuance of common units		$ 720					$ 720
Unit-based compensation	2					2
Stock-based compensation	12			12
Repurchased shares for share buyback program	(104)			(104)
Repurchased shares for share buyback program (in Shares)			(1,016,000)
Distribution to non-controlling interest	(24)					(24)
Dividend paid	(32)				(32)
Exercise of stock options and vesting of restricted stock units	6			6
Exercise of stock and unit options and awards of restricted stock (in Shares)			349,000
Net income (loss)	356				349	7
Balance at end of period at Jun. 30, 2019	15,450		$ 2	12,933	1,069	1,446
Balance at end of period (in Shares) at Jun. 30, 2019			163,949,000
Increase (Decrease) in Stockholders' Equity
Unit-based compensation	2					2
Stock-based compensation	1			1
Repurchased shares for share buyback program	(296)			(296)
Repurchased shares for share buyback program (in Shares)			(2,954,000)
Distribution to non-controlling interest	(29)					(29)
Dividend paid	(30)				(30)
Exercise of stock options and vesting of restricted stock units	3			3
Exercise of stock and unit options and awards of restricted stock (in Shares)			147,000
Net income (loss)	388				368	20
Balance at end of period at Sep. 30, 2019	15,489		$ 2	12,641	1,407	1,439
Balance at end of period (in Shares) at Sep. 30, 2019			161,142,000
Balance at beginning of period at Dec. 31, 2019	$ 14,906		$ 2	12,357	890	1,657
Balance at beginning of period (in Shares) at Dec. 31, 2019	159,002,338		159,002,000
Increase (Decrease) in Stockholders' Equity
Unit-based compensation	$ 5					5
Distribution equivalent rights payments	(1)					(1)
Stock-based compensation	10			10
Repurchased shares for tax withholding	(5)			(5)
Repurchased shares for tax withholding (in Shares)			(75,000)
Repurchased shares for share buyback program	(98)			(98)
Repurchased shares for share buyback program (in Shares)			(1,280,000)
Distribution to non-controlling interest	(43)					(43)
Dividend paid	(59)				(59)
Exercise of stock options and vesting of restricted stock units	1			1
Exercise of stock and unit options and awards of restricted stock (in Shares)			168,000
Net income (loss)	(400)				(272)	(128)
Balance at end of period at Mar. 31, 2020	14,316		$ 2	12,265	559	1,490
Balance at end of period (in Shares) at Mar. 31, 2020			157,815,000
Balance at beginning of period at Dec. 31, 2019	$ 14,906		$ 2	12,357	890	1,657
Balance at beginning of period (in Shares) at Dec. 31, 2019	159,002,338		159,002,000
Increase (Decrease) in Stockholders' Equity
Repurchased shares for share buyback program	$ (98)
Net income (loss)	(3,916)
Balance at end of period at Sep. 30, 2020	$ 10,669		$ 2	12,615	(3,065)	1,117
Balance at end of period (in Shares) at Sep. 30, 2020	157,849,848		157,850,000
Balance at beginning of period at Mar. 31, 2020	$ 14,316		$ 2	12,265	559	1,490
Balance at beginning of period (in Shares) at Mar. 31, 2020			157,815,000
Increase (Decrease) in Stockholders' Equity
Distribution equivalent rights payments	(1)					(1)
Stock-based compensation	11			11
Repurchased shares for tax withholding	(2)			0		(2)
Distribution to non-controlling interest	(19)					(19)
Dividend paid	(59)				(59)
Exercise of stock options and vesting of restricted stock units	0			0
Exercise of stock and unit options and awards of restricted stock (in Shares)			9,000
Change in ownership of consolidated subsidiaries, net	0			329		(329)
Net income (loss)	(2,411)				(2,393)	(18)
Balance at end of period at Jun. 30, 2020	11,835		$ 2	12,605	(1,893)	1,121
Balance at end of period (in Shares) at Jun. 30, 2020			157,824,000
Increase (Decrease) in Stockholders' Equity
Unit-based compensation	3					3
Stock-based compensation	10			10
Repurchased shares for tax withholding	$ 0			0
Repurchased shares for tax withholding (in Shares)			(1,000)
Repurchased shares for share buyback program (in Shares)	0
Distribution to non-controlling interest	$ (15)					(15)
Dividend paid	(59)				(59)
Exercise of stock options and vesting of restricted stock units	0			0
Exercise of stock and unit options and awards of restricted stock (in Shares)			27,000
Net income (loss)	(1,105)				(1,113)	8
Balance at end of period at Sep. 30, 2020	$ 10,669		$ 2	$ 12,615	$ (3,065)	$ 1,117
Balance at end of period (in Shares) at Sep. 30, 2020	157,849,848		157,850,000

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Cash flows from operating activities:
Net income (loss)	$ (3,916)	$ 787
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes	(902)	171
Impairment of oil and natural gas properties	4,999	0
Depreciation, depletion and amortization	1,036	1,046
(Gain) loss on derivative instruments, net	(82)	(3)
Cash received on settlement of derivative instruments	288	33
Other	68	34
Changes in operating assets and liabilities:
Accounts receivable	265	(116)
Accounts payable and accrued liabilities	(18)	(136)
Accrued interest	34	(29)
Revenues and royalties payable	(59)	64
Other	2	1
Net cash provided by (used in) operating activities	1,715	1,852
Cash flows from investing activities:
Drilling, completions and non-operated additions to oil and natural gas properties	(1,404)	(1,883)
Infrastructure additions to oil and natural gas properties	(96)	(104)
Additions to midstream assets	(133)	(186)
Acquisitions of leasehold interests	(89)	(311)
Acquisitions of mineral interests	(65)	(320)
Proceeds from sale of assets	2	301
Contributions to equity method investments	(90)	(225)
Distributions from equity method investments	27	0
Other	(7)	(16)
Net cash provided by (used in) investing activities	(1,855)	(2,744)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	917	1,409
Repayments under credit facility	(1,238)	(1,168)
Proceeds from senior notes	997	0
Repayment of senior notes	(239)	0
Proceeds from joint venture	47	42
Public offering costs	0	(40)
Proceeds from public offerings	0	1,106
Repurchased shares as part of share buyback	(98)	(400)
Dividends to stockholders	(177)	(82)
Distributions to non-controlling interest	(77)	(79)
Other	(21)	(11)
Net cash provided by (used in) financing activities	111	777
Net increase (decrease) in cash and cash equivalents	(29)	(115)
Cash, cash equivalents and restricted cash at beginning of period	128	215
Cash, cash equivalents and restricted cash at end of period	99	100
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	100	115
Accrued capital expenditures	$ 352	$ 560

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DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

9 Months Ended

Sep. 30, 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., together with its subsidiaries (collectively referred to as “Diamondback” or the “Company” unless the context otherwise requires), is an independent oil and gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on December 30, 2011.

The wholly-owned subsidiaries of Diamondback, as of September 30, 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, Rattler Midstream GP LLC, a Delaware limited liability company, 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’s subsidiary Viper Energy Partners LLC, a Delaware limited liability company, Rattler Midstream LP, a Delaware limited partnership, Rattler Midstream Operating LLC, a Delaware limited liability company, 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, and Energen’s wholly-owned subsidiaries Energen Resources Corporation, an Alabama corporation, and EGN Services, Inc., an Alabama corporation.

Basis of Presentation

The condensed 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 September 30, 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 September 30, 2020, the Company owned approximately 71% 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.

These condensed consolidated financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to SEC rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2019, which contains a summary of the Company’s significant accounting policies and other disclosures.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

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 gas markets. Companies in the oil and 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.

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 deemed 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. The adoption of ASU 2016-13 did not result in a material change to the Company’s allowance. At September 30, 2020 and December 31, 2019, the Company recorded an immaterial allowance for expected losses.

Non-controlling Interest

Non-controlling interest in the accompanying condensed consolidated financial statements represents minority interest ownership in Viper and Rattler. 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.

In the second quarter of 2020, the Company recorded 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. See Note 11—Capital Stock and Earnings Per Share for a presentation of the change in ownership.

Recent Accounting Pronouncements

The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Company’s analysis of the effects on its financial statements:

Standard	Description	Date of Adoption	Effect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 2016-13, “Financial Instruments - Credit Losses”	This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash.	Q1 2020	The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”	This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.	Q1 2021	This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company does not believe that the adoption of this update will have an impact on its financial position, results of operations or liquidity.

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REVENUE FROM CONTRACTS WITH CUSTOMERS

9 Months Ended

Sep. 30, 2020

Revenue from Contract with Customer [Abstract]

REVENUE FROM CONTRACTS WITH CUSTOMERS

REVENUE FROM CONTRACTS WITH CUSTOMERS

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

	Three Months Ended September 30, 2020								Three Months Ended September 30, 2019
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	348	$	257	$	1	$	606	$	529	$	350	$	3	$	882
Natural gas sales	19		17		—		36		7		8		1		16
Natural gas liquid sales	36		28		1		65		33		25		—		58
Total	$	403	$	302	$	2	$	707	$	569	$	383	$	4	$	956

	Nine Months Ended September 30, 2020								Nine Months Ended September 30, 2019
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	1,030	$	750	$	5	$	1,785	$	1,561	$	951	$	60	$	2,572
Natural gas sales	32		29		—		61		17		18		1		36
Natural gas liquid sales	88		67		1		156		110		78		2		190
Total	$	1,150	$	846	$	6	$	2,002	$	1,688	$	1,047	$	63	$	2,798

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DIVESTITURES

9 Months Ended

Sep. 30, 2020

Business Combinations [Abstract]

DIVESTITURES

DIVESTITURES

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, 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, 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 18.3 million of Viper’s newly-issued Class B units, approximately 18.3 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits (the “Drop-Down”). The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by the Company, and have an average net royalty interest of approximately 3.2% (the “Drop-Down Assets”). The Drop-Down closed on October 1, 2019 and was effective as of July 1, 2019. Viper funded the cash portion of the purchase price of the Drop-Down Assets through a combination of cash on hand and borrowings under Viper LLC’s revolving credit facility.

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RATTLER MIDSTREAM LP

9 Months Ended

Sep. 30, 2020

Noncontrolling Interest [Abstract]

RATTLER MIDSTREAM LP

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 September 30, 2020, Diamondback owned approximately 71% of Rattler’s total units outstanding.

Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May 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 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. Diamondback, as the holder of the Class B units, and Rattler’s General Partner, as the holder of the general partner interest, are

entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1 million capital contributions, payable quarterly.

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REAL ESTATE ASSETS

9 Months Ended

Sep. 30, 2020

Real Estate [Abstract]

REAL ESTATE ASSETS

REAL ESTATE ASSETS    

The following schedule presents the cost and related accumulated depreciation of the Company’s real estate assets. The Company’s intangible lease assets and related accumulated amortization were immaterial as of September 30, 2020 and December 31, 2019.

	Estimated Useful Lives	September 30, 2020		December 31, 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		(12)		(9)
Total investment in land and buildings, net		$	98	$	101

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PROPERTY AND EQUIPMENT

9 Months Ended

Sep. 30, 2020

Property, Plant and Equipment [Abstract]

PROPERTY AND EQUIPMENT

PROPERTY AND EQUIPMENT

Property and equipment includes the following as of the dates indicated:

	September 30,		December 31,
	2020		2019
	(in millions)
Oil and natural gas properties:
Subject to depletion	$	19,426	$	16,575
Not subject to depletion	7,879		9,207
Gross oil and natural gas properties	27,305		25,782
Accumulated depletion	(3,988)		(2,995)
Accumulated impairment	(6,933)		(1,934)
Oil and natural gas properties, net	16,384		20,853
Midstream assets	1,026		931
Other property, equipment and land	135		125
Accumulated depreciation	(110)		(74)
Total property and equipment, net	$	17,435	$	21,835

Under the full cost 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 proved oil and natural gas properties. As a result of the sharp decline in commodity prices which began during the first quarter of 2020 and continued for most of the second and third quarters of 2020, the Company recorded non-cash ceiling test impairments for the three months and nine months ended September 30, 2020 of $1.5 billion and $5.0 billion, respectively, which were included in accumulated depletion. The impairment charge affected the Company’s results of operations 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. No impairment on proved oil and natural gas properties was recorded for the three months or nine months ended September 30, 2019. Given the rate of change impacting the oil and 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.

Capitalized internal costs were approximately $14 million and $8 million for the three months ended September 30, 2020 and 2019, respectively, and $42 million and $32 million for the nine months ended September 30, 2020 and 2019, 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. Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any of the acreage, associated with acquisition costs not currently being amortized, expire based on current drilling plans.

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ASSET RETIREMENT OBLIGATIONS

9 Months Ended

Sep. 30, 2020

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

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

	Nine Months Ended September 30,
	2020		2019
	(in millions)
Asset retirement obligations, beginning of period	$	94	$	136
Additional liabilities incurred	12		6
Liabilities acquired	3		3
Liabilities settled	(1)		(61)
Accretion expense	5		6
Asset retirement obligations, end of period	113		90
Less current portion(1)	1		—
Asset retirement obligations - long-term	$	112	$	90

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

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EQUITY METHOD INVESTMENTS

9 Months Ended

Sep. 30, 2020

Equity Method Investments and Joint Ventures [Abstract]

EQUITY METHOD INVESTMENTS

EQUITY METHOD INVESTMENTS

The following table presents the carrying values of Rattler’s equity method investments as of the dates indicated:

	Ownership Interest		September 30, 2020		December 31, 2019
			(in millions)
EPIC Crude Holdings, LP	10	%	$	123	$	110
Gray Oak Pipeline, LLC	10	%	135		115
Wink to Webster Pipeline LLC	4	%	75		34
OMOG JV LLC	60	%	195		219
Amarillo Rattler, LLC	50	%	4		1
Total			$	532	$	479

The following table presents income (loss) from Rattler’s equity method investees reflected in the Condensed Consolidated Statement of Operations for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
EPIC Crude Holdings, LP	$	(2)	$	—	$	(5)	$	—
Gray Oak Pipeline, LLC	4		—		6		—
OMOG JV LLC	1		—		(11)		—
Total	$	3	$	—	$	(10)	$	—

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 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 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 2.52% interest rate with a maturity date of March 31, 2022. The short-term promissory note was repaid on May 31, 2019.

