fang-20250331

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, 2025


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

Commission File Number 001-35700

Diamondback Energy, Inc.

(Exact Name of Registrant As Specified in Its Charter)


DE									45-4502447
(State or Other Jurisdiction of Incorporation or Organization)									(I.R.S. Employer Identification Number)

500 West Texas Ave.,
Suite 100
Midland, TX									79701
(Address of principal executive offices)									(Zip code)

(432) 221-7400

(Registrant’s telephone number, including area code)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, par value $0.01 per share

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 May 2, 2025, the registrant had 292,167,960 shares of common stock outstanding.

DIAMONDBACK ENERGY, INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2025

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			2

Condensed Consolidated Statements of Stockholders’ Equity			3
Condensed Consolidated Statements of Cash Flows			4
Notes to the Condensed Consolidated Financial Statements			5
1. Description of the Business and Basis of Presentation			5
2. Summary of Significant Accounting Policies			6
3. Revenue from Contracts with Customers			7
4. Acquisitions and Divestitures			8
5. Endeavor Energy Resources, LP Acquisition			10
6. Property and Equipment			13
7. Asset Retirement Obligations			13
8. Related Party Transactions			14
9. Debt			15
10. Stockholders' Equity and Earnings (Loss) Per Share			17
11. Equity-Based Compensation			19
12. Income Taxes			20
13. Derivatives			21
14. Fair Value Measurements			23
15. Supplemental Information To Statements of Cash Flows			25
16. Commitments and Contingencies			25
17. Subsequent Events			26
18. Segment Information			27

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28

Item 3. Quantitative and Qualitative Disclosures About Market Risk			45

Item 4. Controls and Procedures			46

PART II. OTHER INFORMATION
Item 1. Legal Proceedings			47

Item 1A. Risk Factors			47

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			48

Item 5. Other Information			48

Item 6. Exhibits			49

Signatures			50

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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”) and our other periodic reports under the Exchange Act:



Argus WTI Houston			Grade of oil that serves as a benchmark price for oil at Houston, Texas.
Argus WTI Midland			Grade of oil that serves as a benchmark price for oil at Midland, Texas.
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/d			One barrel of crude oil per day.
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.
Brent			A major trading classification of light sweet oil that serves as a benchmark price for oil worldwide.

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.















Henry Hub			Natural gas gathering point that serves as a benchmark price for natural gas futures on the NYMEX.
HSC Hub			Natural gas gathering point that serves as a benchmark price for natural gas at the Houston Ship Channel area.
Horizontal wells			Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.



MBbls			One thousand barrels of crude oil and other liquid hydrocarbons.

MBO/d			One thousand BO per day.
MBOE			One thousand BOE.
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.
MMcf			Million cubic feet of natural gas.
Net acres			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.








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 should not be 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.




Waha Hub			Natural gas gathering point that serves as a benchmark price for natural gas at western Texas and New Mexico.
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, a light sweet blend of oil produced from fields in western Texas and is a grade of oil that serves as a benchmark for oil on the NYMEX.
WTI Cushing			Grade of oil that serves as a benchmark price for oil at Cushing, Oklahoma.

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GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms that are used in this report and our other periodic reports under the Exchange Act:





April 2024 Notes			The outstanding senior notes issued by Diamondback Energy, Inc. under indentures where Diamondback E&P is the sole guarantor, consisting of the 5.200% Senior Notes due 2027, 5.150% Senior Notes due 2030, 5.400% Senior Notes due 2034, 5.750% Senior Notes due 2054 and 5.900% Senior Notes due 2064.
ASU			Accounting Standards Update.



Equity Plan			The Company’s 2021 Amended and Restated Equity Incentive Plan.
Exchange Act			The Securities Exchange Act of 1934, as amended.
FASB			Financial Accounting Standards Board.
GAAP			Accounting principles generally accepted in the United States.







Nasdaq			The Nasdaq Global Select Market.

OPEC			Organization of the Petroleum Exporting Countries.







SEC			United States Securities and Exchange Commission.
Securities Act			The Securities Act of 1933, as amended.

Guaranteed Senior Notes			The outstanding senior notes issued by Diamondback Energy, Inc. under indentures where Diamondback E&P is the sole guarantor, consisting of the 3.250% Senior Notes due 2026, 5.200% Senior Notes due 2027, 3.500% Senior Notes due 2029, 5.150% Senior Notes due 2030, 3.125% Senior Notes due 2031, 6.250% Senior Notes due 2033, 5.400% Senior Notes due 2034, 5.550% Senior Notes due 2035, 4.400% Senior Notes due 2051, 4.250% Senior Notes due 2052, 6.250% Senior Notes due 2053, 5.750% Senior Notes due 2054 and 5.900% Senior Notes due 2064.
SOFR			The secured overnight financing rate.
TSR			Total stockholder return of the Company’s common stock.
Viper			Viper Energy, Inc.

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

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 or other effects of strategic transactions (including the recently completed Endeavor Acquisition and Double Eagle Acquisition (in each case, as defined below) discussed in this report and other acquisitions or divestitures, including the 2025 Drop Down); 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. Although we believe that the expectations and assumptions reflected in our forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond our control. 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, 2024 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 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, instability in the financial sector;

•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;

•physical and transition risks relating to climate change;

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

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

•changes in U.S. energy, environmental, monetary and trade policies, including with respect to tariffs or other trade barriers, and any resulting trade tensions;

•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;

•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;

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

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

•difficulty in obtaining necessary approvals and permits;

•severe weather conditions and natural disasters;

•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;

•risks related to the recently completed Endeavor Acquisition, Double Eagle Acquisition and the 2025 Drop Down; and

•other risks and factors disclosed or incorporated by reference 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,
	2025		2024
	(In millions, except par values and share data)
Assets
Current assets:
Cash and cash equivalents ($560 million and $27 million related to Viper)	$	1,816	$	161
Restricted cash	225		3
Accounts receivable:
Joint interest and other, net	257		198
Oil and natural gas sales, net ($146 million and $149 million related to Viper)	1,334		1,387

Inventories	117		116
Derivative instruments	267		168
Prepaid expenses and other current assets	67		77
Total current assets	4,083		2,110
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($22,019 million and $22,666 million excluded from amortization at March 31, 2025 and December 31, 2024, respectively) ($6,097 million and $5,713 million related to Viper and $2,279 million and $2,180 million excluded from amortization related to Viper)	83,727		82,240
Other property, equipment and land	1,452		1,440
Accumulated depletion, depreciation, amortization and impairment ($1,148 million and $1,081 million related to Viper)	(20,283)		(19,208)
Property and equipment, net	64,896		64,472
Funds held in escrow	208		1
Equity method investments	383		375

Derivative instruments	61		2
Deferred income taxes, net ($249 million and $185 million related to Viper)	235		173

Other assets	200		159
Total assets	$	70,066	$	67,292
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable - trade	$	124	$	253
Accrued capital expenditures	754		690
Current maturities of debt	914		900
Other accrued liabilities	761		1,020
Revenues and royalties payable	1,575		1,491
Derivative instruments	75		43
Income taxes payable	550		414
Total current liabilities	4,753		4,811
Long-term debt ($822 million and $1,083 million related to Viper)	12,996		12,075
Derivative instruments	93		106
Asset retirement obligations	586		573
Deferred income taxes	9,887		9,826
Other long-term liabilities	8		39
Total liabilities	28,323		27,430
Commitments and contingencies (Note 16)
Stockholders’ equity:
Common stock, $0.01 par value; 800,000,000 shares authorized; 287,287,926 and 290,984,373 shares issued and outstanding at March 31, 2025 and December 31, 2024, respectively	3		3
Additional paid-in capital	33,125		33,501
Retained earnings (accumulated deficit)	5,352		4,238
Accumulated other comprehensive income (loss)	(7)		(6)
Total Diamondback Energy, Inc. stockholders’ equity	38,473		37,736
Non-controlling interest	3,270		2,126
Total equity	41,743		39,862
Total liabilities and stockholders' equity	$	70,066	$	67,292

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,
		2025		2024
		(In millions, except per share amounts, shares in thousands)
Revenues:
Oil sales		$	3,039	$	1,867
Natural gas sales		212		50
Natural gas liquid sales		406		184

Sales of purchased oil		374		116
Other operating income		17		10
Total revenues		4,048		2,227
Costs and expenses:
Lease operating expenses		408		255
Production and ad valorem taxes		228		119
Gathering, processing and transportation		111		77
Purchased oil expense		382		117
Depreciation, depletion, amortization and accretion		1,097		469


General and administrative expenses		73		46

Merger and integration expenses		37		12
Other operating expenses		39		14
Total costs and expenses		2,375		1,109
Income (loss) from operations		1,673		1,118
Other income (expense):
Interest expense, net		(40)		(39)
Other income (expense), net		27		(3)

Gain (loss) on derivative instruments, net		226		(48)



Gain (loss) on extinguishment of debt		—		2
Income (loss) from equity investments, net		8		2
Total other income (expense), net		221		(86)
Income (loss) before income taxes		1,894		1,032
Provision for (benefit from) income taxes		403		223
Net income (loss)		1,491		809
Net income (loss) attributable to non-controlling interest		86		41
Net income (loss) attributable to Diamondback Energy, Inc.		$	1,405	$	768

Earnings (loss) per common share:
Basic		$	4.83	$	4.28
Diluted		$	4.83	$	4.28
Weighted average common shares outstanding:
Basic		289,612		178,477
Diluted		289,612		178,477

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)		Accumulated Other Comprehensive Income (Loss)		Non-Controlling Interest		Total
	Shares	Amount
	($ in millions, shares in thousands)
Balance December 31, 2024	290,984	$	3	$	33,501	$	4,238	$	(6)	$	2,126	$	39,862
Viper equity-based compensation	—	—		—		—		—		1		1
Distribution equivalent rights payments	—	—		—		(1)		—		—		(1)
Stock-based compensation	—	—		22		—		—		—		22
Cash paid for tax withholding on vested equity awards	(155)	—		(25)		—		—		—		(25)
Repurchased shares under buyback program	(3,656)	—		(580)		—		—		—		(580)


Viper LLC's units issued for acquisition	—	—		—		—		—		119		119

Net proceeds from Viper's issuance of common stock	—	—		—		—		—		1,232		1,232
Dividends to non-controlling interest	—	—		—		—		—		(95)		(95)
Dividends paid	—	—		—		(290)		—		—		(290)
Issuance of shares upon vesting of equity awards	115	—		—		—		—		—		—
Change in ownership of consolidated subsidiaries, net	—	—		206		—		—		(199)		7
Other comprehensive income (loss)	—	—		1		—		(1)		—		—
Net income (loss)	—	—		—		1,405		—		86		1,491
Balance March 31, 2025	287,288	$	3	$	33,125	$	5,352	$	(7)	$	3,270	$	41,743


	Common Stock			Additional Paid-in Capital		Retained Earnings (Accumulated Deficit)		Accumulated Other Comprehensive Income (Loss)		Non-Controlling Interest		Total
	Shares	Amount
	($ in millions, shares in thousands)
Balance December 31, 2023	178,724	$	2	$	14,142	$	2,489	$	(8)	$	805	$	17,430

Distribution equivalent rights payments	—	—		—		(4)		—		—		(4)
Stock-based compensation	—	—		21		—		—		—		21
Cash paid for tax withholding on vested equity awards	(187)	—		(34)		—		—		—		(34)
Repurchased shares under buyback program	(279)	—		(42)		—		—		—		(42)


Proceeds from partial sale of investment in Viper Energy, Inc.	—	—		219		—		—		197		416
Dividends to non-controlling interest	—	—		—		—		—		(44)		(44)
Dividends paid	—	—		—		(548)		—		—		(548)
Issuance of shares upon vesting of equity awards	82	—		—		—		—		—		—
Change in ownership of consolidated subsidiaries, net	—	—		(55)		—		—		70		15

Net income (loss)	—	—		—		768		—		41		809
Balance March 31, 2024	178,340	$	2	$	14,251	$	2,705	$	(8)	$	1,069	$	18,019

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,
	2025		2024
	(In millions)
Cash flows from operating activities:
Net income (loss)	$	1,491	$	809
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes	6		52




Depreciation, depletion, amortization and accretion	1,097		469

(Gain) loss on extinguishment of debt	—		(2)

(Gain) loss on derivative instruments, net	(226)		48
Cash received (paid) on settlement of derivative instruments	85		(4)
(Income) loss from equity investment, net	(8)		(2)

Equity-based compensation expense	18		14



Other	24		16
Changes in operating assets and liabilities:
Accounts receivable	(6)		(95)

Income tax receivable	3		12

Prepaid expenses and other current assets	6		89
Accounts payable and accrued liabilities	(374)		(110)


Income taxes payable	135		70
Revenues and royalties payable	84		(35)

Other	20		3
Net cash provided by (used in) operating activities	2,355		1,334
Cash flows from investing activities:
Additions to oil and natural gas properties	(942)		(609)




Property acquisitions	(750)		(153)


Proceeds from sale of assets	41		12







Other	(2)		(1)
Net cash provided by (used in) investing activities	(1,653)		(751)
Cash flows from financing activities:

Proceeds from borrowings under credit facilities	2,277		90
Repayments under credit facilities	(2,538)		(80)
Proceeds from senior notes	1,200		—
Repayment of senior notes	—		(25)












Repurchased shares under buyback program	(575)		(42)

Proceeds from partial sale of investment in Viper Energy, Inc.	—		451

Net proceeds from Viper's issuance of common stock	1,232		—
Dividends paid to stockholders	(290)		(548)

Dividends/distributions to non-controlling interest	(95)		(44)



Other	(36)		(71)
Net cash provided by (used in) financing activities	1,175		(269)
Net increase (decrease) in cash and cash equivalents	1,877		314
Cash, cash equivalents and restricted cash at beginning of period	164		585
Cash, cash equivalents and restricted cash at end of period	$	2,041	$	899

See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Notes to the Condensed 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 primarily in the Permian Basin in West Texas.

