SEC Filing | Diamondback Energy, Inc.

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fang-20220630

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, 2022


☐			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 Ave.
Suite 100
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 29, 2022, the registrant had 173,441,061 shares of common stock outstanding.

DIAMONDBACK ENERGY, INC.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2022

TABLE OF CONTENTS


			Page
Glossary of Oil and Natural Gas Terms			ii
Glossary of Certain Other Terms			iii
Cautionary Statement Regarding Forward-Looking Statements			iv

PART I. FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)			1
Condensed Consolidated Balance Sheets			1
Condensed Consolidated Statements of Operations			3

Condensed Consolidated Statements of Stockholders’ Equity			4
Condensed Consolidated Statements of Cash Flows			6
Condensed Notes to Consolidated Financial Statements			7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29

Item 3. Quantitative and Qualitative Disclosures About Market Risk			48

Item 4. Controls and Procedures			49

PART II. OTHER INFORMATION
Item 1. Legal Proceedings			50

Item 1A. Risk Factors			50

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			54

Item 6. Exhibits			55

Signatures			56

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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.













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.


Oil and natural gas properties			Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.






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.

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.
WTI			West Texas Intermediate.

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GLOSSARY OF CERTAIN OTHER TERMS

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




ASC			Accounting Standards Codification.
ASU			Accounting Standards Update.
December 2019 Notes			The Company’s 3.250% senior unsecured notes due 2026 and the Company’s 3.500% senior unsecured notes due 2029 issued under the IG Indenture and the related first supplemental indenture.


Equity Plan			The Company’s 2021 Amended and Restated 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.


IG Indenture			The indenture, dated as of December 5, 2019, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented by the supplemental indentures relating to the outstanding December 2019 Notes (defined above), the March 2021 Notes (defined below) and the March 2022 Notes (defined below).
LIBOR			The London interbank offered rate.
March 2021 Notes			The Company’s 0.900% Senior Notes due 2023, the Company’s 3.125% Senior Notes due 2031 and the Company’s 4.400% Senior Notes due 2051 issued under the IG Indenture and the related third supplemental indenture.
March 2022 Notes			The Company’s 4.250% Senior Notes due 2052, issued under the IG Indenture and the related third supplemental indenture.

NYMEX			New York Mercantile Exchange.
OPEC			Organization of the Petroleum Exporting Countries.
Rattler			Rattler Midstream LP, a Delaware limited partnership.

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 outstanding December 2019 Notes, the March 2021 Notes and the March 2022 Notes.
SOFR			The secured overnight financing rate.
TSR			Total stockholder return of the Company’s common stock.
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.

iii

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report are “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, which involve risks, uncertainties, and assumptions. All statements, other than statements of historical fact, including statements regarding our: future performance; business strategy; future operations (including drilling plans and capital plans); estimates and projections of revenues, losses, costs, expenses, returns, cash flow, and financial position; reserve estimates and our ability to replace or increase reserves; anticipated benefits of strategic transactions (including acquisitions and divestitures); and plans and objectives of management (including plans for future cash flow from operations and for executing environmental strategies) are forward-looking statements. When used in this report, the words “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to the Company 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, Part II, Item 1A Risk Factors in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022, and our Annual Report on Form 10–K for the year ended December 31, 2021 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.

Factors that could cause our outcomes to differ materially include (but are not limited to) the following:

•changes in supply and demand levels for oil, natural gas, and natural gas liquids, and the resulting impact on the price for those commodities;

•the impact of public health crises, including epidemic or pandemic diseases such as the COVID-19 pandemic, and any related company or government policies or actions;

•actions taken by the members of OPEC and Russia affecting the production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments;

•changes in general economic, business or industry conditions, including changes in foreign currency exchange rates, interest rates and inflation rates and concerns over a potential recession;

•regional supply and demand factors, including delays, curtailment delays or interruptions of production, or governmental orders, rules or regulations that impose production limits;

•federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations;

•transition risks relating to climate change;

•restrictions on the use of water, including limits on the use of produced water and a moratorium on new produced water well permits recently imposed by the Texas Railroad Commission in an effort to control induced seismicity in the Permian Basin;

•significant declines in prices for oil, natural gas, or natural gas liquids, which could require recognition of significant impairment charges;

•changes in U.S. energy, environmental, monetary and trade policies;

•conditions in the capital, financial and credit markets, including the availability and pricing of capital for drilling and development operations and our environmental and social responsibility projects;

•challenges with employee retention and an increasingly competitive labor market due to a sustained labor shortage or increased turnover caused by the COVID-19 pandemic;

•changes in availability or cost of rigs, equipment, raw materials, supplies, oilfield services;

•changes in safety, health, environmental, tax, and other regulations or requirements (including those addressing air emissions, water management, or the impact of global climate change);

•security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, or from breaches of information technology systems of third parties with whom we transact business;

•The timing and completion of the Rattler Merger (as defined in See Note 1—Description of the Business and Basis of Presentation of the condensed notes to the consolidated financial statements included elsewhere in this report);

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•lack of, or disruption in, access to adequate and reliable transportation, processing, storage, and other facilities for our oil, natural gas, and natural gas liquids;

•failures or delays in achieving expected reserve or production levels from existing and future oil and natural gas developments, including due to operating hazards, drilling risks, or the inherent uncertainties in predicting reserve and reservoir performance;

•difficulty in obtaining necessary approvals and permits;

•severe weather conditions;

•acts of war or terrorist acts and the governmental or military response thereto;

•changes in the financial strength of counterparties to our credit agreement and hedging contracts;

•changes in our credit rating; and

•other risks and factors disclosed in this report.

In light of these factors, the events anticipated by our forward-looking statements may not occur at the time anticipated or at all. Moreover, we operate in a very competitive and rapidly changing environment and new risks emerge from time to time. We cannot 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 anticipated by any forward-looking statements we may make. Accordingly, you should not place undue reliance on any forward-looking statements made 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 applicable law.

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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,
	2022		2021
	(In millions, except par values and share data)
Assets
Current assets:
Cash and cash equivalents	$	43	$	654
Restricted cash	16		18
Accounts receivable:
Joint interest and other, net	76		72
Oil and natural gas sales, net	961		598

Inventories	65		62

Derivative instruments	17		13
Income tax receivable	—		1

Prepaid expenses and other current assets	23		28
Total current assets	1,201		1,446
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($8,097 million and $8,496 million excluded from amortization at June 30, 2022 and December 31, 2021, respectively)	34,200		32,914
Midstream assets	1,139		1,076
Other property, equipment and land	190		174
Accumulated depletion, depreciation, amortization and impairment	(14,160)		(13,545)
Property and equipment, net	21,369		20,619
Funds held in escrow	—		12
Equity method investments	660		613
Derivative instruments	33		4
Deferred income taxes, net	33		40
Investment in real estate, net	87		88
Other assets	65		76
Total assets	$	23,448	$	22,898

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,
	2022		2021
Liabilities and Stockholders’ Equity	(In millions, except par values and share data)

Current liabilities:
Accounts payable - trade	$	62	$	36

Accrued capital expenditures	323		295
Current maturities of long-term debt	55		45
Other accrued liabilities	420		419
Revenues and royalties payable	615		452
Derivative instruments	162		174
Deferred income taxes	3		17

Total current liabilities	1,640		1,438
Long-term debt	5,401		6,642
Derivative instruments	123		29
Asset retirement obligations	260		166
Deferred income taxes	1,600		1,338
Other long-term liabilities	34		40
Total liabilities	9,058		9,653
Commitments and contingencies (Note 14)
Stockholders’ equity:
Common stock, $0.01 par value; 400,000,000 shares authorized; 175,201,453 and 177,551,347 shares issued and outstanding at June 30, 2022 and December 31, 2021, respectively	2		2
Additional paid-in capital	13,772		14,084
Retained earnings (accumulated deficit)	(458)		(1,998)

Total Diamondback Energy, Inc. stockholders’ equity	13,316		12,088
Non-controlling interest	1,074		1,157
Total equity	14,390		13,245
Total liabilities and equity	$	23,448	$	22,898

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,
	2022		2021		2022		2021
	(In millions, except per share amounts, shares in thousands)
Revenues:
Oil sales	$	2,189	$	1,395	$	4,135	$	2,339
Natural gas sales	264		107		418		211
Natural gas liquid sales	299		165		588		289

Midstream services	14		12		31		23
Other operating income	2		2		4		3
Total revenues	2,768		1,681		5,176		2,865
Costs and expenses:
Lease operating expenses	159		157		308		259
Production and ad valorem taxes	178		105		339		180
Gathering and transportation	61		56		120		87
Midstream services expenses	23		23		45		51
Depreciation, depletion, amortization and accretion	330		341		643		614


General and administrative expenses	39		36		75		61

Merger and integration expenses	—		2		—		77
Other operating expenses	—		6		8		10
Total costs and expenses	790		726		1,538		1,339
Income (loss) from operations	1,978		955		3,638		1,526
Other income (expense):

Interest expense, net	(39)		(57)		(79)		(113)
Other income (expense), net	1		(7)		2		(6)

Gain (loss) on derivative instruments, net	(101)		(497)		(653)		(661)

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

Gain (loss) on extinguishment of debt	(4)		—		(58)		(61)
Income (loss) from equity investments	28		5		37		2
Total other income (expense), net	(115)		(533)		(751)		(816)
Income (loss) before income taxes	1,863		422		2,887		710
Provision for (benefit from) income taxes	402		94		623		159
Net income (loss)	1,461		328		2,264		551
Net income (loss) attributable to non-controlling interest	45		17		69		20
Net income (loss) attributable to Diamondback Energy, Inc.	$	1,416	$	311	$	2,195	$	531
Earnings (loss) per common share:
Basic	$	7.95	$	1.70	$	12.30	$	3.05
Diluted	$	7.93	$	1.70	$	12.28	$	3.04
Weighted average common shares outstanding:
Basic	176,570		181,009		177,064		172,636
Diluted	176,876		181,199		177,380		172,806
Dividends declared per share	$	3.05	$	0.45	$	6.10	$	0.85

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, 2021	177,551	$	2	$	14,084	$	(1,998)	$	1,157	$	13,245
Unit-based compensation	—	—		—		—		3		3
Distribution equivalent rights payments	—	—		—		—		(1)		(1)

Stock-based compensation	—	—		16		—		—		16
Cash paid for tax withholding on vested equity awards	—	—		(15)		—		—		(15)
Repurchased shares under buyback program	(58)	—		(7)		—		—		(7)
Repurchased units under buyback programs	—	—		—		—		(42)		(42)
Distributions to non-controlling interest	—	—		—		—		(47)		(47)
Dividend paid	—	—		—		(107)		—		(107)
Exercise of stock options and issuance of restricted stock units and awards	58	—		1		—		—		1
Change in ownership of consolidated subsidiaries, net	—	—		(12)		—		15		3
Net income (loss)	—	—		—		779		24		803
Balance March 31, 2022	177,551	2		14,067		(1,326)		1,109		13,852
Unit-based compensation	—	—		—		—		3		3
Distribution equivalent rights payments	—	—		—		(7)		—		(7)
Stock-based compensation	—	—		17		—		—		17
Cash paid for tax withholding on vested equity awards	—	—		—		—		(3)		(3)
Repurchased shares under buyback program	(2,369)	—		(303)		—		—		(303)
Repurchased units under buyback programs	—	—		—		—		(29)		(29)
Distributions to non-controlling interest	—	—		—		—		(63)		(63)
Dividend paid	—	—		—		(541)		—		(541)
Exercise of stock options and vesting of restricted stock units and awards	19	—		—		—		—		—
Change in ownership of consolidated subsidiaries, net	—	—		(9)		—		12		3
Net income (loss)	—	—		—		1,416		45		1,461
Balance June 30, 2022	175,201	$	2	$	13,772	$	(458)	$	1,074	$	14,390

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, 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 Cash Flows

(Unaudited)


	Six Months Ended June 30,
	2022		2021
	(In millions)
Cash flows from operating activities:
Net income (loss)	$	2,264	$	551
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes	273		155




Depreciation, depletion, amortization and accretion	643		614

(Gain) loss on extinguishment of debt	58		61

(Gain) loss on derivative instruments, net	653		661
Cash received (paid) on settlement of derivative instruments	(720)		(484)
(Income) loss from equity investment	(37)		(2)

Equity-based compensation expense	28		23

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

Other	36		15
Changes in operating assets and liabilities:
Accounts receivable	(380)		(172)

Income tax receivable	1		99

Prepaid expenses and other	15		18
Accounts payable and accrued liabilities	(21)		(26)


Income tax payable	(14)		—
Revenues and royalties payable	163		100

Other	(3)		(12)
Net cash provided by (used in) operating activities	2,959		1,578
Cash flows from investing activities:
Drilling, completions and infrastructure additions to oil and natural gas properties	(863)		(645)


Additions to midstream assets	(42)		(17)

Property acquisitions	(381)		(421)



Proceeds from sale of assets	72		100

Funds held in escrow	12		51





Other	(30)		34
Net cash provided by (used in) investing activities	(1,232)		(898)
Cash flows from financing activities:
Proceeds from borrowings under credit facilities	1,579		661
Repayments under credit facilities	(1,563)		(780)
Proceeds from senior notes	750		2,200
Repayment of senior notes	(1,865)		(2,107)
Proceeds from (repayments to) joint venture	(17)		(10)
Premium on extinguishment of debt	(49)		(166)











Repurchased shares under buyback program	(310)		—
Repurchased units under buyback program	(71)		(36)

Dividends to stockholders	(648)		(140)

Distributions to non-controlling interest	(110)		(41)


Financing portion of net cash received (paid) for derivative instruments	—		59
Other	(36)		(32)
Net cash provided by (used in) financing activities	(2,340)		(392)
Net increase (decrease) in cash and cash equivalents	(613)		288
Cash, cash equivalents and restricted cash at beginning of period	672		108
Cash, cash equivalents and restricted cash at end of period(1)	$	59	$	396

(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.

