Diamondback Energy, Inc. - Quarter Report: 2022 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended March 31, 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
Suite 1200
Midland,	TX	79701
(Address of principal executive offices)		(Zip code)

(432) 221-7400

(Registrant’s telephone number, including area code)

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


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

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

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

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

Large Accelerated Filer

☒

Accelerated Filer

☐

Non-Accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

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

As of April 29, 2022, the registrant had 177,492,631 shares of common stock outstanding.

DIAMONDBACK ENERGY, INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 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			5
Condensed Notes to Consolidated Financial Statements			6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			27

Item 3. Quantitative and Qualitative Disclosures About Market Risk			47

Item 4. Controls and Procedures			48

PART II. OTHER INFORMATION
Item 1. Legal Proceedings			49

Item 1A. Risk Factors			49

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			50

Item 6. Exhibits			51

Signatures			52

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GLOSSARY OF OIL AND NATURAL GAS TERMS

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



Basin			A large depression on the earth’s surface in which sediments accumulate.
Bbl or barrel			One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

BO			One barrel of crude oil.
BOE			One barrel of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d			BOE per day.
British Thermal Unit or Btu			The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion			The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.











Finding and development costs			Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Gross acres or gross wells			The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal wells			Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.



MBbl			One thousand barrels of crude oil and other liquid hydrocarbons.
MBO/d			One thousand BO per day.
MBOE/d			One thousand BOE per day.
Mcf			One thousand cubic feet of natural gas.

Mineral interests			The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu			One million British Thermal Units.

Net acres or net wells			The sum of the fractional working interest owned in gross acres.


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 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.
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 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;

•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;

•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;

•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;

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•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)

	March 31,		December 31,
	2022		2021
	(In millions, except par values and share data)
Assets
Current assets:
Cash and cash equivalents	$	149	$	654
Restricted cash	18		18
Accounts receivable:
Joint interest and other, net	113		72
Oil and natural gas sales, net	966		598

Inventories	62		62

Derivative instruments	6		13
Income tax receivable	—		1

Prepaid expenses and other current assets	33		28
Total current assets	1,347		1,446
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($8,512 million and $8,496 million excluded from amortization at March 31, 2022 and December 31, 2021, respectively)	33,645		32,914
Midstream assets	1,118		1,076
Other property, equipment and land	185		174
Accumulated depletion, depreciation, amortization and impairment	(13,840)		(13,545)
Property and equipment, net	21,108		20,619
Funds held in escrow	—		12
Equity method investments	643		613
Derivative instruments	37		4
Deferred income taxes, net	37		40
Investment in real estate, net	88		88
Other assets	71		76
Total assets	$	23,331	$	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)


	March 31,		December 31,
	2022		2021
Liabilities and Stockholders’ Equity	(In millions, except par values and share data)

Current liabilities:
Accounts payable - trade	$	49	$	36

Accrued capital expenditures	301		295
Current maturities of long-term debt	45		45
Other accrued liabilities	411		419
Revenues and royalties payable	578		452
Derivative instruments	339		174
Deferred income taxes	149		17

Total current liabilities	1,872		1,438
Long-term debt	5,803		6,642
Derivative instruments	94		29
Asset retirement obligations	254		166
Deferred income taxes	1,421		1,338
Other long-term liabilities	35		40
Total liabilities	9,479		9,653
Commitments and contingencies (Note 14)
Stockholders’ equity:
Common stock, $0.01 par value; 400,000,000 shares authorized; 177,550,589 and 177,551,347 shares issued and outstanding at March 31, 2022 and December 31, 2021, respectively	2		2
Additional paid-in capital	14,067		14,084
Retained earnings (accumulated deficit)	(1,326)		(1,998)

Total Diamondback Energy, Inc. stockholders’ equity	12,743		12,088
Non-controlling interest	1,109		1,157
Total equity	13,852		13,245
Total liabilities and equity	$	23,331	$	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 March 31,
	2022		2021
	(In millions, except per share amounts, shares in thousands)
Revenues:
Oil sales	$	1,946	$	944
Natural gas sales	154		104
Natural gas liquid sales	289		124

Midstream services	17		11
Other operating income	2		1
Total revenues	2,408		1,184
Costs and expenses:
Lease operating expenses	149		102
Production and ad valorem taxes	161		75
Gathering and transportation	59		31
Midstream services expense	22		28
Depreciation, depletion, amortization and accretion	313		273


General and administrative expenses	36		25

Merger and integration expense	—		75
Other operating expense	8		4
Total costs and expenses	748		613
Income (loss) from operations	1,660		571
Other income (expense):

Interest expense, net	(40)		(56)
Other income (expense), net	1		1

Gain (loss) on derivative instruments, net	(552)		(164)



Gain (loss) on extinguishment of debt	(54)		(61)
Income (loss) from equity investments	9		(3)
Total other income (expense), net	(636)		(283)
Income (loss) before income taxes	1,024		288
Provision for (benefit from) income taxes	221		65
Net income (loss)	803		223
Net income (loss) attributable to non-controlling interest	24		3
Net income (loss) attributable to Diamondback Energy, Inc.	$	779	$	220
Earnings (loss) per common share:
Basic	$	4.39	$	1.34
Diluted	$	4.36	$	1.33
Weighted average common shares outstanding:
Basic	177,565		164,169
Diluted	178,555		164,926
Dividends declared per share	$	3.05	$	0.40

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


	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

See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	Three Months Ended March 31,
	2022		2021
	(In millions)
Cash flows from operating activities:
Net income (loss)	$	803	$	223
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes	89		64




Depreciation, depletion, amortization and accretion	313		273

(Gain) loss on extinguishment of debt	54		61

(Gain) loss on derivative instruments, net	552		164
Cash received (paid) on settlement of derivative instruments	(420)		(178)


Equity-based compensation expense	15		10



Other	5		10
Changes in operating assets and liabilities:
Accounts receivable	(403)		(137)

Income tax receivable	1		100

Prepaid expenses and other	2		22
Accounts payable and accrued liabilities	(13)		(26)


Income tax payable	132		—
Revenues and royalties payable	125		50

Other	(3)		(12)
Net cash provided by (used in) operating activities	1,252		624
Cash flows from investing activities:
Drilling, completions and infrastructure additions to oil and natural gas properties	(418)		(289)


Additions to midstream assets	(19)		(7)

Property acquisitions	(296)		(346)



Proceeds from sale of assets	35		—


Contributions to equity method investments	(29)		(4)
Distributions from equity method investments	—		9



Other	11		50
Net cash provided by (used in) investing activities	(716)		(587)
Cash flows from financing activities:
Proceeds from borrowings under credit facilities	79		432
Repayments under credit facilities	(100)		(455)
Proceeds from senior notes	750		2,200
Repayment of senior notes	(1,500)		(1,916)
Proceeds from (repayments to) joint venture	5		(4)
Premium on extinguishment of debt	(47)		(166)











Repurchased shares under buyback program	(7)		—
Repurchased units under buyback program	(42)		(24)

Dividends to stockholders	(107)		(68)

Distributions to non-controlling interest	(47)		(17)


Financing portion of net cash received (paid) for derivative instruments	—		76
Other	(25)		(29)
Net cash provided by (used in) financing activities	(1,041)		29
Net increase (decrease) in cash and cash equivalents	(505)		66
Cash, cash equivalents and restricted cash at beginning of period	672		108
Cash, cash equivalents and restricted cash at end of period(1)	$	167	$	174

(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 March 31, 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.

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 March 31, 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 March 31, 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 Company’s equity and net income attributable to the Company.