On June 4, 2019, Rattler entered into an equity contribution agreement with respect to Gray Oak. The equity contribution agreement required Rattler to contribute equity or make loans to Gray Oak so that Gray Oak can, to the extent necessary, cure payment defaults under Gray Oak’s credit agreement and, in certain instances, repay Gray Oak’s credit agreement in full. Rattler’s obligations under the equity contribution agreement were limited to its proportionate ownership interest in Gray Oak, and such obligations were guaranteed by Rattler LLC, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. The equity contribution agreement and Rattler’s obligations under the agreement were terminated in September 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 for delivery to multiple Houston area locations (the “Wink to Webster pipeline”). The Wink to Webster pipeline is expected to begin service in the first half of 2021.

On October 1, 2019, Rattler LLC acquired a 60% equity interest in OMOG JV LLC (“OMOG”). On November 7, 2019, OMOG acquired 100% of Reliance Gathering, LLC which owns and operates a crude oil gathering system in the Permian Basin, and was renamed as Oryx Midland Oil Gathering LLC following the acquisition.

On December 20, 2019, Rattler LLC acquired a 50% equity interest in Amarillo Rattler, LLC (“Amarillo Rattler”), 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. Amarillo Rattler 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 Amarillo Rattler in exchange for the Company’s dedication of certain leasehold interests to that agreement.

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. During the nine months ended September 30, 2020, Rattler’s loss from equity method investments includes a proportional charge of $16 million representing impairment recorded by the investee associated with its goodwill. During the three months and nine months ended September 30, 2020, Rattler’s loss from equity method investment includes an immaterial abandonment charge related to a project that is no longer expected to be completed. No other impairments were recorded for Rattler’s equity method investments for the three or nine months ended September 30, 2020 or 2019. Rattler’s investees all serve customers in the oil and gas industry, which has begun to experience 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.

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DEBT

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

DEBT

DEBT

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

	September 30,		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	86		39
Unamortized debt issuance costs	(30)		(19)
Unamortized discount costs	(28)		(31)
Unamortized premium costs	16		9
Revolving credit facility(1)	—		13
Viper revolving credit facility(1)	127		97
Viper 5.375% Senior Notes due 2027	480		500
Rattler revolving credit facility(2)	85		424
Rattler 5.625% Senior Notes due 2025	500		—
Total debt, net	5,847		5,371
Less: current maturities of long-term debt	(191)		—
Total long-term debt	$	5,656	$	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.

References in this section to the Company shall mean Diamondback Energy, Inc. and Diamondback O&G LLC, collectively, unless otherwise specified.

May 2020 Senior Notes

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.

Second Amended and Restated Credit Facility

Diamondback O&G LLC, as borrower, and Diamondback Energy, Inc., as parent guarantor, 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 the Company’s unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied, which changes became effective on November 20, 2019. As of September 30, 2020, the maximum credit amount available under the credit agreement was $2 billion. As of September 30, 2020, the Company had no outstanding borrowings under its revolving credit facility and $2.0 billion available for future borrowings under the revolving credit facility. As of September 30, 2020, there was an aggregate of $3 million in outstanding letters of credit, which reduce the amount available under the credit agreement on a dollar-for-dollar basis. The weighted average interest rate on the credit facility was 1.83% and 2.27% for the three months and nine months ended September 30, 2020, respectively.

As of September 30, 2020, the Company was in compliance with all financial maintenance covenants under the revolving credit facility.

Energen’s Notes

Energen became a wholly owned subsidiary of the Company at the effective time of the merger and remained the issuer of an aggregate principal amount of $530 million in notes (the “Energen Notes”). As of September 30, 2020, the Energen Notes consist 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 7.350% 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.

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 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined semi-annually in May and November. 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 reduced from $775 million to $580 million during the regularly scheduled (semi-annual) spring 2020 redetermination in the second quarter of 2020, and is expected to be reaffirmed at $580 million by the lenders during the regularly scheduled (semi-annual) fall 2020 redetermination in November 2020. As of September 30, 2020, Viper LLC had $127 million of outstanding borrowings and $453 million available for future borrowings under the Viper credit agreement. The weighted average interest rate on the credit facility was 2.14% and 2.66% for the three months and nine months ended September 30, 2020, respectively. The revolving credit facility will mature on November 1, 2022.

As of September 30, 2020, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement.

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 net proceeds of approximately $490 million from the offering of the Viper Notes. Viper loaned the gross proceeds to Viper LLC. Viper LLC used the proceeds from the notes offering to pay down borrowings under its revolving credit facility. During the three months and nine months ended September 30, 2020, Viper repurchased $6 million and $20 million, respectively of the outstanding principal amount of Viper Notes in open market purchases 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. The repurchase brought the total outstanding principal amount of Viper Notes down to $480 million as of September 30, 2020.

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, which is expandable to $1 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of September 30, 2020, Rattler LLC had $85 million of outstanding borrowings and $515 million available for future borrowings under the Rattler credit agreement. The weighted average interest rate on the credit facility was 1.46% and 2.18% for the three months and nine months ended September 30, 2020, respectively.

As of September 30, 2020, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

See Note 18—Subsequent Events for a description of the amendment to the Rattler credit agreement which occurred subsequent to September 30, 2020.

Rattler’s Notes

On July 14, 2020, Rattler completed an offering (the “Notes Offering”) of $500 million in aggregate principal amount of its 5.625% Senior Notes due 2025 (the “Rattler Notes”). Interest on the Rattler Notes is payable on January 15 and July 15 of each year, beginning on January 15, 2021. The Rattler Notes mature on July 15, 2025. Rattler received net proceeds of approximately $490 million from the Notes Offering. Rattler loaned the gross proceeds to Rattler LLC, which Rattler LLC used 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 it may incur 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.

Alliance with Obsidian Resources, L.L.C.

Diamondback O&G LLC 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 September 30, 2020 and December 31, 2019, CEMOF’s return related to this alliance was $86 million and $39 million, respectively. As of September 30, 2020, 15 joint wells have been drilled and completed.

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CAPITAL STOCK AND EARNINGS PER SHARE

9 Months Ended

Sep. 30, 2020

Equity [Abstract]

CAPITAL STOCK AND EARNINGS PER SHARE

CAPITAL STOCK AND EARNINGS PER SHARE

Diamondback did not complete any equity offerings during the nine months ended September 30, 2020 and September 30, 2019.

Rattler’s Initial Public Offering

Please see Note 5—Rattler Midstream LP for information regarding the Rattler Offering.

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 may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the three months ended September 30, 2020, the Company repurchased no common stock under this repurchase program. During the nine months ended September 30, 2020, the Company repurchased approximately $98 million of common stock under this repurchase program. As of September 30, 2020, $1.3 billion remained available for use to repurchase shares under the Company's common stock repurchase program, although the Company has suspended this program to preserve liquidity.

Earnings (Loss) Per Share

The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the diluted earnings per share computation, the per share earnings of Viper and Rattler are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiary.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	($ in millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common stock	$	(1,113)	$	368	$	(3,778)	$	727
Weighted average common shares outstanding:
Basic weighted average common units outstanding	157,833		162,543		157,984		164,070
Effect of dilutive securities:
Potential common shares issuable(1)	—		237		—		396
Diluted weighted average common shares outstanding	157,833		162,780		157,984		164,466
Basic net income (loss) attributable to common stock	$	(7.05)	$	2.27	$	(23.91)	$	4.44
Diluted net income (loss) attributable to common stock	$	(7.05)	$	2.26	$	(23.91)	$	4.42

(1)    For the three and nine months ended September 30, 2020, no potential common units were included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive. For the three months and nine months ended September 30, 2019, there were 50,814 and 40,291 potential common units excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive under the treasury stock method.

Change in Ownership of Consolidated Subsidiaries

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Net income (loss) attributable to the Company	$	(1,113)	$	368	$	(3,778)	$	727
Change in ownership of consolidated subsidiaries	—		—		329		77
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest	$	(1,113)	$	368	$	(3,449)	$	804

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EQUITY-BASED COMPENSATION

9 Months Ended

Sep. 30, 2020

Share-based Payment Arrangement [Abstract]

EQUITY-BASED COMPENSATION

EQUITY-BASED COMPENSATION

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
General and administrative expenses	$	9	$	4	$	27	$	27
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	4		(1)		12		9

Restricted Stock Units

The following table presents the Company’s restricted stock units activity under the Equity Plan during the nine months ended September 30, 2020:

	Restricted Stock Awards & Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	505,867	$	96.01
Granted	183,102	$	60.72
Vested	(139,355)	$	85.21
Forfeited	(19,228)	$	99.01
Unvested at September 30, 2020	530,386	$	86.55

The aggregate fair value of restricted stock units that vested during the nine months ended September 30, 2020 and 2019 was $12 million and $4 million, respectively. As of September 30, 2020, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $27 million, which is expected to be recognized over a weighted-average period of 1.7 years.

During the nine months ended September 30, 2020, the Company modified an insignificant amount of restricted stock units to include dividend equivalent rights during the vesting period which resulted in no incremental compensation costs to be recognized.

Performance Based Restricted Stock Units

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 measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during the performance period of January 1, 2018 to December 31, 2020 and cliff vest at December 31, 2020 subject to continued employment.

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 for the March 2020 awards.

	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 units activity under the Equity Plan for the nine months ended September 30, 2020:

	Performance Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	271,819	$	147.07
Granted	272,601	$	85.73
Vested	(47,554)	$	89.27
Forfeited	(8,396)	$	170.45
Unvested at September 30, 2020(1)	488,470	$	110.33

(1)A maximum of 1,089,464 units could be awarded based upon the Company’s final TSR ranking.

As of September 30, 2020, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $26 million, which is expected to be recognized over a weighted-average period of 2.0 years.

Rattler Long-Term Incentive Plan

On May 22, 2019, the board of directors of Rattler’s General Partner adopted the Rattler Midstream LP Long Term Incentive Plan (“Rattler LTIP”), for employees, consultants and directors of Rattler’s General Partner and any of its affiliates, including Diamondback, who perform services for Rattler. The Rattler LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards.

Under the Rattler LTIP, the board of directors of Rattler’s General Partner is authorized to issue phantom units to eligible employees and non-employee directors. Rattler estimates the fair value of phantom units as the closing price of Rattler’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting, the phantom units entitle the recipient to one common unit of Rattler for each phantom unit. The recipients are also entitled to distribution equivalent rights, which represent the right to receive a cash payment equal to the value of the distributions paid on one phantom unit between the grant date and the vesting date.

The following table presents the phantom unit activity under the Rattler LTIP for the nine months ended September 30, 2020:

	Phantom Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	2,226,895	$	19.14
Granted	53,943	$	10.41
Vested	(449,633)	$	19.14
Forfeited	(23,442)	$	18.23
Unvested at September 30, 2020	1,807,763	$	18.89

The aggregate fair value of phantom units that vested during the nine months ended September 30, 2020 was $9 million. As of September 30, 2020, the unrecognized compensation cost related to unvested phantom units was $31 million. Such cost is expected to be recognized over a weighted-average period of 3.6 years.

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INCOME TAXES

9 Months Ended

Sep. 30, 2020

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

The Company’s effective income tax rates were 21.6% and 20.8% for the three months ended September 30, 2020 and 2019, respectively, and 18.7% and 17.9% for the nine months ended September 30, 2020 and 2019, respectively. Total income tax benefit from continuing operations for the three and nine months ended September 30, 2020 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss primarily due to (i) the impact of recording a valuation allowance on Viper’s deferred tax assets, (ii) state income taxes and (iii) the impact of permanent differences between book and taxable income, partially offset by tax benefit in the first quarter resulting from the carryback of federal net operating losses.

For the nine months ended September 30, 2020, the Company recorded a discrete income tax expense of $143 million related to application in the first quarter of a valuation allowance on Viper’s beginning-of-year deferred tax assets, which consist primarily of its investment in Viper LLC and federal net operating loss carryforwards. A valuation allowance was also applied against the year-to-date tax benefit resulting from Viper’s pre-tax loss for 2020. The determination to record a valuation allowance was based on assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets. In light of those criteria for recognizing the tax benefit of deferred tax assets, Viper’s assessment resulted in application of a valuation allowance against Viper’s deferred tax assets as of March 31, 2020, June 30, 2020, and September 30, 2020. In addition, for the nine months ended September 30, 2020, the Company recorded a discrete income tax benefit of $25 million related to the available carryback of certain federal net operating losses to tax year(s) in which the corporate income tax rate was 35%. Prior to the enactment of the Coronavirus Aid, Relief, and Economic Security Act (“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 benefit associated with federal net operating loss carryforwards at the statutory 21% corporate income tax rate.

Total income tax expense for the three and nine months ended September 30, 2019 differed from amounts computed by applying the federal statutory rate to pre-tax income primarily due to (i) state income taxes, (ii) the impact of permanent differences between book and taxable income and (iii) the revision of estimated deferred taxes recognized by Viper as a result of its change in tax status. For the nine months ended September 30, 2019, the Company recorded a discrete income tax expense of less than $1 million related to equity-based compensation and a discrete benefit of approximately $42 million related to the revision of estimated deferred taxes on Viper’s investment in Viper LLC arising from the change in Viper’s tax status. Based on information available regarding unitholders’ tax basis, Viper revised its estimate of deferred taxes on Viper’s investment in Viper LLC on the date of the tax status change, resulting in discrete deferred tax benefit of $42 million for the nine months ended September 30, 2019.

During the three months ended June 30, 2020, the Company recorded an increase through stockholders’ equity to the carrying value of its investment in Rattler LLC, resulting in an increase in the Company’s deferred tax liability related to 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. As a result of Rattler’s assessment each period, including consideration of all available positive and negative evidence, Rattler continued to determine that it is more likely than not that Rattler will realize its deferred tax assets as of September 30, 2020.

The 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 has considered the impact of this legislation in the period of enactment, resulting in discrete income tax benefit for the three months ended March 31, 2020 related to the anticipated carryback of approximately $179 million of the Company’s federal net operating losses as noted above. 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 total approximately $100 million as of March 31, 2020, June 30, 2020 and September 30, 2020.

As discussed further in Note 5, 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.

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DERIVATIVES

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

DERIVATIVES

All derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the condensed 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 only entered into derivative instruments with counterparties that are also lenders under its credit facility and have been deemed an acceptable credit risk.