As of June 30, 2022, the wholly owned subsidiaries of Diamondback 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.

Rattler Merger

On May 15, 2022, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Rattler, Rattler Midstream GP LLC, the general partner of the Partnership (the “General Partner”), and Bacchus Merger Sub Company, a wholly owned subsidiary of the Company (“Merger Sub”). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger, (i) Merger Sub will be merged with and into Rattler (the “Rattler Merger”), with Rattler surviving and continuing as the surviving entity in the merger and (ii) each issued and outstanding publicly held common unit representing a limited partner interest in Rattler (other than any common units owned by the Company and its subsidiaries) will be converted into the right to receive 0.113 of a share of common stock, par value $0.01 per share, of the Company. The Merger Agreement also specifies the treatment of outstanding Rattler equity awards in connection with the merger. The Company’s board of directors and the board of directors of the General Partner (acting upon the recommendation of its conflicts committee) unanimously approved the merger. The Company and Rattler expect that the Rattler Merger will close, subject to certain conditions, reasonably promptly following the distribution payment date for the second quarter 2022 distribution to Rattler’s unitholders reported by Rattler.

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, 2022, the Company owned approximately 55% 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, 2022, the Company owned approximately 74% 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 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, 2021, 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.

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Condensed Notes to Consolidated Financial Statements - (Continued)

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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.

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 and the effects of the COVID-19 pandemic. 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, the fair value determination of acquired assets and liabilities assumed, 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, 2022 and 2021 to the line items within the condensed consolidated balance sheets:


	Six Months Ended June 30,
	2022		2021
	(In millions)
Cash and cash equivalents	$	43	$	344
Restricted cash	16		18
Restricted cash included in funds held in escrow	—		34
Total cash, cash equivalents and restricted cash	$	59	$	396

Recent Accounting Pronouncements

Recently Adopted Pronouncements

There are no recently adopted pronouncements.

Accounting Pronouncements Not Yet Adopted

In October 2021, the FASB issued ASU 2021-08, "Business Combinations (Topic 805) – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers.” This update requires the acquirer in a business combination to record contract asset and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public business entities beginning after December 15, 2022 with early adoption permitted. The Company continues to evaluate the provisions of this update, but does not believe the adoption will 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 are 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, 2022								Three Months Ended June 30, 2021
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	1,610	$	577	$	2	$	2,189	$	876	$	408	$	111	$	1,395
Natural gas sales	168		95		1		264		75		27		5		107
Natural gas liquid sales	207		91		1		299		102		52		11		165

Total	$	1,985	$	763	$	4	$	2,752	$	1,053	$	487	$	127	$	1,667


	Six Months Ended June 30, 2022								Six Months Ended June 30, 2021
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	3,008	$	1,122	$	5	$	4,135	$	1,445	$	766	$	128	$	2,339
Natural gas sales	266		151		1		418		116		88		7		211
Natural gas liquid sales	398		188		2		588		177		99		13		289

Total	$	3,672	$	1,461	$	8	$	5,141	$	1,738	$	953	$	148	$	2,839

4. ACQUISITIONS AND DIVESTITURES

2022 Activity

On January 18, 2022, the Company acquired, from an unrelated third-party seller, approximately 6,200 net acres in the Delaware Basin for $232 million in cash, including customary post-closing adjustments. The acquisition was funded through cash on hand.

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Condensed Notes to Consolidated Financial Statements - (Continued)

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2021 Activity

Guidon Operating LLC

On February 26, 2021, the Company completed its acquisition of 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 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

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. The purchase price allocation was complete as of the first quarter of 2022. The following table sets forth the Company’s 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 were 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. 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.

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 and $49 million and $65 million of net income for the three and six months ended June 30, 2021, respectively.

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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”).

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. The purchase price allocation was complete as of the first quarter of 2022. The following table sets forth the Company’s purchase price allocation (in millions):



Total consideration	$	987

Fair value of liabilities assumed:
Accounts payable - trade	$	26
Accrued capital expenditures	38
Other accrued liabilities	107
Revenues and royalties payable	67
Derivative instruments	242
Long-term debt	1,710
Asset retirement obligations	54

Other long-term liabilities	63
Amount attributable to liabilities assumed	$	2,307

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	2,922
Other property, equipment and land	16
Deferred income taxes	39
Other assets	106
Amount attributable to assets acquired	3,294
Net assets acquired and liabilities assumed	$	987

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

The purchase price allocation above is based on 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 were 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 $2.0 billion and unproved properties of $733 million, primarily in the Midland Basin and the Williston Basin. In October 2021, the Company completed the divestiture of the Williston Basin properties, acquired as part of the QEP Merger and consisting of approximately 95,000 net acres, to Oasis Petroleum Inc. for net cash proceeds of approximately $586 million, after customary closing adjustments. See “—Williston Basin Divestiture” below.

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 $116 million and $139 million of net income for the three and six months ended June 30, 2021.

Pro Forma Financial Information

The following unaudited summary pro forma financial information for the three and six months ended June 30, 2021 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, respectively, 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, 2021		Six Months Ended June 30, 2021
	(In millions, except per share amounts)
Revenues	$	1,656	$	3,137
Income (loss) from operations	$	1,022	$	1,706
Net income (loss)	$	388	$	534
Basic earnings (loss) per common share	$	2.14	$	2.95
Diluted earnings (loss) per common share	$	2.13	$	2.94

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

Williston Basin Divestiture

On October 21, 2021, the Company completed the divestiture of its Williston Basin oil and natural gas assets, consisting of approximately 95,000 net acres, to Oasis Petroleum Inc., for net cash proceeds of approximately $586 million, after customary closing adjustments. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss recognized on the sale. The Company used its net proceeds from this transaction toward debt reduction.

2021 Drop Down Transaction

On December 1, 2021, Diamondback completed the sale of certain water midstream assets to Rattler in exchange for cash proceeds of approximately $164 million, including post-closing adjustments, in a drop down transaction (the “Drop Down”). The midstream assets consist primarily of produced water gathering and disposal systems, produced water recycling facilities, and sourced water gathering and storage assets acquired by the Company through the Guidon Acquisition and the QEP Merger with a carrying value of approximately $164 million. The Company and Rattler have also mutually agreed to amend their commercial agreements covering produced water gathering and disposal and sourced water gathering services to add certain Diamondback leasehold acreage to Rattler’s dedication. The Drop Down transaction was accounted for as a transaction between entities under common control.

Viper’s Swallowtail Acquisition

On October 1, 2021, Viper acquired certain mineral and royalty interests from the Swallowtail entities pursuant to a definitive purchase and sale agreement for 15.25 million of Viper’s common units and approximately $225 million in cash (the “Swallowtail Acquisition”). The mineral and royalty interests acquired in the Swallowtail Acquisition represent approximately 2,313 net royalty acres primarily in the Northern Midland Basin, of which approximately 62% are operated by Diamondback as of December 31, 2021. The Swallowtail Acquisition had an effective date of August 1, 2021. The cash portion of this transaction was funded through a combination of Viper’s cash on hand and approximately $190 million of borrowings under Viper LLC’s revolving credit facility.

5. PROPERTY AND EQUIPMENT

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


	June 30,		December 31,
	2022		2021
	(In millions)
Oil and natural gas properties:
Subject to depletion	$	26,103	$	24,418
Not subject to depletion	8,097		8,496
Gross oil and natural gas properties	34,200		32,914
Accumulated depletion	(6,019)		(5,434)
Accumulated impairment	(7,954)		(7,954)
Oil and natural gas properties, net	20,227		19,526
Midstream assets	1,139		1,076
Other property, equipment and land	190		174
Accumulated depreciation, amortization, accretion and impairment	(187)		(157)
Total property and equipment, net	$	21,369	$	20,619

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, 2022 or 2021 based on the results of the respective quarterly ceiling tests.

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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.

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,
	2022		2021
	(In millions)
Asset retirement obligations, beginning of period	$	171	$	109
Additional liabilities incurred	26		6
Liabilities acquired	3		63
Liabilities settled and divested	(8)		(4)
Accretion expense	6		5
Revisions in estimated liabilities	75		13
Asset retirement obligations, end of period	273		192
Less current portion(1)	13		7
Asset retirement obligations - long-term	$	260	$	185

(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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7. DEBT

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


	June 30,		December 31,
	2022		2021
	(In millions)
5.375% Senior Notes due 2022	$	25	$	25
7.320% Medium-term Notes, Series A, due 2022	20		20
5.250% Senior Notes due 2023	10		10
2.875% Senior Notes due 2024	—		1,000
4.750% Senior Notes due 2025	—		500
3.250% Senior Notes due 2026	780		800
5.625% Senior Notes due 2026	14		14
7.125% Medium-term Notes, Series B, due 2028	73		100
3.500% Senior Notes due 2029	1,021		1,200
3.125% Senior Notes due 2031	789		900
4.400% Senior Notes due 2051	650		650
4.250% Senior Notes due 2052	750		—
DrillCo Agreement(1)	41		58
Unamortized debt issuance costs	(32)		(31)
Unamortized discount costs	(22)		(28)
Unamortized premium costs	5		8
Unamortized basis adjustment of dedesignated interest rate swap agreements(2)	(113)		(18)
Revolving credit facility	33		—
Viper revolving credit facility	250		304
Viper 5.375% Senior Notes due 2027	430		480
Rattler revolving credit facility	232		195
Rattler 5.625% Senior Notes due 2025	500		500
Total debt, net	5,456		6,687
Less: current maturities of long-term debt	(55)		(45)
Total long-term debt	$	5,401	$	6,642

(1) Represents amounts due under a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. to fund oil and natural gas development.

(2) Represents the unamortized basis adjustment related to two receive-fixed, pay variable interest rate swap agreements which were previously designated as fair value hedges of the Company’s $1.2 billion 3.500% fixed rate senior notes due 2029. These swaps were dedesignated in the second quarter of 2022 as discussed further in Note 11—Derivatives.

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

Credit Agreement

As of June 30, 2022, Diamondback E&P, as borrower, and Diamondback Energy, Inc., as parent guarantor, have a credit agreement, as amended, which provides for a maximum credit amount of $1.6 billion. As of June 30, 2022, the Company had $33 million in outstanding borrowings under the credit agreement and $3 million in outstanding letters of credit, which reduce available borrowings under the credit agreement on a dollar for dollar basis. During both the three and six months ended June 30, 2022 the weighted average interest rate on borrowings under the credit agreement was 2.69%. During the three and six months ended June 30, 2021, the weighted average interest rates on borrowings under the credit agreement were 1.68% and 1.67%, respectively.

