fang-20210630

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 June 30, 2021


☐			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 July 30, 2021, the registrant had 181,053,648 shares of common stock outstanding.

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DIAMONDBACK ENERGY, INC.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2021

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			8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			32

Item 3. Quantitative and Qualitative Disclosures About Market Risk			47

Item 4. Controls and Procedures			48

PART II. OTHER INFORMATION
Item 1. Legal Proceedings			49

Item 1A. Risk Factors			49

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			49

Item 6. Exhibits			50

Signatures			52

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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.

BO			One barrel of crude oil.
BOE			One barrel of 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.











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 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.
MBO/d			One thousand BO per day.
MBOE/d			One thousand BOE per day.
Mcf			One thousand cubic feet of natural gas.

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.
Net revenue interest			An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
			NGLs. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
Oil and natural gas properties			Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.



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).
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.

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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.




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:


2019 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, the second supplemental indenture dated as of May 26, 2020, the third supplemental indenture dated as of March 24, 2021, and the fourth supplemental indenture dated as of June 30, 2021, relating to the December 2019 Notes (defined above), the May 2020 Notes (defined below) and the March 2021 Notes (defined below).
2025 Indenture			The indenture relating to the 2025 Senior Notes (defined below), dated as of December 20, 2016, among the Company, the subsidiary guarantor party thereto and Wells Fargo, as the trustee, as supplemented.
2025 Senior Notes			The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $800 million issued under the 2025 Indenture.
ASC			Accounting Standards Codification.
ASU			Accounting Standards Update.
December 2019 Notes			The Company’s 2.875% senior unsecured notes due 2024 in the aggregate principal amount of $1.0 billion, the Company’s 3.250% senior unsecured notes due 2026 in the aggregate principal amount of $800 million and the Company’s 3.500% senior unsecured notes due 2029 in the aggregate principal amount of $1.2 billion issued under the 2019 Indenture.


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.


LIBOR			The London interbank offered rate.
May 2020 Notes			The Company’s 4.750% Senior Notes due 2025 in the aggregate principal amount of $500.0 million issued under the 2019 Indenture.
March 2021 Notes			The Company’s 0.900% Senior Notes due 2023 in the aggregate principal amount of $650 million, the Company’s 3.125% Senior Notes due 2031 in the aggregate principal amount of $900 million and the Company’s 4.400% Senior Notes due 2051 in the aggregate principal amount of $650 million issued under the 2019 Indenture.
NYMEX			New York Mercantile Exchange.
OPEC			Organization of the Petroleum Exporting Countries.
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.



SEC			United States Securities and Exchange Commission.


Senior Notes			The 2025 Senior Notes, the December 2019 Notes, the May 2020 Notes and the March 2021 Notes.
Viper			Viper Energy Partners LP, a Delaware limited partnership.

Viper LLC			Viper Energy Partners LLC, a Delaware limited liability company and a subsidiary of Viper.



Wells Fargo			Wells Fargo Bank, National Association.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report are “forward-looking statements” as defined by the SEC. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, 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, 2020 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;

•the implications and logistical challenges of epidemic or pandemic diseases, including the COVID-19 pandemic and its impact on the oil and natural gas industry, pricing and demand for oil and natural gas and supply chain logistics;

•logistical challenges and the supply chain disruptions;

•changes in general economic, business or industry conditions, including conditions of the U.S. oil and natural gas industry and the effect of U.S. energy, environmental, monetary and trade policies;

•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 on our industry and business;

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

•regional supply and demand factors, any delays, curtailment delays 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, including our recently completed acquisition of certain assets of Guidon Operating LLC and our merger with QEP Resources, Inc., as well as our anticipated synergies and cost savings from these transactions;

•competition in the oil and natural gas industry;

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

•the impact of severe weather conditions, including the February 2021 winter storms in the Permian Basin, on our production;

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

•our environmental initiatives and targets;

•future operating results;

•future dividends to our stockholders;

•impact of any impairment charges;

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

•capital expenditure plans;

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•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)


	June 30,		December 31,
	2021		2020
	(In millions, except par values and share data)
Assets
Current assets:
Cash and cash equivalents	$	344	$	104
Restricted cash	18		4
Accounts receivable:
Joint interest and other, net	78		56
Oil and natural gas sales, net	579		281

Inventories	52		33

Derivative instruments	13		1
Income tax receivable	33		100
Prepaid expenses and other current assets	25		23
Total current assets	1,142		602
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($8,287 million and $7,493 million excluded from amortization at June 30, 2021 and December 31, 2020, respectively)	32,155		27,377
Midstream assets	1,018		1,013
Other property, equipment and land	160		138
Accumulated depletion, depreciation, amortization and impairment	(12,914)		(12,314)
Property and equipment, net	20,419		16,214
Funds held in escrow	34		51
Equity method investments	518		533
Derivative instruments	5		—
Deferred income taxes, net	28		73
Investment in real estate, net	89		101
Other assets	100		45
Total assets	$	22,335	$	17,619

See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets - (Continued)

(Unaudited)


	June 30,		December 31,
	2021		2020
Liabilities and Stockholders’ Equity	(In millions, except par values and share data)

Current liabilities:
Accounts payable - trade	$	104	$	71

Accrued capital expenditures	236		186
Current maturities of long-term debt	—		191
Other accrued liabilities	455		302
Revenues and royalties payable	404		237
Derivative instruments	773		249


Total current liabilities	1,972		1,236
Long-term debt	7,360		5,624
Derivative instruments	32		57
Asset retirement obligations	185		108
Deferred income taxes	879		783
Other long-term liabilities	17		7
Total liabilities	10,445		7,815
Commitments and contingencies (Note 13)
Stockholders’ equity:
Common stock, $0.01 par value; 400,000,000 shares authorized; 181,049,191 and 158,088,182 shares issued and outstanding at June 30, 2021 and December 31, 2020, respectively	2		2
Additional paid-in capital	14,399		12,656
Retained earnings (accumulated deficit)	(3,475)		(3,864)

Total Diamondback Energy, Inc. stockholders’ equity	10,926		8,794
Non-controlling interest	964		1,010
Total equity	11,890		9,804
Total liabilities and equity	$	22,335	$	17,619

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 June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions, except per share amounts, shares in thousands)
Revenues:
Oil sales	$	1,395	$	352	$	2,339	$	1,179
Natural gas sales	107		21		211		25
Natural gas liquid sales	165		39		289		91

Midstream services	12		11		23		25
Other operating income	2		2		3		4
Total revenues	1,681		425		2,865		1,324
Costs and expenses:
Lease operating expenses	157		103		259		230
Production and ad valorem taxes	105		22		180		93
Gathering and transportation	56		36		87		72
Midstream services expense	23		32		51		55
Depreciation, depletion, amortization and accretion	341		344		614		753
Impairment of oil and natural gas properties	—		2,539		—		3,548

General and administrative expenses	36		20		61		44

Merger and integration expense	2		—		77		—
Other operating expense	6		1		10		3
Total costs and expenses	726		3,097		1,339		4,798
Income (loss) from operations	955		(2,672)		1,526		(3,474)
Other income (expense):

Interest expense, net	(57)		(46)		(113)		(94)
Other income (expense), net	(7)		3		(6)		(6)

Gain (loss) on derivative instruments, net	(497)		(361)		(661)		181

Gain (loss) on sale of equity method investments	23		—		23		—

Loss on extinguishment of debt	—		(3)		(61)		(3)
Income (loss) from equity investments	5		(13)		2		(13)
Total other income (expense), net	(533)		(420)		(816)		65
Income (loss) before income taxes	422		(3,092)		710		(3,409)
Provision for (benefit from) income taxes	94		(681)		159		(598)
Net income (loss)	328		(2,411)		551		(2,811)
Net income (loss) attributable to non-controlling interest	17		(18)		20		(146)
Net income (loss) attributable to Diamondback Energy, Inc.	$	311	$	(2,393)	$	531	$	(2,665)
Earnings (loss) per common share:
Basic	$	1.72	$	(15.16)	$	3.08	$	(16.86)
Diluted	$	1.71	$	(15.16)	$	3.06	$	(16.86)
Weighted average common shares outstanding:
Basic	181,009		157,829		172,636		158,060
Diluted	181,968		157,829		173,518		158,060
Dividends declared per share	$	0.45	$	0.375	$	0.85	$	0.75

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, 2020	158,088	$	2	$	12,656	$	(3,864)	$	1,010	$	9,804
Unit-based compensation	—	—		—		—		3		3
Distribution equivalent rights payments	—	—		—		(1)		—		(1)
Common units issued for acquisitions	22,795	—		1,727		—		—		1,727
Stock-based compensation	—	—		11		—		—		11
Cash paid for tax withholding on vested equity awards	—	—		(6)		—		—		(6)
Repurchased units under buyback programs	—	—		—		—		(24)		(24)
Distributions to non-controlling interest	—	—		—		—		(17)		(17)
Dividend paid	—	—		—		(68)		—		(68)
Exercise of stock options and issuance of restricted stock units and awards	101	—		—		—		—		—
Change in ownership of consolidated subsidiaries, net	—	—		(4)		—		4		—
Net income (loss)	—	—		—		220		3		223
Balance March 31, 2021	180,984	2		14,384		(3,713)		979		11,652
Unit-based compensation	—	—		—		—		3		3
Distribution equivalent rights payments	—	—		—		(1)		(1)		(2)
Stock-based compensation	—	—		15		—		—		15
Cash paid for tax withholding on vested equity awards	—	—		—		—		(2)		(2)
Repurchased units under buyback programs	—	—		—		—		(12)		(12)
Distributions to non-controlling interest	—	—		—		—		(24)		(24)
Dividend paid	—	—		—		(72)		—		(72)
Exercise of stock options and vesting of restricted stock units and awards	65	—		3		—		—		3
Change in ownership of consolidated subsidiaries, net	—	—		(3)		—		4		1
Net income (loss)	—	—		—		311		17		328
Balance June 30, 2021	181,049	$	2	$	14,399	$	(3,475)	$	964	$	11,890

See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity - (Continued)

(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



Cash paid for tax withholding on vested equity awards	—	—		(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	93	—		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 share buyback program	—	—		—		—		(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

See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended June 30,
	2021		2020
	(In millions)
Cash flows from operating activities:
Net income (loss)	$	551	$	(2,811)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes	155		(536)

Impairment of oil and natural gas properties	—		3,548


Depreciation, depletion, amortization and accretion	614		753

Loss on extinguishment of debt	61		3

(Gain) loss on derivative instruments, net	661		(181)
Cash received (paid) on settlement of derivative instruments	(484)		297


Equity-based compensation expense	23		18
(Gain) loss on sale of equity method investments	(23)		—

Other	13		28
Changes in operating assets and liabilities:
Accounts receivable	(172)		229

Income tax receivable	99		(62)

Prepaid expenses and other	18		1
Accounts payable and accrued liabilities	(26)		(50)



Revenues and royalties payable	100		(50)

Other	(12)		(14)
Net cash provided by (used in) operating activities	1,578		1,173
Cash flows from investing activities:
Drilling, completions and non-operated additions to oil and natural gas properties	(623)		(1,178)
Infrastructure additions to oil and natural gas properties	(22)		(80)

Additions to midstream assets	(17)		(94)

Purchase of business and assets, net	(410)		(64)
Acquisitions of mineral interests	(1)		(65)


Proceeds from sale of assets	100		—

Funds held in escrow	51		—
Contributions to equity method investments	(6)		(66)
Distributions from equity method investments	18		18
Proceeds from the sale of equity method investments	23		—


Other	(11)		(6)
Net cash provided by (used in) investing activities	(898)		(1,535)
Cash flows from financing activities:
Proceeds from borrowings under credit facilities	661		652
Repayments under credit facilities	(780)		(390)
Proceeds from senior notes	2,200		497
Repayment of senior notes	(2,107)		(222)
Premium on extinguishment of debt	(166)		—



Proceeds from (repayments to) joint venture	(10)		43








Repurchased shares under buyback program	—		(98)
Repurchased units under buyback program	(36)		—

Dividends to stockholders	(140)		(118)

Distributions to non-controlling interest	(41)		(62)


Financing portion of net cash received (paid) for derivative instruments	59		—
Other	(32)		(9)
Net cash provided by (used in) financing activities	(392)		293
Net increase (decrease) in cash and cash equivalents	288		(69)
Cash, cash equivalents and restricted cash at beginning of period	108		128
Cash, cash equivalents and restricted cash at end of period(1)	$	396	$	59

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Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows - (Continued)

(Unaudited)


	Six Months Ended June 30,
	2021		2020
	(In millions)
Supplemental disclosure of non-cash transactions:
Accrued capital expenditures included in accounts payable and accrued expenses	$	296	$	427

Common stock issued for business combinations	$	1,727	$	—
(1) See Note 2—Summary of Significant Accounting Policies

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 natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas.