As of March 31, 2025, the wholly owned subsidiaries of Diamondback include Diamondback E&P LLC (“Diamondback E&P”), a Delaware limited liability company, Rattler Midstream GP LLC, a Delaware limited liability company, Rattler Midstream LP, a Delaware limited partnership, QEP Resources, Inc., a Delaware corporation and Eclipse Merger Sub II, LLC, a Delaware limited liability company.

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. The Company has one reportable segment, the upstream segment.

On March 5, 2024, the Company exercised certain of its demand rights, pursuant to a registration rights agreement initially entered into on June 23, 2014, as amended and restated on May 9, 2018 and November 10, 2023, and on March 8, 2024, completed a public offering of approximately 13.23 million of Viper’s Class A common stock at a price of $35.00 per share for proceeds, net of underwriters’ discount, of approximately $451 million. After this offering, the Company owned less than 50% of Viper’s combined outstanding Class A common stock and Class B common stock, resulting in Viper no longer being a controlled company under the Nasdaq rules. Following the completion of the Viper 2024 Equity Offering (as defined and discussed in Note 10—Stockholders' Equity and Earnings (Loss) Per Share) the Company’s ownership of Viper’s voting securities was further reduced to approximately 45%. However, the Company determined, in each case, that it still controls the activities of Viper in accordance with the guidance for variable interest entities in Accounting Standards Codification (“ASC”) Topic 810, “Consolidation,” and therefore continues to consolidate Viper in the Company’s financial statements at March 31, 2025. See further discussion of the Company’s determination that Viper is a variable interest entity (“VIE”) in Note 2—Summary of Significant Accounting Policies. The results of operations attributable to the non-controlling interest in Viper are presented within equity and net income and are shown separately from the equity and net income attributable to the Company.

As of March 31, 2025, the Company owned approximately 39% of Viper’s combined outstanding Class A common stock and Class B common stock. The results of operations attributable to the non-controlling interest in Viper are presented within equity and net income and are shown separately from the equity and net income attributable to the Company.

These condensed consolidated financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to SEC rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2024, which contains a summary of the Company’s significant accounting policies and other disclosures.

Reclassifications

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

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2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Company’s condensed 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 condensed 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 liabilities as of the date of the condensed 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. For instance, the war in Ukraine, the Israel-Hamas war and other conflicts in the Middle East, effects of tariffs, actions taken by OPEC and its non-OPEC allies, known collectively as OPEC+, global supply chain disruptions, measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of these events and changing market conditions. Such circumstances generally increase uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.

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

Variable Interest Entity

Viper is a publicly traded corporation formed by the Company in 2014 to provide an attractive return to its stockholders (the largest of which is Diamondback) by focusing on business results, maximizing dividends through organic growth and pursuing accretive growth opportunities through acquisitions of mineral, royalty, overriding royalty, net profits and similar interests from the Company and from third parties. Viper has no employees and the Company provides management, operating and administrative services to Viper under a services and secondment agreement, including the services of the executive officers and other employees.

In connection with the reduction of the Company’s ownership percentage in Viper to below 50% in March 2024, the Company re-evaluated whether Viper should continue to be consolidated in the Company’s financial statements. Viper meets the definition of a VIE under ASC Topic 810 and the Company continues to be the primary beneficiary of the VIE through its ability, via existing contractual agreements, to direct the activities that most significantly affect the economic performance of Viper. The Company also has the obligation to absorb losses and the right to receive benefits that could be significant to Viper. As such, the Company will continue to consolidate the activity of Viper. Neither the Viper 2024 Equity Offering or the Viper 2025 Equity Offering (as defined and discussed in Note 10—Stockholders' Equity and Earnings (Loss) Per Share) were determined to be events that would cause the Company to change its conclusion regarding Viper’s status as a VIE. See Note 17— Subsequent Events for further discussion of changes in the Company’s ownership of Viper.

Viper maintains its own capital structure that is separate from the Company. The Company is not under any obligation to provide additional financial support or investment to Viper. Viper’s assets cannot be used by the Company for general corporate purposes, and the creditors of Viper’s liabilities do not have recourse to the Company’s assets. The assets and liabilities of Viper are included in the Company’s condensed consolidated balance sheets and disclosed parenthetically, if material.

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Recent Accounting Pronouncements

Recently Adopted Pronouncements

There are no recently adopted pronouncements of significance.

Accounting Pronouncements Not Yet Adopted

In December 2023, the FASB issued ASU 2023-09, “Income Taxes (Topic 740) – Improvements to Income Tax Disclosures,” which requires that certain information in a reporting entity’s tax rate reconciliation be disaggregated and provides additional requirements regarding income taxes paid. The amendments are effective for annual periods beginning after December 15, 2024, with early adoption permitted, and should be applied either prospectively or retrospectively. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity.

In November 2024, the FASB issued ASU 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40) – Disaggregation of Income Statement Expenses,” which requires additional disclosure about specified categories of expenses included in relevant expense captions presented on the income statement. The amendments are effective for annual periods beginning after December 15, 2026, and for interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. The amendments may be applied either prospectively or retrospectively. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity.

The Company considers the applicability and impact of all ASUs. ASUs not listed above were assessed and determined to be either not applicable, previously disclosed, or not material upon adoption.

3. REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue from Contracts with Customers

The following tables present the Company’s revenue from contracts with customers:


	Three Months Ended March 31,
		2025		2024
		(In millions)
Oil sales		$	3,039	$	1,867
Natural gas sales		212		50
Natural gas liquid sales		406		184
Total oil, natural gas and natural gas liquid revenues		3,657		2,101
Sales of purchased oil		374		116
Other service revenues		11		8
Total revenue from contracts with customers		$	4,042	$	2,225

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The following tables present the Company’s revenue from oil, natural gas, and natural gas liquids disaggregated by basin:










	Three Months Ended March 31, 2025								Three Months Ended March 31, 2024
	Midland Basin		Delaware Basin		Other		Total		Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	2,801	$	236	$	2	$	3,039	$	1,503	$	360	$	4	$	1,867
Natural gas sales	191		20		1		212		34		15		1		50
Natural gas liquid sales	374		31		1		406		137		47		—		184
Total	$	3,366	$	287	$	4	$	3,657	$	1,674	$	422	$	5	$	2,101

4. ACQUISITIONS AND DIVESTITURES

2025 Activity

See Note 17—Subsequent Events for details on acquisition and divestiture activity subsequent to March 31, 2025.

2024 Activity

Diamondback Acquisitions and Divestitures

Endeavor Acquisition

For details on the Endeavor Acquisition, which closed on September 10, 2024, see Note 5—Endeavor Energy Resources, LP Acquisition.

TRP Energy, LLC Asset Exchange

On December 20, 2024, the Company completed a transaction with TRP Energy, LLC (“TRP”), in which the Company exchanged certain assets including approximately 47,034 gross (35,673 net) acres located in the Delaware Basin and $325 million in cash, subject to customary post-closing adjustments, for certain of TRP’s assets consisting of approximately 21,582 gross (15,421 net) acres located in the Midland Basin with 55 operated locations (the “TRP Exchange”). The TRP Exchange is expected to expand our operating footprint and enhance our inventory of near-term drilling locations, and was valued at approximately $1.4 billion. The Company funded the cash portion of the exchange with cash on hand and borrowings under its revolving credit facility.

The following table presents the acquisition consideration transferred in the TRP Exchange (in millions):


Consideration:
Oil and natural gas properties	$	989
Midstream assets	53
Suspense liabilities relieved	(9)
Cash consideration	325
Total consideration	$	1,358

Acquisition Date Fair Value of Consideration Transferred

The acquisition date fair value of oil and natural gas properties transferred was determined 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. These inputs are not observable in the market and are considered level 3 inputs within the fair value hierarchy. The oil and natural gas properties transferred did not significantly impact the Company’s capitalized costs or proved reserves as of December 31, 2024.

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The acquisition date fair value of midstream assets transferred was determined based on the cost approach, which utilized asset listings and cost records with consideration for the age, condition, utilization and economic support of the assets.

Allocation of Consideration Transferred

The TRP Exchange has been accounted for under the acquisition method of accounting for business combinations in accordance with ASC Topic 805, “Business Combinations.” The following table represents the allocation of the total consideration transferred in the TRP Exchange to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. Although the allocation of consideration transferred is substantially complete as of the date of this filing, title to properties exchanged remain subject to change as the details of the transaction are finalized subsequent to closing. As such, there may be further adjustments to the fair value of certain assets acquired and liabilities assumed. The allocation of consideration transferred will be finalized within twelve months of the closing date of the transaction.

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


Total consideration	$	1,358

Fair value of liabilities assumed:
Suspense liabilities	(3)

Fair value of assets acquired:
Oil and natural gas properties	1,361
Net assets acquired and liabilities assumed	$	1,358

Oil and natural gas properties acquired 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. These inputs are not observable in the market and are considered level 3 inputs within the fair value hierarchy.

With the completion of the TRP Exchange, the Company acquired proved properties of $860 million and unproved properties of $501 million.

The results of operations attributable to the TRP Exchange since the acquisition date have been included in the condensed consolidated statements of operations and include $127 million of total revenue and $111 million of net income for the three months ended March 31, 2025.

WTG Midstream Transaction

The Company owns a 25% non-operating equity investment in Remuda Midstream Holdings LLC, referred to as the “WTG joint venture.” On July 15, 2024, the WTG joint venture sold its WTG Midstream LLC subsidiary (the “WTG Midstream Transaction”), for which the Company received as its portion of the consideration 10.1 million common units issued by Energy Transfer LP (NYSE: ET) and $190 million in cash, subject to customary post-closing adjustments. The common unit consideration is also subject to preferred distributions to incentive members of the WTG joint venture which reduce the proceeds attributable to the Company. At the closing of the WTG Midstream Transaction, the value attributable to the Company of the 10.1 million common units was approximately $135 million, of which approximately $81 million was received by the Company and $54 million was initially held in escrow pursuant to an escrow agreement entered into by the WTG joint venture in connection with the initial transaction. In the first quarter of 2025, the Company received approximately $15 million related to the settlement of working capital and $27 million of the initial escrow amount was released. The total value of distributions received by the Company through March 31, 2025 of $313 million, including certain customary post-closing adjustments, (excluding the remaining $27 million held in escrow) exceeded the carrying value of the Company’s investment balance in the WTG joint venture, resulting in an aggregate gain of approximately $116 million, of which approximately $42 million was recognized during the three months ended March 31, 2025. The gain is included in the caption “Other income (expense), net” in the condensed consolidated statement of operations.

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Viper Acquisitions

Viper Tumbleweed Acquisitions

In September and October of 2024, Viper completed a series of related acquisitions including the Viper TWR Acquisition, the Viper Q Acquisition and the Viper M Acquisition, collectively the (“Viper Tumbleweed Acquisitions”), each as defined and discussed below.

On October 1, 2024, Viper acquired all of the issued and outstanding equity interests in TWR IV, LLC and TWR IV SellCo, LLC from Tumbleweed Royalty IV, LLC (“TWR IV”) and TWR IV SellCo Parent, LLC (the “Viper TWR Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of approximately (i) $464 million in cash, including transaction costs and certain customary post-closing adjustments, (ii) 10.09 million Viper LLC units to TWR IV, (iii) an option for TWR IV to acquire up to 10.09 million shares of Viper’s Class B Common Stock (the “TWR Class B Option”), and (iv) contingent cash consideration of up to $41 million, payable in January of 2026, based on the average price of WTI sweet crude oil prompt month futures contracts for the calendar year 2025 (the “WTI 2025 Average”).

TWR IV can exchange some or all of the Viper LLC units received for an equal number of shares of Viper’s Class A common stock. The mineral and royalty interests acquired in the Viper TWR Acquisition represent approximately 3,067 net royalty acres located primarily in the Permian Basin. Viper funded the cash consideration through a combination of cash on hand, borrowings under the Viper LLC credit agreement and proceeds from the Viper 2024 Equity Offering (as defined and discussed in Note 10—Stockholders' Equity and Earnings (Loss) Per Share).

On September 3, 2024, Viper acquired all of the issued and outstanding equity interests in Tumbleweed-Q Royalties, LLC (the “Viper Q Acquisition”), pursuant to a definitive purchase and sale agreement for consideration consisting of (i) approximately $114 million in cash, including transaction costs and certain customary post-closing adjustments, and (ii) contingent cash consideration of up to $5 million, payable in January of 2026, based on the WTI 2025 Average.

Additionally, on September 3, 2024, Viper acquired all of the issued and outstanding equity interests in MC TWR Royalties, LP and MC TWR Intermediate, LLC (the “Viper M Acquisition” and together with the Viper Q Acquisition, the “Viper Q & M Acquisitions”), pursuant to a definitive purchase and sale agreement for consideration consisting of (i) approximately $76 million in cash, including transaction costs and certain customary post-closing adjustments, and (ii) contingent cash consideration of up to $4 million, payable in January of 2026, based on the WTI 2025 Average. The mineral and royalty interests acquired in the Viper Q & M Acquisitions, represent approximately 406 and 267 net royalty acres located primarily in the Permian Basin, respectively. Viper funded the cash consideration for the Viper Q & M Acquisitions through a combination of cash on hand and borrowings under the Viper LLC credit agreement.

See Note 14—Fair Value Measurements for further discussion of the fair value of the contingent consideration liabilities for each of the Viper Tumbleweed Acquisitions discussed above (collectively, the “2026 WTI Contingent Liability”).