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Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

On June 2, 2022, the Company and Diamondback E&P entered into a thirteenth amendment to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, with Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto.

This amendment, among other things, (i) extended the maturity date to June 2, 2027, which may be further extended by two one-year extensions pursuant to the terms set forth in the credit agreement, (ii) decreased the interest rate margin applicable to the loans and certain fees payable under the credit agreement and (iii) replaced the LIBOR interest rate benchmark with the secured overnight financing rate (“SOFR”). Outstanding borrowings under the credit agreement bear interest at a per annum rate elected by Diamondback E&P that is equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”) or (ii) an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 1-month Adjusted Term SOFR plus 1.0%), in each case plus the applicable margin. After giving effect to the amendment, (i) the applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate, and from 1.125% to 2.000% per annum in the case of Adjusted Term SOFR, in each case based on the pricing level, and (ii) the commitment fee ranges from 0.125% to 0.325% per annum on the average daily unused portion of the commitments, based on the pricing level. The pricing level depends on certain rating agencies’ rating of the Company’s long-term senior unsecured debt. The Company applied the optional expedient in ASU 2020-04, “Reference Rate Reform (Topic 848) - Facilitation of the Effects of Reference Rate Reform on Financial Reporting” for this contract modification, and as a result, the modification did not have an impact on its financial position, results of operations or liquidity.

As of June 30, 2022, the Company was in compliance with all financial maintenance covenants under the credit agreement.

March 2022 Notes Offering

On March 17, 2022, Diamondback Energy, Inc. issued $750 million aggregate principal amount of 4.250% Senior Notes due March 15, 2052 (the “March 2022 Notes”) and received net proceeds of $739 million, after deducting debt issuance costs and discounts of $11 million and underwriting discounts and offering expenses. Interest on the March 2022 Notes is payable semi-annually on March 15 and September 15 of each year, beginning on September 15, 2022.

The March 2022 Notes are the Company’s senior unsecured obligations and are fully and unconditionally guaranteed by Diamondback E&P. The March 2022 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.

The Company may redeem the March 2022 Notes in whole or in part at any time prior to September 15, 2051 at the redemption price set forth in the fifth supplemental indenture to the IG Indenture.

Redemptions and Repurchases of Notes

In the first quarter of 2022, the Company fully redeemed the $500 million and $1.0 billion principal amounts of its outstanding 4.750% 2025 Senior Notes and 2.875% 2024 Senior Notes, respectively. Cash consideration for these redemptions totaled $1.6 billion, including make-whole premiums of $47 million, which resulted in a loss on extinguishment of debt of $54 million during the first quarter of 2022. The Company funded the redemptions with a portion of the net proceeds from the March 2022 Notes offering and cash on hand.

In the second quarter of 2022, the Company repurchased principal amounts of $27 million of its 7.125% Medium-term Notes due 2028, $111 million of its 3.125% Senior Notes due 2031, $179 million of its 3.500% Senior Notes due 2029 and $20 million of its 3.250% Senior Notes due 2026 for total cash consideration, including accrued interest paid, of $322 million. Additionally, Viper repurchased $50 million in principal amount of its 5.375% Senior Notes due 2027 for total cash consideration of $49 million. These repurchases resulted in an immaterial loss on extinguishment of debt during the second quarter of 2022. The Company funded its repurchases with cash on hand and Viper funded its repurchases with cash on hand and borrowings under the Viper credit agreement.

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Viper’s Credit Agreement

Viper LLC’s credit agreement, as amended, 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. As of June 30, 2022, the elected commitment amount was $500 million with $250 million of outstanding borrowings and $250 million available for future borrowings. During the three and six months ended June 30, 2022 and 2021, the weighted average interest rates on borrowings under the Viper credit agreement were 3.20%, 2.88%, 1.93% and 1.90%, respectively. The Viper credit agreement will mature on June 2, 2025. As of June 30, 2022, 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, 2022, Rattler LLC had $232 million of outstanding borrowings and $368 million available for future borrowings under the Rattler credit agreement. During the three and six months ended June 30, 2022 and 2021, the weighted average interest rates on borrowings under the Rattler credit agreement were, in each case, 2.03%, 1.73%, 1.36% and 1.39%, respectively. The revolving credit facility will mature on May 28, 2024. As of June 30, 2022, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

8. STOCKHOLDERS’ EQUITY AND EARNINGS (LOSS) PER SHARE

Stock Repurchase Program

In September 2021, the Company’s board of directors approved a stock repurchase program to acquire up to $2.0 billion of the Company’s outstanding common stock. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the three and six months ended June 30, 2022, the Company repurchased approximately $303 million and $310 million of common stock under this repurchase program, respectively. As of June 30, 2022, approximately $1.3 billion remained available for use to repurchase shares under the Company’s common stock repurchase program.

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,
	2022		2021		2022		2021
	(In millions)
Net income (loss) attributable to the Company	$	1,416	$	311	$	2,195	$	531
Change in ownership of consolidated subsidiaries	(9)		(3)		(21)		(7)
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest	$	1,407	$	308	$	2,174	$	524

Earnings (Loss) Per Share

The Company’s earnings (loss) per share amounts have been computed using the two-class method. The two-class method is an earnings allocation proportional to the respective ownership among holders of common stock and participating securities. 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 non-participating securities 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.

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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,
	2022		2021		2022		2021
	($ in millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common stock	$	1,416	$	311	$	2,195	$	531
Less: distributed and undistributed earnings allocated to participating securities(1)	(13)		(3)		(17)		(5)
Net income (loss) attributable to common stockholders	$	1,403	$	308	$	2,178	$	526
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	176,570		181,009		177,064		172,636
Effect of dilutive securities:
Weighted-average potential common shares issuable(2)	306		190		316		170
Diluted weighted average common shares outstanding	176,876		181,199		177,380		172,806
Basic net income (loss) attributable to common stock	$	7.95	$	1.70	$	12.30	$	3.05
Diluted net income (loss) attributable to common stock	$	7.93	$	1.70	$	12.28	$	3.04

(1) Unvested restricted stock awards that contain non-forfeitable distribution equivalent rights are considered participating securities and therefore are included in the earnings per share calculation pursuant to the two-class method.

(2) For the three months ended June 30, 2022, there were 76,473 potential common shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive. For the three and six months ended June 30, 2021, there were 99,835 and 137,357 potential common shares, respectively, which were excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive.

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, 2022, the Company had 5.1 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, 2022, the Company had outstanding restricted stock units and performance-based restricted stock units under the Equity Plan. The Company also has immaterial amounts of restricted share awards, stock options and stock appreciation rights outstanding which were issued under plans assumed in connection with previously completed mergers. 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,
	2022		2021		2022		2021
	(In millions)
General and administrative expenses	$	13	$	13	$	28	$	23
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$	6	$	5	$	10	$	9

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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, 2022 under the Equity Plan:


	Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2021	1,079,589	$	62.09
Granted	319,035	$	132.84
Vested	(178,185)	$	92.82
Forfeited	(39,231)	$	68.58
Unvested at June 30, 2022	1,181,208	$	76.35

The aggregate fair value of restricted stock units that vested during the six months ended June 30, 2022 was $17 million. As of June 30, 2022, the Company’s unrecognized compensation cost related to unvested restricted stock units was $70 million, which is expected to be recognized over a weighted-average period of 1.9 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, 2022:


	Performance Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2021	456,459	$	100.17
Granted	126,905	$	237.13


Unvested at June 30, 2022(1)	583,364	$	129.96

(1)A maximum of 1,408,973 units could be awarded based upon the Company’s final TSR ranking.

As of June 30, 2022, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $45 million, which is expected to be recognized over a weighted-average period of 1.6 years.

In March 2022, eligible employees received performance restricted stock unit awards totaling 126,905 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 3-year performance period of January 1, 2022 to December 31, 2024 and cliff vest at December 31, 2024 subject to continued employment. The initial payout of the March 2022 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.

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:


	2022
Grant-date fair value	$	237.13

Risk-free rate	1.44		%
Company volatility	72.10		%

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10. INCOME TAXES

The following table provides the Company’s provision for (benefit from) income taxes and the effective income tax rate for the periods indicated:


	Three Months Ended June 30,						Six Months Ended June 30,
	2022			2021			2022			2021
	(In millions, except for tax rate)
Provision for (benefit from) income taxes	$	402		$	94		$	623		$	159
Effective income tax rate	21.6		%	22.3		%	21.6		%	22.4		%

Total income tax expense from continuing operations for the three and six months ended June 30, 2022 and 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. As of June 30, 2022 and 2021, 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.

For the three and six months ended June 30, 2022 and 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’s opening balance sheet net deferred tax asset was finalized during the first quarter of 2022 at $39 million, and primarily consisted of deferred tax assets related to tax attributes acquired from QEP, partially offset by a valuation allowance related to federal and state tax attributes estimated not more likely than to be realized prior to expiration 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.

11. DERIVATIVES

At June 30, 2022, the Company has commodity derivative contracts and interest rate swaps outstanding. All derivative financial instruments are recorded at fair value.

Commodity Contracts

The Company has entered into multiple crude oil and natural gas 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 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. As such, the Company does not require collateral from its counterparties.

The Company had certain commodity derivative contracts that contained an other-than-insignificant financing element at inception during 2021 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.

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As of June 30, 2022, 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 Floor Price	Weighted Average Ceiling Price
OIL
July - Dec.	2022	Basis Swap(1)	10,000	Argus WTI Midland	$0.84		$—	$—
July - Dec.	2022	Roll Swap	55,000	WTI	$0.89		$—	$—
July - Sep.	2022	Costless Collar	19,000	Brent	$—		$53.95	$98.59
July - Sep.	2022	Costless Collar	11,000	Argus WTI Houston	$—		$50.00	$89.28
July - Sep.	2022	Costless Collar	4,000	WTI	$—		$45.00	$92.65
Oct. - Dec.	2022	Costless Collar	15,000	Brent	$—		$55.00	$103.06
Oct. - Dec.	2022	Costless Collar	7,000	Argus WTI Houston	$—		$50.00	$95.55
Oct. - Dec.	2022	Costless Collar	4,000	WTI	$—		$50.00	$128.01
Jan. - June	2023	Costless Collar	6,000	Brent	$—		$60.00	$114.57
Jan. - Dec.	2023	Basis Swap(1)	2,000	Argus WTI Midland	$0.60		$—	$—









NATURAL GAS
July - Dec.	2022	Basis Swap(1)	330,000	Waha Hub	$(0.68)		$—	$—
July - Dec.	2022	Costless Collar	380,000	Henry Hub	$—		$2.79	$6.24
Jan. - June	2023	Basis Swap(1)	320,000	Waha Hub	$(1.19)		$—	$—
Jan. - Mar.	2023	Costless Collar	330,000	Henry Hub	$—		$3.09	$8.52
Apr. - June	2023	Costless Collar	290,000	Henry Hub	$—		$3.12	$8.23
July - Dec.	2023	Costless Collar	270,000	Henry Hub	$—		$3.13	$8.27
July - Dec.	2023	Basis Swap(1)	300,000	Waha Hub	$(1.24)		$—	$—

(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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Settlement Month	Settlement Year	Type of Contract	Bbls Per Day	Index	Strike Price	Weighted Average Differential	Deferred Premium
OIL
July - Sep.	2022	Put	69,000	Brent	$50.87	$—	$1.79
July - Sep.	2022	Put	20,000	Argus WTI Houston	$50.50	$—	$1.84
July - Sep.	2022	Put	8,000	WTI	$47.50	$—	$1.52
Oct. - Dec.	2022	Put	69,000	Brent	$51.01	$—	$1.78
Oct. - Dec.	2022	Put	20,000	Argus WTI Houston	$51.00	$—	$1.81
Oct. - Dec.	2022	Put	8,000	WTI	$55.00	$—	$1.54
July - Dec.	2022	Basis Put(1)	50,000	Brent	$—	$(10.40)	$0.78
Jan. - Mar.	2023	Put	37,000	Brent	$51.89	$—	$1.74
Jan. - Mar.	2023	Put	10,000	Argus WTI Houston	$52.00	$—	$1.77
Jan. - Mar.	2023	Put	6,000	WTI	$55.00	$—	$1.87
Apr. - June	2023	Put	29,000	Brent	$51.72	$—	$1.81
Apr. - June	2023	Put	8,000	Argus WTI Houston	$51.25	$—	$1.77
July - Sep.	2023	Put	9,000	Brent	$50.00	$—	$1.91
July - Sep.	2023	Put	2,000	Argus WTI Houston	$55.00	$—	$1.86

(1) The Company has basis puts for the spread between the Brent crude oil price and NYMEX WTI crude oil price.