The wholly owned subsidiaries of Diamondback, as of June 30, 2021, include Diamondback E&P LLC (Diamondback E&P), 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 QEP Resources, Inc. (“QEP”), a Delaware corporation. Diamondback O&G LLC (“O&G”), Energen Corporation (“Energen”), Energen Resources Corporation and EGN Services, Inc., former wholly owned subsidiaries of Diamondback, were merged with and into Diamondback E&P LLC effective June 30, 2021 as part of the internal restructuring of the Company’s subsidiaries (the “E&P Merger”).

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.

Diamondback’s publicly traded subsidiaries Viper Energy Partners LP (“Viper”) and Rattler Midstream LP (“Rattler”) are consolidated in the Company’s financial statements. As of June 30, 2021, the Company owned approximately 59% 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 June 30, 2021, the Company owned approximately 72% of Rattler’s total units outstanding. The Company’s wholly owned subsidiary, Rattler Midstream GP LLC, is the general partner of Rattler. The results of operations attributable to the non-controlling interest in Viper and Rattler are presented within equity and net income and are shown separately from the Company’s equity and net income attributable to the Company.

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, 2020, which contains a summary of the Company’s significant accounting policies and other disclosures.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.

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 as of the date of the consolidated financial statements. Actual results could differ from those estimates.

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry, given the challenges resulting from volatility in oil and natural gas prices. For instance, in 2020, the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets resulted in significant negative pricing pressures in the first half of 2020, followed by a recovery in pricing and an increase in demand in the second half of 2020 and into 2021. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of changing market conditions. Such circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.

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

Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents and restricted cash as reported at the end of the period in the condensed consolidated statements of cash flows for the six months ended June 30, 2021 and 2020 to the line items within the condensed consolidated balance sheets:


	Six Months Ended June 30,
	2021		2020
	(In millions)
Cash and cash equivalents	$	344	$	51
Restricted cash	18		8
Restricted cash included in funds held in escrow(1)	34		—
Total cash, cash equivalents and restricted cash	$	396	$	59

(1) As of June 30, 2021, the restricted cash included in funds held in escrow on the condensed consolidated balance sheet is related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin.

Recent Accounting Pronouncements

Recently Adopted Pronouncements

In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes." This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company adopted this update effective January 1, 2021. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity.

The Company considers the applicability and impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, the effects of adoption are not expected to be material or clarifications of ASUs previously disclosed.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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 June 30, 2021								Three Months Ended June 30, 2020
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	876	$	408	$	111	$	1,395	$	211	$	141	$	—	$	352
Natural gas sales	75		27		5		107		11		9		1		21
Natural gas liquid sales	102		52		11		165		23		16		—		39

Total	$	1,053	$	487	$	127	$	1,667	$	245	$	166	$	1	$	412


	Six Months Ended June 30, 2021								Six Months Ended June 30, 2020
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	1,445	$	766	$	128	$	2,339	$	682	$	493	$	4	$	1,179
Natural gas sales	116		88		7		211		13		12		—		25
Natural gas liquid sales	177		99		13		289		52		39		—		91

Total	$	1,738	$	953	$	148	$	2,839	$	747	$	544	$	4	$	1,295

4. ACQUISITIONS AND DIVESTITURES

Guidon Operating LLC

On December 21, 2020, the Company entered into a definitive purchase agreement to acquire all leasehold interests and related assets of Guidon Operating LLC (the “Guidon Acquisition”) which include approximately 32,500 net acres in the Northern Midland Basin in exchange for 10.68 million shares of the Company’s common stock and $375 million of cash. The Guidon Acquisition closed on February 26, 2021. The cash portion of this transaction was funded through a combination of cash on hand and borrowings under the Company’s credit facility. As a result of the Guidon Acquisition, the Company added approximately 210 gross producing wells.

The following table presents the acquisition consideration paid in the Guidon Acquisition (in millions, except per share data, shares in thousands):


Consideration:
Shares of Diamondback common stock issued at closing	10,676
Closing price per share of Diamondback common stock on the closing date	$	69.28
Fair value of Diamondback common stock issued	$	740
Cash consideration	375
Total consideration (including fair value of Diamondback common stock issued)	$	1,115

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

Purchase Price Allocation

The Guidon Acquisition has been accounted for as a business combination using the acquisition method. The following table represents the allocation of the total purchase price paid in the Guidon Acquisition to the identifiable assets acquired based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired. Although the purchase price allocation is substantially complete as of the date of this filing, there may be further adjustments to the fair value of certain assets acquired and liabilities assumed, including but not limited to the Company’s oil and natural gas properties. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date and may revise the value of the assets and liabilities as appropriate within that time frame. For the three months ended June 30, 2021, there were no material changes to the allocation presented in the March 31, 2021 10-Q filed with the SEC on May 7, 2021.

The following table sets forth the Company’s preliminary purchase price allocation (in millions):








Total consideration	$	1,115

Fair value of liabilities assumed:
Asset retirement obligations	9

Fair value of assets acquired:
Oil and gas properties	1,110
Midstream assets	14
Amount attributable to assets acquired	1,124
Net assets acquired and liabilities assumed	$	1,115

Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which are then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of acquired midstream assets was based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets.

With the completion of the Guidon Acquisition, the Company acquired proved properties of $537 million and unproved properties of $573 million. The results of operations attributable to the Guidon Acquisition since the acquisition date have been included in the condensed consolidated statements of operations and include $103 million and $133 million of total revenue for the three and six months ended June 30, 2021, respectively, and $49 million and $65 million of net income for the three and six months ended June 30, 2021, respectively.

QEP Resources, Inc.

On March 17, 2021, the Company completed its acquisition of QEP in an all-stock transaction (the “QEP Merger”). The addition of QEP’s assets increased the Company’s net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms of the QEP Merger, each eligible share of QEP common stock issued and outstanding immediately prior to the effective time converted into the right to receive 0.050 of a share of Diamondback common stock, with cash being paid in lieu of any fractional shares (the “merger consideration”). At the closing date of the QEP Merger, the carrying value of QEP’s outstanding debt was approximately $1.6 billion. See Note 7—Debt for further discussion.

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

The following table presents the acquisition consideration paid to QEP stockholders in the QEP Merger (in millions, except per share data, shares in thousands):


Consideration:
Eligible shares of QEP common stock converted into shares of Diamondback common stock	238,153
Shares of QEP equity awards included in precombination consideration	4,221
Total shares of QEP common stock eligible for merger consideration	242,374
Exchange ratio	0.050
Shares of Diamondback common stock issued as merger consideration	12,119
Closing price per share of Diamondback common stock	$	81.41
Total consideration (fair value of the Company's common stock issued)	$	987

Purchase Price Allocation

The QEP Merger has been accounted for as a business combination using the acquisition method. The following table represents the preliminary allocation of the total purchase price for the acquisition of QEP to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired. Although the purchase price allocation is substantially complete as of the date of this filing, certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, final tax returns that provide the underlying tax basis of QEP’s assets and liabilities. As such, there may be further adjustments to the fair value of certain assets acquired and liabilities assumed, including the Company’s oil and natural gas properties. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date. For the three months ended June 30, 2021, there were no material changes to the allocation presented in the March 31, 2021 10-Q filed with the SEC on May 7, 2021.

The following table sets forth the Company’s preliminary purchase price allocation (in millions):



Total consideration	$	987

Fair value of liabilities assumed:
Accounts payable - trade	$	26
Accrued capital expenditures	38
Other accrued liabilities	108
Revenues and royalties payable	67
Derivative instruments	242
Long-term debt	1,710
Asset retirement obligations	54

Other long-term liabilities	47
Amount attributable to liabilities assumed	$	2,292

Fair value of assets acquired:
Cash, cash equivalents and restricted cash	$	22
Accounts receivable - joint interest and other, net	87
Accounts receivable - oil and natural gas sales, net	44
Inventories	18
Income tax receivable	33
Prepaid expenses and other current assets	7
Oil and natural gas properties	2,938
Other property, equipment and land	9
Deferred income taxes	15
Other assets	106
Amount attributable to assets acquired	3,279
Net assets acquired and liabilities assumed	$	987

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

The purchase price allocation above was based on preliminary estimates of the fair values of the assets and liabilities of QEP as of the closing date of the QEP Merger. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs. The fair value of acquired property and equipment, including midstream assets classified in oil and natural gas properties, is based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets. Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which are then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of QEP’s outstanding senior unsecured notes was based on unadjusted quoted prices in an active market, which are considered Level 1 inputs. The value of derivative instruments was based on observable inputs including forward commodity-price curves which are considered Level 2 inputs. Deferred income taxes represent the tax effects of differences in the tax basis and merger-date fair values of assets acquired and liabilities assumed.

With the completion of the QEP Merger, the Company acquired proved properties of $2.3 billion and unproved properties of $444 million, primarily in the Midland Basin and the Williston Basin. The results of operations attributable to the QEP Merger since the acquisition date have been included in the condensed consolidated statements of operations and include $359 million and $413 million of total revenue, and $124 million and $139 million of net income for the three and six months ended June 30, 2021, respectively.

Pro Forma Financial Information

The following unaudited summary pro forma financial information for the three and six months ended June 30, 2021 and 2020 has been prepared to give effect to the QEP Merger and the Guidon Acquisition as if they had occurred on January 1, 2020. The unaudited pro forma financial information does not purport to be indicative of what the combined company’s results of operations would have been if these transactions had occurred on the dates indicated, nor is it indicative of the future financial position or results of operations of the combined company.

The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for QEP’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including adjustments to depreciation, depletion and amortization based on the full cost method of accounting and the purchase price allocated to property, plant, and equipment as well as adjustments to interest expense and the provision for (benefit from) income taxes.

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company for the QEP Merger and the Guidon Acquisition of approximately $2 million and $77 million for the three and six months ended June 30, 2021 and acquisition-related costs incurred by QEP of $31 million through the closing date of the QEP Merger. These acquisition-related costs primarily consist of one-time severance costs and the accelerated or change-in-control vesting of certain QEP share-based awards for former QEP employees based on the terms of the merger agreement relating to the QEP Merger and other bank, legal and advisory fees. The pro forma results of operations do not include any cost savings or other synergies that may result from the QEP Merger and the Guidon Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions, except per share amounts)
Revenues	$	1,656	$	573	$	3,137	$	1,763
Income (loss) from operations	$	1,022	$	(2,714)	$	1,706	$	(3,536)
Net income (loss)	$	388	$	(2,527)	$	534	$	(2,469)
Basic earnings per common share	$	2.14	$	(13.98)	$	2.95	$	(13.66)
Diluted earnings per common share	$	2.13	$	(13.98)	$	2.94	$	(13.66)

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

Divestitures

On May 3, 2021, the Company signed a definitive agreement to divest all of its Williston Basin assets acquired in the QEP Merger, consisting of approximately 95,000 net acres, for a sales price of approximately $745 million, subject to certain closing adjustments. These assets have estimated full year 2021 net production of approximately 15 MBO/d (25 MBOE/d). This transaction is expected to close late in the third quarter of 2021, subject to continued due diligence and closing conditions. The Company intends to use its net proceeds from this transaction for debt reduction.

On June 3, 2021 and June 7, 2021, respectively, the Company closed transactions to divest certain non-core Permian assets including over 7,000 net acres of non-core Southern Midland Basin acreage in Upton county, Texas and approximately 1,300 net acres of non-core, non-operated Delaware Basin assets in Lea county, New Mexico for a combined sales price of $82 million, net of customary purchase price adjustments. These assets have estimated full year 2021 net production of approximately 900 BO/d (2,650 BOE/d) from 140 producing wells. The Company used its net proceeds from these transactions toward debt reduction.

5. PROPERTY AND EQUIPMENT

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


	June 30,		December 31,
	2021		2020
	(In millions)
Oil and natural gas properties:
Subject to depletion	$	23,868	$	19,884
Not subject to depletion	8,287		7,493
Gross oil and natural gas properties	32,155		27,377
Accumulated depletion	(4,811)		(4,237)
Accumulated impairment	(7,954)		(7,954)
Oil and natural gas properties, net	19,390		15,186
Midstream assets	1,018		1,013
Other property, equipment and land	160		138
Accumulated depreciation and impairment	(149)		(123)
Total property and equipment, net	$	20,419	$	16,214

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter which determines a limit, or ceiling, on the book value of proved oil and natural gas properties. No impairment expense was recorded for the three and six months ended June 30, 2021. The Company recorded $2.5 billion and $3.5 billion in impairment expense for the three and six months ended June 30, 2020, respectively, based on the results of the respective quarterly ceiling tests.