As of September 30, 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
Oct. - Dec.	2020	Swaps	11,000	WTI Cushing	$—	$43.47	$—	$—
Oct. - Dec.	2020	Swaps	4,000	WTI Magellan	$—	$61.95	$—	$—
Oct. - Dec.	2020	Swaps	24,200	Brent	$—	$47.62	$—	$—
Oct. - Dec.	2020	Basis Swaps	45,087	WTI Cushing(1)	$(1.33)	$—	$—	$—
Oct. - Dec.	2020	Basis Swaps	8,000	WTL Cushing(1)	$(1.31)	$—	$—	$—
Oct. - Dec.	2020	Rolling Hedge(2)	120,000	WTI Cushing	$(1.05)	$—	$—	$—
Oct. - Dec.	2020	Costless Collar	45,779	WTI Cushing	$—	$—	$35.92	$42.29
Oct. - Dec.	2020	Costless Collar	4,000	WTI Magellan	$—	$—	$39.00	$49.00
Oct. - Dec.	2020	Costless Collar	64,710	Brent	$—	$—	$37.59	$45.63
Jan. - Dec.	2021	Swaps	5,000	WTI Magellan	$—	$37.78	$—	$—
Jan. - Dec.	2021	Swaps	7,500	Brent	$—	$41.58	$—	$—
Jan. - Dec.	2021	Costless Collar	65,000	Brent	$—	$—	$39.25	$48.36
July - Dec.	2021	Swaption	5,000	Brent	$—	$51.00	$—	$—
Jan. - Dec.	2021	Costless Collar	10,000	WTI Cushing	$—	$—	$30.00	$43.05
NATURAL GAS
Oct. - Dec.	2020	Swaps	60,000	Henry Hub	$—	$2.48	$—	$—
Oct. - Dec.	2020	Swaps	60,000	Waha Hub	$—	$1.51	$—	$—
Oct. - Dec.	2020	Basis Swaps	145,000	Waha Hub(1)	$(1.57)	$—	$—	$—
Jan. - Dec.	2021	Swaps	190,000	Henry Hub	$—	$2.62	$—	$—
Jan. - Dec.	2021	Basis Swaps	230,000	Waha Hub(1)	$(0.69)	$—	$—	$—
Jan. - Dec.	2022	Basis Swaps	80,000	Waha Hub(1)	$(0.45)	$—	$—	$—
NATURAL GAS LIQUIDS
Oct. - Dec.	2020	Swaps	7,000	Mont Belvieu Ethane	$—	$8.43	$—	$—
Oct. - Dec.	2020	Swaps	5,000	Mont Belvieu Propane	$—	$21.76	$—	$—
DIESEL
Oct. - Dec.	2021	Swaps	1,000,000	Gulf Cost Ultra Low Sulfur	$—	$1.60	$—	$—

(1) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price or the Midland Argus WTL 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	Strike Price	Swap Price	Put Price	Long Put Price	Option Price
OIL
Oct. - Dec.	2020	Calls(1)	8,000	WTI Magellan	$45.00	$—	$—	$—	$—
Oct. - Dec.	2020	Option	4,700	WTI Cushing	$—	$—	$—	$46.51	$—
Oct. - Dec.	2020	Put Spread	3,800	WTI Magellan	$—	$—	$25.00	$50.00	$—
Oct. - Dec.	2022	Option	5,000	WTI Cushing	$—	$—	$35.00	$—	$—
NATURAL GAS
Oct. - Dec.	2020	Swap Double-Up	30,000	Waha Hub	$—	$1.70	$—	$—	$1.70

(1) Includes a deferred premium at a weighted-average price of $(1.89)/Bbl and a strike price of $45.00/Bbl

Interest Rate Swaps and Treasury Locks

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

The following table summarizes the Company’s interest rate swaps and treasury locks as of September 30, 2020:

Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.551	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.5575	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.297	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.195	%

See Note 18—Subsequent Events for discussion of derivative transactions which occurred subsequent to September 30, 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 15—Fair Value Measurements for further details.

Gains and Losses on Derivative Instruments

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Gain (loss) on derivative instruments, net
Commodity contracts	$	(104)	$	157	$	147	$	(17)
Interest rate swaps	5		20		(65)		20
Total	$	(99)	$	177	$	82	$	3
Net cash received (paid) on settlements
Commodity contracts(1)	(9)		11		288		33
Total	$	(9)	$	11	$	288	$	33

(1)The three and nine months ended September 30, 2020 include cash received on contracts terminated prior to their contractual maturity of $6 million and $17 million, respectively.

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FAIR VALUE MEASUREMENTS

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

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

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

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

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

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

The Company estimates the fair values of proved oil and natural gas properties assumed in business combinations using discounted cash flow techniques and based on market assumptions as to the future commodity prices, internal estimates of future quantities of oil and natural gas reserves, future estimated rates of production, expected recovery rates and risk-adjustment discounts. The estimated fair values of unevaluated oil and natural gas properties were based on the location, engineering and geological studies, historical well performance, and applicable mineral lease terms. Given the unobservable nature of the inputs, the estimated fair values of oil and natural gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of business combinations are estimated using the same assumptions and methodology as described below.

The Company estimates asset retirement obligations pursuant to the provisions of the FASB issued ASC Topic 410, “Asset Retirement and Environmental Obligations.” The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with the future plugging and abandonment of wells and related facilities. Given the unobservable nature of the inputs, including plugging costs and useful lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 8—Asset Retirement Obligations for further discussion of the Company’s asset retirement obligations.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments and Viper’s investment. Viper measures its investment utilizing the fair value option, and as such the investment is 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 condensed consolidated balance sheets as of September 30, 2020 and December 31, 2019. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.

	As of September 30, 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	$	—	$	107	$	—	$	107	$	(92)	$	15
Non-current:
Investment	$	5	$	—	$	—	$	5	$	—	$	5
Derivative Instruments	$	—	$	65	$	—	$	65	$	(65)	$	—
Liabilities:
Current:
Derivative Instruments	$	—	$	178	$	—	$	178	$	(92)	$	86
Non-current:
Derivative Instruments	$	—	$	173	$	—	$	173	$	(65)	$	108

	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 condensed consolidated balance sheets:

	September 30, 2020				December 31, 2019
	Carrying				Carrying
	Value(1)		Fair Value		Value(1)		Fair Value
	(in millions)
Debt:
Revolving credit facility	$	—	$	—	$	13	$	13
4.625% Notes due 2021	$	191	$	194	$	399	$	411
7.320% Medium-term Notes, Series A, due 2022	$	21	$	22	$	21	$	22
2.875% Senior Notes due 2024	$	993	$	1,014	$	992	$	1,012
4.750% Senior Notes due 2025	$	496	$	541	$	—	$	—
5.375% Senior Notes due 2025	$	800	$	830	$	799	$	840
3.250% Senior Notes due 2026	$	793	$	803	$	792	$	812
7.350% Medium-term Notes, Series A, due 2027	$	—	$	—	$	11	$	12
7.125% Medium-term Notes, Series B, due 2028	$	107	$	113	$	108	$	116
3.500% Senior Notes due 2029	$	1,187	$	1,158	$	1,186	$	1,226
Viper revolving credit facility	$	127	$	127	$	97	$	97
Viper's 5.375% Senior Notes due 2027	$	471	$	477	$	490	$	521
Rattler revolving credit facility	$	85	$	85	$	424	$	424
Rattler’s 5.625% Senior Notes due 2025	$	490	505		$	—	$	—
DrillCo Agreement	$	86	$	86	$	39	$	39

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

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 September 30, 2020 quoted market price, a Level 1 classification in the fair value hierarchy.

Fair Value of Financial Assets

The carrying amount of cash and cash equivalents, receivables, prepaid expenses and other current assets, payables and other accrued liabilities approximate their fair value because of the short-term nature of the instruments.

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LEASES

9 Months Ended

Sep. 30, 2020

Leases [Abstract]

LEASES

LEASES

The Company leases certain drilling rigs, facilities, compression and other equipment.

The following table summarizes operating lease costs for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Operating lease costs	$	4	$	7	$	13	$	19

For the nine months ended September 30, 2020 and 2019, cash paid for operating lease liabilities, as reported in cash flows provided by operating activities on the Company’s condensed consolidated statements of cash flows, was $13 million and $19 million, respectively. During the nine months ended September 30, 2020 and 2019, the Company recorded an additional $10 million and $15 million of right-of-use assets in exchange for new lease liabilities, respectively. There were no significant right-of-use assets recorded during the three months ended September 30, 2020 and 2019.

As of September 30, 2020, the Condensed Consolidated Balance Sheet includes operating right-of-use assets of $13 million in other assets, current operating lease liabilities of $9 million in other accrued liabilities , and long-term operating lease liabilities of $4 million in other long-term liabilities. As of September 30, 2020, the weighted average remaining lease term was 1.5 years and the weighted average discount rate was 9.2%.

Schedule of Operating Lease Liability Maturities. The following table summarizes undiscounted cash flows owed by the Company to lessors pursuant to contractual agreements in effect as of September 30, 2020:

	As of September 30, 2020
	(in millions)
2020 (October - December)	$	4
2021	7
2022	3
2023	—
2024	—
Thereafter	—
Total lease payments	14
Less: interest	1
Present value of lease liabilities	$	13

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COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2020
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIESThe Company is a party to various routine legal proceedings, disputes and claims arising in the ordinary course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. 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.

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SUBSEQUENT EVENTS

9 Months Ended

Sep. 30, 2020

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

Third Quarter 2020 Dividend Declaration

On October 29, 2020, the Board of Directors of the Company declared a cash dividend for the third quarter of 2020 of $0.375 per share of common stock, payable on November 19, 2020 to its stockholders of record at the close of business on November 12, 2020.

Amendment to the Rattler Credit Agreement in Connection with Initiation of Rattler’s Common Unit Repurchase Program

On November 2, 2020, Rattler and Rattler LLC entered into a second amendment (the “Second Amendment”) to the Rattler Credit Agreement with Wells Fargo, as the administrative agent, and the lenders party thereto. The Second Amendment permits Rattler to conduct common unit repurchases in connection with the common unit repurchase program approved by the board of directors of Rattler’s General Partner on October 29, 2020.

Under Rattler’s common unit repurchase program to be conducted under Rule 10b-18 of the Exchange Act, Rattler is authorized to acquire up to $100 million of Rattler’s outstanding common units in open market or privately negotiated transactions with cash on hand and free cash flow from operations. The common unit repurchase program is authorized to extend through December 31, 2021, may be suspended from time to time or modified, extended or discontinued by the board of directors of Rattler’s General Partner at any time, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors.

Commodity Contracts

Subsequent to September 30, 2020, the Company entered into new fixed price swaps and basis swaps. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges noted in the table below.

The following tables present the derivative contracts entered into by the Company between October 1, 2020 and November 2, 2020. When aggregating multiple contracts, the weighted average contract price is disclosed.

					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
Jan. - Mar.	2021	Costless Collar	3,000	WTI Cushing	$—	$—	$37.00	$44.19
Mar. - June	2021	Costless Collar	1,000	WTI Cushing	$—	$—	$37.00	$47.00
Jan. - June	2021	Costless Collar	6,000	Brent	$—	$—	$37.50	$45.50
NATURAL GAS
Jan. - Dec.	2021	Swaps	10,000	Henry Hub	$—	$3.05	$—	$—
Jan. - Dec.	2022	Basis Swap	20,000	Waha Hub	$(0.31)	$—	$—	$—

Interest Rate Swaps

Subsequent to September 30, 2020, the Company entered into new interest rate swaps and terminated existing interest rate swaps.

The following table presents the interest rate swaps entered into by the Company subsequent to September 30, 2020.

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	%

The following table presents the interest rate swap contracts terminated by the Company subsequent to September 30, 2020.

Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.551	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.5575	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.297	%

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SEGMENT INFORMATION

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

SEGMENT INFORMATION

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 in the Permian Basin in West Texas and (ii) the midstream operations segment includes midstream services and real estate. All of Rattler’s equity method investments are included in the midstream segment.

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

	Upstream		Midstream Services		Eliminations		Total
Three Months Ended September 30, 2020:	(in millions)
Third-party revenues	$	706	$	14	$	—	$	720
Intersegment revenues	—		83		(83)		—
Total revenues	706		97		(83)		720
Depreciation, depletion and amortization	275		11		—		286
Impairment of oil and natural gas properties	1,451		—		—		1,451
Income (loss) from operations	(1,282)		44		(18)		(1,256)
Interest expense, net	(47)		(6)		—		(53)
Other income (expense)	(103)		4		(1)		(100)
Provision for (benefit from) income taxes	(307)		3		—		(304)
Net income (loss) attributable to non-controlling interest	(1)		9		—		8
Net income (loss) attributable to Diamondback Energy, Inc.	(1,124)		30		(19)		(1,113)
As of September 30, 2020:
Total assets	$	17,245	$	1,812	$	(297)	$	18,760

	Upstream		Midstream Services		Eliminations		Total
Three Months Ended September 30, 2019:	(in millions)
Third-party revenues	$	957	$	18	$	—	$	975
Intersegment revenues	—		97		(97)		—
Total revenues	957		115		(97)		975
Depreciation, depletion and amortization	353		12		—		365
Income (loss) from operations	321		52		(24)		349
Interest expense, net	(37)		(1)		—		(38)
Other income (expense)	181		(1)		(1)		179
Provision for (benefit from) income taxes	99		3		—		102
Net income (loss) attributable to non-controlling interest	20		37		(37)		20
Net income (loss) attributable to Diamondback Energy, Inc.	346		10		12		368
As of December 31, 2019:
Total assets	$	22,125	$	1,636	$	(230)	$	23,531

	Upstream		Midstream Services		Eliminations		Total
Nine Months Ended September 30, 2020:	(in millions)
Third-party revenues	$	2,002	$	42	$	—	$	2,044
Intersegment revenues	—		273		(273)		—
Total revenues	2,002		315		(273)		2,044
Depreciation, depletion and amortization	1,001		35		—		1,036
Impairment of oil and natural gas properties	4,999		—		—		4,999
Income (loss) from operations	(4,787)		134		(77)		(4,730)
Interest expense, net	(137)		(10)		—		(147)
Other income (expense)	73		(10)		(4)		59
Provision for (benefit from) income taxes	(910)		8		—		(902)
Net income (loss) attributable to non-controlling interest	(163)		25		—		(138)
Net income (loss) attributable to Diamondback Energy, Inc.	(3,778)		81		(81)		(3,778)
As of September 30, 2020:
Total assets	$	17,245	$	1,812	$	(297)	$	18,760

	Upstream		Midstream Services		Eliminations		Total
Nine Months Ended September 30, 2019:	(in millions)
Third-party revenues	$	2,802	$	58	$	—	$	2,860
Intersegment revenues	—		264		(264)		—
Total revenues	2,802		322		(264)		2,860
Depreciation, depletion and amortization	1,014		32		—		1,046
Income (loss) from operations	1,004		159		(84)		1,079
Interest expense, net	(132)		(1)		—		(133)
Other income (expense)	16		(1)		(3)		12
Provision for (benefit from) income taxes	167		4		—		171
Net income (loss) attributable to non-controlling interest	60		52		(52)		60
Net income (loss) attributable to Diamondback Energy, Inc.	$	661	$	101	$	(35)	727
As of December 31, 2019:
Total assets	$	22,125	$	1,636	$	(230)	$	23,531

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Basis of Presentation

Basis of PresentationThe condensed consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.