During the six months ended June 30, 2022, the Company terminated certain commodity derivative contracts prior to their contractual maturities as shown in the table below:


					Swaps	Collars
Settlement Month	Settlement Year	Type of Contract	Bbls Per Day	Index	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Ceiling Price
OIL
Apr. - June	2022	Costless Collar	8,000	WTI	$—	$45.00	$71.60
Apr. - June	2022	Costless Collar	8,000	Brent	$—	$45.00	$74.78
Apr. - June	2022	Costless Collar	6,000	Argus WTI Houston	$—	$45.00	$69.53
Apr. - Sep.	2022	Costless Collar	2,000	Brent	$—	$50.00	$80.00
Apr. - Sep.	2022	Costless Collar	2,000	Argus WTI Houston	$—	$50.00	$76.70
July - Sep.	2022	Costless Collar	4,000	Argus WTI Houston	$—	$50.00	$75.00
July - Dec.	2022	Swaption	8,250	Brent	$68.62	$—	$—

Interest Rate Swaps

In the second quarter of 2021, the Company entered into two interest rate swap agreements for notional amounts of $600 million, which were designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 (the “2029 Notes”) at inception. The Company receives a fixed 3.50% rate of interest on these swaps and pays an average variable rate of interest based on three month LIBOR plus 2.1865%, thereby limiting its exposure to changes in the fair value of debt due to movements in LIBOR interest rates. Under hedge accounting, these interest rate swaps were considered perfectly effective and gains and losses due to changes in the fair value of the interest rate swaps were completely offset by changes in the fair value of the hedged portion of the 2029 Notes in the condensed consolidated statements of operations.

In the second quarter of 2022, the Company elected to fully dedesignate these interest rate swaps and hedge accounting was discontinued. The cumulative fair value basis adjustment recorded on the 2029 Notes at the time of dedesignation totaled $135 million. This basis adjustment is being amortized to interest expense over the remaining term of the 2029 Notes utilizing

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the effective interest method. The dedesignated interest rate swaps are considered economic hedges of the Company’s fixed-rate debt. As such, changes in the fair value of the interest rate swaps after the date of dedesignation have been recorded in earnings under the caption “Gain (loss) on derivative instruments, net” in the condensed consolidated statements of operations.

During 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.

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,
	2022		2021		2022		2021
	(In millions)
Gain (loss) on derivative instruments, net:
Commodity contracts	$	(102)	$	(497)	$	(654)	$	(791)
Interest rate swaps	1		—		1		130
Total	$	(101)	$	(497)	$	(653)	$	(661)

Net cash received (paid) on settlements:
Commodity contracts(1)	$	(306)	$	(323)	$	(726)	$	(505)
Interest rate swaps(2)	6		—		6		80
Total	$	(300)	$	(323)	$	(720)	$	(425)

(1)The six months ended June 30, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $135 million.

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

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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.

See Note 4—Acquisitions and Divestitures for discussion of the fair values of proved oil and natural gas properties assumed in business combinations.

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 fair value of interest rate swaps is recorded as an asset or liability on the condensed consolidated balance sheet. At December 31, 2021, the net change in fair value of the Company’s interest rate swaps designated as hedges were offset by the change in value of the hedged item, long-term debt, within the condensed consolidated balance sheet.

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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 under the captions “Derivative instruments” in the Company’s condensed consolidated balance sheets as of June 30, 2022 and December 31, 2021. The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates.


	As of June 30, 2022
	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 assets- Derivative instruments:

Commodity derivative instruments	$	—	$	106	$	—	$	106	$	(89)	$	17

Non-current assets- Derivative instruments:

Commodity derivative instruments	$	—	$	51	$	—	$	51	$	(18)	$	33

Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	231	$	—	$	231	$	(89)	$	142
Interest rate swaps	$	—	$	20	$	—	$	20	$	—	$	20
Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	22	$	—	$	22	$	(18)	$	4
Interest rate swaps	$	—	$	119	$	—	$	119	$	—	$	119


	As of December 31, 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 assets- Derivative instruments:

Commodity derivative instruments	$	—	$	60	$	—	$	60	$	(57)	$	3
Interest rate swaps designated as hedges	$	—	$	10	$	—	$	10	$	—	$	10
Non-current assets- Derivative instruments:

Commodity derivative instruments	$	—	$	12	$	—	$	12	$	(8)	$	4
Interest rate swaps designated as hedges	$	—	$	1	$	—	$	1	$	(1)	$	—
Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	231	$	—	$	231	$	(57)	$	174

Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	9	$	—	$	9	$	(8)	$	1
Interest rate swaps designated as hedges	$	—	$	29	$	—	$	29	$	(1)	$	28

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Assets and Liabilities Not Recorded at Fair Value

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, 2022				December 31, 2021
	Carrying				Carrying
	Value		Fair Value		Value		Fair Value
	(In millions)
Debt	$	5,456	$	5,183	$	6,687	$	7,148

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 quoted market price at each period end, a Level 1 classification in the fair value hierarchy.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include those acquired in a business combination, inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. Refer to Note 4—Acquisitions and Divestitures and Note 5—Property and Equipment for additional discussion of nonrecurring fair value adjustments.

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. SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
		2022		2021
		(In millions)
Supplemental disclosure of cash flow information:

Cash paid (received) for income taxes		$	362	$	(100)
Supplemental disclosure of non-cash transactions:
Accrued capital expenditures included in accounts payable and accrued expenses		$	340	$	296

Common stock issued for business combinations		$	—	$	1,727

14. COMMITMENTS AND CONTINGENCIES

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

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

15. SUBSEQUENT EVENTS

Second Quarter 2022 Dividend Declaration

On July 29, 2022, the board of directors of the Company declared a cash dividend for the second quarter of 2022 of $3.05 per share of common stock, payable on August 23, 2022 to its stockholders of record at the close of business on August 16, 2022. The dividend consists of a base quarterly dividend of $0.75 per share of common stock and a variable quarterly dividend of $2.30 per share of common stock. Future base and variable dividends are at the discretion of the board of directors of the Company.

Stock Repurchase Program

Subsequent to the quarter, the Company repurchased approximately $200 million in shares of Diamondback’s common stock through July 29, 2022. On July 28, 2022, the Company’s board of directors approved an increase in the Company’s common stock repurchase program from $2.0 billion to $4.0 billion.

Redemptions of Notes

In July 2022, the Company fully redeemed principal amounts of $25 million and $20 million of its 5.375% Notes due 2022 and 7.320% Medium-term Notes due 2022, respectively.

16. 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.

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


	Upstream		Midstream Operations		Eliminations		Total
	(In millions)
Three Months Ended June 30, 2022:
Third-party revenues	$	2,753	$	15	$	—	$	2,768
Intersegment revenues	—		90		(90)		—
Total revenues	2,753		105		(90)		2,768
Depreciation, depletion, amortization and accretion	314		16		—		330


Income (loss) from operations	1,962		39		(23)		1,978
Interest expense, net	(30)		(9)		—		(39)
Other income (expense)	(100)		28		(4)		(76)
Provision for (benefit from) income taxes	398		4		—		402
Net income (loss) attributable to non-controlling interest	33		12		—		45
Net income (loss) attributable to Diamondback Energy, Inc.	1,401		42		(27)		1,416
As of June 30, 2022:
Total assets	$	21,833	$	2,022	$	(407)	$	23,448

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)


	Upstream		Midstream Operations		Eliminations		Total
	(In millions)
Three Months Ended June 30, 2021:
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 December 31, 2021:
Total assets	$	21,329	$	1,942	$	(373)	$	22,898


	Upstream		Midstream Operations		Eliminations		Total
	(In millions)
Six Months Ended June 30, 2022:
Third-party revenues	$	5,144	$	32	$	—	$	5,176
Intersegment revenues	—		177		(177)		—
Total revenues	5,144		209		(177)		5,176
Depreciation, depletion, amortization and accretion	606		37		—		643


Income (loss) from operations	3,599		78		(39)		3,638
Interest expense, net	(61)		(18)		—		(79)
Other income (expense)	(700)		37		(9)		(672)
Provision for (benefit from) income taxes	617		6		—		623
Net income (loss) attributable to non-controlling interest	49		20		—		69
Net income (loss) attributable to Diamondback Energy, Inc.	2,172		71		(48)		2,195
As of June 30, 2022:
Total assets	$	21,833	$	2,022	$	(407)	$	23,448


	Upstream		Midstream Operations		Eliminations		Total
	(In millions)
Six Months Ended June 30, 2021:
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


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 December 31, 2021:
Total assets	$	21,329	$	1,942	$	(373)	$	22,898

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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, 2021. 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.

Despite the recovery in commodity prices and rising demand in recent quarters, we expect to hold our oil production levels flat during 2022, using excess cash flow for debt repayment and/or return to our stockholders rather than expanding our drilling program. During the second quarter of 2022 we have continued to use cash on hand to pay down debt and believe that we now have a strong balance sheet that can withstand another down cycle. We are focused on maintaining high cash margins, a low-cost structure to drive an increasing return on capital and operational excellence, working to mitigate inflationary pressures through improvements and efficiencies in our drilling and completion programs. Going forward, we will continue to remain flexible, using a combination of our growing and sustainable base dividend, variable dividend and opportunistic share repurchase program to generate the highest value proposition for our shareholders.

Recent Developments

Second Quarter 2022 Highlights

•We recorded net income of $1.4 billion for the second quarter of 2022.

•Paid dividends to shareholders of $541 million during the second quarter and declared a cash dividend for the second quarter of 2022 of $3.05 per share of common stock, consisting of a base quarterly dividend of $0.75 per share of common stock and a variable quarterly dividend of $2.30 per share of common stock.

•Repurchased approximately $303 million of our common stock, leaving approximately $1.3 billion available for future purchases under our common stock repurchase program at June 30, 2022. The repurchase program was further increased from $2.0 billion to $4.0 billion in July 2022.

•Repurchased an aggregate of $337 million in principal amount of our outstanding senior notes with cash on hand.

•Our cash operating costs for the second quarter of 2022 were $12.24 per BOE, including lease operating expenses of $4.59 per BOE, cash general and administrative expenses of $0.75 per BOE and production and ad valorem taxes and gathering and transportation expenses of $6.90 per BOE.

•Our average production was 380.5 MBOE/d during the second quarter of 2022.

•Drilled 43 gross horizontal wells in the Midland Basin and 9 gross horizontal wells in the Delaware Basin, and turned 62 gross operated horizontal wells (56 in the Midland Basin and 6 in the Delaware Basin) to production.

• Incurred capital expenditures, excluding acquisitions, of $468 million during the second quarter of 2022.

See Part II, Item 1A. Risk Factors in this report for discussion of the potential risks of climate change and related litigation on our financial condition, results of operations or cash flows.

Commodity Prices and Inflation

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, extreme weather conditions and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. During 2021 and the first half of 2022, the posted NYMEX WTI price for crude oil ranged from $47.62 to $123.70 per Bbl, and the NYMEX Henry Hub price

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of natural gas ranged from $2.45 to $9.32 per MMBtu, with seven-year highs reached in 2022. The war in Ukraine, the COVID-19 pandemic, and recent measures to combat inflation have continued to contribute to economic and pricing volatility during 2022. Although the impact of inflation on our business has been insignificant in prior periods, inflation in the U.S. has been rising at its fastest rate in over 40 years, creating inflationary pressure on the cost of services, equipment and other goods in the energy industry and other sectors, which is contributing to labor and materials shortages across the supply-chain. Additionally, OPEC and its non-OPEC allies, known collectively as OPEC+, continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels, and has planned production increases throughout 2022, however such increases cannot be guaranteed. As such, pricing may remain volatile during the second half of 2022.