In connection with the QEP Merger and the Guidon Acquisition, the Company recorded the oil and natural gas properties acquired at fair value, based on forward strip oil and natural gas pricing existing at the closing date of the respective transactions, in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, the Company determined that the fair value of the properties acquired in the QEP Merger and the Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt. As such, the Company requested and received a waiver from the SEC to exclude the properties acquired from the ceiling test calculation for the quarter ended March 31, 2021. As a result, no impairment expense related to the QEP Merger and the Guidon Acquisition was recorded for the three months ended March 31, 2021. Had the Company not received a waiver from the SEC, an impairment charge of approximately $1.1 billion would have been recorded for such period. Management affirmed there has not been a decline in the fair value of these acquired assets. The properties acquired in the QEP Merger and the Guidon Acquisition had total unamortized costs at March 31, 2021 of $3.0 billion and $1.1 billion, respectively.

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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 future trailing 12-month commodity prices decline as compared to the commodity prices used in prior quarters, the Company may have material write downs in subsequent quarters. 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.

6. ASSET RETIREMENT OBLIGATIONS

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


	Six Months Ended June 30,
	2021		2020
	(In millions)
Asset retirement obligations, beginning of period	$	109	$	94
Additional liabilities incurred	6		7
Liabilities acquired	63		1
Liabilities settled and divested	(4)		—
Accretion expense	5		3
Revisions in estimated liabilities	13		—
Asset retirement obligations, end of period	192		105
Less current portion(1)	7		1
Asset retirement obligations - long-term	$	185	$	104

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

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Condensed Notes to Consolidated Financial Statements - (Continued)

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7. DEBT

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


	June 30,		December 31,
	2021		2020
	(In millions)
4.625% Notes due 2021	$	—	$	191
5.375% Senior Notes due 2022(1)	25		—
7.320% Medium-term Notes, Series A, due 2022	20		20
0.900% Senior Notes due 2023	650		—
5.250% Senior Notes due 2023(1)	10		—
2.875% Senior Notes due 2024	1,000		1,000
4.750% Senior Notes due 2025	500		500
5.375% Senior Notes due 2025	432		800
3.250% Senior Notes due 2026	800		800
5.625% Senior Notes due 2026(1)	18		—

7.125% Medium-term Notes, Series B, due 2028	100		100
3.500% Senior Notes due 2029	1,200		1,200
3.125% Senior Notes due 2031	900		—
4.400% Senior Notes due 2051	650		—
DrillCo Agreement(2)	68		79
Unamortized debt issuance costs	(40)		(29)
Unamortized discount costs	(30)		(27)
Unamortized premium costs	14		15
Fair value of interest rate swap agreements(3)	(4)		—
Revolving credit facility	—		23
Viper revolving credit facility	62		84
Viper 5.375% Senior Notes due 2027	480		480
Rattler revolving credit facility	5		79
Rattler 5.625% Senior Notes due 2025	500		500
Total debt, net	7,360		5,815
Less: current maturities of long-term debt	—		(191)
Total long-term debt	$	7,360	$	5,624

(1) At the effective time of the QEP Merger, QEP became a wholly owned subsidiary of the Company and remained the issuer of the notes.

(2) The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. As of June 30, 2021, the amount due to CEMOF related to this alliance was $68 million.

(3) The Company has two interest rate swap agreements in place on the Company’s $1.2 billion 3.500% fixed rate senior notes due 2029. See Note 11—Derivatives for additional information on the Company’s interest rate swaps designated as fair value hedges.

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

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

Second Amended and Restated Credit Facility

On June 2, 2021, Diamondback Energy, Inc., as parent guarantor, and O&G, as borrower (the “Borrower”), entered into a twelfth amendment (the “Amendment”) to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, with Wells Fargo Bank, National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto (as amended, supplemented or otherwise modified to the date thereof and as further amended by the Amendment. The Amendment, among other things, (i) extended the maturity date to June 2, 2026, which may be further extended by two one-year extensions pursuant to the terms set forth in the credit agreement, (ii) decreased the total revolving loan commitments from $2.0 billion to $1.6 billion, which may be increased in an amount up to $1.0 billion (for a total maximum commitment amount of $2.6 billion) upon election of the Borrower (subject to obtaining additional lender commitments and satisfaction of customary conditions) pursuant to the terms set forth in the credit agreement, (iii) added the ability of the Borrower to incur up to $100 million of the loans under the credit agreement as swingline loans and (iv) changed the interest rate applicable to the loans and certain fees payable under the credit agreement. Outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Borrower that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. After giving effect to the Amendment, (i) the applicable margin ranges from 0.250% to 1.125% per annum in the case of the alternate base rate, and from 1.250% to 2.125% per annum in the case of LIBOR, in each case based on the pricing level, and (ii) the commitment fee ranges from 0.150% to 0.350% per annum on the average daily unused portion of the commitments, based on the pricing level. The pricing level depends on certain ratings agencies’ ratings of the Company’s long-term senior unsecured debt.

On June 30, 2021, Diamondback E&P, as successor borrower, Diamondback Energy, Inc., as parent guarantor, and the Administrative Agent entered into that certain Successor Borrower Joinder Agreement (the “Joinder Agreement”) in connection with the E&P Merger. Pursuant to the Joinder Agreement, Diamondback E&P assumed all obligations (including, without limitation, all of the indebtedness) of O&G as the borrower under the credit agreement, the Second Amended and Restated Guaranty Agreement, dated as of November 20, 2019, made by O&G and Diamondback Energy, Inc., and the other documents entered into connection therewith.

As of June 30, 2021, the maximum credit amount available under the credit agreement was $1.6 billion, with no outstanding borrowings and $1.6 billion available for future borrowings. As of June 30, 2021, there was an aggregate of $3 million in outstanding letters of credit, which reduces available borrowings under the credit agreement on a dollar for dollar basis. During the three and six months ended June 30, 2021 and 2020, the weighted average interest rate on loans under the credit agreement was 1.68%, 1.67%, 2.02% and 2.42%, respectively. The borrowing base is scheduled to be redetermined semi-annually in May and November.

As of June 30, 2021, the Company was in compliance with all financial maintenance covenants under the credit agreement.

March 2021 Notes Offering

On March 24, 2021, Diamondback Energy, Inc. issued $650 million aggregate principal amount of 0.900% Senior Notes due March 24, 2023 (the “2023 Notes”), $900 million aggregate principal amount of 3.125% Senior Notes due March 24, 2031 (the “2031 Notes”) and $650 million aggregate principal amount of 4.400% Senior Notes due March 24, 2051 (the “2051 Notes” and together with the 2023 Notes and the 2031 Notes, the “March 2021 Notes”) and received proceeds, net of $24 million in debt issuance costs and discounts, of $2.18 billion. The net proceeds were primarily used to fund the repurchase of other senior notes outstanding as discussed further below. Interest on the March 2021 Notes is payable semi-annually on March 24 and September 24, beginning on September 24, 2021.

The March 2021 Notes are the Company’s senior unsecured obligations and are fully and unconditionally guaranteed by Diamondback E&P. The March 2021 Notes are senior in right of payment to any of the Company’s future subordinated indebtedness and rank equal in right of payment with all of the Company’s existing and future senior indebtedness. At June 30, 2021, the March 2021 Notes are effectively subordinated to the Company’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 Diamondback E&P.

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The Company may not redeem the 2023 Notes in whole or in part at any time prior to September 24, 2021. The Company may redeem (i) the 2031 Notes in whole or in part at any time prior to December 24, 2030 and (ii) the 2051 Notes in whole or in part at any time prior to September 24, 2050, in each case at the redemption price set forth in the 2019 Indenture. If the March 2021 Notes are redeemed on or after the dates noted above, in each case, the March 2021 Notes may be redeemed at a redemption price equal to 100% of the principal amount of the March 2021 Notes to be redeemed plus interest accrued thereon to but not including the redemption date.

Upon the occurrence of a change of control triggering event as defined in the 2019 Indenture, holders may require the Company to purchase some or all of their March 2021 Notes for cash at a price equal to 101% of the principal amount of the March 2021 Notes being purchased, plus accrued and unpaid interest, if any, to the date of purchase.

Repurchases of Notes

On March 17, 2021, at the time of the QEP Merger discussed in Note 4—Acquisitions, QEP had outstanding debt at fair values consisting of $478 million of 5.375% Senior Notes due 2022 (the “QEP 2022 Notes”), $673 million of 5.250% Senior Notes due 2023 (the “QEP 2023 Notes”) and $558 million of 5.625% Senior Notes due 2026 (the “QEP 2026 Notes” and together with the QEP 2022 Notes and QEP 2023 Notes, the “QEP Notes”).

Subsequent to the QEP Merger, in March 2021, the Company repurchased pursuant to tender offers commenced by the Company, approximately $1.65 billion in fair value carrying amount of the QEP Notes for total cash consideration of $1.7 billion, including redemption and early premium fees of $152 million, which resulted in a loss on extinguishment of debt during the six months ended June 30, 2021 of approximately $47 million. The aggregate fair value of the QEP Notes repurchased consisted of (i) $453 million, or 94.65%, of the outstanding fair value carrying amount of the QEP 2022 Notes, (ii) $663 million, or 98.43%, of the outstanding fair value carrying amount of the QEP 2023 Notes and (iii) $538 million, or 96.35%, of the outstanding fair value carrying amount of the QEP 2026 Notes.

In March 2021, the Company also repurchased an aggregate of $368 million principal amount of its 5.375% 2025 Senior Notes, representing approximately 45.97% of the outstanding 2025 Senior Notes, for total cash consideration of $381 million, including redemption and early premium fees of $13 million, which resulted in a loss on extinguishment of debt during the six months ended June 30, 2021 of $14 million. The Company funded the repurchases of the QEP Notes and 2025 Senior Notes with the proceeds from the March 2021 Notes offering discussed above.

In connection with the tender offers to repurchase the QEP Notes discussed above, the Company also solicited consents from holders of the QEP Notes to amend the indenture for the QEP Notes to, among other things, eliminate substantially all of the restrictive covenants and related provisions and certain events of default contained in the indenture under which the QEP Notes were issued. The Company received the requisite number of consents and, on March 23, 2021, entered into a supplemental indenture relating to the QEP Notes adopting these amendments.

In June 2021, the Company redeemed the remaining $191 million principal amount of the outstanding Energen 4.625% senior notes due on September 1, 2021. The Company recorded an immaterial pre-tax loss on extinguishment of debt related to the redemption, which included the write-off of unamortized debt discounts associated with the redeemed notes.

Energen Notes

In connection with the E&P Merger, Diamondback E&P became the successor issuer under the indenture, dated as of September 1, 1996, pursuant to which Energen issued $100 million aggregate principal amount of 7.125% Medium-Term Notes, Series B due 2028 and $20 million aggregate principal amount of 7.32% Medium-Term Notes, Series A due 2022.

Viper’s Credit Agreement

Viper LLC’s existing credit agreement, as amended by the seventh amendment on June 2, 2021 (the “Viper Amendment”), provides for a revolving credit facility in the maximum credit amount of $2.0 billion with a borrowing base of $580 million based on Viper LLC’s oil and natural gas reserves and other factors. Among other changes, the Viper Amendment added new provisions that allow Viper LLC to elect a commitment amount that is less than its borrowing base as determined by the lenders. As of June 30, 2021, the elected commitment amount was $500 million with $62 million of outstanding borrowings and $438 million available for future borrowings. The borrowing base is scheduled to be redetermined semi-annually in May and November. During the three and six months ended June 30, 2021 and 2020, the weighted average interest rate on

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borrowings under the Viper credit agreement was 1.93%, 1.90%, 2.41% and 2.82%, respectively. The Viper credit agreement will mature on June 2, 2025. As of June 30, 2021, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement.

Rattler’s Credit Agreement

Rattler LLC’s credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1.0 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of June 30, 2021, Rattler LLC had $5 million of outstanding borrowings and $595 million available for future borrowings under the Rattler credit agreement. During the three and six months ended June 30, 2021 and 2020, the weighted average interest rate on borrowings under the Rattler credit agreement was 1.36%, 1.39%, 2.43% and 2.64%, respectively. The revolving credit facility will mature on May 28, 2024. As of June 30, 2021, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

8. CAPITAL STOCK AND EARNINGS PER SHARE

Diamondback did not complete any equity offerings during the six months ended June 30, 2021 and June 30, 2020. As discussed in Note 4—Acquisition s, Diamondback issued 12.12 million shares of the Company’s stock as consideration for the QEP Merger and 10.68 million shares of the Company’s stock as consideration for the Guidon Acquisition during the six months ended June 30, 2021.