Use of Estimates

Use of Estimates

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

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 gas markets. Companies in the oil and 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.

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 deemed 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. The adoption of ASU 2016-13 did not result in a material change to the Company’s allowance.

Non-controlling Interest

Non-controlling Interest

Non-controlling interest in the accompanying condensed consolidated financial statements represents minority interest ownership in Viper and Rattler. 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.

In the second quarter of 2020, the Company recorded 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. See Note 11—Capital Stock and Earnings Per Share for a presentation of the change in ownership.

New Accounting Pronouncements

Recent Accounting Pronouncements

The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Company’s analysis of the effects on its financial statements:

Standard	Description	Date of Adoption	Effect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 2016-13, “Financial Instruments - Credit Losses”	This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash.	Q1 2020	The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”	This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.	Q1 2021	This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company does not believe that the adoption of this update will have an impact on its financial position, results of operations or liquidity.

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.

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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

9 Months Ended

Sep. 30, 2020

Accounting Policies [Abstract]

Recent Accounting Pronouncements

The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Company’s analysis of the effects on its financial statements:

Standard	Description	Date of Adoption	Effect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 2016-13, “Financial Instruments - Credit Losses”	This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash.	Q1 2020	The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”	This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.	Q1 2021	This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company does not believe that the adoption of this update will have an impact on its financial position, results of operations or liquidity.

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REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)

9 Months Ended

Sep. 30, 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:

	Three Months Ended September 30, 2020								Three Months Ended September 30, 2019
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	348	$	257	$	1	$	606	$	529	$	350	$	3	$	882
Natural gas sales	19		17		—		36		7		8		1		16
Natural gas liquid sales	36		28		1		65		33		25		—		58
Total	$	403	$	302	$	2	$	707	$	569	$	383	$	4	$	956

	Nine Months Ended September 30, 2020								Nine Months Ended September 30, 2019
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(in millions)
Oil sales	$	1,030	$	750	$	5	$	1,785	$	1,561	$	951	$	60	$	2,572
Natural gas sales	32		29		—		61		17		18		1		36
Natural gas liquid sales	88		67		1		156		110		78		2		190
Total	$	1,150	$	846	$	6	$	2,002	$	1,688	$	1,047	$	63	$	2,798

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REAL ESTATE ASSETS (Tables)

9 Months Ended

Sep. 30, 2020

Real Estate [Abstract]

Schedule of real estate assets

The following schedule presents the cost and related accumulated depreciation of the Company’s real estate assets. The Company’s intangible lease assets and related accumulated amortization were immaterial as of September 30, 2020 and December 31, 2019.

	Estimated Useful Lives	September 30, 2020		December 31, 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		(12)		(9)
Total investment in land and buildings, net		$	98	$	101

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Property and Equipment (Tables)

9 Months Ended

Sep. 30, 2020

Property, Plant and Equipment [Abstract]

Schedule of property and equipment

Property and equipment includes the following as of the dates indicated:

	September 30,		December 31,
	2020		2019
	(in millions)
Oil and natural gas properties:
Subject to depletion	$	19,426	$	16,575
Not subject to depletion	7,879		9,207
Gross oil and natural gas properties	27,305		25,782
Accumulated depletion	(3,988)		(2,995)
Accumulated impairment	(6,933)		(1,934)
Oil and natural gas properties, net	16,384		20,853
Midstream assets	1,026		931
Other property, equipment and land	135		125
Accumulated depreciation	(110)		(74)
Total property and equipment, net	$	17,435	$	21,835

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 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:

	Nine Months Ended September 30,
	2020		2019
	(in millions)
Asset retirement obligations, beginning of period	$	94	$	136
Additional liabilities incurred	12		6
Liabilities acquired	3		3
Liabilities settled	(1)		(61)
Accretion expense	5		6
Asset retirement obligations, end of period	113		90
Less current portion(1)	1		—
Asset retirement obligations - long-term	$	112	$	90

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

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EQUITY METHOD INVESTMENTS (Tables)

9 Months Ended

Sep. 30, 2020

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

The following table presents the carrying values of Rattler’s equity method investments as of the dates indicated:

	Ownership Interest		September 30, 2020		December 31, 2019
			(in millions)
EPIC Crude Holdings, LP	10	%	$	123	$	110
Gray Oak Pipeline, LLC	10	%	135		115
Wink to Webster Pipeline LLC	4	%	75		34
OMOG JV LLC	60	%	195		219
Amarillo Rattler, LLC	50	%	4		1
Total			$	532	$	479

The following table presents income (loss) from Rattler’s equity method investees reflected in the Condensed Consolidated Statement of Operations for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
EPIC Crude Holdings, LP	$	(2)	$	—	$	(5)	$	—
Gray Oak Pipeline, LLC	4		—		6		—
OMOG JV LLC	1		—		(11)		—
Total	$	3	$	—	$	(10)	$	—

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Debt (Tables)

9 Months Ended

Sep. 30, 2020

Debt Disclosure [Abstract]

Schedule of long-term debt

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

	September 30,		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	86		39
Unamortized debt issuance costs	(30)		(19)
Unamortized discount costs	(28)		(31)
Unamortized premium costs	16		9
Revolving credit facility(1)	—		13
Viper revolving credit facility(1)	127		97
Viper 5.375% Senior Notes due 2027	480		500
Rattler revolving credit facility(2)	85		424
Rattler 5.625% Senior Notes due 2025	500		—
Total debt, net	5,847		5,371
Less: current maturities of long-term debt	(191)		—
Total long-term debt	$	5,656	$	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.

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CAPITAL STOCK AND EARNINGS PER SHARE (Tables)

9 Months Ended

Sep. 30, 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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	($ in millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common stock	$	(1,113)	$	368	$	(3,778)	$	727
Weighted average common shares outstanding:
Basic weighted average common units outstanding	157,833		162,543		157,984		164,070
Effect of dilutive securities:
Potential common shares issuable(1)	—		237		—		396
Diluted weighted average common shares outstanding	157,833		162,780		157,984		164,466
Basic net income (loss) attributable to common stock	$	(7.05)	$	2.27	$	(23.91)	$	4.44
Diluted net income (loss) attributable to common stock	$	(7.05)	$	2.26	$	(23.91)	$	4.42

(1)    For the three and nine months ended September 30, 2020, no potential common units were included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive. For the three months and nine months ended September 30, 2019, there were 50,814 and 40,291 potential common units excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive under the treasury stock method.

Schedule of change in ownership interest

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Net income (loss) attributable to the Company	$	(1,113)	$	368	$	(3,778)	$	727
Change in ownership of consolidated subsidiaries	—		—		329		77
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest	$	(1,113)	$	368	$	(3,449)	$	804

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Equity-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2020

Share-based Payment Arrangement [Abstract]

The effects of stock-based compensation plans and related costs

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
General and administrative expenses	$	9	$	4	$	27	$	27
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	4		(1)		12		9

Summary of restricted stock units

The following table presents the Company’s restricted stock units activity under the Equity Plan during the nine months ended September 30, 2020:

	Restricted Stock Awards & Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	505,867	$	96.01
Granted	183,102	$	60.72
Vested	(139,355)	$	85.21
Forfeited	(19,228)	$	99.01
Unvested at September 30, 2020	530,386	$	86.55

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 for the March 2020 awards.

	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 units activity under the Equity Plan for the nine months ended September 30, 2020:

	Performance Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	271,819	$	147.07
Granted	272,601	$	85.73
Vested	(47,554)	$	89.27
Forfeited	(8,396)	$	170.45
Unvested at September 30, 2020(1)	488,470	$	110.33

(1)A maximum of 1,089,464 units could be awarded based upon the Company’s final TSR ranking.

Phantom units activity

The following table presents the phantom unit activity under the Rattler LTIP for the nine months ended September 30, 2020:

	Phantom Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	2,226,895	$	19.14
Granted	53,943	$	10.41
Vested	(449,633)	$	19.14
Forfeited	(23,442)	$	18.23
Unvested at September 30, 2020	1,807,763	$	18.89

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DERIVATIVES (Tables)

9 Months Ended

Sep. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivative contracts

As of September 30, 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
Oct. - Dec.	2020	Swaps	11,000	WTI Cushing	$—	$43.47	$—	$—
Oct. - Dec.	2020	Swaps	4,000	WTI Magellan	$—	$61.95	$—	$—
Oct. - Dec.	2020	Swaps	24,200	Brent	$—	$47.62	$—	$—
Oct. - Dec.	2020	Basis Swaps	45,087	WTI Cushing(1)	$(1.33)	$—	$—	$—
Oct. - Dec.	2020	Basis Swaps	8,000	WTL Cushing(1)	$(1.31)	$—	$—	$—
Oct. - Dec.	2020	Rolling Hedge(2)	120,000	WTI Cushing	$(1.05)	$—	$—	$—
Oct. - Dec.	2020	Costless Collar	45,779	WTI Cushing	$—	$—	$35.92	$42.29
Oct. - Dec.	2020	Costless Collar	4,000	WTI Magellan	$—	$—	$39.00	$49.00
Oct. - Dec.	2020	Costless Collar	64,710	Brent	$—	$—	$37.59	$45.63
Jan. - Dec.	2021	Swaps	5,000	WTI Magellan	$—	$37.78	$—	$—
Jan. - Dec.	2021	Swaps	7,500	Brent	$—	$41.58	$—	$—
Jan. - Dec.	2021	Costless Collar	65,000	Brent	$—	$—	$39.25	$48.36
July - Dec.	2021	Swaption	5,000	Brent	$—	$51.00	$—	$—
Jan. - Dec.	2021	Costless Collar	10,000	WTI Cushing	$—	$—	$30.00	$43.05
NATURAL GAS
Oct. - Dec.	2020	Swaps	60,000	Henry Hub	$—	$2.48	$—	$—
Oct. - Dec.	2020	Swaps	60,000	Waha Hub	$—	$1.51	$—	$—
Oct. - Dec.	2020	Basis Swaps	145,000	Waha Hub(1)	$(1.57)	$—	$—	$—
Jan. - Dec.	2021	Swaps	190,000	Henry Hub	$—	$2.62	$—	$—
Jan. - Dec.	2021	Basis Swaps	230,000	Waha Hub(1)	$(0.69)	$—	$—	$—
Jan. - Dec.	2022	Basis Swaps	80,000	Waha Hub(1)	$(0.45)	$—	$—	$—
NATURAL GAS LIQUIDS
Oct. - Dec.	2020	Swaps	7,000	Mont Belvieu Ethane	$—	$8.43	$—	$—
Oct. - Dec.	2020	Swaps	5,000	Mont Belvieu Propane	$—	$21.76	$—	$—
DIESEL
Oct. - Dec.	2021	Swaps	1,000,000	Gulf Cost Ultra Low Sulfur	$—	$1.60	$—	$—

(1) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price or the Midland Argus WTL 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	Strike Price	Swap Price	Put Price	Long Put Price	Option Price
OIL
Oct. - Dec.	2020	Calls(1)	8,000	WTI Magellan	$45.00	$—	$—	$—	$—
Oct. - Dec.	2020	Option	4,700	WTI Cushing	$—	$—	$—	$46.51	$—
Oct. - Dec.	2020	Put Spread	3,800	WTI Magellan	$—	$—	$25.00	$50.00	$—
Oct. - Dec.	2022	Option	5,000	WTI Cushing	$—	$—	$35.00	$—	$—
NATURAL GAS
Oct. - Dec.	2020	Swap Double-Up	30,000	Waha Hub	$—	$1.70	$—	$—	$1.70

(1) Includes a deferred premium at a weighted-average price of $(1.89)/Bbl and a strike price of $45.00/Bbl

The following table summarizes the Company’s interest rate swaps and treasury locks as of September 30, 2020:

Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.551	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.5575	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.297	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.195	%

The following tables present the derivative contracts entered into by the Company between October 1, 2020 and November 2, 2020. When aggregating multiple contracts, the weighted average contract price is disclosed.

					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
Jan. - Mar.	2021	Costless Collar	3,000	WTI Cushing	$—	$—	$37.00	$44.19
Mar. - June	2021	Costless Collar	1,000	WTI Cushing	$—	$—	$37.00	$47.00
Jan. - June	2021	Costless Collar	6,000	Brent	$—	$—	$37.50	$45.50
NATURAL GAS
Jan. - Dec.	2021	Swaps	10,000	Henry Hub	$—	$3.05	$—	$—
Jan. - Dec.	2022	Basis Swap	20,000	Waha Hub	$(0.31)	$—	$—	$—

Interest Rate Swaps

Subsequent to September 30, 2020, the Company entered into new interest rate swaps and terminated existing interest rate swaps.

The following table presents the interest rate swaps entered into by the Company subsequent to September 30, 2020.

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	%

The following table presents the interest rate swap contracts terminated by the Company subsequent to September 30, 2020.

Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.551	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.5575	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.297	%

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 condensed consolidated statements of operations:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Gain (loss) on derivative instruments, net
Commodity contracts	$	(104)	$	157	$	147	$	(17)
Interest rate swaps	5		20		(65)		20
Total	$	(99)	$	177	$	82	$	3
Net cash received (paid) on settlements
Commodity contracts(1)	(9)		11		288		33
Total	$	(9)	$	11	$	288	$	33

(1)The three and nine months ended September 30, 2020 include cash received on contracts terminated prior to their contractual maturity of $6 million and $17 million, respectively.

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FAIR VALUE MEASUREMENTS (Tables)

9 Months Ended

Sep. 30, 2020

Fair Value Disclosures [Abstract]

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

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 condensed consolidated balance sheets as of September 30, 2020 and December 31, 2019. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.

	As of September 30, 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	$	—	$	107	$	—	$	107	$	(92)	$	15
Non-current:
Investment	$	5	$	—	$	—	$	5	$	—	$	5
Derivative Instruments	$	—	$	65	$	—	$	65	$	(65)	$	—
Liabilities:
Current:
Derivative Instruments	$	—	$	178	$	—	$	178	$	(92)	$	86
Non-current:
Derivative Instruments	$	—	$	173	$	—	$	173	$	(65)	$	108

	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

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 condensed consolidated balance sheets as of September 30, 2020 and December 31, 2019. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.