Rattler Merger

On May 15, 2022, we entered into the Merger Agreement with Rattler, Rattler Midstream GP LLC, the General Partner, and Merger Sub. The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, at the effective time of the Rattler Merger, (i) Merger Sub will be merged with and into Rattler, with Rattler surviving and continuing as the surviving entity in the merger and (ii) each issued and outstanding publicly held common unit representing a limited partner interest in Rattler (other than any common units owned by the Company and its subsidiaries) will be converted into the right to receive 0.113 of a share of common stock, par value $0.01 per share, of the Company. The Merger Agreement also specifies the treatment of outstanding Rattler equity awards in connection with the Merger. Our board of directors and the board of directors of Rattler’s General Partner (acting upon the recommendation of its conflicts committee) unanimously approved the merger. We and Rattler expect that the Rattler Merger will close, subject to certain conditions, reasonably promptly following the distribution payment date for the second quarter 2022 distribution to Rattler’s unitholders reported by Rattler.

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, 2022, we had approximately 448,859 net acres, which primarily consisted of approximately 267,634 net acres in the Midland Basin and 153,166 net acres in the Delaware Basin.

The following table sets forth the total number of operated horizontal wells drilled and completed during the second quarter of 2022:


	Three Months Ended June 30, 2022				Six Months Ended June 30, 2022
	Drilled		Completed(1)		Drilled		Completed(2)
Area	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Midland Basin	43	39	56	52	90	85	110	102
Delaware Basin	9	9	6	6	23	22	21	19

Total	52	48	62	58	113	107	131	121

(1)The average lateral length for the wells completed during the second quarter of 2022 was 10,444 feet. Operated completions during the second quarter of 2022 consisted of 20 Wolfcamp A wells, 15 Lower Spraberry wells, 13 Wolfcamp B wells, seven Jo Mill wells, five Middle Spraberry wells and two Second Bone Spring wells.

(2)The average lateral length for the wells completed during the first six months of 2022 was 10,030 feet. Operated completions during the first six months of 2022 consisted of 35 Wolfcamp A wells, 34 Lower Spraberry wells, 19 Jo Mill wells, 19 Wolfcamp B wells, 14 Middle Spraberry wells, eight Second Bone Spring wells, one Third Bone Spring well and one Barnett well.

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As of June 30, 2022, we operated the following wells:


	As of June 30, 2022
	Vertical Wells		Horizontal Wells		Total
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	2,216	2,075	1,857	1,728	4,073	3,803
Delaware Basin	47	42	710	662	757	704

Total	2,263	2,117	2,567	2,390	4,830	4,507

As of June 30, 2022, we held interests in 11,382 gross (4,619 net) wells, including wells that we do not operate.

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 Fivestones areas within the Permian Basin. Rattler’s water sourcing and distribution assets consist of water wells, hydraulic fracturing pits, pipelines and water treatment and recycling 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 609 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, 2022 and 2021. See Note 16—Segment Information of the condensed notes to the consolidated financial statements included elsewhere in this report for financial information related to our midstream operations.

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Comparison of the Three Months Ended June 30, 2022 and March 31, 2022

As noted in “—Recent Developments,” the markets for oil and natural gas are highly volatile and are influenced by a number of factors which can lead to significant changes in our results of operations and management’s operational strategy on a quarterly basis. Accordingly, our results of operations discussion focuses on a comparison of the current quarter’s results of operations with those of the immediately preceding quarter. We believe our discussion provides investors with a more meaningful analysis of material operational and financial changes which occurred during the quarter based on current market and operational trends.

Results of Operations

The following table sets forth selected operating data for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022		March 31, 2022
Revenues (In millions):
Oil sales	$	2,189	$	1,946
Natural gas sales	264		154
Natural gas liquid sales	299		289
Total oil, natural gas and natural gas liquid revenues	$	2,752	$	2,389

Production Data:
Oil (MBbls)	20,120		20,055
Natural gas (MMcf)	42,912		42,645
Natural gas liquids (MBbls)	7,349		7,161
Combined volumes (MBOE)(1)	34,621		34,324

Daily oil volumes (BO/d)	221,099		222,833
Daily combined volumes (BOE/d)	380,451		381,378

Average Prices:
Oil ($ per Bbl)	$	108.80	$	97.03
Natural gas ($ per Mcf)	$	6.15	$	3.61
Natural gas liquids ($ per Bbl)	$	40.69	$	40.36
Combined ($ per BOE)	$	79.49	$	69.60

Oil, hedged ($ per Bbl)(2)	$	97.32	$	83.47
Natural gas, hedged ($ per Mcf)(2)	$	4.40	$	3.31
Natural gas liquids, hedged ($ per Bbl)(2)	$	40.69	$	40.36
Average price, hedged ($ per BOE)(2)	$	70.65	$	61.30

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

(2)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.

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Production Data. Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables provide information on the mix of our production for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022		March 31, 2022
Oil (MBbls)	58	%	58	%
Natural gas (MMcf)	21	%	21	%
Natural gas liquids (MBbls)	21	%	21	%
	100	%	100	%


	Three Months Ended June 30, 2022				Three Months Ended March 31, 2022
	Midland Basin	Delaware Basin	Other(1)	Total	Midland Basin	Delaware Basin	Other(2)	Total
Production Data:
Oil (MBbls)	14,713	5,378	29	20,120	13,921	6,101	33	20,055
Natural gas (MMcf)	28,539	14,257	116	42,912	26,873	15,681	91	42,645
Natural gas liquids (MBbls)	5,123	2,213	13	7,349	4,750	2,390	21	7,161
Total (MBoe)	24,593	9,967	61	34,621	23,150	11,105	69	34,324

(1)Includes the Eagle Ford Shale and Rockies.

(2)Includes the Eagle Ford Shale and Rockies.

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 second quarter of 2022 increased by $363 million, or 15%, to $2.8 billion from $2.4 billion during the first quarter of 2022. Higher average oil prices, and to a lesser extent natural gas liquids prices, contributed $348 million of the total increase.

Higher commodity prices in the second quarter of 2022 compared to the first quarter of 2022 primarily reflect the continued increase in demand compared to supply for oil due to macroeconomic factors such as the war in Ukraine as discussed in “—Recent Developments” above. The increase in production resulted primarily from having one additional day of production in the second quarter of 2022 compared to the first quarter of 2022.

Other Revenues. The following table shows other insignificant revenues for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022		March 31, 2022
	(In millions)
Midstream services	$	14	$	17
Other operating income	$	2	$	2

Lease Operating Expenses. The following table shows lease operating expenses for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022				March 31, 2022
	Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
Lease operating expenses	$	159	$	4.59	$	149	$	4.34

Lease operating expenses increased by $10 million, or $0.25 on a per BOE basis for the second quarter of 2022 compared to the first quarter of 2022, primarily due to service cost inflation.

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Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022					March 31, 2022
	Amount			Per BOE		Amount			Per BOE
	(In millions, except per BOE amounts)
Production taxes	$	139		$	4.01	$	120		$	3.50
Ad valorem taxes	39			1.13		41			1.19
Total production and ad valorem expense	$	178		$	5.14	$	161		$	4.69

Production taxes as a % of oil, natural gas, and natural gas liquids revenue	5.1		%			5.0		%

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 for the second quarter of 2022 remained consistent with the first quarter of 2022.

Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices, which were adjusted upward during the first quarter of 2022 based on the recovery in commodity prices during 2021 as compared to 2020. For the second quarter of 2022, ad valorem taxes remained relatively consistent with the first quarter of 2022.

Gathering and Transportation Expense. The following table shows gathering and transportation expense for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022				March 31, 2022
	Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
Gathering and transportation expense	$	61	$	1.76	$	59	$	1.72

Gathering and transportation expenses remained relatively consistent in total and on a per BOE basis for the second quarter of 2022 compared to the first quarter of 2022.

Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022		March 31, 2022
	(In millions, except BOE amounts)
Depletion of proved oil and natural gas properties	$	306	$	286
Depreciation of midstream assets	15		20
Depreciation of other property and equipment	3		4
Other amortization	3		—
Asset retirement obligation accretion	3		3
Depreciation, depletion, amortization and accretion expense	$	330	$	313
Oil and natural gas properties depletion rate per BOE	$	8.84	$	8.33

The increase in depletion of proved oil and natural gas properties of $20 million for the second quarter of 2022 as compared to the first quarter of 2022 resulted largely from an increase in the average depletion rate, which was primarily attributable to higher value leasehold being transferred into the amortization base during the second quarter of 2022.

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General and Administrative Expenses. The following table shows general and administrative expenses for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022				March 31, 2022
	Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
General and administrative expenses	$	26	$	0.75	$	21	$	0.61
Non-cash stock-based compensation	13		0.38		15		0.44
Total general and administrative expenses	$	39	$	1.13	$	36	$	1.05

The increase in general and administrative expenses for the second quarter of 2022 compared to the first quarter of 2022 was largely due to a $2 million increase in charitable donations during the second quarter of 2022.

Other Operating Costs and Expenses. The following table shows other insignificant operating costs and expenses for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022		March 31, 2022
	(In millions)
Midstream services expenses	$	23	$	22

Other operating expenses	$	—	$	8

Net Interest Expense. The following table shows the components of net interest expense for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022		March 31, 2022
	(In millions)
Revolving credit agreements	$	6	$	4
Senior notes	54		61
Amortization of debt issuance costs and discounts	7		5
Other	2		1
Capitalized interest	(30)		(31)


Interest expense, net	$	39	$	40

Total interest expense, net was consistent between the second quarter and first quarter of 2022. The components of interest expense reflect a decrease of $7 million in interest expense for our senior notes due to redemptions and repurchases of approximately $1.9 billion in principal in first and second quarters of 2022, partially offset by interest expense incurred on the March 2022 Notes. See Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report 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 months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022		March 31, 2022
	(In millions)
Gain (loss) on derivative instruments, net	$	(101)	$	(552)
Net cash received (paid) on settlements(1)	$	(300)	$	(420)

(1)The three months ended June 30, 2022 includes $6 million in realized settlements related to interest rate swaps. The three months ended March 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $135 million.

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We have not designated our commodity derivative instruments as hedges for accounting purposes. As a result, we mark our commodity derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in earnings.

Certain of our interest rate swaps were designated as fair value hedges for accounting purposes, but were fully dedesignated at management’s election in the second quarter of 2022. After dedesignation, gains and losses due to settlements and changes in the fair value of the interest rate swaps are recognized in earnings in the caption “Gain (loss) on derivative instruments, net” on the condensed consolidated statements of operations. See Note 11—Derivatives of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding our derivative instruments

Other Income (Expense). The following table shows other income and expenses for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022		March 31, 2022
	(In millions)
Other income (expense), net	$	1	$	1
Gain (loss) on extinguishment of debt	$	(4)	$	(54)
Income (loss) from equity investments	$	28	$	9

Gain (loss) on extinguishment of debt reflects the difference between the carrying value and reacquisition price for the repurchases of various senior notes in the second quarter of 2022 and the redemptions of our 4.750% 2025 Senior Notes and 2.875% 2024 Senior Notes in the first quarter of 2022. See Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding gain (loss) on extinguishment of debt.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the three months ended June 30, 2022 and March 31, 2022:


	Three Months Ended
	June 30, 2022		March 31, 2022
	(In millions)
Provision for (benefit from) income taxes	$	402	$	221

The change in our income tax provision for the second quarter of 2022 compared to the first quarter of 2022 was primarily due to the increase in pre-tax income between the periods which resulted primarily from the changes in gain (loss) on derivatives and revenues from oil, natural gas and natural gas liquids discussed above. See Note 10—Income Taxes for further discussion of our income tax expense.