5. ENDEAVOR ENERGY RESOURCES, LP ACQUISITION

On September 10, 2024, the Company completed its acquisition of Endeavor Parent, LLC (“Endeavor”) (the “Endeavor Acquisition”) for consideration consisting of (i) $7.1 billion in cash paid to the Endeavor equityholders, (ii) $238 million for the repayment of Endeavor’s net debt, which included the $219 million net debt position and the associated $19 million make-whole premium paid upon redemption of the senior notes and costs incurred to terminate Endeavor’s revolving credit facility, and (iii) approximately 117.27 million shares of the Company’s common stock. The Endeavor Acquisition included approximately 500,849 gross (361,927 net) acres, which are primarily located in the Permian Basin. Following the Endeavor Acquisition, the Company believes its inventory has industry-leading depth and quality that will be converted into cash flow with the industry’s lowest cost structure, creating a differentiated value proposition for Diamondback stockholders.

The cash consideration for the Endeavor Acquisition was funded through a combination of cash on hand, the net proceeds from the Company’s April 2024 Notes offering and borrowings under the Tranche A Loans (as defined and discussed in Note 9—Debt). Immediately following the close of the Endeavor Acquisition, Endeavor equityholders held approximately 39.8% of Diamondback’s common stock. As of March 31, 2025, Endeavor’s equityholders held approximately 36.2% of the Company’s common stock.

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Following the closing of the Endeavor Acquisition, the Company filed with the SEC a shelf registration statement, which became immediately effective upon filing, registering for resale the shares of common stock issued in the Endeavor Acquisition, as required by the terms of the related registration rights agreement.

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


Consideration:
Shares of Diamondback common stock issued at closing	117,267
Closing price per share of Diamondback common stock on the closing date	$	171.49
Fair value of Diamondback common stock issued	$	20,110

Base cash amount	$	8,000
Preliminary closing adjustments	(928)
Cash consideration to Endeavor equityholders	7,072
Cash payment of net debt position and make-whole amount	238
Total cash consideration	7,310

Total consideration (including fair value of Diamondback common stock issued)	$	27,420

Purchase Price Allocation

The Endeavor Acquisition has been accounted for under the acquisition method of accounting for business combinations in accordance with ASC Topic 805, “Business Combinations.” The following table represents the preliminary allocation of the total purchase price for the acquisition of Endeavor to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. Although the purchase price allocation is substantially complete as of the date of this filing, certain data necessary to complete the purchase price allocation is not yet available, including, but not limited to, final tax returns that provide the underlying tax basis of Endeavor’s assets and liabilities. As such, there may be further adjustments to the fair value of certain assets acquired and liabilities assumed, including Endeavor’s deferred tax liability, oil and natural gas properties, which include mineral and royalty interests acquired, and other property and equipment. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date.

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


Total consideration	$	27,420

Fair value of liabilities assumed:
Accounts payable - trade	$	18
Accrued capital expenditures	173
Other accrued liabilities	613
Revenues and royalties payable	567
Derivative instruments	5
Income taxes payable	261
Other current liabilities	21
Asset retirement obligations	260
Deferred income taxes	7,211
Other long-term liabilities	5
Amount attributable to liabilities acquired	$	9,134

Fair value of assets acquired:

Accounts receivable - joint interest and other, net	$	69
Accounts receivable - oil and natural gas sales, net	659
Inventories	77
Derivative instruments	25
Prepaid expenses and other current assets	20
Oil and natural gas properties	34,824
Other property, equipment and land	849
Other assets	31
Amount attributable to assets acquired	$	36,554

Net assets acquired and liabilities assumed	$	27,420

The purchase price allocation above is based on the fair values of the assets and liabilities of Endeavor as of the closing date of the Endeavor Acquisition. The majority of the value of assets acquired and liabilities assumed was measured 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 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 and mineral interest 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 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 acquisition-date fair values of assets acquired and liabilities assumed. The fair values of asset retirement obligations and inventories were calculated in accordance with the Company’s internal policies as described in Note 2 —Summary of Significant Accounting Policies in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024. The fair values of various current assets and liabilities including accounts receivable and accounts payable approximate their carrying values on the closing date of the Endeavor Acquisition because of the short-term nature of the instruments.

With the completion of the Endeavor Acquisition, the Company acquired proved properties of $20.6 billion and unproved properties of $14.2 billion, primarily in the Midland Basin.

The results of operations attributable to the Endeavor Acquisition since the acquisition date have been included in the condensed consolidated statements of operations and include $1.4 billion of total revenue and $477 million of net income for the three months ended March 31, 2025.

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6. PROPERTY AND EQUIPMENT

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


	March 31,		December 31,
	2025		2024
	(In millions)
Oil and natural gas properties:
Subject to depletion	$	61,708	$	59,574
Not subject to depletion	22,019		22,666
Gross oil and natural gas properties	83,727		82,240
Accumulated depletion	(12,143)		(11,083)
Accumulated impairment	(7,954)		(7,954)
Oil and natural gas properties, net	63,630		63,203
Other property, equipment and land	1,452		1,440
Accumulated depreciation, amortization, accretion and impairment	(186)		(171)
Total property and equipment, net	$	64,896	$	64,472

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, 2025 or 2024 based on the results of the respective quarterly ceiling tests.

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.

7. 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,
	2025		2024
	(In millions)
Asset retirement obligations, beginning of period	$	592	$	245
Additional liabilities incurred	16		1
Liabilities acquired	1		1
Liabilities settled and divested	(12)		(7)
Accretion expense	9		3
Revisions in estimated liabilities	1		31
Asset retirement obligations, end of period	607		274
Less current portion(1)	21		8
Asset retirement obligations - long-term	$	586	$	266

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

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8. RELATED PARTY TRANSACTIONS

Viper

During the first quarter of 2025, Viper deposited approximately $223 million of cash into escrow pursuant to an equity purchase agreement for the 2025 Drop Down (as defined and discussed in Note 17—Subsequent Events). Viper’s escrow deposit is reflected in the caption “Restricted cash” on the Company’s condensed consolidated balance sheet at March 31, 2025.

Deep Blue

On September 1, 2023, the Company closed on a joint venture agreement with Five Point Energy LLC to form Deep Blue Midland Basin LLC (“Deep Blue”), in which the Company owns 30% equity ownership interest. In addition to the Deep Blue transaction, the Company has other significant related party transactions with Deep Blue which include (i) certain accounts receivable from Deep Blue, (ii) accrued capital expenditures and other accrued payables related to a commitment to fund certain capital expenditures on projects that were in process at the time of the Deep Blue transaction, and (iii) lease operating expenses and capitalized expenses related to fees paid to Deep Blue under a 15-year dedication for its produced water and supply water within a 12-county area of mutual interest in the Midland Basin.

The following table presents the significant related party balances included in the condensed consolidated balance sheets at March 31, 2025 and December 31, 2024:


	March 31,		December 31,
	2025		2024
	(In millions)
Current assets - Accounts receivable	$	5	$	5
Long-term assets - Equity method investments	$	145	$	137
Current liabilities - Accrued capital expenditures	$	(30)	$	(31)
Current liabilities - Other accrued liabilities	$	(36)	$	(22)

During the three months ended March 31, 2025 and 2024, the Company recorded approximately $47 million and $31 million, respectively, for water services provided by Deep Blue during the completion phase of wells. These costs were capitalized and are included in the caption “Oil and natural gas properties” on the condensed consolidated balance sheets.

The following table presents the significant related party transactions included in the condensed consolidated statements of operations for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
		2025		2024
		(In millions)
Lease operating expenses		$	37	$	26

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9. DEBT

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


	March 31,		December 31,
	2025		2024
	(In millions)
3.250% Senior Notes due 2026	$	750	$	750
5.625% Senior Notes due 2026	14		14
5.200% Senior Notes due 2027	850		850
7.125% Medium-term Notes, Series B, due 2028	73		73
3.500% Senior Notes due 2029	915		915
5.150% Senior Notes due 2030	850		850
3.125% Senior Notes due 2031	767		767
6.250% Senior Notes due 2033	1,100		1,100
5.400% Senior Notes due 2034	1,300		1,300
5.550% Senior Notes due 2035	1,200		—
4.400% Senior Notes due 2051	650		650
4.250% Senior Notes due 2052	750		750
6.250% Senior Notes due 2053	650		650
5.750% Senior Notes due 2054	1,500		1,500
5.900% Senior Notes due 2064	1,000		1,000
Tranche A Loans	900		900

Unamortized debt issuance costs	(98)		(91)
Unamortized discount costs	(25)		(25)
Unamortized premium costs	2		3
Unamortized basis adjustment of dedesignated interest rate swap agreements(1)	(68)		(72)

Viper revolving credit facility	—		261
Viper 5.375% Senior Notes due 2027	430		430
Viper 7.375% Senior Notes due 2031	400		400
Total debt, net	13,910		12,975
Less: current maturities of debt	914		900
Total long-term debt	$	12,996	$	12,075

(1) Represents the unamortized basis adjustment related to two receive-fixed, pay variable interest rate swap agreements which were previously designated as fair value hedges of the Company’s $1.2 billion 3.500% fixed rate senior notes due 2029. This basis adjustment is being amortized to interest expense over the remaining term of the 2029 Notes utilizing the effective interest method.

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

Credit Agreement

On March 21, 2025, Diamondback E&P, as borrower, and Diamondback Energy, Inc., as parent guarantor, entered into a fifteenth amendment to the existing credit agreement, which made certain amendments to the representations and warranties that must be made to fund the loans under the 2025 Term Loan Agreement (defined below). The credit agreement provides for a maximum credit amount of $2.5 billion. As of March 31, 2025, the Company had no outstanding borrowings under the credit agreement and approximately $2.5 billion available for future borrowings. During the three months ended March 31, 2025, the weighted average interest rate on borrowings under the credit agreement was 5.92%. The credit agreement matures on June 2, 2029.

As of March 31, 2025, the Company was in compliance with all financial maintenance covenants under the credit agreement.

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Term Loan Agreements

2025 Term Loan Agreement

In connection with the Double Eagle Acquisition (as defined and discussed in Note 17—Subsequent Events), Diamondback Energy, Inc., as guarantor, entered into a Term Loan Credit Agreement with Diamondback E&P LLC, as borrower, and Bank of America, N.A., as administrative agent (the “2025 Term Loan Agreement”) on March 21, 2025.

The 2025 Term Loan Agreement provides the Company with the ability to borrow up to $1.5 billion on an unsecured basis to fund a portion of the cash consideration for the Double Eagle Acquisition (as defined and discussed in Note 17—Subsequent Events) and costs and expenses related to the acquisition. As of March 31, 2025, the Company had no outstanding borrowings under the 2025 Term Loan Agreement.

On the date of closing of the Double Eagle Acquisition, the entire amount available under the 2025 Term Loan Agreement was drawn in a single borrowing. Any remaining outstanding amounts will mature and be payable in full on the second anniversary of the initial funding date.

Outstanding borrowings under the Term Loan Agreement bear interest at a per annum rate elected by the Company that is equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”) or (ii) an alternate base rate (which is equal to the greatest of (a) the federal funds effective rate plus 0.50%, (b) the prime rate (c) Adjusted Term SOFR plus 1.0%, and (d) 1.0%), in each case plus the applicable margin. The applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate, and from 1.125% to 2.000% per annum in the case of Adjusted Term SOFR, in each case based on the pricing level, and (ii) the commitment fee is equal to 0.125% per annum on the aggregate principal amount of the commitments. The pricing level depends on the Company’s long-term senior unsecured debt ratings.

2024 Term Loan Agreement

On February 29, 2024, Diamondback Energy, Inc., as guarantor, entered into a Term Loan Credit Agreement with Diamondback E&P LLC, as borrower, and Citibank, N.A., as administrative agent (the “2024 Term Loan Agreement”), which at March 31, 2025, is comprised of $1.0 billion of Tranche A Loans (the “Tranche A Loans”). The Tranche A Loans were drawn to fund a portion of the cash consideration for the Endeavor Acquisition. The initial Tranche A Loans were made in a single borrowing on the date of closing of the Endeavor Acquisition (the “Closing Date”) and any remaining outstanding amounts will mature and be payable in full on the first anniversary of the Closing Date.

As of March 31, 2025, the Company had $900 million in outstanding borrowings under the Tranche A Loans. During the three months ended March 31, 2025, the weighted average interest rate on borrowings under the Term Loan Agreement was 5.68%.

Issuance of Notes

On March 20,2025, the Company issued $1.2 billion aggregate principal amount of 5.550% Senior Notes due April 1, 2035 (the “2035 Notes”). The Company received net proceeds of $1.2 billion, after underwriters’ discounts and transaction costs. Interest on the 2035 Notes is payable semi-annually on April 1 and October 1 of each year. The Company used the net proceeds to fund a portion of the cash consideration for the Double Eagle Acquisition (as defined and discussed in Note 17—Subsequent Events) in the second quarter of 2025.

The 2035 Notes are included in the Guaranteed Senior Notes for the Company, which are senior unsecured obligations and are fully and unconditionally guaranteed by Diamondback E&P, 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.

Viper’s Credit Agreement

Viper LLC’s 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 $1.3 billion. As of March 31, 2025, the elected commitment amount was $1.3 billion, with no outstanding borrowings and $1.3 billion available for future borrowings. During the three months ended

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March 31, 2025 and 2024, the weighted average interest rates on borrowings under the Viper credit agreement were 6.57% and 7.65%, respectively. The revolving credit facility will mature on September 22, 2028. As of March 31, 2025, Viper LLC was in compliance with all financial maintenance covenants under the Viper LLC credit agreement.

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

Stock Repurchase Program

The Company’s board of directors approved a common stock repurchase program to acquire up to $6.0 billion of the Company’s outstanding common stock, excluding excise tax. 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 regulatory and 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, 2025 and 2024, the Company repurchased approximately $575 million, and $42 million of common stock under this repurchase program, respectively, in each case excluding excise tax. As of March 31, 2025, approximately $2.1 billion remained available for future repurchases under the Company’s common stock repurchase program, excluding excise tax.