	As of September 30, 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	$	—	$	107	$	—	$	107	$	(92)	$	15
Non-current:
Investment	$	5	$	—	$	—	$	5	$	—	$	5
Derivative Instruments	$	—	$	65	$	—	$	65	$	(65)	$	—
Liabilities:
Current:
Derivative Instruments	$	—	$	178	$	—	$	178	$	(92)	$	86
Non-current:
Derivative Instruments	$	—	$	173	$	—	$	173	$	(65)	$	108

	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

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 condensed consolidated balance sheets as of September 30, 2020 and December 31, 2019. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.

	As of September 30, 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	$	—	$	107	$	—	$	107	$	(92)	$	15
Non-current:
Investment	$	5	$	—	$	—	$	5	$	—	$	5
Derivative Instruments	$	—	$	65	$	—	$	65	$	(65)	$	—
Liabilities:
Current:
Derivative Instruments	$	—	$	178	$	—	$	178	$	(92)	$	86
Non-current:
Derivative Instruments	$	—	$	173	$	—	$	173	$	(65)	$	108

	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

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 condensed consolidated balance sheets:

	September 30, 2020				December 31, 2019
	Carrying				Carrying
	Value(1)		Fair Value		Value(1)		Fair Value
	(in millions)
Debt:
Revolving credit facility	$	—	$	—	$	13	$	13
4.625% Notes due 2021	$	191	$	194	$	399	$	411
7.320% Medium-term Notes, Series A, due 2022	$	21	$	22	$	21	$	22
2.875% Senior Notes due 2024	$	993	$	1,014	$	992	$	1,012
4.750% Senior Notes due 2025	$	496	$	541	$	—	$	—
5.375% Senior Notes due 2025	$	800	$	830	$	799	$	840
3.250% Senior Notes due 2026	$	793	$	803	$	792	$	812
7.350% Medium-term Notes, Series A, due 2027	$	—	$	—	$	11	$	12
7.125% Medium-term Notes, Series B, due 2028	$	107	$	113	$	108	$	116
3.500% Senior Notes due 2029	$	1,187	$	1,158	$	1,186	$	1,226
Viper revolving credit facility	$	127	$	127	$	97	$	97
Viper's 5.375% Senior Notes due 2027	$	471	$	477	$	490	$	521
Rattler revolving credit facility	$	85	$	85	$	424	$	424
Rattler’s 5.625% Senior Notes due 2025	$	490	505		$	—	$	—
DrillCo Agreement	$	86	$	86	$	39	$	39

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

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LEASES (Tables)

9 Months Ended

Sep. 30, 2020

Leases [Abstract]

Schedule of operating lease costs

The following table summarizes operating lease costs for the three months and nine months ended September 30, 2020 and 2019:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in millions)
Operating lease costs	$	4	$	7	$	13	$	19

Schedule of undiscounted cash flows owned by company to lessors pursuant to contractual agreements

Schedule of Operating Lease Liability Maturities. The following table summarizes undiscounted cash flows owed by the Company to lessors pursuant to contractual agreements in effect as of September 30, 2020:

	As of September 30, 2020
	(in millions)
2020 (October - December)	$	4
2021	7
2022	3
2023	—
2024	—
Thereafter	—
Total lease payments	14
Less: interest	1
Present value of lease liabilities	$	13

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SUBSEQUENT EVENTS (Tables)

9 Months Ended

Sep. 30, 2020

Subsequent Events [Abstract]

Schedule of derivative contracts by Company subsequent aggregating weighted average contract

As of September 30, 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
Oct. - Dec.	2020	Swaps	11,000	WTI Cushing	$—	$43.47	$—	$—
Oct. - Dec.	2020	Swaps	4,000	WTI Magellan	$—	$61.95	$—	$—
Oct. - Dec.	2020	Swaps	24,200	Brent	$—	$47.62	$—	$—
Oct. - Dec.	2020	Basis Swaps	45,087	WTI Cushing(1)	$(1.33)	$—	$—	$—
Oct. - Dec.	2020	Basis Swaps	8,000	WTL Cushing(1)	$(1.31)	$—	$—	$—
Oct. - Dec.	2020	Rolling Hedge(2)	120,000	WTI Cushing	$(1.05)	$—	$—	$—
Oct. - Dec.	2020	Costless Collar	45,779	WTI Cushing	$—	$—	$35.92	$42.29
Oct. - Dec.	2020	Costless Collar	4,000	WTI Magellan	$—	$—	$39.00	$49.00
Oct. - Dec.	2020	Costless Collar	64,710	Brent	$—	$—	$37.59	$45.63
Jan. - Dec.	2021	Swaps	5,000	WTI Magellan	$—	$37.78	$—	$—
Jan. - Dec.	2021	Swaps	7,500	Brent	$—	$41.58	$—	$—
Jan. - Dec.	2021	Costless Collar	65,000	Brent	$—	$—	$39.25	$48.36
July - Dec.	2021	Swaption	5,000	Brent	$—	$51.00	$—	$—
Jan. - Dec.	2021	Costless Collar	10,000	WTI Cushing	$—	$—	$30.00	$43.05
NATURAL GAS
Oct. - Dec.	2020	Swaps	60,000	Henry Hub	$—	$2.48	$—	$—
Oct. - Dec.	2020	Swaps	60,000	Waha Hub	$—	$1.51	$—	$—
Oct. - Dec.	2020	Basis Swaps	145,000	Waha Hub(1)	$(1.57)	$—	$—	$—
Jan. - Dec.	2021	Swaps	190,000	Henry Hub	$—	$2.62	$—	$—
Jan. - Dec.	2021	Basis Swaps	230,000	Waha Hub(1)	$(0.69)	$—	$—	$—
Jan. - Dec.	2022	Basis Swaps	80,000	Waha Hub(1)	$(0.45)	$—	$—	$—
NATURAL GAS LIQUIDS
Oct. - Dec.	2020	Swaps	7,000	Mont Belvieu Ethane	$—	$8.43	$—	$—
Oct. - Dec.	2020	Swaps	5,000	Mont Belvieu Propane	$—	$21.76	$—	$—
DIESEL
Oct. - Dec.	2021	Swaps	1,000,000	Gulf Cost Ultra Low Sulfur	$—	$1.60	$—	$—

(1) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price or the Midland Argus WTL 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	Strike Price	Swap Price	Put Price	Long Put Price	Option Price
OIL
Oct. - Dec.	2020	Calls(1)	8,000	WTI Magellan	$45.00	$—	$—	$—	$—
Oct. - Dec.	2020	Option	4,700	WTI Cushing	$—	$—	$—	$46.51	$—
Oct. - Dec.	2020	Put Spread	3,800	WTI Magellan	$—	$—	$25.00	$50.00	$—
Oct. - Dec.	2022	Option	5,000	WTI Cushing	$—	$—	$35.00	$—	$—
NATURAL GAS
Oct. - Dec.	2020	Swap Double-Up	30,000	Waha Hub	$—	$1.70	$—	$—	$1.70

(1) Includes a deferred premium at a weighted-average price of $(1.89)/Bbl and a strike price of $45.00/Bbl

The following table summarizes the Company’s interest rate swaps and treasury locks as of September 30, 2020:

Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.551	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.5575	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.297	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.195	%

The following tables present the derivative contracts entered into by the Company between October 1, 2020 and November 2, 2020. When aggregating multiple contracts, the weighted average contract price is disclosed.

					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
Jan. - Mar.	2021	Costless Collar	3,000	WTI Cushing	$—	$—	$37.00	$44.19
Mar. - June	2021	Costless Collar	1,000	WTI Cushing	$—	$—	$37.00	$47.00
Jan. - June	2021	Costless Collar	6,000	Brent	$—	$—	$37.50	$45.50
NATURAL GAS
Jan. - Dec.	2021	Swaps	10,000	Henry Hub	$—	$3.05	$—	$—
Jan. - Dec.	2022	Basis Swap	20,000	Waha Hub	$(0.31)	$—	$—	$—

Interest Rate Swaps

Subsequent to September 30, 2020, the Company entered into new interest rate swaps and terminated existing interest rate swaps.

The following table presents the interest rate swaps entered into by the Company subsequent to September 30, 2020.

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	%

The following table presents the interest rate swap contracts terminated by the Company subsequent to September 30, 2020.

Type	Effective Date	Contractual Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.551	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.5575	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.297	%

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SEGMENT INFORMATION (Tables)

9 Months Ended

Sep. 30, 2020

Segment Reporting [Abstract]

Results of the company business segments

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

	Upstream		Midstream Services		Eliminations		Total
Three Months Ended September 30, 2020:	(in millions)
Third-party revenues	$	706	$	14	$	—	$	720
Intersegment revenues	—		83		(83)		—
Total revenues	706		97		(83)		720
Depreciation, depletion and amortization	275		11		—		286
Impairment of oil and natural gas properties	1,451		—		—		1,451
Income (loss) from operations	(1,282)		44		(18)		(1,256)
Interest expense, net	(47)		(6)		—		(53)
Other income (expense)	(103)		4		(1)		(100)
Provision for (benefit from) income taxes	(307)		3		—		(304)
Net income (loss) attributable to non-controlling interest	(1)		9		—		8
Net income (loss) attributable to Diamondback Energy, Inc.	(1,124)		30		(19)		(1,113)
As of September 30, 2020:
Total assets	$	17,245	$	1,812	$	(297)	$	18,760

	Upstream		Midstream Services		Eliminations		Total
Three Months Ended September 30, 2019:	(in millions)
Third-party revenues	$	957	$	18	$	—	$	975
Intersegment revenues	—		97		(97)		—
Total revenues	957		115		(97)		975
Depreciation, depletion and amortization	353		12		—		365
Income (loss) from operations	321		52		(24)		349
Interest expense, net	(37)		(1)		—		(38)
Other income (expense)	181		(1)		(1)		179
Provision for (benefit from) income taxes	99		3		—		102
Net income (loss) attributable to non-controlling interest	20		37		(37)		20
Net income (loss) attributable to Diamondback Energy, Inc.	346		10		12		368
As of December 31, 2019:
Total assets	$	22,125	$	1,636	$	(230)	$	23,531

	Upstream		Midstream Services		Eliminations		Total
Nine Months Ended September 30, 2020:	(in millions)
Third-party revenues	$	2,002	$	42	$	—	$	2,044
Intersegment revenues	—		273		(273)		—
Total revenues	2,002		315		(273)		2,044
Depreciation, depletion and amortization	1,001		35		—		1,036
Impairment of oil and natural gas properties	4,999		—		—		4,999
Income (loss) from operations	(4,787)		134		(77)		(4,730)
Interest expense, net	(137)		(10)		—		(147)
Other income (expense)	73		(10)		(4)		59
Provision for (benefit from) income taxes	(910)		8		—		(902)
Net income (loss) attributable to non-controlling interest	(163)		25		—		(138)
Net income (loss) attributable to Diamondback Energy, Inc.	(3,778)		81		(81)		(3,778)
As of September 30, 2020:
Total assets	$	17,245	$	1,812	$	(297)	$	18,760

	Upstream		Midstream Services		Eliminations		Total
Nine Months Ended September 30, 2019:	(in millions)
Third-party revenues	$	2,802	$	58	$	—	$	2,860
Intersegment revenues	—		264		(264)		—
Total revenues	2,802		322		(264)		2,860
Depreciation, depletion and amortization	1,014		32		—		1,046
Income (loss) from operations	1,004		159		(84)		1,079
Interest expense, net	(132)		(1)		—		(133)
Other income (expense)	16		(1)		(3)		12
Provision for (benefit from) income taxes	167		4		—		171
Net income (loss) attributable to non-controlling interest	60		52		(52)		60
Net income (loss) attributable to Diamondback Energy, Inc.	$	661	$	101	$	(35)	727
As of December 31, 2019:
Total assets	$	22,125	$	1,636	$	(230)	$	23,531

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DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION (Details)	Sep. 30, 2020	May 28, 2019
Viper Energy Partners LP
Noncontrolling Interest [Line Items]
Ownership percentage	58.00%
Rattler MIdstream LP
Noncontrolling Interest [Line Items]
Ownership percentage	71.00%	29.00%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($) $ in Millions	3 Months Ended
	Jun. 30, 2020	Mar. 31, 2019
Accounts, Notes, Loans and Financing Receivable [Line Items]
Change in ownership of consolidated subsidiaries, net	$ 0	$ 3
Non-Controlling Interest
Accounts, Notes, Loans and Financing Receivable [Line Items]
Change in ownership of consolidated subsidiaries, net	(329)	(74)
Non-Controlling Interest | Rattler LLC
Accounts, Notes, Loans and Financing Receivable [Line Items]
Change in ownership of consolidated subsidiaries, net	(329)
Additional Paid-in Capital
Accounts, Notes, Loans and Financing Receivable [Line Items]
Change in ownership of consolidated subsidiaries, net	329	$ 77
Additional Paid-in Capital | Rattler LLC
Accounts, Notes, Loans and Financing Receivable [Line Items]
Change in ownership of consolidated subsidiaries, net	$ 329

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REVENUE FROM CONTRACTS WITH CUSTOMERS (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Disaggregation of Revenue [Line Items]
Revenue	$ 707	$ 956	$ 2,002	$ 2,798
Midland Basin
Disaggregation of Revenue [Line Items]
Revenue	403	569	1,150	1,688
Delaware Basin
Disaggregation of Revenue [Line Items]
Revenue	302	383	846	1,047
Other
Disaggregation of Revenue [Line Items]
Revenue	2	4	6	63
Oil sales
Disaggregation of Revenue [Line Items]
Revenue	606	882	1,785	2,572
Oil sales | Midland Basin
Disaggregation of Revenue [Line Items]
Revenue	348	529	1,030	1,561
Oil sales | Delaware Basin
Disaggregation of Revenue [Line Items]
Revenue	257	350	750	951
Oil sales | Other
Disaggregation of Revenue [Line Items]
Revenue	1	3	5	60
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenue	36	16	61	36
Natural gas sales | Midland Basin
Disaggregation of Revenue [Line Items]
Revenue	19	7	32	17
Natural gas sales | Delaware Basin
Disaggregation of Revenue [Line Items]
Revenue	17	8	29	18
Natural gas sales | Other
Disaggregation of Revenue [Line Items]
Revenue	0	1	0	1
Natural gas liquid sales
Disaggregation of Revenue [Line Items]
Revenue	65	58	156	190
Natural gas liquid sales | Midland Basin
Disaggregation of Revenue [Line Items]
Revenue	36	33	88	110
Natural gas liquid sales | Delaware Basin
Disaggregation of Revenue [Line Items]
Revenue	28	25	67	78
Natural gas liquid sales | Other
Disaggregation of Revenue [Line Items]
Revenue	$ 1	$ 0	$ 1	$ 2