Earnings (Loss) Per Share

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	($ in millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common stock	$	311	$	(2,393)	$	531	$	(2,665)
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	181,009		157,829		172,636		158,060
Effect of dilutive securities:
Potential common shares issuable (1)	959		—		882		—
Diluted weighted average common shares outstanding	181,968		157,829		173,518		158,060
Basic net income (loss) attributable to common stock	$	1.72	$	(15.16)	$	3.08	$	(16.86)
Diluted net income (loss) attributable to common stock	$	1.71	$	(15.16)	$	3.06	$	(16.86)

(1) For the three and six months ended June 30, 2021, there were 80,329 and 105,577 potential common units, respectively, excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive under the treasury stock method. For the three and six months ended June 30, 2020, no potential common units were included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive.

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Change in Ownership of Consolidated Subsidiaries

Non-controlling interests in the accompanying condensed consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur. The following table summarizes changes in the ownership interest in consolidated subsidiaries during the periods presented:



	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Net income (loss) attributable to the Company	$	311	$	(2,393)	$	531	$	(2,665)
Change in ownership of consolidated subsidiaries	(3)		329		(7)		329
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest	$	308	$	(2,064)	$	524	$	(2,336)

9. EQUITY-BASED COMPENSATION

On June 3, 2021, the Company’s stockholders approved and adopted the Company’s 2021 amended and restated equity incentive plan (the “Equity Plan”), which, among other things, increased total shares authorized for issuance from 8.3 million to 11.8 million. At June 30, 2021, the Company had 4.9 million shares of common stock available for future grants.

Under the Equity Plan, approved by the Board of Directors, the Company is authorized to issue incentive and non-statutory stock options, restricted stock awards and restricted stock units, performance awards and stock appreciation rights to eligible employees. At June 30, 2021, the Company had outstanding restricted stock units, performance-based restricted stock units, immaterial amounts of restricted share awards and restricted stock units which were assumed in connection with the QEP Merger and immaterial amounts of stock options and stock appreciation rights. The Company classifies these as equity-based awards and estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The Company values its stock options using a Black-Scholes option valuation model.

In addition to the Equity Plan, Viper and Rattler maintain their own long-term incentive plans which are not significant to the Company.

The following table presents the financial statement impacts of the equity compensation plans and related costs:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
General and administrative expenses	$	13	$	9	$	23	$	18
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$	5	$	2	$	9	$	8

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Restricted Stock Units

The following table presents the Company’s restricted stock unit activity during the six months ended June 30, 2021 under the Equity Plan and the QEP equity incentive plan assumed by the Company in the QEP Merger:


	Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2020	1,113,480	$	48.58
Granted(1)	655,634	$	80.06
Vested	(322,524)	$	77.07
Forfeited	(53,005)	$	49.48
Unvested at June 30, 2021	1,393,585	$	56.76

(1) Includes 164,088 replacement restricted stock unit awards granted in connection with the QEP Merger, the majority of which vested upon closing of the QEP Merger. For additional information regarding the QEP Merger, see Note 4—Acquisitions.

The aggregate fair value of restricted stock units that vested during the six months ended June 30, 2021 and 2020 was $25 million and $9 million, respectively. As of June 30, 2021, the Company’s unrecognized compensation cost related to unvested restricted stock units was $63 million, which is expected to be recognized over a weighted-average period of 2.3 years.

Performance Based Restricted Stock Units

The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the six months ended June 30, 2021:


	Performance Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2020	411,587	$	99.10
Granted	198,454	$	131.06


Unvested at June 30, 2021(1)	610,041	$	109.49

(1)A maximum of 1,431,833 units could be awarded based upon the Company’s final TSR ranking.

As of June 30, 2021, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $38 million, which is expected to be recognized over a weighted-average period of 1.9 years.

In March 2021, eligible employees received performance restricted stock unit awards totaling 198,454 units from which a minimum of 0% and a maximum of 200% of the units could be awarded based upon the measurement of total stockholder return of the Company’s common stock as compared to a designated peer group during the three-year performance period of January 1, 2021 to December 31, 2023 and cliff vest at December 31, 2023 subject to continued employment. The initial payout of the March 2021 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 issuance 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.

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The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions for the awards granted during the period presented:


	2021
Grant-date fair value	$	131.06

Risk-free rate	0.15		%
Company volatility	69.60		%

10. INCOME TAXES

The Company’s effective income tax rates were 22.3% and 22.0% for the three months ended June 30, 2021 and 2020, respectively, and 22.4% and 17.5% for the six months ended June 30, 2021 and 2020, respectively. Total income tax expense from continuing operations for the three and six months ended June 30, 2021 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income primarily due to (i) state income taxes, net of federal benefit, and (ii) the impact of permanent differences between book and taxable income, partially offset by (iii) tax benefit resulting from a reduction in the valuation allowance on Viper’s deferred tax assets due to pre-tax income for the period.

For the six months ended June 30, 2021, the Company’s items of discrete income tax expense or benefit were not material.

On March 17, 2021, the Company completed its acquisition of QEP. For federal income tax purposes, the transaction qualified as a nontaxable merger whereby the Company acquired carryover tax basis in QEP’s assets and liabilities. The Company recorded an opening balance sheet net deferred tax asset of $15 million, primarily consisting of deferred tax assets related to tax attributes acquired from QEP, partially offset by a valuation allowance, and deferred tax liabilities resulting from the excess of financial reporting carrying value over tax basis of oil and natural gas properties and other assets acquired from QEP. The acquired income tax attributes, including federal net operating loss and credit carryforwards, are subject to an annual limitation under Internal Revenue Code Section 382. The Company has considered the positive and negative evidence regarding realizability of these federal tax attributes including taxable income in prior carryback years, the annual limitation imposed by Section 382, and the anticipated timing of reversal of its deferred tax liabilities, resulting in a valuation allowance on the portion of QEP’s federal tax attributes estimated not more likely than not to be realized prior to expiration. In addition, acquired tax attributes include state net operating loss carryforwards for which a valuation allowance has been provided, since the Company does not believe the state net operating losses are more likely than not to be realized based on its assessment of anticipated future operations in those states.

Total income tax expense from continuing operations for the three and six months ended June 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 resulting from the carryback of federal net operating losses.

For the six months ended June 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 consisted primarily of its investment in Viper LLC and federal net operating loss carryforwards. As of June 30, 2021 and 2020, Viper maintained a valuation allowance against its deferred tax assets, based on its assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets. In addition, for the six months ended June 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%.

The Company considered the impact of the American Rescue Plan, enacted on March 11, 2021, and concluded its provisions related to U.S. income taxes for corporations did not materially affect the Company’s current or deferred tax balances. The Company also considered the impact of the CARES Act, enacted March 27, 2020, in the period of enactment, resulting in a net discrete income tax benefit of $25 million for the three months ended March 31, 2020 related to the 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 received a refund of federal taxes in the first quarter of 2021 of approximately $100 million. In addition, the Company’s current and long-term income taxes receivable at June 30, 2021 of approximately $33 million and $31 million, respectively, relate to anticipated refunds of minimum tax credits resulting from available carryback of certain federal net operating losses acquired from QEP.

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11. DERIVATIVES

At June 30, 2021, the Company has commodity derivative contracts and receive-fixed, pay-variable interest rate hedges outstanding. All derivative financial instruments are recorded at fair value.

Commodity Contracts

The Company has entered into multiple crude oil, natural gas and natural gas liquids 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. The Company has not designated its commodity derivative instruments as hedges for accounting purposes and, as a result, marks its commodity 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.”

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

The Company has multiple commodity derivative contracts that contain an other-than-insignificant financing element at inception and, therefore, the cash receipts were classified as cash flows from financing activities in the condensed consolidated statements of cash flow for the three and six months ended June 30, 2021.

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As of June 30, 2021, the Company had the following outstanding commodity derivative contracts. 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
July - Sep.	2021	Swap	38,348	WTI	$—	$42.82	$—	$—
Oct. - Dec.	2021	Swap	30,674	WTI	$—	$42.36	$—	$—
July - Dec.	2021	Swap	5,000	Argus WTI Houston	$—	$37.78	$—	$—
July - Dec.	2021	Swap	5,000	Brent	$—	$41.62	$—	$—
July - Dec.	2021	Basis Swap(1)	34,000	Argus WTI Midland	$0.91	$—	$—	$—
July - Sep.	2021	Roll Swap(2)(3)	57,261	WTI	$0.50	$—	$—	$—
Oct. - Dec.	2021	Roll Swap(2)(3)	64,000	WTI	$0.56	$—	$—	$—
July - Sep.	2021	Costless Collar	17,685	WTI	$—	$—	$35.27	$46.50
July - Sep.	2021	Costless Collar	67,000	Brent	$—	$—	$40.39	$49.28
July - Sep.	2021	Costless Collar	5,000	Argus WTI Houston	$—	$—	$45.00	$57.90
Oct. - Dec.	2021	Costless Collar	5,000	Argus WTI Houston	$—	$—	$45.00	$78.75
Oct. - Dec.	2021	Costless Collar	26,663	WTI	$—	$—	$38.69	$53.80
Oct. - Dec.	2021	Costless Collar	69,000	Brent	$—	$—	$40.52	$49.71
Jan. - June	2022	Swap	1,000	WTI	$—	$45.00	$—	$—
Jan. - Dec.	2022	Basis Swap(1)	10,000	Argus WTI Midland	$0.84	$—	$—	$—
Jan. - Dec.	2022	Roll Swap(2)	20,000	WTI	$0.54	$—	$—	$—
Jan. - Mar.	2022	Costless Collar	16,500	WTI	$—	$—	$45.61	$71.34
Jan. - Mar.	2022	Costless Collar	53,000	Brent	$—	$—	$45.38	$70.61
Jan. - Mar.	2022	Costless Collar	22,000	Argus WTI Houston	$—	$—	$45.91	$70.95
Apr. - June	2022	Costless Collar	8,000	WTI	$—	$—	$46.25	$71.84
Apr. - June	2022	Costless Collar	30,000	Brent	$—	$—	$46.00	$76.37
Apr. - June	2022	Costless Collar	20,000	Argus WTI Houston	$—	$—	$46.00	$71.29
July - Sep.	2022	Costless Collar	7,000	Brent	$—	$—	$46.43	$78.16
Oct. - Dec.	2022	Costless Collar	5,000	Brent	$—	$—	$45.00	$75.56
NATURAL GAS
July - Dec.	2021	Swap	245,000	Henry Hub	$—	$2.65	$—	$—
July - Dec.	2021	Swap	50,000	Waha Hub	$—	$1.92	$—	$—
July - Dec.	2021	Basis Swap(1)	250,000	Waha Hub	$(0.66)	$—	$—	$—
Jan. - Dec.	2022	Basis Swap(1)	210,000	Waha Hub	$(0.34)	$—	$—	$—
Jan. - June	2022	Costless Collar	160,000	Henry Hub	$—	$—	$2.50	$3.93
July - Dec.	2022	Costless Collar	60,000	Henry Hub	$—	$—	$2.50	$4.51
NATURAL GAS LIQUIDS
July - Dec.	2021	Swap	2,000	Mont Belvieu Propane	$—	$29.40	$—	$—

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

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(2) The Company has rolling hedge basis swaps for the differential in 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.

(3) Includes a rolling hedge basis swap contract for the differential between the NYMEX prices for WTI Cushing and WTI CMA calendar month average of each basis for a notional quantity of 4,000 barrels per day with a weighted average differential of $0.00.

Settlement Month

Settlement Year

Type of Contract

Bbls/Mcf Per Day

Index

Strike Price

OIL

Jan. - Mar.

2022

Puts(1)

5,000

WTI

$47.52

(1)Includes immaterial deferred premiums.

Interest Rate Swaps

In the second quarter of 2021, the Company entered into two interest rate swap agreements for notional amounts of $600 million each to limit the Company’s exposure to changes in the fair value of debt due to movements in LIBOR interest rates. These interest rate swaps have been designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 (the “2029 Notes”) whereby the Company will receive the fixed rate of interest and will pay an average variable rate of interest based on three month LIBOR plus 2.1865%. Gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt, and were not material for the three and six months ended June 30, 2021. These interest rate swaps are assumed to be perfectly effective and were determined to qualify for the “shortcut” method of accounting. The swaps expire on December 1, 2029, with an alternative early termination date of September 1, 2029, which mirrors the call option in the 2029 Notes.