Viper 2025 Equity Offering

On February 3, 2025, Viper completed an underwritten public offering of approximately 28.34 million shares of Viper’s Class A common stock, which included 3.70 million shares issued pursuant to an option to purchase additional shares of Viper’s Class A common stock granted to the underwriters, at a price to the public of $44.50 per share for total net proceeds of approximately $1.2 billion, after the underwriters’ discount and transaction costs (the “Viper 2025 Equity Offering”). The net proceeds were used to fund (i) a portion of the cash consideration for the 2025 Drop Down (as defined and discussed in Note 17—Subsequent Event s), (ii) cash consideration for other acquisitions, and (iii) for general corporate purposes.

Viper 2024 Equity Offering

On September 13, 2024, Viper completed an underwritten public offering of approximately 11.5 million shares of its Class A common stock, which included 1.5 million shares issued pursuant to an option to purchase additional shares of Class A common stock granted to the underwriters, at a price to the public of $42.50 per share for total net proceeds to Viper of approximately $476 million, after underwriters’ discounts and transaction costs (the “Viper 2024 Equity Offering”). The net proceeds were used to fund a portion of the cash consideration for the Viper TWR Acquisition.

Change in Ownership of Consolidated Subsidiaries

Non-controlling interests in the accompanying condensed consolidated financial statements represent minority interest ownership in Viper and are presented as a component of equity. When the Company’s relative ownership interests in Viper 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,
		2025		2024
		(In millions)
Net income (loss) attributable to the Company		$	1,405	$	768
Change in ownership of consolidated subsidiaries		206		(55)
Change from net income (loss) attributable to the Company's stockholders and transfers with non-controlling interest		$	1,611	$	713

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Dividends

The following table presents dividends and distribution equivalent rights paid on the Company’s common stock during the respective periods:


	Base		Variable		Total Per Share		Total
	(In millions, except per share amounts)
2025
First quarter	$	1.00	$	—	$	1.00	$	291




2024
First quarter	$	0.90	$	2.18	$	3.08	$	552

Earnings (Loss) Per Share

The Company’s earnings (loss) per share amounts have been computed using the two-class method. The two-class method is an earnings allocation proportional to the respective ownership among holders of common stock and participating securities. Basic earnings (loss) per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive non-participating securities outstanding for the period. Additionally, the per share earnings of Viper are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiaries.

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


	Three Months Ended March 31,
		2025		2024
		(In millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common shares		$	1,405	$	768
Less: distributed and undistributed earnings allocated to participating securities(1)		6		5
Net income (loss) attributable to common stockholders		$	1,399	$	763
Weighted average common shares outstanding:
Basic weighted average common shares outstanding		289,612		178,477
Effect of dilutive securities:
Weighted-average potential common shares issuable		—		—
Diluted weighted average common shares outstanding		289,612		178,477
Basic net income (loss) attributable to common shares		$	4.83	$	4.28
Diluted net income (loss) attributable to common shares		$	4.83	$	4.28

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

See Note 17—Subsequent Events for further discussion of common stock issued for acquisitions subsequent to March 31, 2025.

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11. EQUITY-BASED COMPENSATION

Under the Equity Plan approved by the board of directors, the Company is authorized to issue up to 11.8 million shares of incentive and non-statutory stock options, restricted stock awards and restricted stock units, performance awards and stock appreciation rights to eligible employees. The Company currently has outstanding restricted stock units and performance-based restricted stock units under the Equity Plan. At March 31, 2025, approximately 3.8 million shares of common stock remain available for future grants under the Equity Plan. The Company classifies its restricted stock units and performance-based restricted stock units 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.

In addition to the Equity Plan, Viper maintains its own long-term incentive plan, which is not significant to the Company.

The following table presents the financial statement impacts of equity compensation plans and related costs on the Company’s financial statements:


	Three Months Ended March 31,
		2025		2024
		(In millions)
General and administrative expenses		$	18	$	14
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties		$	5	$	7

Restricted Stock Units

The following table presents the Company’s restricted stock unit activity during the three months ended March 31, 2025 under the Equity Plan:


	Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2024	645,408	$	159.84
Granted	636,843	$	149.98
Vested	(107,814)	$	158.26
Forfeited	(18,782)	$	155.78
Unvested at March 31, 2025	1,155,655	$	154.62

The aggregate grant date fair value of restricted stock units that vested during the three months ended March 31, 2025 was $17 million. As of March 31, 2025, the Company’s unrecognized compensation cost related to unvested restricted stock units was $155 million, which is expected to be recognized over a weighted-average period of 2.5 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, 2025:


	Performance Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2024	278,902	$	278.72
Granted	171,638	$	222.34
Vested	(6,590)	$	158.96

Unvested at March 31, 2025(1)	443,950	$	258.70

(1)A maximum of 1,070,323 units could be awarded based upon the Company’s final TSR ranking.

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As of March 31, 2025, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $72 million, which is expected to be recognized over a weighted-average period of 2.0 years.

In March 2025, eligible employees received performance restricted stock unit awards totaling 171,638 units from which a minimum of 0% and a maximum of 200% of the units could be awarded based upon the measurement of total stockholder return of the Company’s common stock as compared to a designated peer group during the three-year performance period of January 1, 2025 to December 31, 2027 and cliff vest at December 31, 2027 subject to continued employment. The initial payout of the March 2025 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 periods presented:


	March 2025
Grant-date fair value	$	222.34
Risk-free rate	3.99		%
Company volatility	34.60		%

12. INCOME TAXES

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


	Three Months Ended March 31,
		2025			2024
		(In millions, except for tax rate)
Provision for (benefit from) income taxes		$	403		$	223
Effective income tax rate		21.3		%	21.6		%

Total income tax expense from continuing operations for the three months ended March 31, 2025 differed from amounts computed by applying the U.S. federal statutory tax rate to pre-tax income primarily due to (i) state income taxes, net of federal benefit, (ii) the effect of research and development tax credits, (iii) limitations on the deduction of certain permanent items, and (iv) other permanent differences between book and taxable income. For the three months ended March 31, 2024, total income tax expense from continuing operations differed from amounts computed by applying the U.S. 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.

In connection with the closing of the Endeavor Acquisition, the Company recognized a $7.2 billion deferred tax liability.

In connection with the Company’s public offering of Viper’s Class A common stock and resulting decrease in its ownership of Viper in March 2024, the Company recorded a $36 million increase in tax payable and a $3 million increase in deferred tax liability through paid in capital and an $18 million increase in the deferred tax asset, net of valuation allowance, through non-controlling interest on the Company’s condensed consolidated balance sheet.

Based on application of the Inflation Reduction Act of 2022 guidance, the Company’s income tax expense for the three months ended March 31, 2025 was not impacted by the corporate alternative minimum tax.

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13. DERIVATIVES

At March 31, 2025, the Company has commodity derivative contracts and interest rate swaps outstanding. All derivative financial instruments are recorded at fair value.

Commodity Contracts

The Company has entered into multiple crude oil and natural gas derivatives, indexed to the respective indices as noted in the table below, to reduce price volatility associated with certain of its oil and natural gas sales. The Company has not designated its commodity derivative instruments as hedges for accounting purposes and, as a result, marks its commodity derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the condensed consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company 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, collateral is not required from either the counterparties or the Company on its outstanding commodity derivative contracts.

As of March 31, 2025, the Company had the following outstanding commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.


					Swaps	Collars
Settlement Month	Settlement Year	Type of Contract	Bbls/MMBtu Per Day	Index	Weighted Average Differential		Weighted Average Floor Price	Weighted Average Ceiling Price
OIL
Apr. - Dec.	2025	Roll Swap	25,000	WTI Cushing	$0.93		$—	$—
Apr. - Dec.	2025	Basis Swap(1)	71,000	Argus WTI Midland	$1.05		$—	$—
NATURAL GAS
Apr. - Dec.	2025	Costless Collar	690,000	Henry Hub	$—		$2.49	$5.28
Jan. - Dec.	2026	Costless Collar	560,000	Henry Hub	$—		$2.70	$6.35
Jan. - Dec.	2027	Costless Collar	40,000	Henry Hub	$—		$3.00	$6.65
Apr. - Dec.	2025	Basis Swap(1)	610,000	Waha Hub	$(0.88)		$—	$—
May - Dec.	2025	Basis Swap(1)	20,000	HSC Hub	$(0.49)		$—	$—
Jan. - Dec.	2026	Basis Swap(1)	250,000	Waha Hub	$(1.44)		$—	$—
Jan. - Dec.	2027	Basis Swap(1)	220,000	Waha Hub	$(1.46)		$—	$—

(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, the Waha Hub and the HSC Hub natural gas price. The weighted average differential represents the amount of reduction to the Cushing, Oklahoma oil price and the Waha Hub and HSC Hub natural gas price for the notional volumes covered by the basis swap contracts.

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Settlement Month	Settlement Year	Type of Contract	Bbls Per Day	Index	Strike Price	Deferred Premium
OIL
Apr. - Jun.	2025	Put	50,000	Brent	$58.30	$1.50
Apr. - Jun.	2025	Put	96,000	Argus WTI Houston	$55.10	$1.59
Apr. - Jun.	2025	Put	152,000	WTI Cushing	$55.53	$1.59
Jul. - Sep.	2025	Put	36,000	Brent	$56.39	$1.50
Jul. - Sep.	2025	Put	87,000	Argus WTI Houston	$55.00	$1.61
Jul. - Sep.	2025	Put	136,000	WTI Cushing	$54.91	$1.54
Oct. - Dec.	2025	Put	21,000	Brent	$55.00	$1.47
Oct. - Dec.	2025	Put	50,000	Argus WTI Houston	$55.00	$1.63
Oct. - Dec.	2025	Put	76,000	WTI Cushing	$54.84	$1.52
Jan. - Mar.	2026	Put	4,000	Brent	$55.00	$1.45
Jan. - Mar.	2026	Put	5,000	Argus WTI Houston	$55.00	$1.75
Jan. - Mar.	2026	Put	25,000	WTI Cushing	$55.00	$1.32

Interest Rate Swaps and Treasury Locks

Interest Rate Swaps

As of March 31, 2025, the Company has two receive-fixed, pay variable interest rate swap agreements for notional amounts of $300 million and $600 million, respectively, which are considered economic hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 (the “2029 Notes”). The Company receives a fixed 3.50% rate of interest on these swaps and pays the variable rate of SOFR plus 2.1865%. The interest rate swaps are not treated as hedges for accounting purposes and, as a result, changes in fair value are recorded in earnings under the caption “Gain (loss) on derivative instruments, net” in the condensed consolidated statements of operations.

The interest rate swaps were designated as fair value hedges at inception, but the Company subsequently elected to discontinue hedge accounting. The cumulative fair value basis adjustment recorded at the time of dedesignation is being amortized to interest expense over the remaining term of the 2029 Notes utilizing the effective interest method. See Note 9—Debt for further details.

Treasury Locks

During the first quarter of 2025, the Company entered into certain treasury lock contracts to reduce the forecasted interest rate risk associated with the issuance of the 2035 Notes. The treasury locks were terminated and settled upon issuance of the 2035 Notes with a loss of $1 million recognized under the caption “Gain (loss) on derivative instruments, net” on the condensed consolidated statements of operations for the three months ended March 31, 2025.

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 14—Fair Value Measurements for further details.

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Gains and Losses on Derivative Instruments

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


	Three Months Ended March 31,
		2025		2024
		(In millions)
Gain (loss) on derivative instruments, net:
Commodity contracts		$	214	$	(16)
Interest rate swaps		11		(32)
2026 WTI Contingent Liability		2		—
Treasury locks		(1)		—
Total		$	226	$	(48)

Net cash received (paid) on settlements:
Commodity contracts		$	86	$	(4)

Treasury locks		(1)		—
Total		$	85	$	(4)

14. FAIR VALUE MEASUREMENTS

Assets and Liabilities Measured at Fair Value on a Recurring Basis

As discussed in Note 14—Fair Value Measurements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2024, certain financial instruments of the Company are reported at fair value on the Company’s condensed consolidated balance sheets. The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates. The Company has an immaterial investment that is reported at fair value using observable, quoted stock prices and is included in “Other assets” on the Company’s condensed consolidated balance sheets at March 31, 2025 and December 31, 2024.

Viper LLC’s 2026 WTI Contingent Liability is reported at fair value using observable market data inputs and a Monte Carlo pricing model, which are considered Level 2 inputs within the fair value hierarchy. The 2026 WTI Contingent Liability was recorded in “Other accrued liabilities” on the Company’s condensed consolidated balance sheet at March 31, 2025 and in “Other long-term liabilities” on the Company’s consolidated balance sheet at December 31, 2024. The change in fair value of the 2026 WTI Contingent Liability is recognized in “Gain (loss) on derivative instruments, net” on the Company’s condensed consolidated statements of operations for the three months ended March 31, 2025.