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

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.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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 three months ended March 31, 2022 and 2021 to the line items within the condensed consolidated balance sheets:


	Three Months Ended March 31,
	2022		2021
	(In millions)
Cash and cash equivalents	$	149	$	121
Restricted cash	18		19
Restricted cash included in funds held in escrow	—		34
Total cash, cash equivalents and restricted cash	$	167	$	174

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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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 March 31, 2022								Three Months Ended March 31, 2021
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	1,398	$	545	$	3	$	1,946	$	569	$	358	$	17	$	944
Natural gas sales	98		56		—		154		41		61		2		104
Natural gas liquid sales	191		97		1		289		75		47		2		124

Total	$	1,687	$	698	$	4	$	2,389	$	685	$	466	$	21	$	1,172

4. ACQUISITIONS AND DIVESTITURES

First Quarter 2022 Acquisition

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.

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.

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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 $28 million of total revenue and $16 million of net income for the three months ended March 31, 2021.

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.

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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

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 $54 million of total revenue and $23 million of net income for the three months ended March 31, 2021.

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Pro Forma Financial Information

The following unaudited summary pro forma financial information for the three months ended March 31, 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 $75 million for the three months ended March 31, 2021 and acquisition-related costs incurred by QEP of $31 million through the closing date of the QEP Merger. These acquisition-related costs primarily consist of one-time severance costs and the accelerated or change-in-control vesting of certain QEP share-based awards for former QEP employees based on the terms of the merger agreement relating to the QEP Merger and other bank, legal and advisory fees. The pro forma results of operations do not include any cost savings or other synergies that may result from the QEP Merger and the Guidon Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.




	Three Months Ended March 31, 2021
	(In millions, except per share amounts)
Revenues	$	1,481
Income (loss) from operations	$	684
Net income (loss)	$	146
Basic earnings (loss) per common share	$	0.81
Diluted earnings (loss) per common share	$	0.80

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.

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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. 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:


	March 31,		December 31,
	2022		2021
	(In millions)
Oil and natural gas properties:
Subject to depletion	$	25,133	$	24,418
Not subject to depletion	8,512		8,496
Gross oil and natural gas properties	33,645		32,914
Accumulated depletion	(5,716)		(5,434)
Accumulated impairment	(7,954)		(7,954)
Oil and natural gas properties, net	19,975		19,526
Midstream assets	1,118		1,076
Other property, equipment and land	185		174
Accumulated depreciation and impairment	(170)		(157)
Total property and equipment, net	$	21,108	$	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 months ended March 31, 2022 or 2021 based on the results of the respective quarterly ceiling tests.

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

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.

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Condensed Notes to Consolidated Financial Statements - (Continued)

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6. ASSET RETIREMENT OBLIGATIONS

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


	Three Months Ended March 31,
	2022		2021
	(In millions)
Asset retirement obligations, beginning of period	$	171	$	109
Additional liabilities incurred	21		2
Liabilities acquired	2		63
Liabilities settled and divested	(5)		(1)
Accretion expense	3		2
Revisions in estimated liabilities	75		20
Asset retirement obligations, end of period	267		195
Less current portion(1)	13		5
Asset retirement obligations - long-term	$	254	$	190

(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:


	March 31,		December 31,
	2022		2021
	(In millions)

5.375% Senior Notes due 2022(1)	$	25	$	25
7.320% Medium-term Notes, Series A, due 2022(2)	20		20

5.250% Senior Notes due 2023(1)	10		10
2.875% Senior Notes due 2024	—		1,000
4.750% Senior Notes due 2025	—		500

3.250% Senior Notes due 2026	800		800
5.625% Senior Notes due 2026(1)	14		14

7.125% Medium-term Notes, Series B, due 2028(2)	100		100
3.500% Senior Notes due 2029	1,200		1,200
3.125% Senior Notes due 2031	900		900
4.400% Senior Notes due 2051	650		650
4.750% Senior Notes due 2052	750		—
DrillCo Agreement(3)	64		58
Unamortized debt issuance costs	(30)		(31)
Unamortized discount costs	(30)		(28)
Unamortized premium costs	7		8
Fair value of interest rate swap agreements(4)	(90)		(18)
Revolving credit facility	—		—
Viper revolving credit facility	248		304
Viper 5.375% Senior Notes due 2027	480		480
Rattler revolving credit facility	230		195
Rattler 5.625% Senior Notes due 2025	500		500
Total debt, net	5,848		6,687
Less: current maturities of long-term debt	(45)		(45)
Total long-term debt	$	5,803	$	6,642

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

(2) In November 2018, Energen became the Company’s wholly owned subsidiary and remained the issuer of these senior notes. In connection with the E&P Merger, Diamondback E&P became the successor issuer under the indenture.

(3) The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. As of March 31, 2022, the amount due to CEMOF related to this alliance was $64 million. As of March 31, 2022, 20 joint wells under this agreement have been drilled and completed.

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

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

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(Unaudited)

Second Amended and Restated Credit Facility

As of March 31, 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 available of $1.6 billion which was fully available for future borrowings, except for an aggregate of $3 million in outstanding letters of credit, which reduce available borrowings under the credit agreement on a dollar for dollar basis. There were no borrowings under the credit agreement during the three months ended March 31, 2022. During the three months ended March 31, 2021, the weighted average interest rate on borrowings under the credit agreement was 1.65%.

As of March 31, 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 of Notes

On March 18, 2022, the Company redeemed the aggregate $500 million principal amount of its outstanding 4.750% 2025 Senior Notes for total cash consideration of $540 million, including a make-whole premium of $33 million, which resulted in a loss on extinguishment of debt during the three months ended March 31, 2022 of $35 million. The Company funded the redemption with a portion of the net proceeds from the March 2022 Notes offering.

On March 23, 2022, the Company redeemed the aggregate $1.0 billion principal amount of its outstanding 2.875% 2024 Senior Notes for total cash consideration of $1.0 billion, including a make-whole premium of $14 million, which resulted in a loss on extinguishment of debt during the three months ended March 31, 2022 of $19 million. The Company funded the redemption with the remaining proceeds from the March 2022 Notes offering and cash on hand.

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. The borrowing base is scheduled to be redetermined semi-annually in May and November. As of March 31, 2022, the elected commitment amount was $500 million with $248 million of outstanding borrowings and $252 million available for future borrowings. During the three months ended March 31, 2022 and 2021, the weighted average interest rate on borrowings under the Viper credit agreement was 2.58% and 1.88%, respectively. The Viper credit agreement will mature on June 2, 2025. As of March 31, 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 March 31, 2022, Rattler LLC had $230 million of outstanding borrowings and $370 million available for future borrowings under the Rattler credit agreement. During the three months ended March 31, 2022 and 2021, the weighted average interest rate on borrowings under the Rattler credit agreement was, in each case, 1.40%. The revolving credit facility will mature on May 28, 2024. As of March 31, 2022, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

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8. STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE

Stock Repurchase Program

In September 2021, the Company’s board of directors approved a stock repurchase program to acquire up to $2 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 months ended March 31, 2022, the Company repurchased approximately $7 million of common stock under this repurchase program. As of March 31, 2022, approximately $1.6 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 March 31,
	2022		2021
	(In millions)
Net income (loss) attributable to the Company	$	779	$	220
Change in ownership of consolidated subsidiaries	(12)		(4)
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest	$	767	$	216

Earnings (Loss) Per Share

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

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(Unaudited)

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


	Three Months Ended March 31,
	2022		2021
	($ in millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common stock	$	779	$	220
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	177,565		164,169
Effect of dilutive securities:
Potential common shares issuable (1)	990		757
Diluted weighted average common shares outstanding	178,555		164,926
Basic net income (loss) attributable to common stock	$	4.39	$	1.34
Diluted net income (loss) attributable to common stock	$	4.36	$	1.33

(1) For the three months ended March 31, 2022, there were no potential common shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive under the treasury stock method. For the three months ended March 31, 2021, 241,091 potential common shares were excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive under the treasury stock method.