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DIVESTITURE - Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen (Details) - Energen Corporation Merger $ in Millions	Jul. 01, 2019 USD ($) a	May 23, 2019 USD ($) a
Business Acquisition [Line Items]
Area of land (in acre) | a	103,750	6,589
Payment to acquire businesses | $	$ 285	$ 37

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DIVESTITURE - 2019 Drop-Down Transaction (Details) - 2019 Drop-Down Transaction - Viper Energy Partners LP shares in Millions, $ in Millions	Jul. 29, 2019 USD ($) a shares
Business Acquisition [Line Items]
Number of shares to be issued in acquisition (in shares) | shares	18.3
Business combination, total consideration | $	$ 497
Proceeds from divestiture | $	$ 190
Net royalty area (in acre) | a	5,490
Percentage of mineral acres operated	95.00%
Percentage of average net royalty interest in acquired mineral and royalty interests	3.20%
Class B Units
Business Acquisition [Line Items]
Number of shares to be issued in acquisition (in shares) | shares	18.3

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RATTLER MIDSTREAM LP (Details) - USD ($) $ / shares in Units, $ in Millions	May 28, 2019	Sep. 30, 2020
Noncontrolling Interest [Line Items]
Limited partners capital contribution	$ 1
Rattler MIdstream LP
Noncontrolling Interest [Line Items]
Ownership percentage	29.00%	71.00%
Limited partners ownership percentage	71.00%
Rattler MIdstream LP
Noncontrolling Interest [Line Items]
General partners cash contribution	$ 1
Percentage of preferred cash distribution received	8.00%
Rattler MIdstream LP | IPO
Noncontrolling Interest [Line Items]
Offer and issuance of stock (in Shares)	43,700,000
Shares issued (in USD per share)	$ 17.50
Consideration received from offering	$ 720
Rattler MIdstream LP | Class B Units
Noncontrolling Interest [Line Items]
Limited partners' capital account, units issued (in Shares)	107,815,152
Rattler LLC
Noncontrolling Interest [Line Items]
Distribution equivalent rights	$ 727

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REAL ESTATE ASSETS (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 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	(12)	(9)
Total investment in land and buildings, net	$ 98	$ 101
Buildings | Minimum
Real Estate [Line Items]
Real estate assets, estimated useful lives	20 years
Buildings | Maximum
Real Estate [Line Items]
Real estate assets, estimated useful lives	30 years
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

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PROPERTY AND EQUIPMENT (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Oil and natural gas properties:
Not subject to depletion	$ 7,879	$ 9,207
Gross oil and natural gas properties	27,305	25,782
Accumulated depletion and depreciation	(11,031)	(5,003)
Midstream assets	1,026	931
Other property, equipment and land	135	125
Property and equipment, net	17,435	21,835
Oil and Natural Gas
Oil and natural gas properties:
Subject to depletion	19,426	16,575
Not subject to depletion	7,879	9,207
Gross oil and natural gas properties	27,305	25,782
Accumulated depletion and depreciation	(3,988)	(2,995)
Accumulated impairment	(6,933)	(1,934)
Oil and natural gas properties, net	16,384	20,853
Other Property and Equipment, Net
Oil and natural gas properties:
Accumulated depletion and depreciation	(110)	(74)
Other property, equipment and land	$ 135	$ 125

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PROPERTY AND EQUIPMENT - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Property, Plant and Equipment [Abstract]
Impairment of oil and natural gas properties	$ 1,451	$ 0	$ 4,999	$ 0
Capitalized internal costs	$ 14	$ 8	$ 42	$ 32
Timing of inclusion of costs in amortization calculation			5 years

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Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of period			$ 94	$ 136
Additional liabilities incurred			12	6
Liabilities acquired			3	3
Liabilities settled			(1)	(61)
Asset retirement obligation accretion	$ 2	$ 1	5	6
Asset retirement obligations, end of period	113	90	113	90
Less current portion	1	0	1	0
Asset retirement obligations - long-term	$ 112	$ 90	$ 112	$ 90	$ 94

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EQUITY METHOD INVESTMENTS - Carrying Values of Rattler’s Equity Method Investments (Details) - USD ($) $ in Millions	Sep. 30, 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	$ 532	$ 479
Rattler LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments	532	479
EPIC Crude Holdings, LP | Rattler LLC
Schedule of Equity Method Investments [Line Items]
Equity method interest investment ownership percentage							10.00%
Equity method investments	123	110
Gray Oak Pipeline, LLC | Rattler LLC
Schedule of Equity Method Investments [Line Items]
Equity method interest investment ownership percentage						10.00%
Equity method investments	135	115
Wink to Webster Pipeline LLC | Rattler LLC
Schedule of Equity Method Investments [Line Items]
Equity method interest investment ownership percentage					4.00%
Equity method investments	75	34
OMOG JV LLC | Rattler LLC
Schedule of Equity Method Investments [Line Items]
Equity method interest investment ownership percentage				60.00%
Equity method investments	195	219
Amarillo Rattler, LLC | Rattler LLC
Schedule of Equity Method Investments [Line Items]
Equity method interest investment ownership percentage			50.00%
Equity method investments	$ 4	$ 1

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EQUITY METHOD INVESTMENTS - Income (Loss) from Rattler’s Equity Method Investees (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Schedule of Equity Method Investments [Line Items]
(Income) loss from equity investment	$ 3	$ 0	$ (10)	$ 0
EPIC Crude Holdings, LP | Rattler LLC
Schedule of Equity Method Investments [Line Items]
(Income) loss from equity investment	(2)	0	(5)	0
Gray Oak Pipeline, LLC | Rattler LLC
Schedule of Equity Method Investments [Line Items]
(Income) loss from equity investment	4	0	6	0
OMOG JV LLC | Rattler LLC
Schedule of Equity Method Investments [Line Items]
(Income) loss from equity investment	$ 1	$ 0	$ (11)	$ 0

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EQUITY METHOD INVESTMENTS - Narrative (Details) - Rattler LLC Mcf in Thousands	9 Months Ended
	Sep. 30, 2020 USD ($) Mcf	Sep. 30, 2019 USD ($)	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 [Line Items]
Impairments in equity method investments | $	$ 0	$ 0
Joint Venture of Wink to Webster Project
Schedule of Equity Method Investments [Line Items]
Ownership percentage						4.00%
EPIC Crude Holdings, LP
Schedule of Equity Method Investments [Line Items]
Equity method interest investment ownership percentage									10.00%
Gray Oak Pipeline, LLC
Schedule of Equity Method Investments [Line Items]
Equity method interest investment ownership percentage								10.00%
Gray Oak Pipeline, LLC | 2.52% Short-Term Promissory Note
Schedule of Equity Method Investments [Line Items]
Equity method investment promissory note | $							$ 123,000,000
Debt instrument stated interest rate							2.52%
OMOG JV LLC
Schedule of Equity Method Investments [Line Items]
Equity method interest investment ownership percentage					60.00%
Goodwill impairment charge | $	$ 16,000,000
OMOG JV LLC | Reliance Gathering LLC
Schedule of Equity Method Investments [Line Items]
Percentage of voting interests acquired				100.00%
Amarillo Rattler, LLC
Schedule of Equity Method Investments [Line Items]
Equity method interest investment ownership percentage			50.00%
Gas gathering and cryogenic processing system capacity | Mcf	30
Amarillo Rattler, LLC | Dawson, Martin and Andrews Counties, Texas
Schedule of Equity Method Investments [Line Items]
Gas gathering and cryogenic processing system capacity | Mcf			40
Distance of gathering and regional transportation pipelines | mi			84
Amarillo Rattler, LLC | Martin County, Texas
Schedule of Equity Method Investments [Line Items]
Gas gathering and cryogenic processing system capacity | Mcf			60

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DEBT - Long-term Debt (Details) - USD ($) $ in Millions	Sep. 30, 2020	May 26, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 5,847.0		$ 5,371.0
Unamortized debt issuance costs	(30.0)		(19.0)
Unamortized discount costs	(28.0)		(31.0)
Unamortized premium costs	16.0		9.0
Current maturities of long-term debt	(191.0)		0.0
Total debt, net	5,656.0		5,371.0
4.625% Notes due 2021
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 191.0	$ 209.0	399.0
Debt instrument stated interest rate	4.625%	4.625%
7.320% Medium-term Notes, Series A, due 2022
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 20.0		21.0
Debt instrument stated interest rate	7.32%
2.875% Senior Notes due 2024
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 1,000.0		1,000.0
Debt instrument stated interest rate	2.875%
4.750% Senior Notes due 2025
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 500.0		0.0
Debt instrument stated interest rate	4.75%
5.375% Senior Notes due 2025
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 800.0		800.0
Debt instrument stated interest rate	5.375%
3.250% Senior Notes due 2026
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 800.0		800.0
Debt instrument stated interest rate	3.25%
7.350% Medium-term Notes, Series A, due 2027
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 0.0		11.0
Debt instrument stated interest rate	7.35%
7.125% Medium-term Notes, Series B, due 2028
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 100.0		108.0
Debt instrument stated interest rate	7.125%
3.500% Senior Notes due 2029
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 1,200.0		1,200.0
Debt instrument stated interest rate	3.50%
DrillCo Agreement
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 86.0		39.0
Company revolving credit facility
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	0.0		13.0
Viper revolving credit facility | Viper Energy Partners LP
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 127.0		97.0
Viper 5.375% Senior Notes due 2027
Debt Instrument [Line Items]
Debt instrument stated interest rate	5.375%
Viper 5.375% Senior Notes due 2027 | Viper Energy Partners LP
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 480.0		500.0
Rattler revolving credit facility | Rattler LLC
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 85.0		424.0
Rattler 5.625% Senior Notes due 2025
Debt Instrument [Line Items]
Debt instrument stated interest rate	5.625%
Rattler 5.625% Senior Notes due 2025 | Rattler LLC
Debt Instrument [Line Items]
Outstanding borrowings on revolving credit facility	$ 500.0		$ 0.0

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DEBT - May 2020 Senior Notes (Details) - USD ($)		9 Months Ended
	May 26, 2020	Sep. 30, 2020	Sep. 30, 2019
Debt Instrument [Line Items]
Proceeds from senior notes		$ 997,000,000	$ 0
Senior Notes | May 2020 Notes
Debt Instrument [Line Items]
Aggregate principal amount	$ 500,000,000
Debt instrument stated interest rate	4.75%
Proceeds from senior notes	$ 496,000,000

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DEBT - Second Amended and Restated Credit Facility (Details)	3 Months Ended	9 Months Ended
	Sep. 30, 2020 USD ($) numberOfLetters	Sep. 30, 2020 USD ($) numberOfLetters	Dec. 31, 2019 USD ($)
Line of Credit Facility [Line Items]
Outstanding borrowings	$ 5,847,000,000	$ 5,847,000,000	$ 5,371,000,000
Revolving credit facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity	2,000,000,000	2,000,000,000
Outstanding borrowings	0	0	$ 13,000,000
Remaining borrowing capacity	$ 2,000,000,000.0	$ 2,000,000,000.0
Number of letters of credit outstanding | numberOfLetters	3,000,000	3,000,000
Weighted average rate	1.83%	2.27%

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DEBT - Energen Notes (Details) - USD ($)	3 Months Ended
	Sep. 30, 2020	May 26, 2020	Dec. 31, 2019	Nov. 29, 2018
Debt Instrument [Line Items]
Outstanding borrowings	$ 5,847,000,000		$ 5,371,000,000
Energen Notes
Debt Instrument [Line Items]
Outstanding borrowings				$ 530,000,000
4.625% Notes due 2021
Debt Instrument [Line Items]
Outstanding borrowings	$ 191,000,000	$ 209,000,000	399,000,000
Debt instrument stated interest rate	4.625%	4.625%
7.125% Medium-term Notes, Series B, due 2028
Debt Instrument [Line Items]
Outstanding borrowings	$ 100,000,000		108,000,000
Debt instrument stated interest rate	7.125%
7.320% Medium-term Notes, Series A, due 2022
Debt Instrument [Line Items]
Outstanding borrowings	$ 20,000,000		21,000,000
Debt instrument stated interest rate	7.32%
7.350% Medium-term Notes, Series A, due 2027
Debt Instrument [Line Items]
Outstanding borrowings	$ 0		$ 11,000,000
Debt instrument stated interest rate	7.35%
Repurchased principal amount	$ 10,000,000
Redemption price, percentage of principal amount redeemed	120.00%

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DEBT - Viper’s Credit Agreement (Details)		3 Months Ended	9 Months Ended
	Jul. 20, 2018 USD ($) redeterminations	Sep. 30, 2020 USD ($)	Sep. 30, 2020 USD ($)	Jun. 30, 2020 USD ($)	Dec. 31, 2019 USD ($)
Line of Credit Facility [Line Items]
Outstanding borrowings		$ 5,847,000,000	$ 5,847,000,000		$ 5,371,000,000
Viper revolving credit facility | Viper Energy Partners LP
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000,000,000
Number of redeterminations | redeterminations	3
Period of redetermination	12 months
Current borrowing capacity	$ 775,000,000	580,000,000	580,000,000	$ 580,000,000
Outstanding borrowings		127,000,000	127,000,000		$ 97,000,000
Remaining borrowing capacity		$ 453,000,000	$ 453,000,000
Weighted average rate		2.14%	2.66%

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DEBT - Viper’s Notes (Details) - USD ($)		3 Months Ended	9 Months Ended
	Oct. 16, 2019	Sep. 30, 2020	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Debt Instrument [Line Items]
Proceeds from senior notes			$ 997,000,000	$ 0
Outstanding borrowings		$ 5,847,000,000	$ 5,847,000,000		$ 5,371,000,000
Viper 5.375% Senior Notes due 2027
Debt Instrument [Line Items]
Debt instrument stated interest rate		5.375%	5.375%
Viper Energy Partners LP | Viper 5.375% Senior Notes due 2027
Debt Instrument [Line Items]
Outstanding borrowings		$ 480,000,000	$ 480,000,000		$ 500,000,000
Viper Energy Partners LP | Senior Notes | Viper 5.375% Senior Notes due 2027
Debt Instrument [Line Items]
Debt instrument stated interest rate	5.375%
Aggregate principal amount	$ 500,000,000
Proceeds from senior notes	$ 490,000,000
Repurchase of debt		$ 6,000,000	$ 20,000,000
Viper Energy Partners LP | Senior Notes | Viper 5.375% Senior Notes due 2027 | Minimum
Debt Instrument [Line Items]
Discount percentage		97.50%	97.50%
Viper Energy Partners LP | Senior Notes | Viper 5.375% Senior Notes due 2027 | Maximum
Debt Instrument [Line Items]
Discount percentage		98.50%	98.50%