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The following table provides the fair value of financial instruments that are recorded at fair value in the condensed consolidated balance sheets as of March 31, 2025 and December 31, 2024:


	As of March 31, 2025
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Current assets- Derivative instruments:

Commodity derivative instruments	$	—	$	420	$	—	$	420	$	(153)	$	267

Non-current assets- Derivative instruments:
Commodity derivative instruments	$	—	$	118	$	—	$	118	$	(57)	$	61
Non-current assets- Other assets:
Investment	$	49	$	—	$	—	$	49	$	—	$	49

Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	199	$	—	$	199	$	(153)	$	46
Interest rate swaps	$	—	$	29	$	—	$	29	$	—	$	29
Current liabilities- Other accrued liabilities:
2026 WTI Contingent Liability	$	—	$	28	$	—	$	28	$	—	$	28
Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	66	$	—	$	66	$	(57)	$	9
Interest rate swaps	$	—	$	84	$	—	$	84	$	—	$	84


	As of December 31, 2024
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Current assets- Derivative instruments:

Commodity derivative instruments	$	—	$	274	$	—	$	274	$	(106)	$	168

Non-current assets- Derivative instruments:
Commodity derivative instruments	$	—	$	19	$	—	$	19	$	(17)	$	2
Non-current assets- Other assets:
Investment	$	8	$	—	$	—	$	8	$	—	$	8

Liabilities:
Current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	121	$	—	$	121	$	(106)	$	15
Interest rate swaps	$	—	$	28	$	—	$	28	$	—	$	28
Non-current liabilities- Derivative instruments:
Commodity derivative instruments	$	—	$	27	$	—	$	27	$	(17)	$	10
Interest rate swaps	$	—	$	96	$	—	$	96	$	—	$	96
Non-current liabilities- Other long-term liabilities:
2026 WTI Contingent Liability	$	—	$	30	$	—	$	30	$	—	$	30

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Assets and Liabilities Not Recorded at Fair Value

The following table provides the fair value of financial instruments that are not recorded at fair value in the condensed consolidated balance sheets:


	March 31, 2025				December 31, 2024
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
Debt	$	13,910	$	13,606	$	12,975	$	12,564

The fair values of the Company’s credit agreement and Tranche A Loans and Viper LLC’s credit agreement approximate their carrying values based on borrowing rates available to the Company for bank loans with similar terms and maturities and are 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 natural gas properties, equity method investments, asset retirement obligations and other long-lived assets that are written down to fair value when impaired or held for sale. Refer to Note 4—Acquisitions and Divestitures, Note 5—Endeavor Energy Resources, LP Acquisition and Note 6—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, prepaid expenses and other current assets, payables, other accrued liabilities and funds held in escrow approximate their fair value because of the short-term nature of the instruments.

15. SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
		2025		2024
		(In millions)
Supplemental disclosure of cash flow information:

Cash (paid) received for income taxes, net		$	(252)	$	(2)
Supplemental disclosure of non-cash transactions:
Accrued capital expenditures included in accounts payable and accrued expenses		$	746	$	674


Viper LLC's units issued for acquisition		$	119	$	—

16. 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, employment claims, claims alleging violations of antitrust laws, 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 accrued liabilities for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

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Diamondback Energy, Inc. and Subsidiaries

Notes to the Condensed Consolidated Financial Statements - (Continued)

(Unaudited)

Environmental Matters

The United States Department of the Interior, Bureau of Safety and Environmental Enforcement, ordered several oil and gas operators, including a corporate predecessor of Energen Corporation, to perform decommissioning and reclamation activities related to a Louisiana offshore oil and gas production platform and related facilities. In response to the insolvency of the operator of record, the government ordered the former operators and/or alleged former lease record title owners to decommission the platform and related facilities. The Company has agreed to an arrangement with other operators to contribute to a trust to fund the decommissioning costs, however, the Company’s portion of such costs are not expected to be material.

Several coastal Louisiana parishes and the State of Louisiana have filed numerous lawsuits under Louisiana’s State and Local Coastal Resources Management Act (“SLCRMA”) against numerous oil and gas producers seeking damages for coastal erosion in or near oil fields located within Louisiana’s coastal zone. The Company is a defendant in five of these cases. The Company has exercised contractual indemnification rights where applicable. Plaintiffs’ SLCRMA theories are unprecedented, and there remains significant uncertainty about the claims (both as to scope and damages). Although the Company cannot predict the ultimate outcome of these matters, the Company believes the claims lack merit and intends to continue vigorously defending these lawsuits.

17. SUBSEQUENT EVENTS

First Quarter 2025 Dividend Declaration

On May 1, 2025, the board of directors of the Company declared a cash dividend for the first quarter of 2025 of $1.00 per share of common stock, payable on May 22, 2025 to its stockholders of record at the close of business on May 15, 2025. Future base and variable dividends are at the discretion of the Company’s board of directors.

2025 Drop Down Transaction

On May 1, 2025, the Company’s wholly owned subsidiary Endeavor Energy Resources, LP (“EER LP”) divested all of the issued and outstanding equity interests in 1979 Royalties, LP and 1979 Royalties GP, LLC (collectively, the “Endeavor Subsidiaries”), each of which is a subsidiary of the Company, pursuant to a definitive equity purchase agreement with Viper and Viper LLC in exchange for consideration consisting of (i) $1.0 billion in cash, and (ii) the issuance of 69.63 million Viper LLC units and an equivalent number of shares of Viper’s Class B common stock, subject to transaction costs and certain customary post-closing adjustments (the “2025 Drop Down”). Viper funded the cash consideration for the 2025 Drop Down with a portion of the proceeds from the Viper 2025 Equity Offering and borrowings under Viper LLC’s credit agreement. The 2025 Drop Down was accounted for as a transaction between entities under common control. On May 5, 2025, the Company used the cash proceeds received from the 2025 Drop Down to repay in full and terminate the $900 million Tranche A Loans.

EER LP can exchange some or all of the Viper LLC units received together with an equal number of shares of Viper’s Class B common stock for an equal number of shares of Viper’s Class A common stock. The mineral and royalty interests held and divested by the Endeavor Subsidiaries at closing of the 2025 Drop Down represent approximately 22,847 net royalty acres in the Permian Basin, 69% of which are operated by the Company, have an average net royalty interest of approximately 2.8% and current oil production of approximately 17,097 BO/d (the “Endeavor Mineral and Royalty Interests”). The Endeavor Mineral and Royalty Interests include interests in horizontal wells comprised of 6,055 gross proved developed production wells (of which approximately 29% are operated by the Company), 116 gross completed wells and 394 gross drilled but uncompleted wells, all of which are principally concentrated in the Midland Basin, with the balance located primarily in the Delaware and Williston Basins.

Immediately after the completion of the 2025 Drop Down, the Company beneficially owned approximately 53.7% of Viper’s outstanding common stock (or approximately 52% of Viper’s outstanding common stock, on a fully diluted basis after giving effect to the outstanding TWR Class B Option).

Double Eagle Acquisition

On April 1, 2025, the Company completed its acquisition of all of the issued and outstanding interests of DE Permian, LLC, DE IV Combo, LLC, and DE IV Operating, LLC, each of which are wholly owned subsidiaries of Double Eagle IV Midco, LCC (“Double Eagle”) (the “Double Eagle Acquisition”) for consideration of $3.0 billion in cash and approximately 6.84 million shares of the Company’s common stock, subject to transaction costs and certain customary post-closing

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Diamondback Energy, Inc. and Subsidiaries

Notes to the Condensed Consolidated Financial Statements - (Continued)

(Unaudited)

adjustments. The Double Eagle Acquisition consists of approximately 67,700 gross (40,000 net) acres, which are primarily located in the Midland Basin, and approximately 407 gross (342 net) horizontal locations in primary development targets. The Company funded the cash portion of the Double Eagle Acquisition through a combination of proceeds from the 2035 Notes, proceeds from the 2025 Term Loan Agreement, and borrowings on the Company’s credit facility.

Retirement of Notes

In the second quarter of 2025, the Company opportunistically repurchased principal amounts of $111 million of our 4.400% Senior Notes due 2051, $89 million of our 4.250% Senior Notes due 2052 and $20 million of our 5.750% Senior Notes due 2054 in open market transactions for total cash consideration, including accrued interest paid, of $167 million, at an average of 75.3% of par value.

18. SEGMENT INFORMATION

The Company is managed on a consolidated basis as one operating segment and one reportable segment, 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. This singular operating and reportable segment is comprised of (i) the Company and its wholly owned subsidiaries, and (ii) Viper and its consolidated subsidiaries, which have been aggregated due to the similarity in their economic characteristics, products and services, processes, type of customers, method of distribution for their products and the regulatory environment in which they operate. The upstream segment derives its revenue from customers through the sale of oil and natural gas products as well as other immaterial service contracts. See Note 3—Revenue from Contracts with Customers for further discussion of the Company’s sources of revenue.

The Chief Operating Decision Maker (“CODM”) uses the Company’s condensed consolidated financial results to make key operating decisions, assess performance and to allocate resources. The measures of segment profit or loss and total assets utilized by the CODM are net income and total assets as reported on the condensed consolidated statements of operations and the condensed consolidated balance sheets, respectively. The significant expense categories, their amounts and other segment items that are regularly provided to the CODM are those that are reported in the Company’s condensed consolidated statements of operations.

The CODM uses consolidated net income as a measure of profitability to evaluate segment performance and to make capital allocation decisions such as reinvestment in the business or return of capital through the payment of base and variable dividends or repurchases under the share repurchase program.

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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 condensed consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2024. 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 are 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 discussed in Note 1—Description of the Business and Basis of Presentation and Note 18—Segment Information of the notes to the condensed consolidated financial statements, as of March 31, 2025, we have one reportable segment, the upstream segment.

First Quarter 2025 Financial and Operating Highlights

•Recorded net income of $1.4 billion.

•Increased our annual base dividend to $4.00 per share of common stock, paid dividends to stockholders of $290 million during the first quarter of 2025 and declared a base cash dividend payable in the second quarter of 2025 of $1.00 per share of common stock.

•Repurchased $575 million of our common stock, excluding excise taxes, and had approximately $2.1 billion available for future repurchases under our common stock repurchase program at March 31, 2025.

•Our cash operating costs were $10.48 per BOE, including lease operating expenses of $5.33 per BOE, cash general and administrative expenses of $0.72 per BOE and production and ad valorem taxes of $2.98 per BOE and gathering, processing and transportation expenses of $1.45 per BOE.

•Our average production was 850.7 MBOE/d.

•Drilled 124 gross horizontal wells in the Midland Basin and two gross horizontal wells in the Delaware Basin, and turned 123 gross operated horizontal wells (116 in the Midland Basin and seven in the Delaware Basin) to production.

•Cash capital expenditures, excluding acquisitions, of $942 million.

Transactions and Recent Developments

Acquisitions and Divestitures

2025 Drop Down Transaction

On May 1, 2025, our wholly owned subsidiary EER LP divested the Endeavor Subsidiaries to Viper and Viper LLC in exchange for consideration consisting of (i) 1.0 billion in cash, and (ii) the issuance of 69.63 million Viper LLC units and an equal number of shares of Viper’s Class B common stock (which securities are exchangeable for an equal number of Viper’s Class A common stock), subject to transaction costs and certain customary post-closing adjustments. Viper funded the cash consideration for the 2025 Drop Down with a portion of the proceeds from the Viper 2025 Equity Offering and borrowings under Viper LLC’s credit agreement. The mineral and royalty interests held and divested by the Endeavor Subsidiaries at closing of the 2025 Drop Down represent approximately 22,847 net royalty acres located primarily in the Permian Basin. The Endeavor Subsidiaries sold in the 2025 Drop Down were acquired by us in the recently completed Endeavor Acquisition. On May 5, 2025, we used the cash proceeds received from the 2025 Drop Down to repay in full and terminate the $900 million Tranche A Loans.

Double Eagle Acquisition

On April 1, 2025, we completed the Double Eagle Acquisition for consideration of $3.0 billion in cash and approximately 6.84 million shares of our common stock, subject to transaction costs and certain customary post-closing

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adjustments. The Double Eagle Acquisition consists of approximately 67,700 gross (40,000 net) acres, which are primarily located in the Midland Basin, and approximately 407 gross (342 net) horizontal locations in primary development targets. We funded the cash portion of the Double Eagle Acquisition through a combination of proceeds from the 2035 Notes, proceeds from the 2025 Term Loan Agreement and borrowings under our credit facility.

Retirement of Notes

In the second quarter of 2025, we opportunistically repurchased principal amounts of $111 million of our 4.400% Senior Notes due 2051, $89 million of our 4.250% Senior Notes due 2052 and $20 million of our 5.750% Senior Notes due 2054 in open market transactions for total cash consideration of $167 million, including accrued interest paid, at an average of 75.3% of par value.

See Note 17—Subsequent Events of the notes to the condensed consolidated financial statements for further discussion of the transactions above.

Capital Transactions

Term Loan Agreement

In connection with the Double Eagle Acquisition, we entered into the 2025 Term Loan Agreement. The 2025 Term Loan Agreement provided the Company with the ability to borrow up to $1.5 billion, which we drew in a single borrowing to fund a portion of the cash consideration for the Double Eagle Acquisition on April 1, 2025.

2035 Notes Offering

On March 20,2025, we issued the 2035 Notes for net proceeds of $1.2 billion, after underwriters’ discounts and transaction costs, which we used to fund a portion of the cash consideration for the Double Eagle Acquisition.

See Note 9—Debt of the notes to the condensed consolidated financial statements for further discussion of the transactions above.

Viper 2025 Equity Offering

On February 3, 2025, Viper completed an underwritten public offering of approximately 28.34 million shares of its Class A common stock, which included 3.70 million shares issued pursuant to an option to purchase additional shares of its Class A common stock granted to the underwriters at a price to the public of $44.50 per share for total net proceeds to Viper of approximately 1.2 billion, after the underwriters’ discount and estimated transaction costs.

See Note 10—Stockholders' Equity and Earnings (Loss) Per Share of the notes to the condensed consolidated financial statements for further discussion of the transactions above.

Commodity Prices

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to tariffs or other trade barriers, and any resulting trade tensions, extreme weather conditions and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. During the three months ended March 31, 2025 and 2024, WTI prices averaged $71.42 and $76.91 per Bbl, respectively, and Henry Hub prices averaged $3.87 and $2.10 per MMBtu, respectively.

For additional information around risks related to commodity prices, see Part II. Item 3. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.

Upstream Operations

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. 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.

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As of March 31, 2025, we had approximately 859,484 net acres, which primarily consisted of approximately 737,736 net acres in the Midland Basin and 121,748 net acres in the Delaware Basin.

The following table sets forth the total number of operated horizontal wells drilled and completed during the periods indicated:


	Three Months Ended March 31, 2025
	Drilled		Completed(1)
Area:	Gross	Net	Gross	Net
Midland Basin	124	116	116	112
Delaware Basin	2	2	7	7

Total	126	118	123	119

(1)The average lateral length for the wells completed during the first quarter of 2025 was 11,978 feet. Operated completions during the first quarter of 2025 consisted of 30 Wolfcamp A wells, 28 Lower Spraberry wells, 22 Wolfcamp B wells, 17 Jo Mill wells, eight Middle Spraberry wells, four Dean wells, four Barnett wells, three Third Bone Spring wells, three Wolfcamp D wells, two Second Bone Spring wells and two Upper Spraberry wells.