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 March 31, 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 March 31, 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 March 31,
	2022		2021
	(In millions)
General and administrative expenses	$	15	$	10
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$	4	$	4

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Restricted Stock Units

The following table presents the Company’s restricted stock unit activity during the three months ended March 31, 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	309,535	$	131.72
Vested	(157,534)	$	87.10
Forfeited	(15,041)	$	62.98
Unvested at March 31, 2022	1,216,549	$	75.71

The aggregate fair value of restricted stock units that vested during the three months ended March 31, 2022 was $14 million. As of March 31, 2022, the Company’s unrecognized compensation cost related to unvested restricted stock units was $81 million, which is expected to be recognized over a weighted-average period of 2.2 years.

Performance Based Restricted Stock Units

The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the three months ended March 31, 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 March 31, 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 March 31, 2022, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $52 million, which is expected to be recognized over a weighted-average period of 1.9 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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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

10. INCOME TAXES

The Company’s effective income tax rates were 21.6% and 22.6% for the three months ended March 31, 2022 and 2021, respectively. Total income tax expense from continuing operations for the three months ended March 31, 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 March 31, 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 months ended March 31, 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. As of March 31, 2022, the Company’s opening balance sheet net deferred tax asset was $39 million, primarily consisting of deferred tax assets related to tax attributes acquired from QEP, partially offset by a valuation allowance, and deferred tax liabilities resulting from the excess of financial reporting carrying value over tax basis of oil and natural gas properties and other assets acquired from QEP. The acquired income tax attributes, including federal net operating loss and credit carryforwards, are subject to an annual limitation under Internal Revenue Code Section 382. The Company has considered the positive and negative evidence regarding realizability of these federal tax attributes including taxable income in prior carryback years, the annual limitation imposed by Section 382, and the anticipated timing of reversal of its deferred tax liabilities, resulting in a valuation allowance on the portion of QEP’s federal tax attributes estimated not more likely than not to be realized prior to expiration. In addition, acquired tax attributes include state net operating loss carryforwards for which a valuation allowance has been provided, since the Company does not believe the state net operating losses are more likely than not to be realized based on its assessment of anticipated future operations in those states.

11. DERIVATIVES

At March 31, 2022, the Company has commodity derivative contracts and receive-fixed, pay-variable interest rate hedges outstanding. All derivative financial instruments are recorded at fair value.

Commodity Contracts

The Company has entered into multiple crude oil 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 three months ended March 31, 2021.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

As of March 31, 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 Fixed Price	Weighted Average Floor Price	Weighted Average Ceiling Price
OIL
Apr. - June	2022	Swap	1,000	WTI	$—	$45.00	$—	$—
Apr. - June	2022	Swap	13,900	Brent	$—	$67.54	$—	$—
Apr. - June	2022	Basis Swap(1)	17,000	Argus WTI Midland	$0.66	$—	$—	$—
July - Dec.	2022	Basis Swap(1)	10,000	Argus WTI Midland	$0.84	$—	$—	$—
Apr. - Dec.	2022	Roll Swap	55,000	WTI	$0.89	$—	$—	$—
Apr. - June	2022	Costless Collar	5,000	WTI	$—	$—	$50.00	$80.44
Apr. - June	2022	Costless Collar	24,000	Brent	$—	$—	$46.67	$77.49
Apr. - June	2022	Costless Collar	20,000	Argus WTI Houston	$—	$—	$47.50	$75.25
July - Sep.	2022	Costless Collar	4,000	WTI	$—	$—	$45.00	$92.65
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
Oct. - Dec.	2022	Costless Collar	4,000	WTI	$—	$—	$50.00	$128.01
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
Jan. - June	2023	Costless Collar	6,000	Brent	$—	$—	$60.00	$114.57









NATURAL GAS
Apr. - June	2022	Basis Swap(1)	230,000	Waha Hub	$(0.36)	$—	$—	$—
Apr. - June	2022	Costless Collar	390,000	Henry Hub	$—	$—	$2.65	$5.20
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)	270,000	Waha Hub	$(1.12)	$—	$—	$—
Jan. - Mar.	2023	Costless Collar	270,000	Henry Hub	$—	$—	$2.95	$7.59
Apr. - June	2023	Costless Collar	230,000	Henry Hub	$—	$—	$2.96	$7.07
July - Dec.	2023	Basis Swap(1)	250,000	Waha Hub	$(1.17)	$—	$—	$—
July - Dec.	2023	Costless Collar	210,000	Henry Hub	$—	$—	$2.96	$7.01

(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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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)


Settlement Month	Settlement Year	Type of Contract	Bbls Per Day	Index	Strike Price	Weighted Average Differential	Deferred Premium
OIL
Apr. - June	2022	Put	10,000	WTI	$47.50	$—	$1.49
Apr. - June	2022	Put	24,000	Brent	$50.00	$—	$1.80
Apr. - June	2022	Put	8,000	Argus WTI Houston	$50.00	$—	$1.87
July - Sep.	2022	Put	8,000	WTI	$47.50	$—	$1.52
July - Sep.	2022	Put	36,000	Brent	$50.00	$—	$1.83
July - Sep.	2022	Put	12,000	Argus WTI Houston	$50.00	$—	$1.89
Oct. - Dec.	2022	Put	32,000	Brent	$50.00	$—	$1.83
Oct. - Dec.	2022	Put	10,000	Argus WTI Houston	$50.00	$—	$1.85
Apr. - Dec.	2022	Basis Put(1)	50,000	Brent	$—	$(10.40)	$0.78

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

During the three months ended March 31, 2022, the Company completed certain hedge restructurings by terminating certain commodity derivative contracts prior to their contractual maturities which resulted in net cash settlements of $135 million. The following table presents the commodity derivatives that were terminated:


					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 each to limit the Company’s exposure to changes in the fair value of debt due to movements in LIBOR interest rates. These interest rate swaps have been designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 (the “2029 Notes”) whereby the Company will receive the fixed rate of interest and will pay an average variable rate of interest based on three month LIBOR plus 2.1865%. Gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt and totaled $90 million for the three months ended March 31, 2022, as discussed further in Note 7—Debt.

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 three months ended March 31, 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 three months ended March 31, 2022.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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 March 31,
	2022		2021
	(In millions)
Gain (loss) on derivative instruments, net:
Commodity contracts	$	(552)	$	(294)
Interest rate swaps	—		130
Total	$	(552)	$	(164)

Net cash received (paid) on settlements:
Commodity contracts(1)	$	(420)	$	(182)
Interest rate swaps(2)	—		80
Total	$	(420)	$	(102)

(1)The three months ended March 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $135 million.

(2)The three months ended March 31, 2021 includes cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.

12. FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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

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 and the net change in fair value of the Company’s interest rate swaps designated as hedges are offset by change in value of the hedged item, long-term debt, within the condensed consolidated balance sheet..

The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s condensed consolidated balance sheets as of March 31, 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 March 31, 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:

Derivative instruments	$	—	$	83	$	—	$	83	$	(80)	$	3
Interest rate swaps designated as hedges	$	—	$	6	$	—	$	6	$	(3)	$	3
Non-current:

Derivative instruments	$	—	$	56	$	—	$	56	$	(19)	$	37
Interest rate swaps designated as hedges	$	—	$	—	$	—	$	—	$	—	$	—
Liabilities:
Current:
Derivative instruments	$	—	$	419	$	—	$	419	$	(80)	$	339
Interest rate swaps designated as hedges	$	—	$	3	$	—	$	3	$	(3)	$	—
Non-current:
Derivative instruments	$	—	$	20	$	—	$	20	$	(19)	$	1
Interest rate swaps designated as hedges	$	—	$	93	$	—	$	93	$	—	$	93

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)


	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:

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

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

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

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:


	March 31, 2022				December 31, 2021
	Carrying				Carrying
	Value		Fair Value		Value		Fair Value
	(In millions)
Debt	$	5,848	$	5,966	$	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.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

13. SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
	2022		2021
	(In millions)



Supplemental disclosure of non-cash transactions:
Accrued capital expenditures included in accounts payable and accrued expenses	$	293	$	252

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.