During 2020 and the first quarter of 2021, the Company used interest rate swaps to reduce its exposure to variable rate interest payments associated with the Company’s revolving credit facility. These interest rate swaps were not designated as hedging instruments and as a result, the Company recognized all changes in fair value immediately in earnings. During the first quarter of 2021, the Company terminated all of its previously outstanding interest rate swaps which resulted in cash received upon settlement of $80 million, net of fees, during the six months ended June 30, 2021. The interest swaps contained an other-than-insignificant financing element at inception, and therefore, the cash receipts were classified as cash flows from financing activities in the condensed consolidated statements of cash flow for the six months ended June 30, 2021.

Balance Sheet Offsetting of Derivative Assets and Liabilities

The fair value of derivative instruments 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 12—Fair Value Measurements for further details.

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Gains and Losses on Derivative Instruments

The following table summarizes the gains and losses on derivative instruments not designated as hedging instruments included in the condensed consolidated statements of operations:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Gain (loss) on derivative instruments, net
Commodity contracts	$	(497)	$	(353)	$	(791)	$	251
Interest rate swaps	—		(8)		130		(70)
Total	$	(497)	$	(361)	$	(661)	$	181

Net cash received (paid) on settlements
Commodity contracts	$	(323)	$	210	$	(505)	$	297
Interest rate swaps(1)	—		—		80		—
Total	$	(323)	$	210	$	(425)	$	297

(1)The six months ended June 30, 2021 include cash received on contracts terminated prior to their contractual maturity of $80 million.

12. 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.

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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 Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s commodity derivative instruments and interest rate swaps. The fair values of the Company’s commodity 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. Interest rate swaps designated as fair value hedges and those that are not designated as hedges are determined based on inputs that are readily available in public markets, can be derived from information available in publicly quoted markets, or are provided by financial institutions that trade these contracts. These valuations are Level 2 inputs.

The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s condensed consolidated balance sheets as of June 30, 2021 and December 31, 2020. The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates.


	As of June 30, 2021
	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	$	—	$	34	$	—	$	34	$	(34)	$	—
Interest rate swaps designated as hedges	$	—	$	13	$	—	$	13	$	—	$	13
Non-current:

Derivative instruments	$	—	$	14	$	—	$	14	$	(9)	$	5
Interest rate swaps designated as hedges	$	—	$	13	$	—	$	13	$	(13)	$	—
Liabilities:
Current:
Derivative instruments	$	—	$	807	$	—	$	807	$	(34)	$	773

Non-current:
Derivative instruments	$	—	$	24	$	—	$	24	$	(9)	$	15
Interest rate swaps designated as hedges	$	—	$	30	$	—	$	30	$	(13)	$	17

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)


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

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

Non-current:

Derivative instruments	$	—	$	187	$	—	$	187	$	(187)	$	—

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

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

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:


	June 30, 2021				December 31, 2020
	Carrying				Carrying
	Value		Fair Value		Value		Fair Value
	(In millions)
Debt	$	7,360	$	7,888	$	5,815	$	6,213

The fair values of the Company’s credit agreement, 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 June 30, 2021 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, funds held in escrow, prepaid expenses and other current assets, payables and other accrued liabilities approximate their fair value because of the short-term nature of the instruments.

13. COMMITMENTS AND CONTINGENCIES

The Company is a party to various routine legal proceedings, disputes and claims arising in the course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Company, cannot be predicted with certainty, the Company’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

The Company acquired certain contractual obligations in conjunction with the QEP Merger including an aggregate of approximately $68 million in various transportation, gathering and purchase commitments.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

14. SUBSEQUENT EVENTS

Second Quarter 2021 Dividend Declaration

On July 29, 2021, the Board of Directors of the Company declared a cash dividend for the second quarter of 2021 of $0.45 per share of common stock, payable on August 19, 2021 to its stockholders of record at the close of business on August 12, 2021.

Pending Full Redemption of the Outstanding 5.375% Senior Notes due 2025

On July 23, 2021, the Company elected to effect an optional redemption of all of the Company’s 5.375% Senior Notes due 2025 outstanding as of the Redemption Date (defined below) in the aggregate principal amount of $432 million (the “2025 Notes”) and gave notice to the holders of the 2025 Notes of such redemption.

The 2025 Notes are called for redemption on August 24, 2021 (the “Redemption Date”), at a redemption price equal to 102.688% of the principal amount on the Redemption Date, plus accrued interest to the Redemption Date (the “Redemption Price”). Interest on the 2025 Notes will cease to accrue on and after the Redemption Date unless the Company defaults in making the redemption payment, and thereupon the only remaining right of holders of the 2025 Notes is to receive payment of the Redemption Price. The Company intends to fund the redemption with cash on hand and borrowings under its revolving credit facility.

15. SEGMENT INFORMATION

The Company reports its operations in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which is focused on owning, operating, developing and acquiring midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. All of the Company’s equity method investments are included in the midstream operations segment.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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


	Upstream		Midstream Operations		Eliminations		Total
Three Months Ended June 30, 2021:	(In millions)
Third-party revenues	$	1,669	$	12	$	—	$	1,681
Intersegment revenues	—		99		(99)		—
Total revenues	1,669		111		(99)		1,681

Depreciation, depletion, amortization and accretion	325		16		—		341


Income (loss) from operations	927		39		(11)		955
Interest expense, net	(48)		(9)		—		(57)
Other income (expense)	(502)		28		(2)		(476)
Provision for (benefit from) income taxes	91		3		—		94
Net income (loss) attributable to non-controlling interest	5		12		—		17
Net income (loss) attributable to Diamondback Energy, Inc.	281		43		(13)		311
As of June 30, 2021:
Total assets	$	20,947	$	1,740	$	(352)	$	22,335


	Upstream		Midstream Operations		Eliminations		Total
Three Months Ended June 30, 2020:	(In millions)
Third-party revenues	$	412	$	13	$	—	$	425
Intersegment revenues	—		77		(77)		—
Total revenues	412		90		(77)		425

Depreciation, depletion, amortization and accretion	332		12		—		344
Impairment of oil and natural gas properties	2,539		—		—		2,539

Income (loss) from operations	(2,642)		29		(59)		(2,672)
Interest expense, net	(44)		(2)		—		(46)
Other income (expense)	(358)		(13)		(3)		(374)
Provision for (benefit from) income taxes	(682)		1		—		(681)
Net income (loss) attributable to non-controlling interest	(18)		10		(10)		(18)
Net income (loss) attributable to Diamondback Energy, Inc.	(2,344)		3		(52)		(2,393)
As of December 31, 2020:
Total assets	$	16,128	$	1,809	$	(318)	$	17,619

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)


	Upstream		Midstream Operations		Eliminations		Total
Six Months Ended June 30, 2021:	(In millions)
Third-party revenues	$	2,841	$	24	$	—	$	2,865
Intersegment revenues	—		186		(186)		—
Total revenues	2,841		210		(186)		2,865

Depreciation, depletion, amortization and accretion	587		27		—		614

Impairment of midstream assets	—		3		—		3
Income (loss) from operations	1,479		77		(30)		1,526
Interest expense, net	(97)		(16)		—		(113)
Other income (expense)	(724)		25		(4)		(703)
Provision for (benefit from) income taxes	154		5		—		159
Net income (loss) attributable to non-controlling interest	2		18		—		20
Net income (loss) attributable to Diamondback Energy, Inc.	502		63		(34)		531
As of June 30, 2021:
Total assets	$	20,947	$	1,740	$	(352)	$	22,335


	Upstream		Midstream Operations		Eliminations		Total
Six Months Ended June 30, 2020:	(In millions)
Third-party revenues	$	1,295	$	29	$	—	$	1,324
Intersegment revenues	—		189		(189)		—
Total revenues	1,295		218		(189)		1,324

Depreciation, depletion, amortization and accretion	728		25		—		753
Impairment of oil and natural gas properties	3,548		—		—		3,548
Income (loss) from operations	(3,424)		90		(140)		(3,474)
Interest expense, net	(89)		(5)		—		(94)
Other income (expense)	177		(13)		(5)		159
Provision for (benefit from) income taxes	(603)		5		—		(598)
Net income (loss) attributable to non-controlling interest	(146)		51		(51)		(146)
Net income (loss) attributable to Diamondback Energy, Inc.	(2,587)		16		(94)		(2,665)
As of December 31, 2020:
Total assets	$	16,128	$	1,809	$	(318)	$	17,619

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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, 2020. 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 operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) through our subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.

Recent Developments

First Quarter 2021 Acquisitions

On February 26, 2021, we completed the Guidon Acquisition, which included approximately 32,500 net acres in the Northern Midland Basin, in exchange for 10.68 million shares of the Company’s common stock and $375 million of cash.

On March 17, 2021, we completed the acquisition of QEP pursuant to the Agreement and Plan of Merger, dated as of December 20, 2020, by and among Diamondback, Bohemia Merger Sub, Inc., a Delaware corporation and QEP. Pursuant to the merger agreement, at the effective time of the QEP Merger, Bohemia Merger Sub, Inc. merged with and into QEP, with QEP continuing as the surviving corporation and as a wholly owned subsidiary of Diamondback. The addition of QEP’s assets increased our net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms of the merger agreement, we issued approximately 12.12 million shares of our common stock (valued at a price of $81.41 per share on the closing date) to the former QEP stockholders, with a total value of approximately $987 million.

See Note 4—Acquisitions and Divestitures for additional discussion of the Guidon Acquisition and the QEP Merger.

Recent and Pending Divestitures

On May 3, 2021, we signed a definitive agreement to divest all of our Williston Basin assets acquired in the QEP Merger, consisting of approximately 95,000 net acres, for a sales price of approximately $745 million, subject to certain closing adjustments. This transaction is expected to close late in the third quarter of 2021, subject to continued due diligence and closing conditions. We intend to use our net proceeds from this transaction toward debt reduction.

On June 3, 2021 and June 7, 2021, respectively, we closed transactions to divest certain non-core Permian assets, including over 7,000 net acres of non-core Southern Midland Basin acreage in Upton county and approximately 1,300 net acres of non-core, non-operated Delaware Basin assets in Lea county, New Mexico, for a combined sales price of $82 million, net of customary purchase price adjustments. We used our net proceeds from these transactions toward debt reduction.

March 2021 Notes Offering and Repurchase of Notes

On March 24, 2021, we completed an offering of our March 2021 Notes resulting in aggregate net proceeds of $2.18 billion. The net proceeds were primarily used to fund the repurchase of $1.65 billion in fair value carrying amount of the QEP Notes that remained outstanding at the effective time of the QEP Merger for total cash consideration of $1.7 billion, and $368 million principal amount of 2025 Senior Notes, for total cash consideration of $381 million. These refinancing transactions are expected to result in an estimated annual interest cost savings of approximately $40 million in addition to an estimated $60 million to $80 million of previously announced expected annual cost synergies from the QEP Merger.

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Redemption of the Energen 4.625% Senior Notes

In June 2021, we redeemed the remaining $191 million principal amount of the outstanding Energen 4.625% senior notes due on September 1, 2021. We recorded an immaterial pre-tax loss on extinguishment of debt related to the redemption, which included the write-off of unamortized debt discounts associated with the repurchased notes.

Pending Full Redemption of the Outstanding 5.375% Senior Notes due 2025

On July 23, 2021, we elected to effect an optional redemption of all of our 2025 Notes outstanding as of August 24, 2021 in the aggregate principal amount of $432 million, at a redemption price equal to 102.688% of the principal amount plus accrued interest. We intend to fund the redemption with cash on hand and borrowings under our revolving credit facility.

Amendment and Joinder to the Second Amended and Restated Credit Facility

On June 2, 2021, we entered into an amendment to the credit agreement, which among other things (i) extended the maturity date to June 2, 2026, (ii) decreased the total revolving loan commitments from $2.0 billion to $1.6 billion, which amount may be increased in an amount up to $1.0 billion (for a total maximum commitment amount of $2.6 billion), (iii) added the ability to incur up to $100 million of the loans under the credit agreement as swingline loans and (iv) changed the interest rate applicable to the loans and certain fees payable under the credit agreement.

For additional discussion of our 2021 debt transactions and the amendment to the second amended and restated credit facility, see Note 7—Debt and Note 14—Subsequent Events—Pending Full Redemption of the Outstanding 5.375% Senior Notes due 2025.

COVID-19 and Commodity Prices

In early March 2020, oil prices dropped sharply and continued to decline, briefly reaching negative levels as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken by OPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the ongoing COVID-19 pandemic. However, certain restrictions on conducting business that were implemented in response to the COVID-19 pandemic have been lifted as improved treatments and vaccinations for COVID-19 have been rolled-out globally since late 2020. As a result, oil and natural gas market prices have improved in response to the increase in demand.

During 2020 and 2021, the posted NYMEX WTI price for crude oil ranged from $(37.63) to $75.25 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.48 to $3.75 per MMBtu. On July 16, 2021, the NYMEX WTI price for crude oil was $71.81 per Bbl and the NYMEX Henry Hub price of natural gas was $3.67 per MMBtu. Commodity prices have historically been volatile and we cannot predict events which may lead to future fluctuations in these prices.