As of March 31, 2025, we operated the following wells:


	As of March 31, 2025
	Vertical Wells		Horizontal Wells		Total
Area:	Gross	Net	Gross	Net	Gross	Net
Midland Basin	4,411	4,181	4,369	4,100	8,780	8,281
Delaware Basin	172	152	507	469	679	621

Total	4,583	4,333	4,876	4,569	9,459	8,902

As of March 31, 2025, we held interests in 31,344 gross (9,290 net) wells, including 2,390 gross (367 net) wells in which we have a non-operated working interest.

Guidance

Given recent weakness in commodity prices, we have reduced our activity levels and lowered our capital budget to prioritize free cash flow generation. We believe that our revised development plan enhances capital efficiency and provides flexibility to adjust our activity levels up or down, as appropriate, if commodity prices strengthen or weaken further.

The following table presents our updated estimates of certain financial and operating results for the full year of 2025 and the second quarter of 2025:


			2025 Guidance
Net production - MBOE/d			857 - 900 (from 883 - 909)
Oil production - MBO/d			480 - 495 (from 485 - 498)
Q2 2025 oil production - MBO/d (total - MBOE/d)			485 - 500 (866 - 900)

(Unit costs $/BOE):
Lease operating expenses, including workovers			$5.65 - $6.05 (from $5.90 - $6.30)
General and administrative expenses - cash			$0.60 - $0.75
Non-cash stock-based compensation			$0.25 - $0.35
Depreciation, depletion, amortization and accretion			$14.00 - $15.00
Interest expense (net of interest income)			$0.40 - $0.65 (from $0.25 - $0.50)
Gathering, processing and transportation			$1.40 - $1.60 (from $1.20 - $1.40)

Production and ad valorem taxes (% of revenue)			~7%
Corporate tax rate (% of pre-tax income)			23%
Cash tax rate (% of pre-tax income)			19% - 22% (from 17% - 20%)
Q2 2025 cash taxes (in millions)(1)			$340 - $400

(1) Includes approximately $170 million of cash taxes related to the Viper dropdown transaction.

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Results of Operations

Comparison of the Three Months Ended March 31, 2025 and December 31, 2024

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

The following table sets forth selected operating data for the three months ended March 31, 2025 and December 31, 2024:


	Three Months Ended
	March 31, 2025		December 31, 2024
Revenues (In millions):
Oil sales	$	3,039	$	3,042
Natural gas sales	212		51
Natural gas liquid sales	406		378
Total oil, natural gas and natural gas liquid revenues	$	3,657	$	3,471

Production Data:
Oil (MBbls)	42,835		43,785
Natural gas (MMcf)	100,578		107,249
Natural gas liquids (MBbls)	16,961		19,615
Combined volumes (MBOE)(1)	76,559		81,275

Daily oil volumes (BO/d)	475,944		475,924
Daily combined volumes (BOE/d)	850,656		883,424

Average Prices:
Oil ($ per Bbl)	$	70.95	$	69.48
Natural gas ($ per Mcf)	$	2.11	$	0.48
Natural gas liquids ($ per Bbl)	$	23.94	$	19.27
Combined ($ per BOE)	$	47.77	$	42.71

Oil, hedged ($ per Bbl)(2)	$	70.06	$	68.72
Natural gas, hedged ($ per Mcf)(2)	$	3.34	$	0.82
Natural gas liquids, hedged ($ per Bbl)(2)	$	23.94	$	19.27
Average price, hedged ($ per BOE)(2)	$	48.89	$	42.76

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

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

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Production Data. Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables provide information on the mix of our production for the three months ended March 31, 2025 and December 31, 2024:


	Three Months Ended
	March 31, 2025		December 31, 2024
Oil (MBbls)	56	%	54	%
Natural gas (MMcf)	22		22
Natural gas liquids (MBbls)	22		24
	100	%	100	%


	Three Months Ended March 31, 2025				Three Months Ended December 31, 2024
	Midland Basin	Delaware Basin	Other	Total	Midland Basin	Delaware Basin	Other	Total
Production Data:
Oil (MBbls)	39,341	3,460	34	42,835	39,134	4,603	48	43,785
Natural gas (MMcf)	90,341	9,961	276	100,578	93,596	13,318	335	107,249
Natural gas liquids (MBbls)	15,769	1,155	37	16,961	17,551	2,041	23	19,615
Total (MBOE)	70,167	6,275	117	76,559	72,284	8,864	127	81,275

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 2025 increased by $186 million to $3.7 billion compared to the fourth quarter of 2024. The net increase was due to an additional $306 million related to improved average prices received for our oil, natural gas and natural gas liquids production, which was partially offset by a $120 million decrease attributable to the 6% decline in our combined production volumes.

Net Sales of Purchased Oil. We have entered into purchase transactions and separate sales transactions with third parties to satisfy certain of our unused oil pipeline capacity commitments. The following table presents the net sales of purchased oil from third parties for the three months ended March 31, 2025 and December 31, 2024:


	Three Months Ended
(In millions)	March 31, 2025		December 31, 2024
Sales of purchased oil	$	374	$	225
Purchased oil expense	382		225
Net sales of purchased oil	$	(8)	$	—

Other Revenues. The following table presents other insignificant revenue for the three months ended March 31, 2025 and December 31, 2024:


	Three Months Ended
(In millions)	March 31, 2025		December 31, 2024
Other operating income	$	17	$	15

Lease Operating Expenses. The following table shows lease operating expenses for the three months ended March 31, 2025 and December 31, 2024:


	Three Months Ended
	March 31, 2025				December 31, 2024
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
Lease operating expenses	$	408	$	5.33	$	461	$	5.67

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Lease operating expenses decreased in total and on a per BOE basis for the first quarter of 2025 compared to the fourth quarter of 2024 primarily due to (i) a $38 million reduction in cost estimates related to producing properties acquired in the Endeavor Acquisition, (ii) a $7 million decrease due to applying a contingent volume discount for water services from Deep Blue in the first quarter of 2025, (iii) a $6 million reduction in well workover expenses, and (iv) other individually insignificant changes.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended March 31, 2025 and December 31, 2024:


	Three Months Ended
	March 31, 2025						December 31, 2024
(In millions, except per BOE amounts)	Amount		Per BOE		Percentage of oil, natural gas and natural gas liquids revenue		Amount		Per BOE		Percentage of oil, natural gas and natural gas liquids revenue
Production taxes	$	171	$	2.23	4.7	%	$	168	$	2.07	4.8	%
Ad valorem taxes	57		0.75		1.5		57		0.70		1.7
Total production and ad valorem expense	$	228	$	2.98	6.2	%	$	225	$	2.77	6.5	%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of oil, natural gas and natural gas liquids revenue remained consistent from the fourth quarter of 2024 to the first quarter of 2025.

Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes remained relatively consistent in total and per BOE during the first quarter of 2025 compared to the fourth quarter of 2024.

Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expense for the three months ended March 31, 2025 and December 31, 2024:


	Three Months Ended
	March 31, 2025				December 31, 2024
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
Gathering, processing and transportation	$	111	$	1.45	$	95	$	1.17

The increase in gathering, processing and transportation expenses is primarily attributable to (i) a $6 million increase from the restructuring of certain sales contracts acquired from Endeavor in the first quarter of 2025, for which gathering and transportation charges were previously recorded as a reduction to revenue, (ii) increases in the contractual pricing of our gathering, processing and transportation costs, and (iii) other individually insignificant items.

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, 2025 and December 31, 2024:


	Three Months Ended
(In millions, except BOE amounts)	March 31, 2025		December 31, 2024
Depletion of proved oil and natural gas properties	$	1,065	$	1,121
Depreciation and amortization of other property and equipment	23		25
Other amortization	—		2
Asset retirement obligation accretion	9		8
Depreciation, depletion, amortization and accretion	$	1,097	$	1,156
Oil and natural gas properties depletion rate per BOE	$	13.91	$	13.79
Depreciation, depletion, amortization and accretion per BOE	$	14.33	$	14.22

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Depletion of proved oil and natural gas properties decreased by $56 million for the first quarter of 2025 compared to the fourth quarter of 2024. This change was comprised of a $65 million decrease due to the decline in production volumes, and a $9 million increase due to a slightly higher depletion rate in the first quarter of 2025.

General and Administrative Expenses. The following table shows general and administrative expenses for the three months ended March 31, 2025 and December 31, 2024:


	Three Months Ended
	March 31, 2025				December 31, 2024
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
General and administrative expenses	$	55	$	0.72	$	56	$	0.69
Non-cash stock-based compensation	18		0.24		16		0.20
Total general and administrative expenses	$	73	$	0.96	$	72	$	0.89

Other Operating Costs and Expenses. The following table shows other operating costs and expenses for the three months ended March 31, 2025 and December 31, 2024:


	Three Months Ended
(In millions)	March 31, 2025		December 31, 2024
Merger and integration expenses	$	37	$	30

Other operating expenses	$	39	$	35

Merger and integration expenses for the first quarter of 2025 were primarily comprised of $23 million of employee severance costs and $2 million of IT and other integration service costs incurred in connection with the Endeavor Acquisition, $10 million in advisory and legal fees incurred as part of the TRP Exchange, and other individually insignificant costs. Merger and integration expenses for the three months ended December 31, 2024 were primarily comprised of employee severance costs related to the Endeavor Acquisition. See Note 5—Endeavor Energy Resources, LP Acquisition and Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements for further details regarding the Endeavor Acquisition and the TRP Exchange, respectively.

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, 2025 and December 31, 2024:


	Three Months Ended
(In millions)	March 31, 2025		December 31, 2024
Gain (loss) on derivative instruments, net	$	226	$	36
Net cash received (paid) on settlements	$	85	$	(15)

The change in gain (loss) on derivative instruments for the first quarter of 2025 compared to the fourth quarter of 2024 primarily reflects (i) an increase of $87 million in cash received on the settlement of natural gas contracts, (ii) an increase of $59 million in the value of our unsettled oil and natural gas contracts due to a decline in market prices for oil and natural gas compared to our contract prices, (iii) a $26 million increase in the value of our interest rate swap contracts driven by a decline in expected future interest rates, (iv) a $19 million decrease in cash paid on the settlement of interest rate swaps, and (v) other individually insignificant changes.

See Note 13—Derivatives of the notes to the condensed consolidated financial statements for further details regarding our derivative instruments.

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Other Income (Expense). The following table shows other income and expenses for the three months ended March 31, 2025 and December 31, 2024:


	Three Months Ended
(In millions)	March 31, 2025		December 31, 2024
Interest expense, net	$	(40)	$	(34)
Other income (expense), net	$	27	$	(7)

Income (loss) from equity investments, net	$	8	$	(2)

The increase in interest expense, net for the first quarter of 2025 compared to the fourth quarter of 2024 primarily consists of (i) a $15 million decrease in capitalized interest costs, which increased interest expense, and (ii) a $3 million increase in interest expense on senior notes primarily related to the newly issued 2035 Notes. These increases were partially offset by (i) a $5 million increase in interest income due to holding proceeds from the 2035 Notes in short-term interest bearing accounts until the closing date of the Double Eagle Acquisition, (ii) a $3 million decrease in interest expense on our Tranche A loans due to a $100 million repayment of principal in the fourth quarter of 2024, (iii) a $2 million decrease in interest expense on Viper’s revolving credit facility due to a lower average quarterly outstanding balance during the first quarter of 2025, and (iv) other individually insignificant changes.

See Note 9—Debt of the notes to the condensed consolidated financial statements for further details regarding outstanding borrowings.

The increase in other income (expense), net for the first quarter of 2025 compared to the fourth quarter of 2024 is primarily due to a gain of $42 million related to the receipt of additional proceeds in connection with the WTG Midstream Transaction, which was partially offset by a $10 million loss on the remeasurement of an investment recorded at fair value and other individually insignificant items.

See Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements for further details regarding the Company’s divestiture activity.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the three months ended March 31, 2025 and December 31, 2024:


	Three Months Ended
(In millions)	March 31, 2025		December 31, 2024
Provision for (benefit from) income taxes	$	403	$	115

The change in our income tax provision for the first quarter of 2025 compared to the fourth quarter of 2024 was primarily due to the increase in pre-tax income between the periods which resulted largely from changes in revenues, operating expenses, and the gain on derivative contracts as discussed above. In addition to the increase in pre-tax income for the first quarter of 2025, the income tax provision for the fourth quarter of 2024 included a partially offsetting net tax benefit of $156 million due to the release of Viper’s remaining valuation allowance. See Note 12—Income Taxes of the notes to the condensed consolidated financial statements for further discussion of our income tax expense.