15. SUBSEQUENT EVENTS

First Quarter 2022 Dividend Declaration

On April 27, 2022, the Board of Directors of the Company declared a cash dividend for the first quarter of 2022 of $3.05 per share of common stock, payable on May 23, 2022 to its stockholders of record at the close of business on May 12, 2022. The dividend consists of a base quarterly dividend of $0.70 per share of common stock and a variable quarterly dividend of $2.35 per share of common stock. Future base and variable dividends are at the discretion of the Board of Directors of the Company.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

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 March 31, 2022:
Third-party revenues	$	2,391	$	17	$	—	$	2,408
Intersegment revenues	—		87		(87)		—
Total revenues	2,391		104		(87)		2,408

Depreciation, depletion, amortization and accretion	292		21		—		313


Income (loss) from operations	1,637		39		(16)		1,660
Interest expense, net	(31)		(9)		—		(40)
Other income (expense)	(600)		9		(5)		(596)
Provision for (benefit from) income taxes	219		2		—		221
Net income (loss) attributable to non-controlling interest	16		8		—		24
Net income (loss) attributable to Diamondback Energy, Inc.	771		29		(21)		779
As of March 31, 2022:
Total assets	$	21,727	$	1,996	$	(392)	$	23,331


	Upstream		Midstream Operations		Eliminations		Total
	(In millions)
Three Months Ended March 31, 2021:
Third-party revenues	$	1,172	$	12	$	—	$	1,184
Intersegment revenues	—		87		(87)		—
Total revenues	1,172		99		(87)		1,184
Depreciation, depletion, amortization and accretion	262		11		—		273


Income (loss) from operations	552		38		(19)		571
Interest expense, net	(49)		(7)		—		(56)
Other income (expense)	(222)		(3)		(2)		(227)
Provision for (benefit from) income taxes	63		2		—		65
Net income (loss) attributable to non-controlling interest	(3)		6		—		3
Net income (loss) attributable to Diamondback Energy, Inc.	221		20		(21)		220
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.

Recent Developments

March 2022 Notes Offering

On March 17, 2022, we issued the March 2022 Notes for an aggregate principal amount of $750 million and received net proceeds of $739 million, after deducting debt issuance costs and discounts of $11 million and underwriting discounts and offering expenses.

Redemption of Notes

On March 18, 2022, we redeemed the aggregate $500 million principal amount of our outstanding 4.750% 2025 Senior Notes with a portion of the net proceeds from the March 2022 Notes offering.

On March 23, 2022, we redeemed the aggregate $1.0 billion principal amount of our outstanding 2.875% 2024 Senior Notes with the remaining net proceeds from the March 2022 Notes offering and cash on hand.

For additional discussion of our debt transactions during the first quarter of 2022, see Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report.

Stock and Unit Repurchase Programs

During the three months ended March 31, 2022, we repurchased approximately $7 million of Diamondback common stock, and as of March 31, 2022, $1.6 billion remained available for future purchases of common stock under our common stock repurchase program.

During the three months ended March 31, 2022, Viper repurchased approximately $39 million of common units under its repurchase program. As of March 31, 2022, $41 million remained available for future purchases of common units under Viper’s common unit repurchase program. On April 27, 2022, Viper increased the authorization of its common unit repurchase program from $150 million to $250 million.

During the three months ended March 31, 2022, Rattler repurchased approximately $3 million of common units under its repurchase program. As of March 31, 2022, $85 million remained available for future purchases of common units under Rattler’s common unit repurchase program.

See “—Liquidity and Capital Resources” below for additional discussion.

Commodity Prices

During 2021 and the first quarter 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 of natural gas ranged from $2.45 to $6.31 per MMBtu. On April 13, 2022, the NYMEX WTI price for crude oil was $104.25 per Bbl and the NYMEX Henry Hub price of natural gas was $7.00 per MMBtu. The Russian-Ukrainian military conflict and the COVID-19 pandemic have contributed to economic and pricing volatility in the first quarter of 2022 as industry and market participants evaluate global demand and production outlooks. On March 31, 2022,

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OPEC and its non-OPEC allies, known collectively as OPEC+, agreed to continue their program (commenced in August 2021) of gradual monthly output increases, raising its output target by 432,000 Bbl per day for May 2022, which is expected to further boost oil supply in response to rising demand. In its report issued on April 12, 2022 OPEC noted its expectation that world oil demand will rise by 3.7 million Bbls per day in 2022, down 480,000 Bbls per day from its previous forecast due to the impact of the Russian-Ukrainian military conflict, rising inflation and the resurgence of the Omicron coronavirus variant in China. Although this demand outlook is expected to underpin oil prices, already seen at a seven-year high in February 2022, we cannot predict any future volatility in or levels of commodity prices or demand for crude oil.

Despite the recovery in commodity prices and rising demand, 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.

First Quarter 2022 and Recent Operating and Environmental and Social Responsibility (ESG) Highlights

•We recorded net income of $779 million for the first quarter of 2022.

•Our average production was 381.4 MBOE/d during the first quarter of 2022.

•During the first quarter of 2022, we drilled 47 gross horizontal wells in the Midland Basin and 14 gross horizontal wells in the Delaware Basin.

•We turned 69 gross operated horizontal wells (54 in the Midland Basin and 15 in the Delaware Basin) to production and had capital expenditures, excluding acquisitions, of $437 million during the first quarter of 2022.

•The average lateral length for the wells completed during the first quarter of 2022 was 9,658 feet.

•Our cash operating costs for the first quarter of 2022 were $11.36 per BOE, including lease operating expenses of $4.34 per BOE, cash general and administrative expenses of $0.61 per BOE and production and ad valorem taxes and gathering and transportation expenses of $6.41 per BOE.

•On April 27, 2022, our board of directors declared a cash dividend for the first quarter of 2022 of $3.05 per share of common stock, payable on May 23, 2022 to our stockholders of record at the close of business on May 12, 2022. The dividend consists of a base quarterly dividend of $0.70 per share of common stock and a variable quarterly dividend of $2.35 per share of common stock. Future base and variable dividends are at the discretion of our board of directors.

•In January 2022, we acquired approximately 6,200 net acres from a third-party seller in Ward County, Texas for a purchase price of $232 million, net of customary post-closing adjustments, with average production of 1.3 MBO/d (2.3 MBOE/d) during the first quarter of 2022. The acquisition was funded with cash on hand and included 58 estimated gross (43 net) horizontal locations with an average lateral length of over 10,300 feet. The acquired acreage is 100% operated by us, with an average 74% working interest and 66% net revenue interest (85% effective net revenue interest).

•During the first quarter of 2022, we flared approximately 1.5% of our gross natural gas production.

•As of April 30, 2022, we have installed Continuous Emissions Monitoring Systems that cover approximately 70% of our operated oil volume production and monitor methane emissions, carbon monoxide and hydrogen sulfide (H2S) in real time. We intend to increase this monitoring effect to cover over 90% of our operated oil production by year-end 2023.

•By investing in infrastructure in our high activity areas, we now have the ability to run a dedicated e-frac fleet for the foreseeable future. We have partnered with Halliburton to secure our first e-fleet frac-core, which will run on our Martin County acreage off power generated from a central location and delivered via existing lines, reducing our Scope 1 emissions profile. This partnership is expected to lower our cost per foot primarily due to fuel savings, decrease our footprint on location and increase our operational efficiency as a result of lower maintenance and non-productive time. We expect this fleet to be operational in the fourth quarter of 2022.

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

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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 March 31, 2022, we had approximately 451,295 net acres, which primarily consisted of approximately 268,850 net acres in the Midland Basin and 153,782 net acres in the Delaware Basin.

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


	Three Months Ended March 31, 2022
	Drilled		Completed(1)
Area	Gross	Net	Gross	Net
Midland Basin	47	46	54	50
Delaware Basin	14	13	15	13

Total	61	59	69	63

(1)The average lateral length for the wells completed during the first quarter of 2022 was 9,658 feet. Operated completions during the first quarter of 2022 consisted of 19 Lower Spraberry wells, 15 Wolfcamp A wells, 11 Jo Mill wells, 10 Middle Spraberry wells, six Wolfcamp B wells, six Second Bone Spring wells, one Third Bone Spring well and one Barnett well.