In addition to the volatility in commodity prices and the impact of the COVID-19 pandemic on our business and industry, our results of operations may be 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.

As a result of the reduction in crude oil demand caused by factors discussed above, in 2020, we lowered our 2020 capital budgets and production guidance. We have since restored curtailed production in the second half of 2020 to stem production declines and respond to improved demand and increasing commodity prices, but have elected to keep production relatively flat during the first six months of 2021, focusing on cost control and using excess cash flow for debt payment and return of capital to our stockholders. We expect to continue to exercise capital discipline and maintain flat oil production for the foreseeable future. If this maintenance plan continues into 2022, we expect to be able to hold fourth quarter 2021 Permian oil production flat with 10% to 15% more capital than our current 2021 plan, demonstrating our improved capital efficiency that incorporates a full year of capital expenditures on the assets we acquired in the first quarter of 2021 in the QEP Merger and the Guidon Acquisition. We expect to be in a position to continue to increase our return of capital to stockholders and, beginning in 2022, plan to return 50% of our free cash flow to our stockholders. The form of such capital return will be decided by our board of directors at the appropriate time, based on its assessment of which opportunities present the best return to our stockholders at that time.

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Second Quarter 2021 Operating Highlights

•We recorded net income of $311 million for the second quarter ended June 30, 2021.

•Our average production was 401.5 MBOE/d during the second quarter of 2021 which includes a full quarter of production from our Guidon Acquisition and QEP Merger.

•During the second quarter of 2021, we drilled 47 gross horizontal wells in the Midland Basin and nine gross horizontal wells in the Delaware Basin.

•We turned 65 gross operated horizontal wells (47 in the Midland Basin and 14 in the Delaware Basin) to production and had capital expenditures, excluding acquisitions, of $366 million during the second quarter of 2021.

•The average lateral length for the wells completed during the second quarter of 2021 was 11,137 feet.

•Our cash operating costs for the second quarter ended June 30, 2021 were $9.33 per BOE, including lease operating expenses of $4.30 per BOE, cash general and administrative expenses of $0.63 per BOE and production and ad valorem taxes and gathering and transportation expenses of $4.40 per BOE.

•On July 29, 2021, our board of directors declared a cash dividend for the second quarter of 2021 of $0.45 per share of common stock, payable on August 19, 2021 to our stockholders of record at the close of business of August 12, 2021.

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 within the Permian 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. Additionally, our publicly-traded subsidiary, Viper, is focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin and derives royalty income and lease bonus income from such interests.

As of June 30, 2021, we had approximately 542,242 net acres, which primarily consisted of approximately 264,777 net acres in the Midland Basin and 149,309 net acres in the Delaware Basin. As discussed above, during the second quarter of 2021, we closed transactions to divest over 7,000 net acres of non-core Southern Midland Basin acreage in Upton county and approximately 1,300 net acres of non-core, non-operated Delaware Basin assets in Lea county, New Mexico for an aggregate sales price of $82 million, net of customary purchase price adjustments. Additionally, we entered into a definitive agreement to divest all of our Williston Basin net acres for $745 million, subjected to certain closing adjustments. This transaction is expected to close late in the third quarter of 2021, subject to continued due diligence and closing conditions.

The following table sets forth the total number of operated horizontal wells drilled and completed during the three and six months ended June 30, 2021:


	Three Months Ended June 30, 2021				Six Months Ended June 30, 2021
	Drilled		Completed(1)		Drilled		Completed(2)
Area	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Midland Basin	47	43	47	44	88	83	89	81
Delaware Basin	9	9	14	14	17	16	39	37
Other	—	—	4	3	—	—	4	3
Total	56	52	65	61	105	99	132	121

(1)The average lateral length for the wells completed during the second quarter of 2021 was 11,137 feet. Operated completions during the second quarter of 2021 consisted of 19 Lower Spraberry wells, ten Wolfcamp A wells, nine Middle Spraberry wells, eight Jo Mill wells, six Wolfcamp B wells, five Third Bone Springs wells, two Second Bone Springs wells, two Dean wells, two Bakken wells and two Three Forks wells.

(2)The average lateral length for the wells completed during the first six months of 2021 was 10,729 feet. Operated completions during the first six months of 2021 consisted of 38 Wolfcamp A wells, 29 Lower Spraberry wells, 15 Middle Spraberry wells, 13 Wolfcamp B wells, 13 Jo Mill wells, eight Second Bone Springs wells, eight Third Bone Springs wells, three Dean wells, two Bakken wells, two Three Forks wells and one Barnett well.

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As of June 30, 2021, we operated the following wells:


	As of June 30, 2021
	Vertical Wells		Horizontal Wells		Total
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	2,313	2,126	1,721	1,588	4,034	3,714
Delaware Basin	27	24	626	588	653	612
Other	—	—	402	347	402	347
Total	2,340	2,150	2,749	2,523	5,089	4,673

As of June 30, 2021, we held interests in 10,936 gross (4,816 net) wells, including wells that we do not operate. During the first quarter of 2021, we acquired interests in 1,671 gross (1,240 net) wells as part of the QEP Merger.

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 consist 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 gathering and disposal system spans approximately 519 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.

The midstream operations segment’s revenues and operating expenses were not significant to our condensed consolidated statements of operations for the three and six months ended June 30, 2021 and 2020. See Note 15—Segment Information for further details regarding acquisitions

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Results of Operations

The following table sets forth selected operating data for the three and six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Revenues (In millions):
Oil sales	$	1,395	$	352	$	2,339	$	1,179
Natural gas sales	107		21		211		25
Natural gas liquid sales	165		39		289		91
Total oil, natural gas and natural gas liquid revenues	$	1,667	$	412	$	2,839	$	1,295

Production Data:
Oil (MBbls)	22,067		16,045		38,645		34,370
Natural gas (MMcf)	44,506		31,857		78,615		63,977
Natural gas liquids (MBbls)	7,047		5,411		12,452		10,949
Combined volumes (MBOE)(1)	36,532		26,765		64,200		55,982

Daily oil volumes (BO/d)(2)	242,495		176,323		213,508		188,846
Daily combined volumes (BOE/d)(2)	401,451		294,126		354,696		307,592

Average Prices:
Oil ($ per Bbl)	$	63.22	$	21.99	$	60.53	$	34.31
Natural gas ($ per Mcf)	$	2.40	$	0.63	$	2.68	$	0.39
Natural gas liquids ($ per Bbl)	$	23.41	$	7.17	$	23.21	$	8.33
Combined ($ per BOE)	$	45.63	$	15.39	$	44.22	$	23.13

Oil, hedged ($ per Bbl)(3)	$	49.85	$	35.21	$	48.54	$	42.73
Natural gas, hedged ($ per MMBtu)(3)	$	1.82	$	0.33	$	2.18	$	0.38
Natural gas liquids, hedged ($ per Bbl)(3)	$	23.27	$	7.17	$	23.05	$	8.33
Average price, hedged ($ per BOE)(3)	$	36.82	$	22.95	$	36.36	$	28.30

(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.

(2)The volumes presented are based on actual results and are not calculated using the rounded numbers in the table above.

(3)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include 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.

Production Data

Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables set forth the mix of our production data by product and basin for the three and six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Oil (MBbls)	61	%	60	%	60	%	61	%
Natural gas (MMcf)	20	%	20	%	21	%	19	%
Natural gas liquids (MBbls)	19	%	20	%	19	%	20	%
	100	%	100	%	100	%	100	%

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	Three Months Ended June 30, 2021				Three Months Ended June 30, 2020
	Midland Basin	Delaware Basin	Other(1)	Total	Midland Basin	Delaware Basin	Other(2)	Total
Production Data:
Oil (MBbls)	13,960	6,391	1,716	22,067	9,382	6,626	37	16,045
Natural gas (MMcf)	25,119	16,238	3,149	44,506	17,049	14,721	87	31,857
Natural gas liquids (MBbls)	4,363	2,068	616	7,047	3,146	2,244	21	5,411
Total (MBoe)	22,510	11,165	2,857	36,532	15,370	11,324	73	26,765


	Six Months Ended June 30, 2021				Six Months Ended June 30, 2020
	Midland Basin	Delaware Basin	Other(1)	Total	Midland Basin	Delaware Basin	Other(2)	Total
Production Data:
Oil (MBbls)	23,800	12,827	2,018	38,645	19,893	14,386	91	34,370
Natural gas (MMcf)	43,576	31,293	3,746	78,615	32,882	30,868	227	63,977
Natural gas liquids (MBbls)	7,599	4,137	716	12,452	6,194	4,707	48	10,949
Total (MBoe)	38,662	22,180	3,358	64,200	31,567	24,238	177	55,982

(1)Includes the Eagle Ford Shale, Rockies and High Plains.

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

Comparison of the Three Months Ended June 30, 2021 and 2020 and Six Months Ended June 30, 2021 and 2020

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

Our oil, natural gas and natural gas liquids revenues for the three months ended June 30, 2021 increased by $1.3 billion, or 305%, to $1.7 billion from $412 million during the three months ended June 30, 2020. Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed to $1.1 billion of the total increase. The remainder of the overall change is due to a 36% increase in combined volumes sold

Our oil, natural gas and natural gas liquids revenues for the six months ended June 30, 2021 increased by $1.5 billion, or 119%, to $2.8 billion from $1.3 billion during the six months ended June 30, 2020. Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed to $1.4 billion of the total increase. The remainder of the overall change is due to a 15% increase in combined volumes sold.

In both cases, higher commodity prices in the 2021 periods compared to the 2020 periods primarily reflect a recovery from historically low prices experienced in 2020 due to the COVID-19 pandemic as discussed in “— Recent Developments” above. The increase in production for the 2021 periods compared to the 2020 periods resulted primarily from the Guidon Acquisition and QEP Merger during the first quarter of 2021 and an overall recovery in our drilling and production activities after curtailments in the second quarter of 2020 in response to the COVID-19 pandemic.

Lease Operating Expenses. The following table shows lease operating expenses for the three and six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,								Six Months Ended June 30,
	2021				2020				2021				2020
	Amount		Per BOE		Amount		Per BOE		Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
Lease operating expenses	$	157	$	4.30	$	103	$	3.85	$	259	$	4.03	$	230	$	4.11

Lease operating expenses increased by $54 million, or $0.45 per BOE for the second quarter of 2021 compared to the second quarter of 2020 and increased by $29 million, or $0.08 per BOE for the first half of 2021 compared to the first half of 2020, primarily due to an increase in production between periods driven by the Guidon Acquisition and the QEP Merger in the first quarter of 2021. The production acquired from QEP has higher lease operating costs per BOE on average than our historical properties. Additionally, the increase in lease operating costs for the first half of 2021 compared to the first half of

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2020 was partially offset by a decrease of approximately $12 million in power generation costs related to enhancements in infrastructure which occurred between periods.

See Note 4—Acquisitions for further details regarding acquisitions.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three and six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,										Six Months Ended June 30,
	2021					2020					2021					2020
	Amount			Per BOE		Amount			Per BOE		Amount			Per BOE		Amount			Per BOE
	(In millions, except per BOE amounts)
Production taxes	$	87		$	2.38	$	19		$	0.73	$	147		$	2.29	$	61		$	1.09
Ad valorem taxes	18			0.49		3			0.10		33			0.51		32			0.58
Total production and ad valorem expense	$	105		$	2.87	$	22		$	0.83	$	180		$	2.80	$	93		$	1.67

Production taxes as a % of oil, natural gas, and natural gas liquids revenue	5.2		%			4.6		%			5.2		%			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 increased for the three and six months ended June 30, 2021 compared to the same periods in 2020 due to the addition of production revenues from the newly acquired Williston Basin properties which have a higher production tax rate than our other properties.

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 June 30, 2021 as compared to the three months ended June 30, 2020 increased by $15 million primarily due to valuation adjustments that were made in 2020 related to the COVID-19 pandemic. Ad valorem taxes for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020 remained relatively flat.

Gathering and Transportation Expense. The following table shows gathering and transportation expense for the three and six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,								Six Months Ended June 30,
	2021				2020				2021				2020
	Amount		Per BOE		Amount		Per BOE		Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
Gathering and transportation expense	$	56	$	1.53	$	36	$	1.35	$	87	$	1.36	$	72	$	1.29

The per BOE increases for gathering and transportation expenses for the three and six months ended June 30, 2021, compared to the same periods in 2020 are primarily attributable to the increase in production between periods, which was primarily driven by the Guidon Acquisition and the QEP Merger. The increase in gathering and transportation expense per BOE was also driven by QEP production, which on average has a higher gathering and transportation cost per BOE than our historical properties.