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Comparison of the Six Months Ended June 30, 2022 and 2021

The following table sets forth selected operating data for the six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
		2022		2021
Revenues (In millions):
Oil sales		$	4,135	$	2,339
Natural gas sales		418		211
Natural gas liquid sales		588		289
Total oil, natural gas and natural gas liquid revenues		$	5,141	$	2,839

Production Data:
Oil (MBbls)		40,175		38,645
Natural gas (MMcf)		85,557		78,615
Natural gas liquids (MBbls)		14,510		12,452
Combined volumes (MBOE)(1)		68,945		64,200

Daily oil volumes (BO/d)		221,961		213,508
Daily combined volumes (BOE/d)		380,912		354,696

Average Prices:
Oil ($ per Bbl)		$	102.92	$	60.53
Natural gas ($ per Mcf)		$	4.89	$	2.68
Natural gas liquids ($ per Bbl)		$	40.52	$	23.21
Combined ($ per BOE)		$	74.57	$	44.22

Oil, hedged ($ per Bbl)(2)		$	90.40	$	48.54
Natural gas, hedged ($ per Mcf)(2)		$	3.86	$	2.18
Natural gas liquids, hedged ($ per Bbl)(2)		$	40.52	$	23.05
Average price, hedged ($ per BOE)(2)		$	65.99	$	36.36

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

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 six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
	2022		2021
Oil (MBbls)	58	%	60	%
Natural gas (MMcf)	21	%	21	%
Natural gas liquids (MBbls)	21	%	19	%
	100	%	100	%

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	Six Months Ended June 30, 2022				Six Months Ended June 30, 2021
	Midland Basin	Delaware Basin	Other(1)	Total	Midland Basin	Delaware Basin	Other(2)	Total
Production Data:
Oil (MBbls)	28,634	11,479	62	40,175	23,800	12,827	2,018	38,645
Natural gas (MMcf)	55,412	29,938	207	85,557	43,576	31,293	3,746	78,615
Natural gas liquids (MBbls)	9,873	4,603	34	14,510	7,599	4,137	716	12,452
Total (MBoe)	47,742	21,072	131	68,945	38,662	22,180	3,358	64,200

(1)Includes the Eagle Ford Shale and Rockies.

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

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 six months ended June 30, 2022 increased by $2.3 billion, or 81%, to $5.1 billion from $2.8 billion during the six months ended June 30, 2021. Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed $2.1 billion of the total increase. The remainder of the overall change is due to a 7% increase in combined volumes sold.

Higher commodity prices during the six months ended June 30, 2022 compared to the same period in 2021 primarily reflect the increase in demand for oil due to economic recovery from the COVID-19 pandemic and other macroeconomic factors such as the war in Ukraine as discussed in “—Recent Developments” above. The increase in production for the six months ended June 30, 2022 compared to the same period in 2021 resulted primarily from recognizing six months of production in the current period associated with production from the Guidon Acquisition and QEP Merger, which occurred late in the first quarter 2021, and new well additions between periods.

Other Revenues. The following table shows the other insignificant revenues for the six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
	2022		2021
	(In millions)
Midstream services	$	31	$	23
Other operating income	$	4	$	3

Lease Operating Expenses. The following table shows lease operating expenses for the six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
		2022	2021
			Amount		Per BOE		Amount		Per BOE
			(In millions, except per BOE amounts)
Lease operating expenses			$	308	$	4.47	$	259	$	4.03

Lease operating expenses increased by $49 million, or $0.44 per BOE for the six months ended June 30, 2022 compared to the same period in 2021. Approximately $15 million of this increase is due to production and operating expenses incurred on wells acquired in the Guidon Acquisition and the QEP Merger in the first quarter of 2021, including certain properties in the Williston Basin that were divested in the fourth quarter of 2021. These properties, on average, have higher lease operating expenses per BOE than our historical properties. The remainder of the increase is attributable to service cost inflation. As a result of inflationary pressures, we have increased the expected range for our total lease operating expenses in 2022 to between $614 million and $694 million.

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Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
		2022	2021
			Amount			Per BOE		Amount			Per BOE
			(In millions, except per BOE amounts)
Production taxes			$	259		$	3.76	$	147		$	2.29
Ad valorem taxes			80			1.16		33			0.51
Total production and ad valorem expense			$	339		$	4.92	$	180		$	2.80

Production taxes as a % of oil, natural gas, and natural gas liquids revenue			5.0		%			5.2		%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of production revenues remained consistent for the six months ended June 30, 2022 compared to the same period in 2021.

Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes for the six months ended June 30, 2022 as compared to the same period in 2021 increased by $47 million primarily due to higher overall valuations resulting from an increase in commodity prices between valuation periods.

Gathering and Transportation Expense. The following table shows gathering and transportation expense for the six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
		2022	2021
			Amount		Per BOE		Amount		Per BOE
			(In millions, except per BOE amounts)
Gathering and transportation expense			$	120	$	1.74	$	87	$	1.36

The increase in gathering and transportation expenses for the six months ended June 30, 2022 compared to the same period in 2021 is primarily attributable to the increase in production between periods, as well as an overall increase in the cost per BOE. On a per BOE basis, several individually insignificant factors contributed to the overall increase including higher third-party gas gathering expenses incurred after the sale of certain gas gathering assets during the fourth quarter of 2021, production added from the QEP Merger which has higher average gathering and transportation costs per BOE than our historical properties and annual contractual rate escalations.

We expect gathering and transportation expenses to range from approximately $232 to $250 million in 2022.


	Six Months Ended June 30,
		2022		2021
		(In millions, except BOE amounts)
Depletion of proved oil and natural gas properties		$	592	$	575
Depreciation of midstream assets		35		26
Depreciation of other property and equipment		7		8
Other amortization		3		—
Asset retirement obligation accretion		6		5
Depreciation, depletion, amortization and accretion expense		$	643	$	614
Oil and natural gas properties depletion rate per BOE		$	8.59	$	8.96

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The increase in depletion of proved oil and natural gas properties of $17 million for the six months ended June 30, 2022 as compared to the same period in 2021 resulted largely from higher production volumes partially offset by a lower average depletion rate. The decline in rate resulted primarily from higher SEC prices utilized in the reserve calculations in the 2022 period, lengthening the economic life of the reserve base and resulting in higher projected remaining reserve volumes on our wells.

Impairment of Oil and Natural Gas Properties. No impairment expense was recorded for the six months ended June 30, 2022. In connection with the QEP Merger and the Guidon Acquisition in the first quarter of 2021, 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 during the six months ended June 30, 2021.

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 significantly 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 of the condensed notes to the consolidated financial statements included elsewhere in this report 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 six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
		2022	2021
			Amount		Per BOE		Amount		Per BOE
			(In millions, except per BOE amounts)
General and administrative expenses			$	47	$	0.68	$	38	$	0.59
Non-cash stock-based compensation			28		0.41		23		0.36
Total general and administrative expenses			$	75	$	1.09	$	61	$	0.95

The increase in general and administrative expenses for the six months ended June 30, 2022 compared to the same period in 2021 was due primarily to higher compensation costs resulting from growth in our headcount and an increase in salary and benefits costs in the current year. Additionally, equity compensation increased by $5 million for the six months ended June 30, 2022 compared to the same period in 2021, primarily due to a higher grant-date fair value for performance stock units issued in the first quarter of 2022 and the accelerated vesting of restricted stock held by transitional employees related to the QEP Merger.

Merger and Integration Expense. The following tables shows merger and integration expense for the six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
		2022		2021
		(In millions)
Merger and integration expenses		$	—	$	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 consisted of $38 million in severance costs and $30 million in banking, legal and advisory fees, and the Guidon Acquisition related expenses consisted primarily of advisory and legal fees. See Note 4—Acquisitions and Divestitures of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding the QEP Merger and the Guidon Acquisition.

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Other Operating Costs and Expenses. The following table shows the other insignificant operating costs and expenses for the six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
	2022		2021
	(In millions)
Midstream services expenses	$	45	$	51
Other operating expenses	$	8	$	10

Net Interest Expense. The following table shows the components of net interest expense for the six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
		2022		2021
		(In millions)
Revolving credit agreements		$	10	$	5
Senior notes		115		131
Amortization of debt issuance costs and discounts		12		8
Other		3		4
Capitalized interest		(61)		(35)


Interest expense, net		$	79	$	113

The decrease in net interest expense for the six months ended June 30, 2022 compared to the same period in 2021, primarily reflects (i) a decrease in interest expense on our senior notes due largely to redemptions and repurchases of principal between the periods, and (ii) an increase in capitalized interest costs. See Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding outstanding borrowings.


	Six Months Ended June 30,
		2022		2021
		(In millions)
Gain (loss) on derivative instruments, net(1)		$	(653)	$	(661)
Net cash received (paid) on settlements(2)		$	(720)	$	(425)

(1)The six months ended June 30, 2022 includes $6 million in losses related to interest rate swaps.

(2)The six months ended June 30, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $135 million. The six months ended June 30, 2021 includes cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.

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 instruments, net.” See Note 11—Derivatives of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding our derivative instruments.

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Other Income (Expense). The following table shows other income and expenses for the six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
			2022		2021
		(In millions)
Other income (expense), net			$	2	$	(6)
Gain (loss) on extinguishment of debt			$	(58)	$	(61)
Income (loss) from equity investments			$	37	$	2

Gain (loss) on extinguishment of debt reflects the difference between the carrying value and reacquisition price for the repurchases and redemptions of various senior notes during the 2022 and 2021 periods. See Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding gain (loss) on extinguishment of debt.

The increase in income from our equity investments primarily reflects higher capacity utilization and price realizations for our midstream investees in the second quarter of 2022 compared to the first quarter of 2022, as well as $19 million in income from Rattler’s investment in an interconnected gas gathering system in the Midland Basin, which was acquired in the fourth quarter of 2021.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the six months ended June 30, 2022 and 2021:


	Six Months Ended June 30,
		2022		2021
		(In millions)
Provision for (benefit from) income taxes		$	623	$	159

The change in our income tax provision for the six months ended June 30, 2022 compared to the same period in 2021 was primarily due to the increase in pre-tax income which resulted largely from the changes in revenues from oil, natural gas and natural gas liquids, gain (loss) on derivatives and other expenses discussed above. See Note 10—Income Taxes of the condensed notes to the consolidated financial statements included elsewhere in this report for further discussion of our income tax expense.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

Historically, our primary sources of liquidity include cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of senior notes and sales of non-core assets. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties. At June 30, 2022, we had approximately $1.6 billion of liquidity consisting of $21 million in standalone cash and cash equivalents and $1.6 billion available under our credit facility. As discussed below, our capital budget for 2022 is $1.82 billion to $1.90 billion. In July 2022, we fully redeemed the principal amounts of $25 million and $20 million of our 5.375% Notes due 2022 and 7.320% Medium-term Notes due 2022, respectively, and have an additional $10 million of senior notes maturing in the next 12 months.

Our working capital requirements are supported by our cash and cash equivalents and our credit facility. We may draw on our revolving credit facility to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, debt service obligations, debt maturities, repurchases of equity or debt securities and other amounts that may ultimately be paid in connection with contingencies.

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. In order to mitigate this volatility, we entered into derivative contracts with a number of financial institutions, all of which are participants in our credit

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facility, hedging a portion of our estimated future crude oil and natural gas production through the end of 2023 as discussed further in Note 11—Derivatives and Item 3. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk. The level of our hedging activity and duration of the financial instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.

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 war in Ukraine, the COVID-19 pandemic, and/or other adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Although the Company expects that its sources of funding will be adequate to fund its short-term and long-term liquidity requirements, we cannot assure you the needed capital will be available on acceptable terms or at all.

Cash Flow

Our cash flows for the six months ended June 30, 2022 and 2021 are presented below:


	Six Months Ended June 30,
	2022		2021
	(In millions)
Net cash provided by (used in) operating activities	$	2,959	$	1,578
Net cash provided by (used in) investing activities	(1,232)		(898)
Net cash provided by (used in) financing activities	(2,340)		(392)
Net increase (decrease) in cash	$	(613)	$	288

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.

The increase in operating cash flows for the six months ended June 30, 2022 compared to the same period in 2021 primarily resulted from an additional $2.3 billion in total revenue, which was partially offset by (i) a change of $462 million in cash paid for taxes due to making payments of $362 million in 2022 compared to receiving a refund of $100 million in federal taxes under the 2020 CARES act in 2021, (ii) an increase in our cash operating expenses of approximately $165 million primarily due to costs incurred for the properties acquired in the QEP Merger and the Guidon Acquisition, (iii) $236 million due to making net cash payments of $720 million on our derivative contracts in 2022 compared to net cash payments of $484 million on our derivative contracts in 2021, and (iv) fluctuations in other working capital balances due primarily to the timing of when collections are made on accounts receivable and payments are made on accounts payable and accrued liabilities. See “—Results of Operation s” for discussion of significant changes in our revenues and expenses.