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DEBT - Rattler's Credit Agreement (Details) - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2020	Dec. 31, 2019	May 28, 2019
Line of Credit Facility [Line Items]
Outstanding borrowings	$ 5,847,000,000	$ 5,847,000,000	$ 5,371,000,000
Rattler revolving credit facility | Rattler LLC
Line of Credit Facility [Line Items]
Maximum borrowing capacity	600,000,000	600,000,000
Expandable amount				$ 1,000,000,000
Outstanding borrowings	85,000,000	85,000,000	$ 424,000,000
Remaining borrowing capacity	$ 515,000,000	$ 515,000,000
Weighted average rate	1.46%	2.18%

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

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DEBT - Alliance with Obsidian Resources, L.L.C. (Details) - DrillCo Agreement $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($) well	Dec. 31, 2019 USD ($)	Sep. 10, 2018 USD ($)
Collaborative Arrangement and Arrangement Other than Collaborative [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	$ 86	$ 39
Wells drilled and completed under joint venture agreement | well	15
CEMOF
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Interest rate upon reaching final internal rate of return			15.00%

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CAPITAL STOCK AND EARNINGS PER SHARE - Capital Stock (Details) - USD ($)	3 Months Ended					9 Months Ended
	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	May 31, 2019
Equity [Abstract]
Stock repurchase program authorized amount							$ 2,000,000,000
Repurchased shares for share buyback program (in Shares)	0
Stock repurchase program amount repurchased		$ 98,000,000	$ 296,000,000	$ 104,000,000	$ 13,000,000	$ 98,000,000
Stock repurchase remaining authorized amount	$ 1,300,000,000					$ 1,300,000,000

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CAPITAL STOCK AND EARNINGS PER SHARE - Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Basic:
Net income (loss) attributable to common stock	$ (1,113)	$ 368	$ (3,778)	$ 727
Basic weighted average common units outstanding (in shares)	157,833,000	162,543,000	157,984,000	164,070,000
Effect of dilutive securities:
Potential common shares issuable (in shares)	0	237,000	0	396,000
Diluted:
Diluted weighted average common shares outstanding (in shares)	157,833,000	162,780,000	157,984,000	164,466,000
Basic net income attributable to common stock (in USD per share)	$ (7.05)	$ 2.27	$ (23.91)	$ 4.44
Diluted net income attributable to common stock (in USD per share)	$ (7.05)	$ 2.26	$ (23.91)	$ 4.42
Restricted stock units (in shares)		50,814		40,291

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CAPITAL STOCK AND EARNINGS PER SHARE - Change in Ownership of Consolidated Subsidiaries (Details) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Sep. 30, 2019	Mar. 31, 2019	Sep. 30, 2020	Sep. 30, 2019
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income (loss) attributable to the Company	$ (1,113,000)		$ 368,000		$ (3,778,000)	$ 727,000
Change in ownership of consolidated subsidiaries, net		$ 0		$ 3,000
Limited Partner
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income (loss) attributable to the Company	(1,113,000)		368,000		(3,778,000)	727,000
Change in ownership of consolidated subsidiaries, net	0		0		329,000	77,000
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest	$ (1,113,000)		$ 368,000		$ (3,449,000)	$ 804,000

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EQUITY-BASED COMPENSATION - Schedule of Stock-Based Compensation Plans and Related Costs (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
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	$ 4	$ (1)	$ 12	$ 9
General and administrative expenses
Share-based Payment Arrangement, Expensed and Capitalized, Amount [Line Items]
General and administrative expenses	$ 9	$ 4	$ 27	$ 27

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EQUITY-BASED COMPENSATION - Restricted Stock Units (Details) - Equity Plan - Restricted Stock Units (RSUs)	9 Months Ended
	Sep. 30, 2020 $ / shares shares
Restricted Stock Awards & Units (in Shares)
Unvested, beginning balance (in shares) | shares	505,867
Granted (in shares) | shares	183,102
Vested (in shares) | shares	(139,355)
Forfeited (in shares) | shares	(19,228)
Unvested, ending balance (in shares) | shares	530,386
Weighted Average Grant-Date Fair Value
Unvested, beginning balance (in USD per share) | $ / shares	$ 96.01
Granted (in USD per share) | $ / shares	60.72
Vested (in USD per share) | $ / shares	85.21
Forfeited (in USD per share) | $ / shares	99.01
Unvested, ending balance (in USD per share) | $ / shares	$ 86.55

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EQUITY-BASED COMPENSATION - Restricted Stock Units (Narratives) (Details) - Restricted Stock Units (RSUs) - Equity Plan - USD ($)	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregated fair value of restricted stock	$ 12,000,000	$ 4,000,000
Share based award not recognized	$ 27,000,000
Share based payment not recognized	1 year 8 months 12 days
Incremental compensation	$ 0

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EQUITY-BASED COMPENSATION - Performance Based Restricted Stock Units (Narratives) (Details) - Performance Shares - Equity Plan $ in Millions	1 Months Ended			9 Months Ended
	Mar. 31, 2020 shares	Mar. 31, 2019 installment shares	Feb. 28, 2018 shares	Sep. 30, 2020 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	225,047		117,423	272,601
Performance shares, performance period				3 years
Share based award not recognized | $				$ 26
Share based payment not recognized				2 years
Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		199,723
Share based compensation arrangement by share-based payment award number of shares authorized percent of shares granted	250.00%
Five-Year
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		32,958
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%
Minimum | Tranche One
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%
Minimum | Five-Year
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%
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%
Maximum | Tranche One
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%
Maximum | Five-Year
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%
Number of installments | installment		5

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EQUITY-BASED COMPENSATION - Valuation Assumptions (Details) - Equity Plan - Performance Shares - $ / shares	1 Months Ended			9 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Feb. 28, 2018	Sep. 30, 2020
Restricted Stock Awards & Units
Granted (in USD per share)	$ 70.17	$ 137.22	$ 170.45	$ 85.73
Risk-free rate	0.86%	2.55%	1.99%
Company volatility	36.70%	35.00%	35.90%
Five-Year
Restricted Stock Awards & Units
Granted (in USD per share)		$ 132.48

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EQUITY-BASED COMPENSATION - Performance Restricted Stock Activity (Details) - Equity Plan - Performance Shares - $ / shares	1 Months Ended			9 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Feb. 28, 2018	Sep. 30, 2020
Awards & Units (in shares)
Unvested, beginning balance (in shares)				271,819
Granted (in shares)	225,047		117,423	272,601
Vested (in shares)				(47,554)
Forfeited (in shares)				(8,396)
Unvested, ending balance (in shares)				488,470
Weighted Average Exercise Price (in USD per share)
Unvested, beginning balance (in USD per share)				$ 147.07
Granted (in USD per share)	$ 70.17	$ 137.22	$ 170.45	85.73
Vested (in USD per share)				89.27
Forfeited (in USD per share)				170.45
Unvested, ending balance (in USD per share)				$ 110.33
Share based compensation arrangement by share based payment maximum award potential (in shares)				1,089,464

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EQUITY-BASED COMPENSATION - Rattler Phantom Units (Details) - Phantom Share Units (PSUs) - Rattler Midstream LP Long-Term Incentive Plan	9 Months Ended
	Sep. 30, 2020 $ / shares shares
Phantom Units
Unvested, beginning balance (in shares) | shares	2,226,895
Granted (in shares) | shares	53,943
Vested (in shares) | shares	(449,633)
Forfeited (in shares) | shares	(23,442)
Unvested, ending balance (in shares) | shares	1,807,763
Weighted Average Grant-Date Fair Value
Unvested, beginning balance (in USD per share) | $ / shares	$ 19.14
Granted (in USD per share) | $ / shares	10.41
Vested (in USD per share) | $ / shares	19.14
Forfeited (in USD per share) | $ / shares	18.23
Unvested, ending balance (in USD per share) | $ / shares	$ 18.89

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EQUITY-BASED COMPENSATION - Rattler Phantom Units (Narratives) (Details) - Phantom Share Units (PSUs) - Rattler Midstream LP Long-Term Incentive Plan $ in Millions	9 Months Ended
	Sep. 30, 2020 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregated fair value of restricted stock	$ 9.0
Share based award not recognized	$ 31.0
Share based payment not recognized	3 years 7 months 6 days

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INCOME TAXES (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Jun. 30, 2020
Income Tax Disclosure [Abstract]
Effective income tax rate	21.60%		20.80%	18.70%	17.90%
Discrete income tax expense (benefit) related to deferred taxes recorded during the period				$ 143	$ (42)
Discrete income tax benefit				25
Discrete income tax benefit, equity based compensation, less than					$ 1
Federal net losses		$ 179
Current federal taxes receivable	$ 100	$ 100		$ 100		$ 100

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DERIVATIVES - Open Derivative Positions (Details)	9 Months Ended
	Sep. 30, 2020 MMBTU $ / bbl $ / MMBTU bbl
OIL | 2020 | Swaps | WTI Cushing
Derivative [Line Items]
Volume (Bbls) | bbl	11,000
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	43.47
OIL | 2020 | Swaps | WTI Magellan
Derivative [Line Items]
Volume (Bbls) | bbl	4,000
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	61.95
OIL | 2020 | Swaps | Brent
Derivative [Line Items]
Volume (Bbls) | bbl	24,200
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	47.62
OIL | 2020 | Basis Swaps | WTI Cushing
Derivative [Line Items]
Volume (Bbls) | bbl	45,087
Weighted average differential (per Bbl)	(1.33)
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	0
OIL | 2020 | Basis Swaps | WTL Cushing
Derivative [Line Items]
Volume (Bbls) | bbl	8,000
Weighted average differential (per Bbl)	(1.31)
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	0
OIL | 2020 | Rolling Hedge | WTI Cushing
Derivative [Line Items]
Volume (Bbls) | bbl	120,000
Weighted average differential (per Bbl)	(1.05)
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	0
OIL | 2020 | Costless Collar | WTI Cushing
Derivative [Line Items]
Volume (Bbls) | bbl	45,779
Weighted Average Floor Price (USD per Bbl)	35.92
Weighted Average Ceiling Price (USD per Bbl)	42.29
OIL | 2020 | Costless Collar | WTI Magellan
Derivative [Line Items]
Volume (Bbls) | bbl	4,000
Weighted Average Floor Price (USD per Bbl)	39.00
Weighted Average Ceiling Price (USD per Bbl)	49.00
OIL | 2020 | Costless Collar | Brent
Derivative [Line Items]
Volume (Bbls) | bbl	64,710
Weighted Average Floor Price (USD per Bbl)	37.59
Weighted Average Ceiling Price (USD per Bbl)	45.63
OIL | 2020 | Calls | WTI Magellan
Derivative [Line Items]
Volume (Bbls) | bbl	8,000
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	0
Weighted Average Put Price (USD per Bbl)	0
Strike Price (USD per Bbl)	45.00
Option price (per Mcf)	0
Premium (per Bbl)	1.89
OIL | 2020 | Calls | WTI Magellan | Long
Derivative [Line Items]
Weighted Average Put Price (USD per Bbl)	0
OIL | 2020 | Option | WTI Cushing
Derivative [Line Items]
Volume (Bbls) | bbl	4,700
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	0
Weighted Average Put Price (USD per Bbl)	0
Strike Price (USD per Bbl)	0
Option price (per Mcf)	0
OIL | 2020 | Option | WTI Cushing | Long
Derivative [Line Items]
Weighted Average Put Price (USD per Bbl)	46.51
OIL | 2020 | Put Spread | WTI Magellan
Derivative [Line Items]
Volume (Bbls) | bbl	3,800
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	0
Weighted Average Put Price (USD per Bbl)	25.00
Strike Price (USD per Bbl)	0
Option price (per Mcf)	0
OIL | 2020 | Put Spread | WTI Magellan | Long
Derivative [Line Items]
Weighted Average Put Price (USD per Bbl)	50.00
OIL | 2021 | Swaps | WTI Magellan
Derivative [Line Items]
Volume (Bbls) | bbl	5,000
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	37.78
OIL | 2021 | Swaps | Brent
Derivative [Line Items]
Volume (Bbls) | bbl	7,500
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	41.58
OIL | 2021 | Costless Collar | WTI Cushing
Derivative [Line Items]
Volume (Bbls) | bbl	10,000
Weighted Average Floor Price (USD per Bbl)	30.00
Weighted Average Ceiling Price (USD per Bbl)	43.05
OIL | 2021 | Costless Collar | Brent
Derivative [Line Items]
Volume (Bbls) | bbl	65,000
Weighted Average Floor Price (USD per Bbl)	39.25
Weighted Average Ceiling Price (USD per Bbl)	48.36
OIL | 2021 | Swaption | Brent
Derivative [Line Items]
Volume (Bbls) | bbl	5,000
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	51.00
OIL | 2022 | Option | WTI Cushing
Derivative [Line Items]
Volume (Bbls) | bbl	5,000
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	0
Weighted Average Put Price (USD per Bbl)	35.00
Strike Price (USD per Bbl)	0
Option price (per Mcf)	0
OIL | 2022 | Option | WTI Cushing | Long
Derivative [Line Items]
Weighted Average Put Price (USD per Bbl)	0
NATURAL GAS | 2020 | Swaps | Henry Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	60,000
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | $ / MMBTU	2.48
NATURAL GAS | 2020 | Swaps | Waha Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	60,000
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | $ / MMBTU	1.51
NATURAL GAS | 2020 | Basis Swaps | Waha Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	145,000
Weighted average differential (per Bbl)	(1.57)
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | $ / MMBTU	0
NATURAL GAS | 2020 | Swap Double-Up | Waha Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	30,000
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	1.70
Weighted Average Put Price (USD per Bbl)	0
Strike Price (USD per Bbl)	0
Option price (per Mcf)	1.70
NATURAL GAS | 2020 | Swap Double-Up | Waha Hub | Long
Derivative [Line Items]
Weighted Average Put Price (USD per Bbl)	0
NATURAL GAS | 2021 | Swaps | Henry Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	190,000
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | $ / MMBTU	2.62
NATURAL GAS | 2021 | Basis Swaps | Henry Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	230,000
Weighted average differential (per Bbl)	(0.69)
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | $ / MMBTU	0
NATURAL GAS | 2022 | Basis Swaps | Waha Hub
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	80,000
Weighted average differential (per Bbl)	(0.45)
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | $ / MMBTU	0
NATURAL GAS LIQUIDS | 2020 | Swaps | Mont Belvieu Ethane
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	7,000
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | $ / MMBTU	8.43
NATURAL GAS LIQUIDS | 2020 | Swaps | Mont Belvieu Propane
Derivative [Line Items]
Volume, energy measure (MMBtu) | MMBTU	5,000
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | $ / MMBTU	21.76
DIESEL | 2021 | Swaps | Gulf Cost Ultra Low Sulfur
Derivative [Line Items]
Volume (Bbls) | bbl	1,000,000
Weighted average differential (per Bbl)	0
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)	1.60