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Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the three and six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions, except BOE amounts)
Depletion of proved oil and natural gas properties	$	318	$	330	$	575	$	722
Depreciation of midstream assets	15		10		26		20
Depreciation of other property and equipment	5		3		8		8
Asset retirement obligation accretion	3		1		5		3
Depreciation, depletion and amortization expense	$	341	$	344	$	614	$	753
Oil and natural gas properties depletion rate per BOE	$	8.70	$	12.33	$	8.96	$	12.90

The decrease in depletion of proved oil and natural gas properties of $12 million for the three months ended June 30, 2021 as compared to the three months ended June 30, 2020 and $147 million for the six months ended June 30, 2021 as compared to the six months ended June 30, 2020 resulted largely from a reduction in the average depletion rate for our oil and natural gas properties in 2021. The decline in rate resulted primarily from a decrease in the net book value of our properties due to the full cost ceiling impairments recorded in 2020.

Impairment of Oil and Natural Gas Properties. No impairment expense was recorded for the three and six months ended June 30, 2021. In connection with the QEP Merger and the Guidon Acquisition, we recorded the oil and natural gas properties acquired at fair value. Pursuant to SEC guidance, we determined the fair value of the properties acquired in the QEP Merger and the Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt. As such, we requested and received a waiver from the SEC to exclude the acquired properties from the first quarter 2021 ceiling test calculation. As a result, no impairment expense related to the QEP Merger and the Guidon Acquisition was recorded for the three months ended March 31, 2021. Had we not received the waiver from the SEC, an impairment charge of approximately $1.1 billion would have been recorded in the first quarter of 2021. The properties acquired in the QEP Merger and the Guidon Acquisition had total unamortized costs at March 31, 2021 of $3.0 billion and $1.1 billion, respectively.

As a result of the sharp decline in commodity prices during 2020, we recorded non-cash ceiling test impairments for the three and six months ended June 30, 2020 of $2.5 billion and $3.5 billion, respectively, which are included in accumulated depletion, depreciation, amortization and impairment on our condensed consolidated balance sheet.

Impairment charges affect our results of operations but do not reduce our 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 fall as compared to the commodity prices used in prior quarters, we may have material write-downs in subsequent quarters. See Note 5—Property and Equipment for further details regarding factors that impact the impairment of oil and natural gas properties.

General and Administrative Expenses. The following table shows general and administrative expenses for the three and six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,								Six Months Ended June 30,
	2021				2020				2021				2020
	Amount		Per BOE		Amount		Per BOE		Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
General and administrative expenses	$	23	$	0.63	$	11	$	0.41	$	38	$	0.59	$	26	$	0.46
Non-cash stock-based compensation	13		0.36		9		0.33		23		0.36		18		0.33
Total general and administrative expenses	$	36	$	0.99	$	20	$	0.74	$	61	$	0.95	$	44	$	0.79

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The increases in general and administrative expenses for the three and six months ended June 30, 2021 compared to the three and six months ended June 30, 2020 were due largely to additional payroll and other employee driven costs of $9 million and $11 million, respectively, related to the QEP Merger and the Guidon Acquisition. Additionally, equity compensation increased by $4 million for each of the 2021 periods compared to the 2020 periods.

Merger and Integration Expense. The following tables shows merger and integration expense for the three and six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Merger and integration expense	$	2	$	—	$	77	$	—

Total merger and integration expense for the six months ended June 30, 2021 includes $68 million in costs incurred for the QEP Merger and $9 million in costs incurred for the Guidon Acquisition. The QEP Merger related expenses primarily consist of $38 million in severance costs and $30 million in banking, legal and advisory fees, and the Guidon Acquisition related expenses consist primarily of advisory and legal fees. See Note 4—Acquisitions for further details regarding the QEP Merger and the Guidon Acquisition.

Net Interest Expense. The following table shows the components of net interest expense for the three and six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Revolving credit agreements	$	2	$	6	$	5	$	13
Senior notes	70		49		131		98
Amortization of debt issuance costs and discounts	4		2		8		5
Other	2		2		4		5
Capitalized interest	(21)		(13)		(35)		(27)


Interest expense, net	$	57	$	46	$	113	$	94

Net interest expense increased by $11 million and $19 million for the three and six months ended June 30, 2021 compared to the same periods in 2020. In both cases, the increase was primarily due to interest expense related to our May 2020 Notes, Rattler’s 5.625% Senior Notes due 2025, and to a lesser extent, interest expense incurred on the QEP Notes that remained outstanding following the QEP Merger completed in March 2021 and the newly issued March 2021 Notes. These increases were partially offset by interest cost savings on the repurchase of $368 million in outstanding principal of our 2025 Notes in March 2021, and the reduction in borrowings under our revolving credit agreements during 2021. See Note 7—Debt for further details regarding outstanding borrowings and interest expense.

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 and six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Gain (loss) on derivative instruments, net	$	(497)	$	(361)	$	(661)	$	181
Net cash received (paid) on settlements(1)	$	(323)	$	210	$	(425)	$	297

(1)The six months ended June 30, 2021 include cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.

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 commodity 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

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instruments, net.” As part of the QEP Merger, we received by novation from QEP certain derivative instruments which were included on our balance sheet as of June 30, 2021.

We have designated certain of our interest rate swaps as fair value hedges for accounting purposes. As a result, gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt and no gain or loss is recognized due to hedge ineffectiveness. Changes in fair value are recorded as an adjustment to the carrying value of the 2029 Notes in the condensed consolidated balance sheet. Beginning on December 1, 2021, semi-annual cash settlements of these interest rate swaps will be recorded in interest expense in the condensed consolidated statements of operations.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the three and six months ended June 30, 2021 and 2020:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
	(In millions)
Provision for (benefit from) income taxes	$	94	$	(681)	$	159	$	(598)

The changes in our income tax provision for the three and six months ended June 30, 2021 compared to the same periods in 2020 were primarily due to the increase in pre-tax income for the three and six months ended June 30, 2021, partially offset by income tax expense resulting from recording a valuation allowance on Viper’s deferred tax assets for the three and six months ended June 30, 2020.

Liquidity and Capital Resources

As of June 30, 2021, we had $1.6 billion of availability for future borrowings under the credit agreement and approximately $344 million of cash on hand. Historically, our primary sources of liquidity have been cash flows from operations, proceeds from our public equity offerings, borrowings under the credit agreement and proceeds from the issuance of our senior notes. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties and return of capital to our stockholders.

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 commodity pricing environment and uncertain 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 six months ended June 30, 2021 and 2020 are presented below:


	Six Months Ended June 30,
	2021		2020
	(In millions)
Net cash provided by (used in) operating activities	$	1,578	$	1,173
Net cash provided by (used in) investing activities	(898)		(1,535)
Net cash provided by (used in) financing activities	(392)		293
Net increase (decrease) in cash	$	288	$	(69)

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 increase in operating cash flows for the six months ended June 30, 2021 compared to the same period in 2020 primarily resulted from (i) an increase of $1.5 billion in our total revenues, and (ii) receipt of a $99 million refund of an income tax receivable related to the carryback of federal net operating losses and the accelerated refund of minimum tax credits allowed under the CARES Act in 2020. These net cash inflows were partially offset by (i) a reduction of $781 million due to making net cash payments of $484 million on our derivative contracts in the six months ended June 30, 2021 compared to receiving net cash of $297 million on our derivative contracts in the six months ended June 30, 2020, (ii) an increase in our cash operating expenses of approximately $228 million primarily due to the QEP Merger and the Guidon Acquisition, and (iii) working capital changes, primarily due to recording working capital assets and liabilities acquired in the QEP Merger during March 2021. See “— Results of Operations” for discussion of significant changes in our revenues and expenses.

Investing Activities

Net cash used in investing activities was $898 million compared to $1.5 billion during the six months ended June 30, 2021 and 2020, respectively. The majority of our net cash used for investing activities during the six months ended June 30, 2021 was for the purchase and development of oil and natural gas properties and related assets, including the acquisition of certain leasehold interests as part of the Guidon Acquisition. These expenditures were partially offset by proceeds from the sale of leasehold acreage discussed in Note 4—Acquisitions and D ivestitures.

The majority of our net cash used in investing activities during the six months ended June 30, 2020 was incurred for drilling and completion costs in conjunction with our development program. Our capital expenditures for each period are discussed further below.

Capital Expenditure Activities

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


	Six Months Ended June 30,
	2021		2020
	(In millions)
Drilling, completions and non-operated additions to oil and natural gas properties(1)(2)	$	623	$	1,178
Infrastructure additions to oil and natural gas properties	22		80
Additions to midstream assets	17		94
Total	$	662	$	1,352

(1)During the six months ended June 30, 2021, in conjunction with our development program, we drilled 105 gross (99 net) operated horizontal wells, of which 88 gross (83 net) wells were in the Midland Basin and 17 gross (16 net) wells were in the Delaware Basin, and turned 132 gross (121 net) operated horizontal wells to production, of which 89 gross (81 net) wells were in the Midland Basin and 39 gross (37 net) wells were in the Delaware Basin.

(2)During the six months ended June 30, 2020, in conjunction with our development program, we drilled 151 gross (141 net) operated horizontal wells, of which 92 gross (86 net) wells were in the Midland Basin and 59 gross (55 net) wells were in the Delaware Basin, and turned 95 gross (83 net) operated horizontal wells to production, of which 51 gross (47 net) wells were in the Delaware Basin and 44 gross (36 net) wells were in the Midland Basin.

Financing Activities

Net cash used in financing activities for the six months ended June 30, 2021 was $392 million compared to net cash provided by financing activities for the six months ended June 30, 2020 of $293 million. During the six months ended June 30, 2021, the amount used in financing activities was primarily attributable to (i) $2.1 billion paid for the repurchase of a portion of the QEP Notes and the 2025 Senior Notes and the Energen Notes and the redemption of the Energen 4.62% Senior Notes due 2021, as well as $166 million of additional premiums paid in connection with the repurchases, (ii) $140 million of dividends paid to stockholders, (iii) $119 million of repayments under our credit facilities, net of borrowings, (iv) $41 million in distributions to non-controlling interest, and (v) $36 million of unit repurchases as part of the Viper and Rattler unit repurchase programs. These cash outflows were partially offset by $2.2 billion in proceeds from the March 2021 Notes and $59 million in net cash receipts from the early settlement of interest rate swaps and commodity derivative contracts that contained an other-than-insignificant financing element.

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Net cash provided by financing activities for the six months ended June 30, 2020 was primarily attributable to (i) $275 million in proceeds, net of repayments, from senior notes, (ii) $262 million of borrowings, net of repayments, under our credit facilities and (iii) $43 million in proceeds from joint ventures. These cash inflows were partially offset by (i) $118 million of dividends to stockholders, (ii) $98 million of share repurchases as part of our previous stock repurchase program, and (iii) $62 million of distributions to non-controlling interest.

Indebtedness

At June 30, 2021, our debt, including the debt of Viper and Rattler, consists of approximately $7.3 billion in aggregate outstanding principal amount of senior notes, $67 million in aggregate outstanding borrowings under revolving credit facilities and $68 million in outstanding amounts due under our DrillCo Agreement. Our revolving credit facilities and significant changes in our outstanding indebtedness during the six months ended June 30, 2021 are discussed further below. See Note 7—Debt for additional discussion of our outstanding debt at June 30, 2021.

Second Amended and Restated Credit Facility

As discussed in “— Recent Developments” on June 2, 2021, we entered into an amendment to the credit agreement. As of June 30, 2021, the maximum credit amount available under the credit agreement was $1.6 billion, with no outstanding borrowings and $1.6 billion available for future borrowings. As of June 30, 2021, there was an aggregate of $3 million in outstanding letters of credit, which reduces available borrowings under the credit agreement on a dollar for dollar basis. The borrowing base is scheduled to be redetermined semi-annually in May and November. During the three and six months ended June 30, 2021, the weighted average interest rate on the credit facility was 1.68% and 1.67%, respectively.

As of June 30, 2021, we were in compliance with all financial maintenance covenants under the credit agreement.

March 2021 Notes Offering

On March 24, 2021, we issued $650 million of our 2023 Notes, $900 million of our 2031 Notes and $650 million of our 2051 Notes and received proceeds of $2.18 billion, net of $24 million in debt issuance costs and discounts. The net proceeds were primarily used to fund the repurchase of other senior notes outstanding as discussed further below. Interest on the March 2021 Notes is payable semi-annually on March 24 and September 24, beginning on September 24, 2021.