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Comparison of the Three Months Ended March 31, 2025 and 2024

The following table sets forth selected operating data for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
	2025		2024
Revenues (In millions):
Oil sales	$	3,039	$	1,867
Natural gas sales	212		50
Natural gas liquid sales	406		184
Total oil, natural gas and natural gas liquid revenues	$	3,657	$	2,101

Production Data:
Oil (MBbls)	42,835		24,874
Natural gas (MMcf)	100,578		50,602
Natural gas liquids (MBbls)	16,961		8,653
Combined volumes (MBOE)(1)	76,559		41,961

Daily oil volumes (BO/d)	475,944		273,341
Daily combined volumes (BOE/d)	850,656		461,110

Average Prices:
Oil ($ per Bbl)	$	70.95	$	75.06
Natural gas ($ per Mcf)	$	2.11	$	0.99
Natural gas liquids ($ per Bbl)	$	23.94	$	21.26
Combined ($ per BOE)	$	47.77	$	50.07

Oil, hedged ($ per Bbl)(2)	$	70.06	$	74.13
Natural gas, hedged ($ per Mcf)(2)	$	3.34	$	1.36
Natural gas liquids, hedged ($ per Bbl)(2)	$	23.94	$	21.26
Average price, hedged ($ per BOE)(2)	$	48.89	$	49.97

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

Production Data. Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables set forth the mix of our production data by product and basin for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
	2025		2024
Oil (MBbls)	56	%	59	%
Natural gas (MMcf)	22		20
Natural gas liquids (MBbls)	22		21
	100	%	100	%

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	Three Months Ended March 31, 2025				Three Months Ended March 31, 2024
	Midland Basin	Delaware Basin	Other	Total	Midland Basin	Delaware Basin	Other	Total
Production Data:
Oil (MBbls)	39,341	3,460	34	42,835	20,055	4,768	51	24,874
Natural gas (MMcf)	90,341	9,961	276	100,578	37,494	12,894	214	50,602
Natural gas liquids (MBbls)	15,769	1,155	37	16,961	6,643	1,990	20	8,653
Total (MBOE)	70,167	6,275	117	76,559	32,947	8,907	107	41,961

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

Our oil, natural gas and natural gas liquids revenues for the three months ended March 31, 2025 increased by $1.6 billion, or 74%, to $3.7 billion from the same period in 2024 primarily due to the 82% growth in our combined production volumes.

Approximately 73% of the increase in our combined production volumes is attributable to the Endeavor Acquisition. The remainder of production growth is largely attributable to new wells added between periods.

Net Sales of Purchased Oil. We entered into purchase transactions and separate sale transactions with third parties to satisfy certain of our unused oil pipeline capacity commitments. The following table presents the net sales of purchased oil from third parties for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
(In millions)	2025		2024
Sales of purchased oil	$	374	$	116
Purchased oil expense	382		117
Net sales of purchased oil	$	(8)	$	(1)

Other Revenues. The following table shows the other insignificant revenues for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
(In millions)	2025		2024
Other operating income	$	17	$	10

Lease Operating Expenses. The following table shows lease operating expenses for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
	2025				2024
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
Lease operating expenses	$	408	$	5.33	$	255	$	6.08

Lease operating expenses increased in total for the three months ended March 31, 2025 compared to the same period in 2024 primarily due to costs associated with operating wells acquired as part of the Endeavor Acquisition.

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Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
	2025						2024
(In millions, except per BOE amounts)	Amount		Per BOE		Percentage of oil, natural gas and natural gas liquids revenue		Amount		Per BOE		Percentage of oil, natural gas and natural gas liquids revenue
Production taxes	$	171	$	2.23	4.7	%	$	82	$	1.96	3.9	%
Ad valorem taxes	57		0.75		1.5		37		0.88		1.8
Total production and ad valorem expense	$	228	$	2.98	6.2	%	$	119	$	2.84	5.7	%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes increased by $89 million compared to the same period in 2024, due primarily to (i) $70 million in additional taxes related to production from the Endeavor Acquisition, and (ii) a refund recorded during the three months ended March 31, 2024 of $17 million for the settlement of an audit, which reduced production taxes in the prior year period.

Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes for the three months ended March 31, 2025 as compared to the same period in 2024 increased by $20 million, primarily due to $28 million of additional taxes incurred on properties from the Endeavor Acquisition, which was partially offset by an $8 million decrease caused by a decline in expected ad valorem tax rates on legacy properties for 2025 compared to the rates during 2024.

Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expense for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
	2025				2024
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
Gathering, processing and transportation	$	111	$	1.45	$	77	$	1.84

The increase in gathering, processing and transportation expenses for the three months ended March 31, 2025 compared to the same period in 2024 is attributable primarily to (i) $7 million from the restructuring in 2025 of certain revenue contracts acquired from Endeavor, for which gathering and transportation charges were previously recorded as a reduction to revenue, and (ii) growth in legacy production volumes.


	Three Months Ended March 31,
(In millions, except BOE amounts)	2025		2024
Depletion of proved oil and natural gas properties	$	1,065	$	452
Depreciation and amortization of other property and equipment	23		12
Other amortization	—		2
Asset retirement obligation accretion	9		3
Depreciation, depletion, amortization and accretion	$	1,097	$	469
Oil and natural gas properties depletion rate per BOE	$	13.91	$	10.77
Depreciation, depletion, amortization and accretion per BOE	$	14.33	$	11.18

The increase in depletion of proved oil and natural gas properties of $613 million for the three months ended March 31, 2025 as compared to the same period in 2024 consists primarily of $373 million from growth in production volumes and $240 million due to an increase in the depletion rate resulting largely from the addition of higher value leasehold costs and proved reserves from the Endeavor Acquisition and, to a lesser extent, Viper’s Tumbleweed Acquisitions subsequent to the first quarter of 2024.

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Additionally, depreciation and amortization of other property and equipment increased as a result of the acquisition of other property and equipment in connection with the Endeavor Acquisition.

General and Administrative Expenses. The following table shows general and administrative expenses for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
	2025				2024
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
General and administrative expenses	$	55	$	0.72	$	32	$	0.76
Non-cash stock-based compensation	18		0.24		14		0.34
Total general and administrative expenses	$	73	$	0.96	$	46	$	1.10

General and administrative expenses increased for the three months ended March 31, 2025 compared to the same period in 2024 primarily due to an $18 million increase in employee compensation and benefit costs related to increasing headcount and annual compensation adjustments, and a $9 million increase in software costs.

Other Operating Costs and Expenses. The following table shows the other operating costs and expenses for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
(In millions)	2025		2024
Merger and integration expenses	$	37	$	12
Other operating expenses	$	39	$	14

Merger and integration expenses for the three months ended March 31, 2025 were primarily comprised of (i) $23 million of employee severance costs and $2 million of IT and other integration service costs incurred in connection with the Endeavor Acquisition, (ii) $10 million in advisory and legal fees related to the TRP Exchange, and (iii) other individually insignificant costs. Merger and integration expenses for the three months ended March 31, 2024 relate to costs incurred for the Endeavor Acquisition.

See Note 5—Endeavor Energy Resources, LP Acquisition and Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements for further details regarding the Endeavor Acquisition and TRP Exchange, respectively.

The increase in other operating expenses for the three months ended March 31, 2025 compared to the same period in 2024 primarily resulted from (i) a $16 million increase in midstream service costs largely associated with the additional production from the Endeavor Acquisition, (ii) a $4 million loss on the sale of non-core property, plant and equipment acquired from Endeavor, and (iii) other individually insignificant items.


	Three Months Ended March 31,
(In millions)	2025		2024
Gain (loss) on derivative instruments, net	$	226	$	(48)
Net cash received (paid) on settlements	$	85	$	(4)

The change from a loss to a gain on derivative instruments for the three months ended March 31, 2025 compared to the same period in 2024 primarily reflects (i) a $140 million increase in the value of our unsettled commodity derivative contracts primarily due to a $117 million increase in the value of our natural gas contracts, (ii) a $106 million increase in cash received on the settlement of our natural gas contracts, and (iii) a $43 million increase in the value of our unsettled interest rate swap contracts primarily due to a decline in expected future interest rates. These gains were partially offset by paying an additional $16 million on settlements of oil our contracts in the first quarter of 2025. See Note 13—Derivatives of the notes to the condensed consolidated financial statements for further details regarding our derivative instruments.

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Other Income (Expense). The following table shows other income and expenses for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
(In millions)	2025		2024
Interest expense, net	$	(40)	$	(39)
Other income (expense), net	$	27	$	(3)

Gain (loss) on extinguishment of debt	$	—	$	2
Income (loss) from equity investments, net	$	8	$	2

Interest expense, net increased by $1 million for the three months ended March 31, 2025 compared to the same period in 2024. This decrease primarily consisted of (i) a $79 million increase in interest expense incurred on senior notes related to the issuance of the April 2024 Notes, and to a lesser extent, the 2035 Notes, and (ii) a $13 million increase in interest expense incurred on our Tranche A Loans. These increases were largely offset by (i) an additional $82 million in capitalized interest costs, which reduce interest expense, (ii) a $7 million reduction in the amortization of debt issuance costs primarily related to the remaining debt issuance costs on our terminated bridge facility being fully amortized in 2024, and (iii) other individually insignificant changes.

See Note 9—Debt of the notes to the condensed consolidated financial statements for further details regarding outstanding borrowings.

Other income (expense), net for the three months ended March 31, 2025 increased compared to the three months ended March 31, 2024, primarily due to a gain of $42 million from additional proceeds received related to the WTG Midstream Transaction as discussed further in Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements. This gain was partially offset by a loss of $10 million on the remeasurement of an investment recorded at fair value and other individually insignificant items.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the three months ended March 31, 2025 and 2024:


	Three Months Ended March 31,
(In millions)	2025		2024
Provision for (benefit from) income taxes	$	403	$	223

The change in our income tax provision for the three months ended March 31, 2025 compared to the same period in 2024 was primarily due to the increase in pre-tax income resulting largely from higher revenues from oil and natural gas liquids, along with changes in gain (loss) on derivative instruments, net as discussed above. See Note 12—Income Taxes of the notes to the condensed consolidated financial statements 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 have included 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, repayment of debt and returning capital to stockholders. At March 31, 2025, we had approximately $3.8 billion of liquidity consisting of $1.3 billion in standalone cash and cash equivalents and $2.5 billion available under our credit facility. We further had $1.5 billion available under the 2025 Term Loan Agreement, which was fully drawn on April 1, 2025 to partially fund the Double Eagle Acquisition. As discussed above, due to recent weakness in commodity prices, we have reduced activity levels and lowered our capital budget for 2025 to $3.40 billion to $3.80 billion to prioritize free cash flow generation.

At March 31, 2025, we had approximately $900 million of Tranche A Loans and $14 million of senior notes maturing in the next 12 months. On May 5, 2025, the Company used the cash proceeds received from the 2025 Drop Down to repay in full and terminate the $900 million Tranche A Loans.

Future cash flows are subject to a number of variables, including the level of oil and natural gas production and volatility of commodity prices. Further, significant additional capital expenditures will be required to more fully develop our

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properties. Prices for our commodities are determined primarily by prevailing market conditions, regional and worldwide economic activity, weather and other substantially variable factors. These factors are beyond our control and are difficult to predict as discussed further in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2024. In order to mitigate this volatility, we enter into derivative contracts with a number of financial institutions, all of which are participants in our credit facility, to economically hedge a portion of our estimated future crude oil and natural gas production as discussed further in Note 13—Derivatives of the notes to the condensed consolidated financial statements 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.

Cash Flow

Our cash flows for the three months ended March 31, 2025 and 2024 are presented below:


	Three Months Ended March 31,
	2025		2024
	(In millions)
Net cash provided by (used in) operating activities	$	2,355	$	1,334
Net cash provided by (used in) investing activities	(1,653)		(751)
Net cash provided by (used in) financing activities	1,175		(269)
Net increase (decrease) in cash	$	1,877	$	314

Operating Activities

The increase in operating cash flows for the three months ended March 31, 2025 compared to the same period in 2024 primarily resulted from (i) $1.6 billion in additional revenue, excluding sales of purchased oil, and (ii) an increase of $89 million in cash received on settlements of derivatives. These cash inflows were partially offset by (i) higher cash operating expenses, excluding purchased oil expense, of approximately $369 million, (ii) an increase of $250 million in cash paid for taxes, and (iii) fluctuations in other working capital balances due primarily to the timing of when collections were made on accounts receivable and payments were made on accounts payable. See “—Results of Operations” for discussion of significant changes in our revenues and expenses.

Investing Activities

The majority of our net cash used in investing activities during the three months ended March 31, 2025 and 2024 was for drilling and completion costs incurred in conjunction with our development program as well as the acquisition of properties and equipment including the $208 million escrow deposit for the Double Eagle Acquisition.

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,
	2025		2024
	(In millions)
Operated drilling and completion additions to oil and natural gas properties(1)	$	(864)	$	(572)
Capital workovers, non-operated additions to oil and natural gas properties and science	(21)		(8)
Infrastructure, environmental and midstream additions	(57)		(29)
Total	$	(942)	$	(609)

(1) See “—Transactions and Recent Developments—Upstream Operations” above for additional detail on wells drilled and turned to production during the three and three months ended March 31, 2025 and 2024.

Financing Activities

During the three months ended March 31, 2025, net cash provided by financing activities was primarily attributable to $1.2 billion of proceeds from the issuance of the 2035 Notes and $1.2 billion in proceeds from the Viper 2025 Equity Offering.

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These cash inflows were partially offset by (i) $575 million of repurchases as part of the share repurchase program, (ii) $290 million of dividends paid to stockholders, (iii) $261 million in repayments on our credit facilities, net of borrowings, (iv) $95 million in dividends paid to non-controlling interest, (v) and various other individually insignificant costs.

During the three months ended March 31, 2024, net cash used in financing activities was primarily attributable to (i) $548 million of dividends paid to stockholders, (ii) $44 million in dividends to non-controlling interest, (iii) $42 million of repurchases as part of the share repurchase programs, (iv) $34 million in cash paid for tax withholdings on vested employee stock awards (v) $33 million of debt issuance costs primarily associated with the Term Loan Agreement and Bridge Facility, and (vi) $25 million paid for the retirement of principal outstanding on certain senior notes. These cash outflows were partially offset by $451 million in proceeds from the public offering of Viper’s Class A common stock and an additional $10 million in borrowings under credit facilities, net of repayments.

Capital Resources

Our working capital requirements are primarily supported by our cash and cash equivalents and available borrowings under our revolving 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. Further, the 2025 Term Loan Agreement and net proceeds from the 2035 Notes were also available to finance the cash portion of the Double Eagle Acquisition as of March 31, 2025. Because of the alternatives available to us, 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 capital requirements.

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. Any prolonged volatility in the capital, financial and/or credit markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Revolving Credit Facilities and Other Debt Instruments

As of March 31, 2025, our debt, including the debt of Viper, consisted of approximately $13.2 billion in aggregate outstanding principal amount of senior notes and $900 million in aggregate outstanding borrowings under the Tranche A Loans. On May 5, 2025, the Company used the cash proceeds received from the 2025 Drop Down to repay in full and terminate the $900 million Tranche A Loans.