As of March 31, 2022, we operated the following wells:


	As of March 31, 2022
	Vertical Wells		Horizontal Wells		Total
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	2,278	2,114	1,803	1,674	4,081	3,788
Delaware Basin	48	44	703	655	751	699
Other	—	—	—	—	—	—
Total	2,326	2,158	2,506	2,329	4,832	4,487

As of March 31, 2022, we held interests in 11,289 gross (4,601 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 600 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 months ended March 31, 2022 and 2021. See Note 16—Segment Information of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding acquisitions.

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Results of Operations

The following table sets forth selected operating data for the first quarter of 2022 and 2021:


	Three Months Ended March 31,
	2022		2021
Revenues (In millions):
Oil sales	$	1,946	$	944
Natural gas sales	154		104
Natural gas liquid sales	289		124
Total oil, natural gas and natural gas liquid revenues	$	2,389	$	1,172

Production Data:
Oil (MBbls)	20,055		16,578
Natural gas (MMcf)	42,645		34,109
Natural gas liquids (MBbls)	7,161		5,405
Combined volumes (MBOE)(1)	34,324		27,668

Daily oil volumes (BO/d)	222,833		184,200
Daily combined volumes (BOE/d)	381,378		307,422

Average Prices:
Oil ($ per Bbl)	$	97.03	$	56.94
Natural gas ($ per Mcf)	$	3.61	$	3.05
Natural gas liquids ($ per Bbl)	$	40.36	$	22.94
Combined ($ per BOE)	$	69.60	$	42.36

Oil, hedged ($ per Bbl)(2)	$	83.47	$	46.81
Natural gas, hedged ($ per Mcf)(2)	$	3.31	$	2.64
Natural gas liquids, hedged ($ per Bbl)(2)	$	40.36	$	22.76
Average price, hedged ($ per BOE)(2)	$	61.30	$	35.75

(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one 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 set forth the mix of our production data by product and basin for the first quarter of 2022 and 2021:


	Three Months Ended March 31,
	2022		2021
Oil (MBbls)	58	%	60	%
Natural gas (MMcf)	21	%	21	%
Natural gas liquids (MBbls)	21	%	19	%
	100	%	100	%


	Three Months Ended March 31, 2022				Three Months Ended March 31, 2021
	Midland Basin	Delaware Basin	Other(1)	Total	Midland Basin	Delaware Basin	Other(2)	Total
Production Data:
Oil (MBbls)	13,921	6,101	33	20,055	9,840	6,436	302	16,578
Natural gas (MMcf)	26,873	15,681	91	42,645	18,457	15,055	597	34,109
Natural gas liquids (MBbls)	4,750	2,390	21	7,161	3,236	2,069	100	5,405
Total (MBoe)	23,150	11,105	69	34,324	16,152	11,014	502	27,668

(1)Includes the Eagle Ford Shale and Rockies.

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

Comparison of the Three Months Ended March 31, 2022 and 2021

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 first quarter of 2022 increased by $1.2 billion, or 104%, to $2.4 billion from $1.2 billion during the same period in 2021. Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed $1.0 billion of the total increase. The remainder of the overall change is due to a 24% increase in combined volumes sold.

Higher commodity prices in the first quarter of 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 Russian-Ukrainian military conflict as discussed in “—Recent Developments” above. The increase in production for the first quarter of 2022 compared to the same period in 2021 resulted primarily from recognizing a full quarter’s production in the first quarter of 2022 related to the Guidon Acquisition and QEP Merger, which occurred late in the first quarter of 2021.

Other Revenues. The following table shows the other insignificant revenues for the three months ended March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022		2021
	(In millions)
Midstream services	$	17	$	11
Other operating income	$	2	$	1

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Lease Operating Expenses. The following table shows lease operating expenses for the three months ended March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022				2021
	Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
Lease operating expenses	$	149	$	4.34	$	102	$	3.69

Lease operating expenses increased by $47 million, or $0.65 per BOE for the first quarter of 2022 compared to the first quarter of 2021. This increase is primarily due to recording a full quarter of production and operating expenses from the Guidon Acquisition and the QEP Merger in the first quarter of 2022. The increase on a per BOE basis is primarily due to the impact of production acquired from the Guidon Acquisition and the QEP Merger, which on average have higher lease operating expenses per BOE than our historical properties and, to a lesser extent, an increase in well workover activity.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022					2021
	Amount			Per BOE		Amount			Per BOE
	(In millions, except per BOE amounts)
Production taxes	$	120		$	3.50	$	60		$	2.17
Ad valorem taxes	41			1.19		15			0.54
Total production and ad valorem expense	$	161		$	4.69	$	75		$	2.71

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

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 first quarter of 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 first quarter of 2022 as compared to the same period in 2021 increased by $26 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 three months ended March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022				2021
	Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
Gathering and transportation expense	$	59	$	1.72	$	31	$	1.12

The increase in gathering and transportation expenses for the first quarter of 2022, compared to the same period in 2021 is primarily attributable to the increase in production between periods. The increase on a per BOE basis is primarily attributable to several individually insignificant factors including an increase in third-party gas gathering expenses related to 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.

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Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the three months ended March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022		2021
	(In millions, except BOE amounts)
Depletion of proved oil and natural gas properties	$	286	$	257
Depreciation of midstream assets	20		11
Depreciation of other property and equipment	4		3
Asset retirement obligation accretion	3		2
Depreciation, depletion, amortization and accretion expense	$	313	$	273
Oil and natural gas properties depletion rate per BOE	$	8.33	$	9.29

The increase in depletion of proved oil and natural gas properties of $29 million for the first quarter of 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 first quarter of 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 in the first quarter of 2021. The properties acquired in the QEP Merger and the Guidon Acquisition had total unamortized costs at March 31, 2021 of $3.0 billion and $1.1 billion, respectively.

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 three months ended March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022				2021
	Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
General and administrative expenses	$	21	$	0.61	$	15	$	0.54
Non-cash stock-based compensation	15		0.44		10		0.36
Total general and administrative expenses	$	36	$	1.05	$	25	$	0.90

The increase in general and administrative expenses for the first quarter of 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 bonus costs in the current year. Additionally, equity compensation increased by $5 million for the first quarter of 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.

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Merger and Integration Expense. The following tables shows merger and integration expense for the three months ended March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022		2021
	(In millions)
Merger and integration expense	$	—	$	75

Total merger and integration expense for the first quarter of 2021 includes $67 million in costs incurred for the QEP Merger and $8 million in costs incurred for the Guidon Acquisition. The QEP Merger related expenses primarily consisted of $38 million in severance costs and $23 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.

Other Operating Costs and Expenses. The following table shows the other insignificant operating costs and expenses for the three months ended March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022		2021
	(In millions)
Midstream services expense	$	22	$	28
Other operating expense	8		4

Net Interest Expense. The following table shows the components of net interest expense for the three months ended March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022		2021
	(In millions)
Revolving credit agreements	$	4	$	3
Senior notes	61		61
Amortization of debt issuance costs and discounts	5		4
Other	1		4
Capitalized interest	(31)		(14)
Total	40		58
Less: interest income	—		2
Interest expense, net	$	40	$	56

Net interest expense decreased by $16 million for the first quarter of 2022 compared to the same period in 2021, primarily due to 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.

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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 March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022		2021
	(In millions)
Gain (loss) on derivative instruments, net	$	(552)	$	(164)
Net cash received (paid) on settlements(1)(2)	$	(420)	$	(102)

(1)The three months ended March 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $135 million.

(2)The three months ended March 31, 2021 includes cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.