Repurchases of Notes

On March 17, 2021, in conjunction with the QEP Merger discussed in Note 4—Acquisitions, QEP’s outstanding debt had fair values consisting of $478 million of the QEP 2022 Notes, $673 million of the QEP 2023 Notes, and $558 million of the QEP 2026 Notes.

Subsequent to the QEP Merger, in March 2021, we repurchased pursuant to tender offers commenced by us approximately $1.65 billion in fair value carrying amount of the QEP Notes for total cash consideration of $1.7 billion, including redemption and early premium fees, which resulted in a loss on extinguishment of debt during the three months ended March 31, 2021 of approximately $47 million. The aggregate fair value of the QEP Notes repurchased consisted of (i) $453 million, or 94.65%, of the outstanding fair value carrying amount of the QEP 2022 Notes, (ii) $663 million, or 98.43%, of the outstanding fair value carrying amount of the QEP 2023 Notes, and (iii) $538 million, or 96.35%, of the outstanding fair value carrying amount of the QEP 2026 Notes.

In March 2021, we also repurchased an aggregate of $368 million principal amount of our 5.375% 2025 Senior Notes, representing approximately 45.97% of the outstanding 2025 Senior Notes, for total cash consideration of $381 million, including redemption and early premium fees, which resulted in a loss on extinguishment of debt during the six months ended June 30, 2021 of $14 million.

We funded the repurchases of the QEP Notes and 2025 Senior Notes with the proceeds from the March 2021 Notes offering discussed above.

In connection with the tender offers to repurchase the QEP Notes discussed above, we also solicited consents from holders of the QEP Notes to amend the indenture for the QEP Notes to, among other things, eliminate substantially all of the restrictive covenants and related provisions and certain events of default contained in the indenture under which the QEP Notes were issued. We received the requisite number of consents and, on March 23, 2021, entered into a supplemental indenture relating to the QEP Notes adopting these amendments.

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Pending Full Redemption of the Outstanding 5.375% Senior Notes due 2025

As discussed in “— Recent Developments” on July 23, 2021, we elected to effect an optional redemption of all of the 2025 Notes in the aggregate principal amount of $432 million on August 24, 2021 at the Redemption Price equal to 102.688% of the principal amount plus accrued interest.

Viper’s Credit Agreement

The Viper credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion, with a borrowing base of $580 million as of June 30, 2021, although Viper LLC had elected a commitment amount of $500 million, based on Viper LLC’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be redetermined semi-annually in May and November. As of June 30, 2021, there were $62 million of outstanding borrowings and $438 million available for future borrowings under the Viper credit agreement. During the three and six months ended June 30, 2021, the weighted average interest rate on borrowings under the Viper credit agreement was 1.93% and 1.90%, respectively. The Viper credit agreement will mature on June 2, 2025.

As of June 30, 2021, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement.

Rattler’s Credit Agreement

The Rattler credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1.0 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of June 30, 2021, there were $5 million of outstanding borrowings and $595 million available for future borrowings under the Rattler credit agreement. During the three and six months ended June 30, 2021, the weighted average interest rate on borrowings under the Rattler credit agreement was 1.36% and 1.39%. The Rattler credit agreement matures on May 28, 2024.

As of June 30, 2021, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

Capital Requirements and Sources of Liquidity

Our primary short and long-term liquidity requirements consist primarily of (i) capital expenditures, (iii) payments of contractual obligations, including debt maturities, (iv) dividends and share repurchases, and (v) working capital obligations.

Our board of directors initially approved a 2021 capital budget for drilling and completion, midstream and infrastructure of approximately $1.4 billion to $1.6 billion. We have updated our 2021 capital budget to approximately $1.5 billion to $1.6 billion to give effect to the QEP Merger, representing an increase at the midpoint of 9% over our original 2021 capital budget. We estimate that, of these expenditures, approximately:

•$1.38 billion to $1.45 billion will be spent on drilling and completing 265 to 275 gross (246 to 256 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 10,300 feet;

•$50 million to $70 million will be spent on midstream infrastructure, excluding joint venture investments; and

•$100 million to $110 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 six months ended June 30, 2021, we spent $603 million on drilling and completion, $17 million on midstream, $20 million on non-operated properties and $22 million on infrastructure, for total capital expenditures, excluding acquisitions, of $662 million.

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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 nine drilling rigs and three completion crews. We currently continue to execute on our strategy to hold oil production flat while using cash flow from operations to reduce debt, strengthen our balance sheet and return capital to our stockholders. We currently intend to reduce our estimated 2021 capital budget by 6% at the midpoint of the previously disclosed guidance due to cost control and outperformance of our 2021 development plan, intending to maintain current production levels with less capital and fewer completed wells than was originally expected in our 2021 development plan. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence and our capital expenditure budget in response to changes in commodity prices and overall market conditions.

Based upon current oil and natural gas prices and production expectations for 2021, 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 and thereafter. 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. We cannot assure you that the needed capital will be available on acceptable terms or at all. Further, our 2021 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

Guarantor Financial Information

In connection with the merger of certain of the Company’s wholly owned subsidiaries as of June 30, 2021 completed as part of the internal subsidiary restructuring, Diamondback E&P became the successor borrower to O&G under the credit agreement, the successor issuer of the Energen Medium-Term Notes and the sole guarantor under the indentures governing the December 2019 Notes, the May 2020 Notes, the 2025 Senior Notes and the March 2021 Notes.

Guarantees 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 2019 Indenture and the 2025 Indenture, such as, with certain exceptions, (1) in the event Diamondback E&P (or all or substantially all of its assets) is sold or disposed of, (2) in the event Diamondback E&P 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 E&P’s guarantees of the December 2019 Notes, the May 2020 Notes, the 2025 Senior Notes and the March 2021 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 E&P 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 E&P’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 E&P. 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 E&P, 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.


	June 30, 2021		December 31, 2020
Summarized Balance Sheets:	(In millions)
Assets:
Current assets	$	774	$	308

Property and equipment, net	$	14,314	$	6,934
Other noncurrent assets	$	47	$	6
Liabilities:
Current liabilities	$	1,659	$	355
Intercompany accounts payable, non-guarantor subsidiary	$	84	$	335
Long-term debt	$	6,204	$	4,293
Other noncurrent liabilities	$	1,088	$	886


	Six Months Ended June 30, 2021
Summarized Statement of Operations:	(In millions)
Revenues	$	2,196
Income (loss) from operations	$	1,160
Net income (loss)	$	314

Contractual Obligations

In addition to the changes in debt discussed in “—Indebtedness” above and in Note 7—Debt included in the notes to the condensed consolidated financial statements included elsewhere in this report, we acquired certain contractual obligations during the six months ended June 30, 2021 in conjunction with the QEP Merger including an aggregate of approximately $68 million in various transportation, gathering and purchase commitments. There were no other significant changes in our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2020.

Critical Accounting Policies and Estimates

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, 2020.

Off-Balance Sheet Arrangements

We had no material off-balance sheet arrangements as of June 30, 2021. Please read Note 13—Commitments and Contingencies included in the notes to the condensed consolidated financial statements included elsewhere in 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. Although demand and market prices for oil and natural gas have recently increased due to the rising energy use, easing of the COVID-19 pandemic and the improvements in the U.S. economic activity, we cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty. Further, the prices we receive for production depend on many other factors outside of our control.

We use derivatives, including swaps, basis swaps, puts, swaptions, roll swaps, and costless collars, to reduce price volatility associated with certain of our oil and natural gas sales.

At June 30, 2021, we had a net liability derivative position related to our commodity price derivatives of $783 million, related to our commodity price risk derivatives. Utilizing actual derivative contractual volumes under our commodity price derivatives as of June 30, 2021, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to $860 million, an increase of $77 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability position to $706 million, a decrease of $77 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 shut 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 June 30, 2021, see Note 11—Derivatives.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are due to the concentration of receivables from the sale of our oil and natural gas production (approximately $579 million at June 30, 2021), and to a lesser extent, receivables resulting from joint interest receivables (approximately $78 million at June 30, 2021).

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.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facilities and changes in the fair value of our fixed-rate debt. The terms of the credit agreement 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 1.125% per annum in the case of the alternative base rate and from 1.25% to 2.125% per annum in the case of LIBOR, in each case based on the pricing level. The pricing level depends on certain rating agencies’ ratings of our long-term senior unsecure debt. We believe significant interest rate changes would not have a material near-term impact on our future earnings or cash flows. For additional information on our variable interest rate debt at June 30, 2021, see Note 7—Debt.

Historically, we have at times used interest rates swaps to manage our exposure to (i) interest rate changes on our floating-rate date and (ii) fair value changes on our fixed-rate debt. At June 30, 2021, we have interest rate swap agreements for a notional amount of $1.2 billion to manage the impact of market interest rates on interest expense. These interest rate swaps have been designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 whereby we

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will receive the fixed rate of interest and will pay an average variable rate of interest based on three month LIBOR plus 2.1865%. For additional information on our interest rate swaps, see Note 11—De rivativ es.

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 June 30, 2021, 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 June 30, 2021, 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 June 30, 2021, 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 natural 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. See Note 13—Commitments and Contingencies.

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, 2020, filed with the SEC on February 25, 2021, and in subsequent filings we make with the SEC. There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2020.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the six months ended June 30, 2021 was as follows:


Period	Total Number of Shares Purchased(1)	Average Price Paid Per Share(2)		Total Number of Shares Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
	($ In millions, except per share amounts, shares in thousands)



April 1, 2021 - April 30, 2021	—	$	—	—	$	—
May 1, 2021 - May 31, 2021	—	$	—	—	$	—
June 1, 2021 - June 30, 2021	4	$	86.44	—	$	—



Total	4	$	86.44	—

(1)Includes shares of common stock repurchased from employees in order to satisfy tax withholding requirements. Such shares are cancelled and retired immediately upon repurchase.

(2)The average price paid per share is net of any commissions paid to repurchase stock.

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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			Certificate of Amendment No. 2 to 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 June 8, 2021).
3.4			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			Registration Rights Agreement, dated as of February 26, 2021, by and among the Company, Guidon Operating LLC and Guidon Energy Holdings LP (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-3, File No. 333-255731, filed by the Company with the SEC on May 3, 2021.
4.3			Letter Agreement, dated as of April 27, 2021, by and among the Company, Guidon Operating LLC and Guidon Energy Holdings LP relating to the Registration Rights Agreement referenced as Exhibit 4.2 hereto (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-3, File No. 333-255731, filed by the Company with the SEC on May 3, 2021).
10.1			Twelfth Amendment to Second Amended and Restated Credit Agreement and First Amendment to Second Amended and Restated Guaranty Agreement, dated as of June 2, 2021, between Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by th e Company with the SEC on June 8, 2021).
10.2*			Successor Borrower Joinder Agreement, dated as of June 30, 2021, entered into on June 30, 2021, by and among Diamondback E&P LLC, as successor borrower, Diamondback Energy, Inc., as parent guarantor, and Wells Fargo Bank, National Association, as administrative agent for the lenders.
10.3*			Fourth Supplemental Indenture, dated as of June 30, 2021, among Diamondback E&P LLC, as successor by merger to Diamondback O&G LLC, each a subsidiary of the Company, the Company and Wells Fargo Bank, National Association, as trustee under the indenture, as supplemented by several supplements, relating, as applicable, to the Company’s 2.875% Senior Notes due 2024, 3.250% Senior Notes due 2026, 3.500% Senior Notes due 2029, 4.750% Senior Notes due 2025, 0.900% Senior Notes due 2023, 3.125% Senior Notes due 2031 and 4.400% Senior Notes due 2051.
10.4*			First Supplemental Indenture, dated as of June 30, 2021, between Diamondback E&P LLC, as successor by merger to Energen, and The Bank of New York Mellon Trust Company, N.A., successor in interest to The Bank of New York, as trustee under the indenture relating to Energen’s notes.
10.5*			Fourth Supplemental Indenture, dated as of June 30, 2021, among Diamondback E&P LLC, as successor in interest to Diamondback O&G LLC, each a subsidiary of the Company, the Company and Wells Fargo Bank, National Association, as trustee under the indenture relating to the Company’s 5.375% Senior Notes due 2025.
10.6			Seventh Amendment to Amended and Restated Senior Secured Revolving Credit Agreement and Second Amendment to Guaranty and Collateral Agreement, dated as of June 2, 2021, by and among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-36505, filed by Viper Energy Partners LP with the SEC on June 8, 2021).
22.1*			List of Issuers and Guarantor Subsidiaries .
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.

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Exhibit Number			Description
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 June 30, 2021, 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:	August 5, 2021	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer
		(Principal Executive Officer)

Date:	August 5, 2021	/s/ Kaes Van’t Hof
		Kaes Van’t Hof
		Chief Financial Officer
		(Principal Financial Officer)