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DERIVATIVES - Interest rate swaps and treasury locks (Details) $ in Millions	Sep. 30, 2020 USD ($)
Interest Rate Swap One
Offsetting Assets [Line Items]
Notional Amount (in millions)	$ 250
Interest Rate	1.551%
Interest Rate Swap Two
Offsetting Assets [Line Items]
Notional Amount (in millions)	$ 250
Interest Rate	1.5575%
Interest Rate Swap Three
Offsetting Assets [Line Items]
Notional Amount (in millions)	$ 250
Interest Rate	1.297%
Interest Rate Swap Four
Offsetting Assets [Line Items]
Notional Amount (in millions)	$ 250
Interest Rate	1.195%

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DERIVATIVES - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments, net	$ (99)	$ 177	$ 82	$ 3
Net cash received (paid) on settlements	(9)	11	288	33
Commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments, net	(104)	157	147	(17)
Net cash received (paid) on settlements	(9)	11	288	33
Cash received on contract	6		17
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) on derivative instruments, net	$ 5	$ 20	$ (65)	$ 20

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FAIR VALUE MEASUREMENTS - Recurring Measurements (Details) - USD ($) $ in Millions	Sep. 30, 2020	Dec. 31, 2019
Current:
Derivative instruments	$ 15	$ 46
Non-current:
Derivative instruments	0	7
Current:
Derivative instruments	86	27
Non-current:
Derivative instruments	108	0
Viper Energy Partners LP | Recurring | Investment
Non-current:
Total Gross Fair Value	5	19
Gross Amounts Offset in Balance Sheet	0	0
Derivative instruments	5	19
Viper Energy Partners LP | Recurring | Derivative Instruments
Current:
Total Gross Fair Value	107	64
Gross Amounts Offset in Balance Sheet	(92)	(18)
Derivative instruments	15	46
Non-current:
Total Gross Fair Value	65	7
Gross Amounts Offset in Balance Sheet	(65)	0
Derivative instruments	0	7
Current:
Total Gross Fair Value	178	45
Gross Amounts Offset in Balance Sheet	(92)	(18)
Derivative instruments	86	27
Non-current:
Total Gross Fair Value	173
Gross Amounts Offset in Balance Sheet	(65)
Derivative instruments	108
Viper Energy Partners LP | Recurring | Level 1 | Investment
Non-current:
Total Gross Fair Value	5	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 2 | Investment
Non-current:
Total Gross Fair Value	0	0
Viper Energy Partners LP | Recurring | Level 2 | Derivative Instruments
Current:
Total Gross Fair Value	107	64
Non-current:
Total Gross Fair Value	65	7
Current:
Total Gross Fair Value	178	45
Non-current:
Total Gross Fair Value	173
Viper Energy Partners LP | Recurring | Level 3 | Investment
Non-current:
Total Gross Fair Value	0	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

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FAIR VALUE MEASUREMENTS - Nonrecurring Measurements (Details) - USD ($) $ in Millions	Sep. 30, 2020	May 26, 2020	Dec. 31, 2019
4.625% Notes due 2021
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt instrument stated interest rate	4.625%	4.625%
7.320% Medium-term Notes, Series A, due 2022
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt instrument stated interest rate	7.32%
2.875% Senior Notes due 2024
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt instrument stated interest rate	2.875%
4.750% Senior Notes due 2025
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt instrument stated interest rate	4.75%
5.375% Senior Notes due 2025
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt instrument stated interest rate	5.375%
3.250% Senior Notes due 2026
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt instrument stated interest rate	3.25%
7.350% Medium-term Notes, Series A, due 2027
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt instrument stated interest rate	7.35%
7.125% Medium-term Notes, Series B, due 2028
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt instrument stated interest rate	7.125%
3.500% Senior Notes due 2029
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt instrument stated interest rate	3.50%
Viper 5.375% Senior Notes due 2027
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt instrument 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
Debt instrument stated interest rate	5.625%
Reported Value Measurement | Company revolving credit facility | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	$ 0		$ 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	800		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 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	127		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	471		490
Reported Value Measurement | Rattler revolving credit facility | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	85		424
Reported Value Measurement | DrillCo Agreement | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt, fair value	86		39
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	490		0
Estimate of Fair Value Measurement | 4.625% Notes due 2021 | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior notes due	194		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	113		116
Estimate of Fair Value Measurement | DrillCo Agreement | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt, fair value	86		39
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	505		0
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	1,014		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	541		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	830		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	803		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	1,158		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	477		521
Level 2 | Estimate of Fair Value Measurement | Company revolving credit facility | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	0		13
Level 2 | Estimate of Fair Value Measurement | Viper revolving credit facility | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	127		97
Level 2 | Estimate of Fair Value Measurement | Rattler revolving credit facility | Nonrecurring
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	$ 85		$ 424

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LEASES - Summary of Operating Lease Costs (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019
Leases [Abstract]
Operating lease costs	$ 4	$ 7	$ 13	$ 19

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LEASES - Additional Information (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Leases [Abstract]
Statement of consolidated cash flow	$ 13	$ 19
Additional amount of operating lease right of use asset recorded	10	$ 15
Operating right of use asset	13
Operating lease liability current	9
Operating lease liability noncurrent	$ 4
Weighted average remaining lease term	1 year 6 months
Weighted average discount rate	9.20%

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LEASES - Summary of Undiscounted Cash Flows Owed by the Company to Lessors Pursuant to Contractual Agreements (Details) $ in Millions	Sep. 30, 2020 USD ($)
Leases [Abstract]
2020 (October - December)	$ 4
2021	7
2022	3
2023	0
2024	0
Thereafter	0
Total lease payments	14
Less: interest	1
Present value of lease liabilities	$ 13

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SUBSEQUENT EVENTS - Narratives (Details) - USD ($)		3 Months Ended		9 Months Ended
	Oct. 29, 2020	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	May 31, 2019
Subsequent Event [Line Items]
Dividends declared per share (in USD per share)		$ 0.375	$ 0.1875	$ 1.125	$ 0.5625
Stock repurchase program authorized amount						$ 2,000,000,000
Subsequent Event
Subsequent Event [Line Items]
Dividends declared per share (in USD per share)	$ 0.375
Subsequent Event | Common Stock | Rattler LLC
Subsequent Event [Line Items]
Stock repurchase program authorized amount	$ 100,000,000

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SUBSEQUENT EVENTS - Schedule of Derivative Contracts (Details) $ in Millions	1 Months Ended	9 Months Ended
	Nov. 02, 2020 MMBTU $ / MMBTU $ / bbl bbl	Sep. 30, 2020 USD ($) MMBTU $ / bbl $ / MMBTU bbl	Nov. 05, 2020 USD ($)
WTI Cushing | OIL | Costless Collar | 2021
Subsequent Event [Line Items]
Volume (Bbls) | bbl		10,000
Weighted Average Floor Price (USD per Bbl)		30.00
Weighted Average Ceiling Price (USD per Bbl)		43.05
WTI Cushing | OIL | Costless Collar | Subsequent Event | Jan. - Mar.
Subsequent Event [Line Items]
Volume (Bbls) | bbl	3,000
Weighted Average Floor Price (USD per Bbl)	37.00
Weighted Average Ceiling Price (USD per Bbl)	44.19
WTI Cushing | OIL | Costless Collar | Subsequent Event | Mar. - June
Subsequent Event [Line Items]
Volume (Bbls) | bbl	1,000
Weighted Average Floor Price (USD per Bbl)	37.00
Weighted Average Ceiling Price (USD per Bbl)	47.00
Brent | OIL | Costless Collar | 2021
Subsequent Event [Line Items]
Volume (Bbls) | bbl		65,000
Weighted Average Floor Price (USD per Bbl)		39.25
Weighted Average Ceiling Price (USD per Bbl)		48.36
Brent | OIL | Costless Collar | Subsequent Event | 2021
Subsequent Event [Line Items]
Volume (Bbls) | bbl	6,000
Weighted Average Floor Price (USD per Bbl)	37.50
Weighted Average Ceiling Price (USD per Bbl)	45.50
Brent | OIL | Swaps | 2021
Subsequent Event [Line Items]
Volume (Bbls) | bbl		7,500
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon)		41.58
Weighted average differential (per Bbl)		0
Henry Hub | NATURAL GAS | Swaps | 2021
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) | MMBTU		190,000
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | $ / MMBTU		2.62
Weighted average differential (per Bbl)		0
Henry Hub | NATURAL GAS | Swaps | Subsequent Event
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) | MMBTU	10,000
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | $ / MMBTU	3.05
Henry Hub | NATURAL GAS | Basis Swaps | 2021
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) | MMBTU		230,000
Weighted Average Fixed Price (per Bbl/MMBtu/Gallon) | $ / MMBTU		0
Weighted average differential (per Bbl)		(0.69)
Waha Hub | NATURAL GAS | Basis Swaps | Subsequent Event
Subsequent Event [Line Items]
Volume, energy measure (MMBtu) | MMBTU	20,000
Weighted average differential (per Bbl) | $ / MMBTU	(0.31)
Interest Rate Swap One
Subsequent Event [Line Items]
Notional Amount (in millions) | $		$ 250
Interest Rate		1.551%
Interest Rate Swap One | Subsequent Event
Subsequent Event [Line Items]
Notional Amount (in millions) | $			$ 250
Interest Rate			1.692%
Interest Rate Swap Two
Subsequent Event [Line Items]
Notional Amount (in millions) | $		$ 250
Interest Rate		1.5575%
Interest Rate Swap Two | Subsequent Event
Subsequent Event [Line Items]
Notional Amount (in millions) | $			$ 250
Interest Rate			1.8361%
Interest Rate Swap Three
Subsequent Event [Line Items]
Notional Amount (in millions) | $		$ 250
Interest Rate		1.297%
Interest Rate Swap Three | Subsequent Event
Subsequent Event [Line Items]
Notional Amount (in millions) | $			$ 250
Interest Rate			1.852%
Interest Rate Swap One, Terminated | Subsequent Event
Subsequent Event [Line Items]
Notional Amount (in millions) | $			$ 250
Interest Rate			1.551%
Interest Rate Swap Two, Terminated | Subsequent Event
Subsequent Event [Line Items]
Notional Amount (in millions) | $			$ 250
Interest Rate			1.5575%
Interest Rate Swap Three, Terminated | Subsequent Event
Subsequent Event [Line Items]
Notional Amount (in millions) | $			$ 250
Interest Rate			1.297%

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SEGMENT INFORMATION- Additional Information (Details)	9 Months Ended
	Sep. 30, 2020 segment
Segment Reporting [Abstract]
Number of business segments	2

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SEGMENT INFORMATION - Summary of Business Segments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2020	Sep. 30, 2019	Dec. 31, 2019
Segment Reporting Information [Line Items]
Total revenues	$ 720	$ 975	$ 2,044	$ 2,860
Depreciation, depletion and amortization	286	365	1,036	1,046
Impairment of oil and natural gas properties	1,451	0	4,999	0
Income (loss) from operations	(1,256)	349	(4,730)	1,079
Interest expense, net	(53)	(38)	(147)	(133)
Other income (expense)	(100)	179	59	12
Provision for (benefit from) income taxes	(304)	102	(902)	171
Net income (loss) attributable to non-controlling interest	8	20	(138)	60
Net income (loss) attributable to Diamondback Energy, Inc.	(1,113)	368	(3,778)	727
Total assets	18,760		18,760		$ 23,531
Upstream
Segment Reporting Information [Line Items]
Total revenues	706	957	2,002	2,802
Midstream Services
Segment Reporting Information [Line Items]
Total revenues	97	115	315	322
Operating Segments | Upstream
Segment Reporting Information [Line Items]
Total revenues	706	957	2,002	2,802
Depreciation, depletion and amortization	275	353	1,001	1,014
Impairment of oil and natural gas properties	1,451		4,999
Income (loss) from operations	(1,282)	321	(4,787)	1,004
Interest expense, net	(47)	(37)	(137)	(132)
Other income (expense)	(103)	181	73	16
Provision for (benefit from) income taxes	(307)	99	(910)	167
Net income (loss) attributable to non-controlling interest	(1)	20	(163)	60
Net income (loss) attributable to Diamondback Energy, Inc.	(1,124)	346	(3,778)	661
Total assets	17,245		17,245		22,125
Operating Segments | Midstream Services
Segment Reporting Information [Line Items]
Total revenues	14	18	42	58
Depreciation, depletion and amortization	11	12	35	32
Impairment of oil and natural gas properties	0		0
Income (loss) from operations	44	52	134	159
Interest expense, net	(6)	(1)	(10)	(1)
Other income (expense)	4	(1)	(10)	(1)
Provision for (benefit from) income taxes	3	3	8	4
Net income (loss) attributable to non-controlling interest	9	37	25	52
Net income (loss) attributable to Diamondback Energy, Inc.	30	10	81	101
Total assets	1,812		1,812		1,636
Eliminations
Segment Reporting Information [Line Items]
Total revenues	(83)	(97)	(273)	(264)
Depreciation, depletion and amortization	0	0	0	0
Impairment of oil and natural gas properties	0		0
Income (loss) from operations	(18)	(24)	(77)	(84)
Interest expense, net	0	0	0	0
Other income (expense)	(1)	(1)	(4)	(3)
Provision for (benefit from) income taxes	0	0	0	0
Net income (loss) attributable to non-controlling interest	0	(37)	0	(52)
Net income (loss) attributable to Diamondback Energy, Inc.	(19)	$ 12	(81)	$ (35)
Total assets	$ (297)		$ (297)		$ (230)