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

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

Other Income (Expense). The following table shows other insignificant income and expenses for the three months ended March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022		2021
	(In millions)
Other income (expense), net	$	1	$	1
Gain (loss) on extinguishment of debt	$	(54)	$	(61)
Income (loss) from equity investments	$	9	$	(3)

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 in the first quarter of 2022.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the three months ended March 31, 2022 and 2021:


	Three Months Ended March 31,
	2022		2021
	(In millions)
Provision for (benefit from) income taxes	$	221	$	65

The change in our income tax provision for the first quarter of 2022 compared to the same period in 2021 was primarily due to the increase in pre-tax income which resulted primarily 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.

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Comparison of the Three Months Ended March 31, 2022 and December 31, 2021

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. As a result, beginning with the first quarter of 2022, we have elected to change our results of operations discussion to focus on a comparison of the current quarter’s results of operations with those of the immediately preceding quarter. We believe the change in our discussion will provide 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 March 31, 2022 and December 31, 2021:


	Three Months Ended
	March 31, 2022		December 31, 2021
Revenues (In millions):
Oil sales	$	1,946	$	1,551
Natural gas sales	154		206
Natural gas liquid sales	289		254
Total oil, natural gas and natural gas liquid revenues	$	2,389	$	2,011

Production Data:
Oil (MBbls)	20,055		20,819
Natural gas (MMcf)	42,645		45,220
Natural gas liquids (MBbls)	7,161		7,254
Combined volumes (MBOE)(1)	34,324		35,610

Daily oil volumes (BO/d)	222,833		226,293
Daily combined volumes (BOE/d)	381,378		387,065

Average Prices:
Oil ($ per Bbl)	$	97.03	$	74.50
Natural gas ($ per Mcf)	$	3.61	$	4.56
Natural gas liquids ($ per Bbl)	$	40.36	$	35.02
Combined ($ per BOE)	$	69.60	$	56.47

Oil, hedged ($ per Bbl)(2)	$	83.47	$	58.70
Natural gas, hedged ($ per Mcf)(2)	$	3.31	$	3.12
Natural gas liquids, hedged ($ per Bbl)(2)	$	40.36	$	34.46
Average price, hedged ($ per BOE)(2)	$	61.30	$	45.30

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

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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 provides information on the mix of our production for the three months ended March 31, 2022 and December 31, 2021:


	Three Months Ended
	March 31, 2022		December 21, 2021
Oil (MBbls)	58	%	59	%
Natural gas (MMcf)	21	%	21	%
Natural gas liquids (MBbls)	21	%	20	%
	100	%	100	%


	Three Months Ended March 31, 2022				Three Months Ended December 31, 2021
	Midland Basin	Delaware Basin	Other(1)	Total	Midland Basin	Delaware Basin	Other(2)	Total
Production Data:
Oil (MBbls)	13,921	6,101	33	20,055	14,047	6,598	174	20,819
Natural gas (MMcf)	26,873	15,681	91	42,645	26,261	18,531	428	45,220
Natural gas liquids (MBbls)	4,750	2,390	21	7,161	4,864	2,311	79	7,254
Total (MBoe)	23,150	11,105	69	34,324	23,288	11,998	324	35,610

(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 first quarter of 2022 increased by $378 million, or 19%, to $2.4 billion from $2.0 billion during the fourth quarter of 2021. Higher average oil prices, and to a lesser extent natural gas liquids prices, contributed $450 million of the total increase. The remainder of the overall change is due to a 4% decrease in combined volumes sold.

Higher commodity prices in the 2022 period compared to the 2021 period primarily reflect the increase in demand for oil due to economic recovery from the COVID-19 pandemic and other macroeconomic factors such as the Russian-Ukrainian military conflict as discussed in “—Recent Developments” above. The decrease in production resulted primarily from having two fewer days of production in the first quarter of 2022 compared to the fourth quarter of 2021.

Other Revenues. The following table shows other insignificant revenues for the three months ended March 31, 2022 and December 31, 2021:


	Three Months Ended
	March 31, 2022		December 31, 2021
	(In millions)
Midstream services	$	17	$	10
Other operating income	$	2	$	1

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Lease Operating Expenses. The following table shows lease operating expenses for the three months ended March 31, 2022 and December 31, 2021:


	Three Months Ended
	March 31, 2022				December 31, 2021
	Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
Lease operating expenses	$	149	$	4.34	$	150	$	4.21

Lease operating expenses remained consistent in total and increased by $0.13 on a per BOE basis for the first quarter of 2022 compared to the fourth quarter of 2021. The increase on a per BOE basis is primarily related to service cost inflation, as well as the impact of having two fewer operating days over which to allocate fixed lease operating expenses.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended March 31, 2022 and December 31, 2021:


	Three Months Ended
	March 31, 2022					December 31, 2021
	Amount			Per BOE		Amount			Per BOE
	(In millions, except per BOE amounts)
Production taxes	$	120		$	3.50	$	104		$	2.92
Ad valorem taxes	41			1.19		17			0.48
Total production and ad valorem expense	$	161		$	4.69	$	121		$	3.40

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 for the first quarter of 2022 remained consistent with the fourth quarter of 2021.

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. Additionally, the fourth quarter of 2021 also included a downward revision to our full 2021 ad valorem accrual based on actual tax assessments received, which caused ad valorem taxes on a per BOE rate to be lower in that period. These adjustment resulted in an overall increase in ad valorem tax expense of $24 million for the first quarter of 2022 compared to the fourth quarter of 2021.

Gathering and Transportation Expense. The following table shows gathering and transportation expense for the three months ended March 31, 2022 and December 31, 2021:


	Three Months Ended
	March 31, 2022				December 31, 2021
	Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
Gathering and transportation expense	$	59	$	1.72	$	58	$	1.63

Gathering and transportation expenses remained relatively consistent in total and increased by $0.09 on a per BOE basis for the first quarter of 2022 compared to the fourth quarter of 2021. The increase is primarily related to additional third-party gas gathering charges incurred following the divestiture of certain gas gathering assets during the fourth quarter of 2021.

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	Three Months Ended
	March 31, 2022		December 31, 2021
	(In millions, except BOE amounts)
Depletion of proved oil and natural gas properties	$	286	$	303
Depreciation of midstream assets	20		11
Depreciation of other property and equipment	4		4
Asset retirement obligation accretion	3		2
Depreciation, depletion, amortization and accretion expense	$	313	$	320
Oil and natural gas properties depletion rate per BOE	$	8.33	$	8.51

The decrease in depletion of proved oil and natural gas properties of $17 million for the first quarter of 2022 as compared to the fourth quarter of 2021 resulted largely from lower production in the first quarter of 2022 coupled with a decline in the average depletion rate. The decline in rate resulted primarily from higher SEC prices utilized in the reserve calculations in the 2021 period, which lengthened the economic life of the reserve base and resulted in higher projected remaining reserve volumes on our wells.

General and Administrative Expenses. The following table shows general and administrative expenses for the three months ended March 31, 2022 and December 31, 2021:


	Three Months Ended
	March 31, 2022				December 31, 2021
	Amount		Per BOE		Amount		Per BOE
	(In millions, except per BOE amounts)
General and administrative expenses	$	21	$	0.61	$	33	$	0.93
Non-cash stock-based compensation	15		0.44		14		0.39
Total general and administrative expenses	$	36	$	1.05	$	47	$	1.32

The decrease in general and administrative expenses for the first quarter of 2022 compared to the fourth quarter of 2021 was due largely to compensation related accrual adjustments made during the fourth quarter of 2021 for annual bonuses. Equity compensation for the first quarter of 2022 remained consistent with the fourth quarter of 2021.

