Diamondback Energy, Inc. - Quarter Report: 2020 September (Form 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


☐			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

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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).

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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

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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.

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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;

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•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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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

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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

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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.

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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

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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.

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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.

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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.

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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”).

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

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Condensed Notes to Consolidated Financial Statements-(Continued)

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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.

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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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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		%

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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.

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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.

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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.

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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.

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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.

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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.

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Condensed Notes to Consolidated Financial Statements-(Continued)

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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.

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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

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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

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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.

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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	%

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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

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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

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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.

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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.

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•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.

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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)