As of March 31, 2025, the maximum credit amount available under our credit agreement was $2.5 billion, with no outstanding borrowings and $2.5 billion available for future borrowings. Our credit agreement matures on June 2, 2029.

As of March 31, 2025, the maximum credit amount available under our 2025 Term Loan Agreement was $1.5 billion, which was drawn in a single borrowing on April 1, 2025 to fund a portion of the cash consideration for the Double Eagle Acquisition. Our 2025 Term Loan Agreement matures on the second anniversary of the initial funding date.

2035 Notes Offering

On March 20, 2025, we issued the 2035 Notes for net proceeds of $1.2 billion, after underwriters’ discounts and transaction costs, which we used to fund a portion of the cash consideration for the Double Eagle Acquisition.

Viper LLC’s Credit Agreement

The Viper LLC credit agreement, as amended, matures on September 22, 2028 and provides for a revolving credit facility in the maximum credit amount of $2.0 billion, with a borrowing base of $1.3 billion and an elected commitment amount of $1.3 billion. As of March 31, 2025, the Viper LLC credit agreement had no outstanding borrowings and $1.3 billion available for future borrowings.

On May 1, 2025, we completed the 2025 Drop Down with Viper as discussed in Note 17— Subsequent Events of the notes to the condensed consolidated financial statements. Approximately $255 million of the cash consideration for this transaction was funded through borrowings under the Viper LLC credit agreement, reducing the amount that remained available for future borrowings under this facility to $995 million as of May 1, 2025.

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For additional discussion of our debt as of March 31, 2025, see Note 9—Debt of the notes to the condensed consolidated financial statements.

Viper 2025 Equity Offering

During the first quarter of 2025, Viper completed the Viper 2025 Equity Offering for total net proceeds of approximately $1.2 billion, after the underwriters’ discount and transaction costs. For additional discussion of the Viper 2025 Equity Offering, see Note 10—Stockholders' Equity and Earnings (Loss) Per Share of the notes to the condensed consolidated financial statements.

Capital Requirements

In addition to future operating expenses and working capital commitments discussed in “—Transactions and Recent Developments—Upstream Operations” our primary short and long-term liquidity requirements, excluding those of Viper, consist primarily of (i) capital expenditures, (ii) payments of principal and interest on our revolving credit agreements, Tranche A Loans, and senior notes, (iii) payments of other contractual obligations, (iv) cash used to pay for dividends and repurchases of securities, (v) and the cash portion of the Double Eagle Acquisition.

2025 Capital Spending Plan

Our board of directors has approved our revised 2025 capital budget for drilling, midstream, infrastructure and environmental expenditures, which takes into consideration recent weakness in commodity prices and our reduced activity levels to prioritize free cash flow generation. Our revised capital budget for the full year 2025 is approximately $3.40 billion to $3.80 billion, including $2.78 billion to $3.09 billion for operated horizontal drilling and completions, $280 million to $320 million for non-operated activity and capital workovers and $340 million to $390 million spent on infrastructure, midstream and environmental capital expenditures. We currently expect to drill approximately 385 to 435 gross (349 to 395 net) horizontal wells and complete approximately 475 to 550 gross (444 to 514 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 11,500 feet.

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 16 drilling rigs and five completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence and our capital expenditure budget in response to changes in commodity prices and overall market conditions.

Interest on 2035 Notes

On March 20, 2025, we issued $1.2 billion in aggregate principal amount of the 2035 Notes, as discussed further in Note 9—Debt. As a result, we expect to incur additional future cash interest costs on the 2035 Notes of approximately $33 million in 2025, $133 million cumulatively in the years from 2026 through 2027, $133 million cumulatively in the years from 2028 and 2029, and $366 million cumulatively between 2030 and 2035.

Retirement of Notes

In the second quarter of 2025, we opportunistically repurchased $220 million in principal amounts of our senior notes in open market transactions for total cash consideration of $167 million, at an average of 75.3% of par value. We may continue to opportunistically repurchase principal amounts of our and Viper’s senior notes in future periods.

See Note 17—Subsequent Events of the notes to the condensed consolidated financial statements for further discussion of these transactions.

Return of Capital Commitment

Currently, our board of directors has approved a return of capital commitment of at least 50% of free cash flow to our stockholders through repurchases under our share repurchase program, base dividends and variable dividends. The remainder of our free cash flow will be used primarily to reduce debt. On May 1, 2025, our board of directors declared a base cash dividend for the first quarter of 2025 of $1.00 per share of common stock.

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Free cash flow is a non-GAAP financial measure. As used by us, free cash flow is defined as cash flow from operating activities before changes in working capital in excess of cash capital expenditures and other adjustments as determined by us. We believe 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.

On September 18, 2024, our board of directors approved an increase in our common stock repurchase program from $4.0 billion to $6.0 billion, excluding excise tax. Since the inception of the stock repurchase program, we repurchased an aggregate of 30.2 million shares of our common stock for a total cost of $4.2 billion, excluding excise tax, as of May 2, 2025. Subject to regulatory restrictions and other factors discussed elsewhere in this report, 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, however, the stock repurchase program is at the discretion of our board of directors and can be amended, terminated or suspended at any time. See Note 10—Stockholders' Equity and Earnings (Loss) Per Share of the notes to the condensed consolidated financial statements.

Guarantor Financial Information

Diamondback E&P is the sole guarantor under the indentures governing the outstanding Guaranteed Senior 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 indentures governing the Guaranteed Senior Notes, such as, with certain exceptions, (i) in the event Diamondback E&P (or all or substantially all of its assets) is sold or disposed of, (ii) in the event Diamondback E&P ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (iii) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.

Diamondback E&P’s guarantees of the Guaranteed Senior Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The rights of holders of the Guaranteed 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, 2025		December 31, 2024
Summarized Balance Sheets:	(In millions)
Assets:
Current assets	$	1,979	$	933
Property and equipment, net	$	22,128	$	21,795
Other noncurrent assets	$	292	$	32
Liabilities:
Current liabilities	$	3,735	$	2,943
Intercompany accounts payable, non-guarantor subsidiary	$	3,418	$	3,381
Long-term debt	$	12,174	$	10,978
Other noncurrent liabilities	$	3,014	$	2,979

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	Three Months Ended March 31, 2025
Summarized Statement of Operations:	(In millions)
Revenues	$	1,711
Income (loss) from operations	$	442
Net income (loss)	$	381

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, 2024.

Recent Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies of the notes to the condensed consolidated financial statements for recent accounting pronouncements 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 can be volatile and unpredictable. We cannot predict events, including the outcome of the war in Ukraine and the Israel-Hamas war along with other conflicts in the Middle East, changes in interest rates and inflation and global supply chain disruptions that may lead to future price volatility. We cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty. Further, the prices we receive for production depend on many other factors outside of our control.

We use derivatives, including swaps, basis swaps, 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, 2025, we had a net asset derivative position of $273 million related to our commodity price risk derivatives. Utilizing actual derivative contractual volumes under our commodity price derivatives as of March 31, 2025, a 10% increase in forward curves associated with the underlying commodity would have decreased the net asset position by $2 million to $271 million, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net asset position by $15 million to $288 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, 2025, see Note 13—Derivatives of the notes to the condensed consolidated financial statements.

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 $1.3 billion at March 31, 2025), and to a lesser extent, receivables resulting from joint interest and other receivables (approximately $170 million at March 31, 2025).

Joint interest receivables arise from billings to entities that own partial interests in 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. 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.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facilities, Tranche A Loans, and changes in the fair value of our fixed rate debt. Outstanding borrowings under the credit agreement bear interest at a per annum rate elected by Diamondback E&P. At March 31, 2025, the applicable margin ranges from 0.125% to 1.000% per annum in the case of the alternate base rate, and from 1.125% to 2.000% per annum in the case of

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Adjusted Term SOFR, in each case based on the pricing level for both our revolving credit facilities and Tranche A Loans. The pricing level depends on certain rating agencies’ ratings of our long-term senior unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.325% per year on the unused portion of the commitment for our revolving credit facilities. For our Tranche A Loans, we are obligated to pay a commitment fee equal to 0.125% per year on the aggregate principal amount of the commitments. 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, 2025, see Note 9—Debt of the notes to the condensed consolidated financial statements.

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, 2025, we have interest rate swap agreements for a notional amount of $900 million to manage the impact of changes to the fair value of our fixed rate senior notes due to changes in market interest rates through December 2029. We pay an average variable rate of interest for these swaps based on three month SOFR plus 2.1865% and receive a fixed interest rate of 3.50% from our counterparties. At March 31, 2025, our receive-fixed, pay-variable interest rate swaps were in a net liability position of $113 million, and the weighted average variable rate was 6.10%. For additional information on our interest rate swaps, see Note 13—Derivatives of the notes to the condensed consolidated financial statements.

ITEM 4. CONTROLS AND PROCEDURES

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

As of March 31, 2025, 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, 2025, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting. Management’s assessment of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the Endeavor Acquisition on September 10, 2024. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. The Company is in the process of integrating Endeavor’s and our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, there were no changes in our internal control over financial reporting that occurred during the first quarter of 2025, that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Diamondback has elected to use a $1 million threshold for disclosing certain environmental proceedings to which a federal, state or local governmental authority is a party.

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, employment claims, claims alleging violations of antitrust laws, 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 16—Commitments and Contingencies of the notes to the condensed consolidated financial statements.

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, in addition to the factors discussed elsewhere in this report, 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, 2024, filed with the SEC on February 26, 2025 and in subsequent filings we make with the SEC. Except as discussed 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, 2024. For a discussion of the recent trends and uncertainties impacting our business, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments.”

Changes in U.S. trade policy and the impact of tariffs may have a material adverse effect on our business and results of operations.

Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments. In recent months, the uncertainty over such policies has caused substantial volatility in commodity, capital and financial markets, increased concerns over domestic and global inflation and adversely impacted consumer confidence in the U.S. and worldwide.

Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, significant inflation and diminished expectations for the economy, and ultimately reduced demand for oil and natural gas. Such conditions could have a material adverse impact on our business, results of operations and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms and cost of capital. Such adverse changes could increase our costs of capital and limit our access to external financing sources to fund acquisitions, repurchases of securities or other capital requirements.

Changes in tariffs and trade restrictions can be announced with little or no advance notice. The adoption and expansion of tariffs or other trade restrictions, increasing trade tensions, or other changes in governmental policies related to taxes and tariffs, are difficult to predict, which makes attendant risks difficult to anticipate and mitigate. If we are unable to navigate further changes in U.S. or international trade policy, it could have a material adverse impact on our business and results of operations.

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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, 2025 was as follows:


Period	Total Number of Shares Purchased(1)	Average Price Paid Per Share(2)(4)		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)(4)
	($ In millions, except per share amounts, shares in thousands)
January 1, 2025 - January 31, 2025	689	$	173.16	689	$	2,556
February 1, 2025 - February 28, 2025	853	$	158.94	853	$	2,420
March 1, 2025 - March 31, 2025	2,269	$	151.87	2,114	$	2,100
Total	3,811	$	157.30	3,656

(1)Includes 154,807 shares of common stock repurchased from executives 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)On September 18, 2024, our board of directors approved an increase in our common stock repurchase program from $4.0 billion to $6.0 billion, excluding excise tax. The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time.

(4)The Inflation Reduction Act of 2022, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022. All dollar amounts presented exclude such excise taxes, as applicable.

ITEM 5. OTHER INFORMATION

None of the Company’s directors or officers adopted or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the Company’s fiscal quarter ended March 31, 2025.

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ITEM 6. EXHIBITS

EXHIBIT INDEX


Exhibit Number						Description
2.1#						Agreement and Plan of Merger, dated as of February 11, 2024, by and among the Company, Endeavor, Merger Sub I, Merger Sub II and the Company Representative (for purposes of certain sections set forth therein) (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No 001-35700, filed by the Company with the SEC on February 12, 2024).
2.2#						Letter Agreement, amending the Merger Agreement, by and among the Company, Endeavor, Merger Sub I, Merger Sub II and the Company Representative, dated March 18, 2024 (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No 001-35700, filed by the Company with the SEC on March 18, 2024).
3.1						Second 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 14, 2023).
3.2						Certificate of Amendment No. 1 to Second 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 September 10, 2024).
3.3						Fifth Amended and Restated Bylaws of the Company, adopted as of September 18, 2024 (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on September 18, 2024).
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						Third Supplemental Indenture, dated as of March 20, 2025, between Diamondback Energy, Inc., Diamondback E&P LLC and Computershare Trust Company, National Association, as Trustee (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 20, 2025).
10.1+*						Diamondback Energy, Inc. Amended and Restated Senior Management Severance Plan, adopted effective as of April 6, 2025 (including a form of participation agreement attached thereto as Schedule C).
10.2						Term Loan Credit Agreement, dated as of March 21 , 202 5 , by and among the Company, as borrower, the lenders party thereto, and Bank of America , N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No 001-35700, filed by the Company with the SEC on March 21, 2025).
10.3						F ifteenth Amendment to Second Amended and Restated Credit Agreement, dated as of March 21 , 202 5 , by and among the Company, as borrower, the lenders and other parties party thereto, and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.2 to the Form 8-K, File No 001-35700, filed by the Company with the SEC on March 21 , 202 5 ).
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, 2025, 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) Notes to the Condensed Consolidated Financial Statements.
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

______________


+			Management contract, compensatory plan or arrangement.
*			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.
#			Schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K promulgated by the SEC. The Registrant agrees to furnish supplementally a copy of any omitted schedule or exhibit to the SEC upon request.

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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 7, 2025	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer
		(Principal Executive Officer)

Date:	May 7, 2025	/s/ Jere W. Thompson III
		Jere W. Thompson III
		Chief Financial Officer
		(Principal Financial Officer)