Other Operating Costs and Expenses. The following table shows other insignificant operating costs and expenses for the three months ended March 31, 2022 and December 31, 2021:


	Three Months Ended
	March 31, 2022		December 31, 2021
	(In millions)
Midstream services expense	$	22	$	19
Merger and integration expense	$	—	$	1
Other operating expense	$	8	$	(5)

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Net Interest Expense. The following table shows the components of net interest expense for the three months ended March 31, 2022 and December 31, 2021:


	Three Months Ended
	March 31, 2022		December 31, 2021
	(In millions)
Revolving credit agreements	$	4	$	4
Senior notes	61		55
Amortization of debt issuance costs and discounts	5		5
Other	1		2
Capitalized interest	(31)		(37)
Total	40		29
Less: interest income	—		—
Interest expense, net	$	40	$	29

Net interest expense increased by $11 million for the first quarter of 2022 compared to the fourth quarter of 2021. The increase was primarily due to (i) interest expense in the fourth quarter of 2021 reflecting the receipt of a $7 million cash settlement on our fair value interest rate swaps which offset a portion of the interest expense on our 2029 Notes, and (ii) a decrease in capitalized interest costs. Our fair value interest rate swaps settle semi-annually in December and June. 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.


	Three Months Ended
	March 31, 2022		December 31, 2021
	(In millions)
Gain (loss) on derivative instruments, net	$	(552)	$	47
Net cash received (paid) on settlements(1)	$	(420)	$	(403)

(1)The first quarter of 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $135 million.

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

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Other Income (Expense). The following table shows other income and expenses for the three months ended March 31, 2022 and December 31, 2021:


	Three Months Ended
	March 31, 2022		December 31, 2021
	(In millions)
Other income (expense), net	$	1	$	(6)
Gain (loss) on extinguishment of debt	$	(54)	$	(2)
Income (loss) from equity investments	$	9	$	9

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 first quarter of 2022 and fourth quarter of 2021:


	Three Months Ended
	March 31, 2022		December 31, 2021
	(In millions)
Provision for (benefit from) income taxes	$	221	$	279

The change in our income tax provision for the first quarter of 2022 compared to the fourth quarter of 2021 was primarily due to the decrease 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.

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 March 31, 2022, we had approximately $1.7 billion of liquidity consisting of $0.1 billion in cash and cash equivalents and $1.6 billion available under our credit facility. As discussed below, our capital budget for 2022 is $1.75 billion to $1.90 billion. Further, we have $45 million of senior notes maturities 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 and repayment of 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 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.

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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 Russian-Ukrainian military conflict, 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 that the needed capital will be available on acceptable terms or at all.

Cash Flow

Our cash flows for the three months ended March 31, 2022 and 2021 are presented below:


	Three Months Ended March 31,
	2022		2021
	(In millions)
Net cash provided by (used in) operating activities	$	1,252	$	624
Net cash provided by (used in) investing activities	(716)		(587)
Net cash provided by (used in) financing activities	(1,041)		29
Net increase (decrease) in cash	$	(505)	$	66

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 three months ended March 31, 2022 compared to the same period in 2021 primarily resulted from an increase of $1.2 billion in our total revenues, which was partially offset by cash outflows of (i) $242 million due to making net cash payments of $420 million on our derivative contracts in the first quarter of 2022 compared to net cash payments of $178 million on our derivative contracts in the first quarter of 2021, (ii) an increase in our cash operating expenses of approximately $90 million primarily due to the QEP Merger and the Guidon Acquisition, (iii) an increase of $31 million in our cash paid for interest primarily due to interest payments on senior notes which were issued in 2021 and (iv) other working capital changes including an increase in accounts receivable for oil and natural gas sales and revenues and a partially offsetting increase in revenues and royalties payable, which stem from higher commodity prices in 2022, as well as recording a payable for income taxes expected to be paid in 2022 compared to an income tax receivable related to the carryback of federal net operating losses and the accelerated refund of minimum tax credits allowed under the 2020 CARES Act in the prior year. See “—Results of Operations” for discussion of significant changes in our revenues and expenses.

Investing Activities

Net cash used in investing activities was $716 million compared to $587 million during the three months ended March 31, 2022 and 2021, respectively. The majority of our net cash used for investing activities during the three months ended March 31, 2022 was for drilling and completion costs in conjunction with our development program and as well as the purchase of oil and gas properties, which is discussed further in Note 4—Acquisitions and Divestitures.

The majority of our net cash used in investing activities during the three months ended March 31, 2021 was for the purchase and development of oil and natural gas properties and related assets including the acquisition of certain leasehold interests as part of the Guidon Acquisition. Our capital expenditures for each period are discussed further below.

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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:


	Three Months Ended March 31,
	2022		2021
	(In millions)
Drilling, completions and non-operated additions to oil and natural gas properties(1)(2)	$	374	$	281
Infrastructure additions to oil and natural gas properties	44		8
Additions to midstream assets	19		7
Total	$	437	$	296

(1)During the three months ended March 31, 2022, in conjunction with our development program, we drilled 61 gross (59 net) operated horizontal wells, of which 47 gross (46 net) wells were in the Midland Basin and 14 gross (13 net) wells were in the Delaware Basin, and turned 69 gross (63 net) operated horizontal wells to production, of which 54 gross (50 net) wells were in the Midland Basin and 15 gross (13 net) wells were in the Delaware Basin.

(2)During the three months ended March 31, 2021, in conjunction with our development program, we drilled 49 gross (47 net) operated horizontal wells, of which 41 gross (40 net) wells were in the Midland Basin and eight gross (seven net) wells were in the Delaware Basin, and turned 67 gross (60 net) operated horizontal wells to production, of which 42 gross (37 net) wells were in the Midland Basin and 25 gross (23 net) wells were in the Delaware Basin .

Financing Activities

Net cash used in financing activities for the three months ended March 31, 2022 was $1.0 billion compared to net cash provided by financing activities for the three months ended March 31, 2021 of $29 million. During the three months ended March 31, 2022, the amount used in financing activities was primarily attributable to (i) $1.5 billion paid for the repurchase of principal outstanding on certain senior notes as discussed in “—2022 Debt Transactions” below, as well as $47 million of additional premiums paid in connection with the repurchases, (ii) $107 million of dividends paid to stockholders, (iii) $47 million in distributions to non-controlling interests, and (iv) $49 million of repurchases as part of the share and unit repurchase programs, and (v) $21 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 provided by financing activities for the three months ended March 31, 2021 was primarily attributable to $2.2 billion in proceeds from the March 2021 Notes and $76 million in proceeds that relate primarily to the early settlement of interest rate swaps that contained an other-than-insignificant financing element. These net increases in cash flows from financing activities were partially offset by $1.9 billion paid for the repurchase of a portion of the QEP Notes and 2025 Senior Notes, as well as $166 million of additional premiums paid in connection with the repurchases, $68 million of dividends paid to stockholders, $24 million of unit repurchases as part of the Viper and Rattler unit repurchase programs and $23 million of repayments under our credit facilities, net of borrowings.

Capital Resources

Revolving Credit Facilities and Other Debt Instruments

As of March 31, 2022, our debt, including the debt of Viper and Rattler, consists of approximately $5.4 billion in aggregate outstanding principal amount of senior notes, $478 million in aggregate outstanding borrowings under revolving credit facilities and $64 million in outstanding amounts due under our DrillCo Agreement.

As of March 31, 2022, the maximum credit amount available under our credit agreement was $1.6 billion, with no outstanding borrowings and $1.6 billion available for future borrowings. As of March 31, 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. There were no borrowings under our credit agreement during the three months ended March 31, 2022.

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Viper’s Credit Agreement

The Viper credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion, with a borrowing base of $580 million as of March 31, 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. The borrowing base is scheduled to be redetermined semi-annually in May and November, and is expected to be reaffirmed at $580 million by the lenders during the redetermination in May 2022. As of March 31, 2022, there were $248 million of outstanding borrowings and $252 million available for future borrowings under the Viper credit agreement. During the three months ended March 31, 2022, the weighted average interest rate on borrowings under the Viper credit agreement was 2.58%. The Viper credit agreement will mature on June 2, 2025.