Investing Activities

The majority of our net cash used for investing activities during the six months ended June 30, 2022 and 2021 was for drilling and completion costs in conjunction with our development program as well as the purchase of oil and gas properties which are discussed further in Note 4—Acquisitions and Divestitures of the condensed notes to the consolidated financial statements included elsewhere in this report.

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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,
	2022		2021
	(In millions)
Drilling, completions and non-operated additions to oil and natural gas properties(1)	$	781	$	623
Infrastructure additions to oil and natural gas properties	82		22
Additions to midstream assets	42		17
Total	$	905	$	662

(1) See “—Recent Developments - Upstream Segment” above for additional detail on wells drilled and turned to production during the three and six months ended June 30, 2022 and 2021.

Financing Activities

During the six months ended June 30, 2022, net cash used in financing activities was primarily attributable to (i) $1.9 billion paid for the repurchase and redemption of principal outstanding on certain senior notes as discussed in “—2022 Debt Transactions” below, as well as $49 million of additional premiums paid in connection with the redemptions, (ii) $648 million of dividends paid to stockholders, (iii) $110 million in distributions to non-controlling interests, (iv) $381 million of repurchases as part of the share and unit repurchase programs, and (v) $16 million of repayments under credit facilities, net of borrowings. These cash outflows were partially offset by $750 million in proceeds from the March 2022 Notes.

Net cash used in financing activities for the six months ended June 30, 2021 was primarily attributable to (i) $2.1 billion paid for the repurchase of principal outstanding on certain senior notes 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.

Capital Resources

Revolving Credit Facilities and Other Debt Instruments

As of June 30, 2022, our debt, including the debt of Viper and Rattler, consists of approximately $5.1 billion in aggregate outstanding principal amount of senior notes, $515 million in aggregate outstanding borrowings under revolving credit facilities and $41 million in outstanding amounts due under our DrillCo Agreement.

As of June 30, 2022, the maximum credit amount available under our credit agreement was $1.6 billion, with $33 million in outstanding borrowings and approximately $1.6 billion available for future borrowings. As of June 30, 2022, there was an aggregate of $3 million in outstanding letters of credit, which reduce available borrowings under our credit agreement on a dollar for dollar basis. During the second quarter of 2022, we extended the maturity date on our credit agreement by one year to June 2, 2027, and may further extend it by two one-year extensions pursuant to the terms set forth in the credit agreement.

Viper’s Credit Agreement

The Viper credit agreement, as amended to date, matures on June 2, 2025 and 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, 2022, although Viper LLC had elected a commitment amount of $500 million, based on Viper LLC’s oil and natural gas reserves and other factors. As of June 30, 2022, there were $250 million of outstanding borrowings and $250 million available for future borrowings under the Viper credit agreement.

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Rattler’s Credit Agreement

The Rattler credit agreement, as amended to date, matures on May 28, 2024 and 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, 2022, there were $232 million of outstanding borrowings and $368 million available for future borrowings under the Rattler credit agreement.

2022 Debt Transactions

On March 17, 2022, we issued $750 million in aggregate principal amount of March 2022 Notes for net proceeds of $739 million, which were used to fund, together with cash on hand, the redemption of all of our outstanding 4.750% Senior Notes due 2025 and 2.875% Senior Notes due 2024 in the aggregate principal amount of $1.5 billion. Interest on the March 2022 Notes is payable semi-annually on March 15 and September 15 of each year, beginning on September 15, 2022.

In the second quarter of 2022, we repurchased an aggregate of $337 million in various tranches of senior notes with cash on hand, and Viper repurchased $50 million of its 5.375% senior notes due 2027 with cash on hand and borrowings under the Viper credit agreement.

Subject to market conditions and other factors, we expect to continue to issue debt securities from time to time in the future to refinance our maturing debt. The availability, interest rate and other terms of any new borrowings will depend on the ratings assigned by credit rating agencies, among other factors. We may also from time to time opportunistically repurchase some of our outstanding Senior Notes of one or more tranches or series, in open market purchases or in privately negotiated transactions.

We are currently in compliance, and expect to continue to be in compliance, with all financial maintenance covenants in our debt instruments.

For additional discussion of our outstanding debt as of June 30, 2022, see Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Our credit rating from Standard and Poor’s Global Ratings Services is BBB-. Our credit rating from Fitch Investor Services is BBB. Our credit rating from Moody’s Investor Services is Baa3. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.

Capital Requirements

In addition to future operating expenses and working capital commitments discussed in —Results of Operations, our primary short and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) payments of other contractual obligations and (iii) cash used to pay for dividends and repurchases of securities as discussed below.

Based upon current oil and natural gas prices and production expectations for 2022, 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 2022 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

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2022 Capital Spending Plan

Our board of directors has approved a revised 2022 capital budget for drilling, midstream and infrastructure of approximately $1.82 billion to $1.90 billion. We estimate that, of these expenditures, approximately:

•$1.63 billion to $1.67 billion will be spent primarily on drilling 270 to 290 gross (248 to 267 net) horizontal wells and completing 260 to 280 gross (240 to 258 net) horizontal wells across our operated and non-operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 10,200 feet;

•$80 million to $100 million will be spent on midstream infrastructure, excluding joint venture investments; and

•$110 million to $130 million will be spent on infrastructure and environmental 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.

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 13 drilling rigs and 4 completion crews. 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.

Dividends and Repurchases of Securities

In addition to our base dividend program, in the first quarter of 2022 we initiated a variable dividend strategy whereby we may pay a quarterly variable dividend based the prior quarter’s free cash flow remaining after the payment of the base dividend. Beginning in the third quarter of 2022, our board of directors approved an increase to this return of capital commitment to at least 75% of free cash flow, from the previous commitment of at least 50% of free cash flow. We have declared a base plus variable cash dividend for the second quarter of 2022 of $3.05 per share of common stock.

Free cash flow is a non-GAAP financial measure. As used by the Company, free cash flow is defined as cash flow from operating activities before changes in working capital in excess of cash capital expenditures. The Company believes that free cash flow is useful to investors as it provides a measure to compare both cash flow from operating activities and additions to oil and natural gas properties across periods on a consistent basis.

Future base and variable dividends are at the discretion of our board of directors, and, if declared, the board of directors may change the dividend amount based on the Company's outlook for commodity prices, liquidity, debt levels, capital resources, free cash flow and other factors. The Company can provide no assurance that dividends will be authorized or declared in the future or as to the amount of any future dividends. Any future variable dividends, if declared and paid, will by their nature fluctuate based on the Company's free cash flow, which will depend on a number of factors beyond the Company's control, including commodity prices.

As of July 29, 2022, we have repurchased 8.3 million shares of our common stock for a total cost of $940 million since the inception of the repurchase program. On July 28, 2022, our board of directors approved an increase in our common stock repurchase program from $2.0 billion to $4.0 billion. We intend to continue to purchase shares under this repurchase program opportunistically with available funds primarily from cash flow from operations and liquidity events such as the sale of assets while maintaining sufficient liquidity to fund our capital expenditure programs. See Note 8—Stockholders' Equity and Earnings Per Share of the condensed notes to the consolidated financial statements included elsewhere in this report for further discussion of the repurchase program.

Income Taxes

We expect our cash tax rate to be 10% to 15% of pre-tax income for the year ended December 31, 2022. See Note 10—Income Taxes of the condensed notes to the consolidated financial statements included elsewhere in this report for further discussion of our income taxes.

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Guarantor Financial Information

As of June 30, 2022, Diamondback E&P is the sole guarantor under the indentures governing the outstanding December 2019 Notes, the March 2021 Notes and the March 2022 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 IG 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 outstanding December 2019 Notes, the March 2021 Notes and the March 2022 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.

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, 2022		December 31, 2021
Summarized Balance Sheets:	(In millions)
Assets:
Current assets	$	851	$	1,148

Property and equipment, net	$	15,678	$	14,778
Other noncurrent assets	$	59	$	55
Liabilities:
Current liabilities	$	1,419	$	1,221
Intercompany accounts payable, non-guarantor subsidiary	$	1,899	$	1,440
Long-term debt	$	3,945	$	5,093
Other noncurrent liabilities	$	1,967	$	1,549


	Six Months Ended June 30, 2022
Summarized Statement of Operations:	(In millions)
Revenues	$	4,028
Income (loss) from operations	$	2,775
Net income (loss)	$	1,449

Critical Accounting Estimates

There have been no changes in our critical accounting estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2021.

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Recent Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies included in the condensed notes to the consolidated financial statements included elsewhere in this Quarterly Report for recent accounting pronouncements and accounting policies not yet adopted, if any.

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, we cannot predict events, including the outcome of the war in Ukraine or the COVID-19 pandemic, 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, roll swaps, costless collars, puts and basis puts, to reduce price volatility associated with certain of our oil and natural gas sales.

At June 30, 2022, we had a net liability derivative position of $96 million, related to our commodity price risk derivatives. Utilizing actual derivative contractual volumes under our commodity price derivatives as of June 30, 2022, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position by $63 million to $159 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability position by $55 million to $41 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. For additional information on our open commodity derivative instruments at June 30, 2022, see Note 11—Derivatives included in the condensed notes to the consolidated financial statements included elsewhere in this Quarterly Report.

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.

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 $961 million at June 30, 2022), and to a lesser extent, receivables resulting from joint interest receivables (approximately $76 million at June 30, 2022).

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. Outstanding borrowings under the credit agreement bear interest at a per annum rate elected by Diamondback E&P. At June 30, 2022, the applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate, and from 1.125% to 2.000% per annum in the case of Adjusted Term SOFR, 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, 2022, see Note 7—Debt included in the condensed notes to the consolidated financial statements included elsewhere in this Quarterly Report.

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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, 2022, we have interest rate swap agreements for a notional amount of $1.2 billion to manage the impact of changes to the fair value of our fixed rate senior notes due to changes in market interest rates through December 2029. We pay an average variable rate of interest for these swaps based on three month LIBOR plus 2.1865% and receive a fixed interest rate of 3.5% from our counterparties, At June 30, 2022, our receive-fixed, pay-variable interest rate swaps were in a net liability position of $139 million, and the weighted average variable rate was 2.94%. For additional information on our interest rate swaps, see Note 11—Derivatives included in the condensed notes to the consolidated financial statements included elsewhere in this Quarterly Report.

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 Exchange Act, 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, 2022, 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, 2022, 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, 2022, 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 14—Commitments and Contingencies included in the condensed notes to the consolidated financial statements included elsewhere in this Quarterly Report and Part II, Item 1A. Risk Factors for additional discussion of the potential risk of climate change-related litigation on our financial condition, results of operations or cash flows.

ITEM 1A. RISK FACTORS

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

As of the date of this filing, we continue to be subject to the risk factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 24, 2022, Part II, Item 1A Risk Factors in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022, filed with the SEC on May 5, 2022, and in subsequent filings we make with the SEC. Except as provided below, there have been no material changes in our risk factors from those described in such reports.

The Rattler Merger is subject to conditions, including some conditions that may not be satisfied on a timely basis, if at all. Failure to complete the Rattler Merger, or significant delays in completing the Rattler Merger, could negatively affect our and Rattler’s future business and financial results and the trading prices of shares of our common stock and Rattler’s common units.

We and Rattler expect that the Rattler Merger will close reasonably promptly following the distribution payment date for the second quarter 2022 distribution to Rattler’s unitholders reported by Rattler. The completion of the Rattler Merger is subject to certain closing conditions, is not assured and is subject to risks. The Merger Agreement contains conditions, some of which are beyond our and Rattler’s control, that, if not satisfied or waived, may prevent, delay or otherwise result in the Rattler Merger not occurring.

In addition, if the Rattler Merger is not completed on or before December 31, 2022, either we or Rattler may choose not to proceed with the Rattler Merger by terminating the Merger Agreement, subject to certain limitations, and we and Rattler can mutually decide to terminate the Merger Agreement at any time prior to the effective time of the Rattler Merger. Further, either we or Rattler may elect to terminate the Merger Agreement in certain other circumstances specified in the Merger Agreement.