Rattler’s Credit Agreement

The Rattler credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1.0 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of March 31, 2022, there were $230 million of outstanding borrowings and $370 million available for future borrowings under the Rattler credit agreement. During the three months ended March 31, 2022, the weighted average interest rate on borrowings under the Rattler credit agreement was 1.40%. The Rattler credit agreement matures on May 28, 2024.

2022 Debt Transactions

On March 17, 2022, Diamondback Energy, Inc. issued the $750 million 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.

For additional discussion of our outstanding debt as of March 31, 2022, see Note 7—D ebt of the condensed notes to the consolidated financial statements included elsewhere in this report.

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

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 approved a 2022 capital budget for drilling, midstream and infrastructure of approximately $1.75 billion to $1.90 billion, maintaining our annualized fourth quarter 2021 cash capital expenditure guidance presented in November of 2021. We estimate that, of these expenditures, approximately:

•$1.56 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.

During the three months ended March 31, 2022, we spent $374 million on drilling and completion, $19 million on midstream and $44 million on infrastructure, for total capital expenditures, excluding acquisitions, of $437 million.

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 10 drilling rigs and four completion crews. We continue to execute on our strategy to hold oil production flat while using cash flow from operations to reduce debt, strengthen our balance sheet and return capital to our stockholders. We 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

We paid common stock dividends of $107 million and $68 million during three months ended March 31, 2022 and 2021, respectively. In addition to our base dividend program, we have initiated a variable dividend strategy whereby we may pay a quarterly variable dividend of up to 50 percent of the prior quarter’s free cash flow remaining after the payment of the base dividend. On April 27, 2022, our board of directors declared a cash dividend for the first quarter of 2022 of $3.05 per share of common stock, payable on May 23, 2022 to our stockholders of record at the close of business on May 12, 2022. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors. The dividend consists of a base quarterly dividend of $0.70 per share of common stock and a variable quarterly dividend of $2.35 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.

In September 2021, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock. We repurchased approximately $7 million of our common stock under this program during the three months ended March 31, 2022, and have $1.6 billion remaining for future repurchases under the repurchase program at March 31, 2022. 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.

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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.

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.

Guarantor Financial Information

As of March 31, 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.


	March 31, 2022		December 31, 2021
Summarized Balance Sheets:	(In millions)
Assets:
Current assets	$	967	$	1,148

Property and equipment, net	$	15,339	$	14,778
Other noncurrent assets	$	67	$	55
Liabilities:
Current liabilities	$	1,629	$	1,221
Intercompany accounts payable, non-guarantor subsidiary	$	1,637	$	1,440
Long-term debt	$	4,270	$	5,093
Other noncurrent liabilities	$	1,758	$	1,549

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	Three Months Ended March 31, 2022
Summarized Statement of Operations:	(In millions)
Revenues	$	1,855
Income (loss) from operations	$	1,253
Net income (loss)	$	436

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.

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 Russian-Ukrainian military conflict 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 March 31, 2022, we had a net liability derivative position of $300 million, related to our commodity price risk derivatives. Utilizing actual derivative contractual volumes under our commodity price derivatives as of March 31, 2022, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position by $128 million to $428 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability position by $105 million to $195 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 March 31, 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 $966 million at March 31, 2022), and to a lesser extent, receivables resulting from joint interest receivables (approximately $113 million at March 31, 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.

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

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facilities and changes in the fair value of our fixed rate debt. The terms of the credit agreement provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.125% per annum in the case of the alternative base rate and from 1.25% to 2.125% per annum in the case of LIBOR, in each case based on the pricing level. The pricing level depends on certain rating agencies’ ratings of our long-term senior unsecure debt. We believe significant interest rate changes would not have a material near-term impact on our future earnings or cash flows. For additional information on our variable interest rate debt at March 31, 2022, see Note 7—Debt included in the condensed notes to the consolidated financial statements included elsewhere in this Quarterly Report.

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 March 31, 2022, we have interest rate swap agreements for a notional amount of $1.2 billion to manage the impact of market interest rates on interest expense. These interest rate swaps have been designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 whereby we will receive the fixed rate of interest and will pay an average variable rate of interest based on three month LIBOR plus 2.1865%. For additional information on our interest rate swaps, see Note 11—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 Securities Exchange Act of 1934, as amended, or the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of March 31, 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 March 31, 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 March 31, 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.

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, 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 our Annual Report on Form 10-K for the year ended December 31, 2021.

We cannot predict the impact of the ongoing military conflict between Russia and Ukraine and the related humanitarian crisis on the global economy, energy markets, geopolitical stability and our business.

Our leasehold acreage is located primarily in the Permian Basin in West Texas. However, the broader consequences of the Russian-Ukrainian conflict, which may include further sanctions, embargoes, supply chain disruptions, regional instability and geopolitical shifts, may have adverse effects on global macroeconomic conditions, increase volatility in the price and demand for oil and natural gas, increase exposure to cyberattacks, cause disruptions in global supply chains, increase foreign currency fluctuations, cause constraints or disruption in the capital markets and limit sources of liquidity. We cannot predict the extent of the conflict’s effect on our business and results of operations as well as on the global economy and energy markets.

Our targets related to sustainability and emissions reduction initiatives, including our public statements and disclosures regarding them, may expose us to numerous risks.

We have developed, and will continue to develop, targets related to our ESG initiatives, including our emissions reduction targets and strategy. Statements in this and other reports we file with the SEC and other public statements related to these initiatives reflect our current plans and expectations and are not a guarantee the targets will be achieved or achieved on the currently anticipated timeline. Our ability to achieve our ESG targets, including emissions reductions, is subject to numerous factors and conditions, some of which are outside of our control, and failure to achieve our announced targets or comply with ethical, environmental or other standards, including reporting standards, may expose us to government enforcement actions or private litigation and adversely impact our business. Further, our continuing efforts to research, establish, accomplish and accurately report on these targets may create additional operational risks and expenses and expose us to reputational, legal and other risks.

Investor and regulatory focus on ESG matters continues to increase. If our ESG initiatives do not meet our investors’ or other stakeholders’ evolving expectations and standards, investment in our stock may be viewed as less attractive and our reputation, contractual, employment and other business relationships may be adversely impacted.

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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 March 31, 2022 was as follows:


Period	Total Number of Shares Purchased(1)	Average Price Paid Per Share(2)		Total Number of Shares Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan(3)
	($ In millions, except per share amounts, shares in thousands)
January 1, 2022 - January 31, 2022	15	$	109.89	15	$	1,567
February 1, 2022 - February 28, 2022	—	$	—	—	$	1,567
March 1, 2022 - March 31, 2022	151	$	132.99	43	$	1,562






Total	166	$	130.92	58

(1)Includes 108,508 shares of common stock repurchased from employees in order to satisfy tax withholding requirements. Such shares are cancelled and retired immediately upon repurchase.

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

(3)In September 2021, the Company’s board of directors authorized a $2 billion common stock repurchase program. 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
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).
4.4						Fifth Supplemental Indenture, dated as of March 17, 2022, among Diamondback Energy, Inc., Diamondback E&P LLC and Computershare Trust Company, National Association, as trustee (including the form of the March 2022 Notes) (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 17, 2022).
10.1						Diamondback Energy, Inc. Amended and Restated Senior Management Severance Plan, adopted effective as of February 21, 2022 (including a form of participation agreement attached thereto as Schedule C) (incorporated by reference to Exhibit 10 .9 to the Form 10 -K, File No. 001-35700, filed by the Company with the SEC on February 24 , 2022).
22.1						List of Issuers and Guarantor Subsidiaries (incorporated by reference to Exhibit 22.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on 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 March 31, 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.

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SIGNATURES

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


		DIAMONDBACK ENERGY, INC.

Date:	May 5, 2022	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer
		(Principal Executive Officer)

Date:	May 5, 2022	/s/ Kaes Van’t Hof
		Kaes Van’t Hof
		Chief Financial Officer
		(Principal Financial Officer)