If the Rattler Merger is not completed, or if there are significant delays in completing the Rattler Merger, our or Rattler’s future business and financial results and the trading prices of shares of our common stock and Rattler’s common units could be negatively affected, and each of us will be subject to several risks, described in more detail in our Registration Statement on Form S-4, initially filed with the SEC on June 13, 2022, amended on July 21, 2022 and declared effective by the SEC on July 28, 2022, in connection with the Rattler Merger under the heading “Risk Factors—Risks Related to the Merger,” including the following:

•there may be negative reactions from the financial markets due to the fact that current prices of shares of our common stock and Rattler’s common units may reflect a market assumption that the Rattler Merger will be completed;

•the attention of our and Rattler’s respective management will have been diverted to the Rattler Merger rather than our and Rattler’s own operations and pursuit of other opportunities that could have been beneficial to our and Rattler’s respective businesses;

•we and Rattler will be required to pay our respective costs relating to the Rattler Merger, such as legal, accounting, financial advisory, filing fees, written consent costs, mailing and printing fees, whether or not the Rattler Merger is

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completed, and many of the expenses that will be incurred, by their nature, are difficult to estimate accurately at the present time;

•in connection with the termination of the Merger Agreement as a result of a material uncured breach by a party, the breaching party is obligated to reimburse the other party’s expenses, up to $3.5 million; and

•litigation related to any failure to complete the Rattler Merger or related to any enforcement proceeding commenced against us or Rattler to perform our respective obligations pursuant to the Merger Agreement can subject us and Rattler to the risks discussed in more detail below.

Rattler is currently, and each of Diamondback and Rattler may in the future be, a target of individual or class action securities or derivative lawsuits, which could result in substantial costs and may delay or prevent the closing of the Rattler Merger

Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into merger agreements in an effort to enjoin the relevant merger or seek monetary relief. Rattler is currently a defendant in a lawsuit relating to the Merger Agreement, and we and Rattler may in the future be defendants in litigation relating to the Merger Agreement and the Rattler Merger and, even if the pending or any future lawsuits are without merit, defending against these claims can result in substantial costs and divert management time and resources. We and Rattler cannot predict the outcome of any such lawsuits, nor can either company predict the amount of time and expense that would be required to resolve such litigation. An unfavorable resolution of any such litigation surrounding the Rattler Merger could delay or prevent its consummation. In addition, the costs of defending the litigation, even if resolved in our or Rattler’s favor, could be substantial, and such litigation could distract us and Rattler from pursuing the consummation of the Rattler Merger and other potentially beneficial business opportunities.

We and Rattler may incur substantial transaction-related costs in connection with the Rattler Merger. If the Rattler Merger does not occur, we and Rattler will not benefit from these costs.

We and Rattler expect to incur substantial expenses in connection with completing the Rattler Merger, including fees paid to legal, financial and accounting advisors, filing fees, written consent costs, mailing and printing costs. Many of the expenses that will be incurred, by their nature, are difficult to estimate accurately at the present time.

The market value of our common stock could decline if large amounts of our common stock are sold following the Rattler Merger and the market value of our common stock could also decline as a result of issuances and sales of shares of our common stock other than in connection with the Rattler Merger.

Following completion of the Rattler Merger, the public holders of Rattler’s common units will no longer own such common units and instead will own interests in a combined company operating an expanded business with more assets and a different mix of liabilities. Our current stockholders and former public holders of Rattler’s common units may not wish to continue to invest in the combined company, or may wish to reduce their investment in the combined company, in order to comply with institutional investing guidelines, to increase diversification or to track any rebalancing of stock indices in which our common stock or Rattler’s common units are or were included. If, following the completion of the Rattler Merger, large amounts of our common stock are sold, the price for shares of our common stock could decline.

Furthermore, we cannot predict the effect that issuances and sales of our common stock, whether taking place before completion of the Rattler Merger (subject to the limitations of the Merger Agreement) or after completion of the Rattler Merger, including issuances and sales in connection with capital markets transactions, acquisition transactions or other transactions, may have on the market value of our common stock. The issuance and sale of substantial amounts of our common stock could adversely affect the market value of our common stock.

Transition risks relating to climate change may have a material and adverse effect on us.

Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have been increasingly focused on climate change matters in recent years. This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in:

•the enactment of climate change-related regulations, policies and initiatives by governments, investors, and other companies, including alternative energy or “zero carbon” requirements and fuel or energy conservation measures;

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•technological advances with respect to the generation, transmission, storage and consumption of energy (including advances in wind, solar and hydrogen power, as well as battery technology);

•increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, nuclear, and geothermal sources as well as electric vehicles); and

•development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services.

Any of these developments, which relate to the transition from hydrocarbon energy sources to alternative energy sources and therefore to a lower-carbon economy, may reduce the demand for products manufactured with (or powered by) hydrocarbons and the demand for, and in turn the prices of, the oil and natural gas that we produce and sell, which would likely have a material and adverse impact on us. Please see the risk factor in our Annual Report on Form 10–K for the year ended December 31, 2021 titled “Market conditions for oil and natural gas, and particularly volatility in prices for oil and natural gas, have in the past adversely affected, and may in the future adversely affect, our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves” for more information regarding the potential impact on us of reduced demand for oil and natural gas.

If any of these developments reduce the desirability of participating in the oilfield services, midstream or downstream portions of the oil and gas industry, then these developments may also reduce the availability to us of necessary third-party services and facilities that we rely on, which could increase our operational costs and adversely affect our ability to explore for, produce, transport and process oil and natural gas and successfully carry out our business and financial strategy. These developments could also reduce the number of customers willing to purchase the oil and natural gas we produce. Please see the risk factors in our Annual Report on Form 10–K for the year ended December 31, 2021 titled (i) “The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations” for more information regarding the effect on us of reduced availability of oilfield services, and (ii) “We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce” for more information regarding the potential impact on us of reduced availability of midstream or downstream customers for our oil and natural gas.

In addition to potentially reducing demand for our oil and natural gas and potentially reducing the availability of oilfield services and midstream and downstream customers, any of these developments may also create reputational risks associated with the exploration for, and production of, hydrocarbons, which may adversely affect the availability and cost to us of capital. For example, a number of prominent investors have publicly announced their intention to no longer invest in the oil and gas sector in response to concerns related to climate change, and other financial institutions and investors may decide to do likewise in the future. If financial institutions and other investors refuse to invest in or provide capital to the oil and gas sector in the future because of these reputational risks, that could result in capital being unavailable to us, or only at significantly increased cost. Please see the risk factor in our Annual Report on Form 10–K for the year ended December 31, 2021 titled “Our development and exploration operations and our ability to complete acquisitions require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves” for more information regarding our need for capital and the potential impact on us of an increased cost of, or unavailability of, capital.

In addition, the enactment of climate change-related regulations, policies and initiatives may also result in increases in our compliance costs and other operating costs and have other adverse effects, such as a greater potential for governmental investigations or litigation. For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, please see the discussion in our Annual Report on Form 10–K for the year ended December 31, 2021 in the section entitled “Business—Regulation—Climate Change.” Please also see the risk factors in our Annual Report on Form 10-K for the year ended December 31, 2021 titled “Our operations are subject to various governmental laws and regulations which require compliance that can be burdensome and expensive” and “Changes in environmental laws could increase our operating costs and adversely impact our business, financial condition and cash flows” for more information regarding the potential impact on us of increased environmental regulations.

Continuing political and social concerns relating to climate change may result in significant litigation and related expenses.

Increasing attention to global climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs or otherwise adversely affect us. For example, shareholder activism has recently been increasing in our industry, and shareholders may attempt to effect changes to our business or governance to deal

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with climate change-related issues, whether by shareholder proposals, public campaigns, proxy solicitations or otherwise, which may result in significant management distraction and potentially significant expense.

Additionally, cities, counties, and other governmental entities in several states in the U.S. have filed lawsuits against energy companies seeking damages allegedly associated with climate change. Similar lawsuits may be filed in other jurisdictions. If any such lawsuits were to be filed against us, we could incur substantial legal defense costs and, if any such litigation were adversely determined, we could incur substantial damages.

Any of these climate change-related litigation risks could result in unexpected costs, negative sentiments about our company, disruptions in our operations, and increases to our operating expenses, which in turn could have an adverse effect on our business, financial condition and results of operations.

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks (including weather-related risks) associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

Our producing properties are currently geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids, and extreme weather conditions, such as the severe winter storms in the Permian Basin in February 2021, and their adverse impact on production volumes, availability of electrical power, road accessibility and transportation facilities.

Extreme regional weather events may occur that can affect our suppliers or customers, which could adversely affect us. For example, a significant hurricane or similar weather event could damage refining and other oil and natural gas-related facilities on the Gulf Coast of Texas and Louisiana, which (if significant enough) could limit the availability of gathering and transportation facilities across Texas and could then cause production in the Permian Basin (including potentially our production) to be curtailed or shut in or (in the case of natural gas) flared. Further, any increase in flaring of our natural gas production due to weather-related events or otherwise could make it difficult for us to achieve our publicly-announced sustainability and emissions reduction targets, which could expose us to reputational risks and adversely impact our contractual and other business relationships. Any of the above-referenced events could have a material adverse effect on us. Likewise, a weather event like the severe winter storms in the Permian Basin in February 2021 could reduce the availability of electrical power, road accessibility, and transportation facilities, which could have an adverse impact on our production volumes (and therefore on our financial condition and results of operations).

In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

In addition to the geographic concentration of our producing properties described above, as of December 31, 2021, most of our proved reserves are concentrated in the Wolfberry play in the Midland Basin. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

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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 three months ended June 30, 2022 was as follows:


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



April 1, 2022 - April 30, 2022	59	$	120.01	59	$	1,555
May 1, 2022 - May 31, 2022	1,908	$	128.68	1,908	$	1,310
June 1, 2022 - June 30, 2022	402	$	123.64	402	$	1,260



Total	2,369	$	127.61	2,369

(1)The average price paid per share includes any commissions paid to repurchase stock.

(2)In September 2021, the Company’s board of directors authorized a $2.0 billion common stock repurchase program. On July 28, 2022, our board of directors approved an increase in our common stock repurchase program from $2.0 billion to $4.0 billion. The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time.

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ITEM 6. EXHIBITS

EXHIBIT INDEX


Exhibit Number						Description
2.1						Agreement and Plan of Merger, dated as of May 15, 2022, by and among Diamondback Energy, Inc., Rattler Midstream GP LLC, Bacchus Merger Sub Company and Rattler Midstream LP (incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 16, 2022
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						Thirteenth Amendment to Second Amended and Restated Credit Agreement, dated as of June 2, 2022, between Diamondback Energy, Inc., as parent guarantor, Diamondback E&P 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 the Company with the SEC on June 7 , 2022).
22.1						List of Issuers and Guarantor Subsidiaries (incorporated by reference to Exhibit 2 2 .1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on August 5, 2021).
31.1*						Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*						Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1**						Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2**						Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101						The following financial information from the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2022, 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.

Table of Contents

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 3, 2022	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer
		(Principal Executive Officer)

Date:	August 3, 2022	/s/ Kaes Van’t Hof
		Kaes Van’t Hof
		Chief Financial Officer
		(Principal Financial Officer)

Document

EXHIBIT 31.1

CERTIFICATION

I, Travis D. Stice, certify that:

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

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

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

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

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

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

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

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

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

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

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



Date:	August 3, 2022	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer

Document

EXHIBIT 31.2

CERTIFICATION

I, Kaes Van't Hof, certify that:

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

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



Date:	August 3, 2022	/s/ Kaes Van't Hof
		Kaes Van't Hof
		Chief Financial Officer

Document

EXHIBIT 32.1

CERTIFICATION OF PERIOD REPORT

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

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

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



Date:	August 3, 2022	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer

Document

EXHIBIT 32.2

CERTIFICATION OF PERIOD REPORT

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

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

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



Date:	August 3, 2022	/s/ Kaes Van't Hof
		Kaes Van't Hof
		Chief Financial Officer