Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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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, 2025. 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**, Part I. Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2025 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 17—Segment Information of the notes to the condensed consolidated financial statements, as of March 31, 2026, we have one reportable segment, the upstream segment.

First Quarter 2026 Financial and Operating Highlights

Recorded net income of $25 million, which includes impairment of approximately $1.4 billion recorded on our proved oil and natural gas properties.
Our cash operating costs were $11.26 per BOE, including lease operating expenses of $6.21 per BOE, cash general and administrative expenses of $0.65 per BOE, production and ad valorem taxes of $3.04 per BOE and gathering, processing and transportation expenses of $1.36 per BOE.
Incurred cash capital expenditures, excluding acquisitions, of $933 million.
Paid dividends to stockholders of $295 million, or $1.05 per share, during the first quarter of 2026 and declared a base cash dividend payable in the second quarter of 2026 of $1.10 per share of common stock.
Repurchased $548 million of our common stock, excluding excise taxes, leaving approximately $2.1 billion available for future repurchases at March 31, 2026.
Our average production was 979.4 MBOE/d.
Drilled 118 gross horizontal wells in the Midland Basin and turned 147 gross operated horizontal wells in the Midland Basin to production.

Transactions and Recent Developments

Divestiture

Viper Divestiture of Non-Permian Assets

On February 9, 2026, Viper completed the Viper Non-Permian Divestiture for net cash proceeds of approximately $610 million, including transaction costs and customary post-closing adjustments. The divested properties consisted of approximately 9,400 net royalty acres in the Denver-Julesburg, Eagle Ford and Williston basins with current production of approximately 4,750 BO/d. Proceeds from the Viper Non-Permian Divestiture were used to repay amounts outstanding under the Viper 2025 Term Loan and the Viper Revolving Credit Facility and for general corporate purposes.

Commodity Prices

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Geopolitical global conflicts, tariffs or other trade barriers and any resulting trade tensions, regional and worldwide economic activity, changes in trade or other government policies or regulations, including with respect to U.S. energy and monetary policies, extreme weather conditions and other substantially variable factors influence market conditions for these products. For example, in the last quarter the global crude oil market shifted from a supply-demand surplus to a deficit, materially reducing crude oil and refined products from the markets, and increasing benchmark crude oil prices. These factors are beyond our control and are difficult to predict. OPEC+ continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels and can heavily influence volatility in oil prices. During the three months ended March 31, 2026 and 2025, WTI prices averaged $72.67 and $71.42 per Bbl, respectively, and Henry Hub prices averaged $3.47 and $3.87 per MMBtu, respectively.

Upstream Operations

Our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations with exploratory development in the Barnett and Woodford shales 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.

As of March 31, 2026, we had approximately 890,496 net acres in the Permian Basin, which primarily consisted of approximately 797,074 net acres in the Midland Basin and 93,422 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, 2026
	Drilled		Completed(1)
Area:	Gross	Net	Gross	Net
Midland Basin	118	111	147	137


Total	118	111	147	137

(1)The average lateral length for the wells completed during the first quarter of 2026 was 11,332 feet. Operated completions during the first quarter of 2026 consisted of 32 Lower Spraberry wells, 31 Wolfcamp A wells, 31 Jo Mill wells, 30 Wolfcamp B wells, eight Wolfcamp D wells, seven Middle Spraberry wells, six Dean wells and two Upper Spraberry wells.

As of March 31, 2026, we operated the following wells:


	As of March 31, 2026
	Vertical Wells		Horizontal Wells		Total
Area:	Gross	Net	Gross	Net	Gross	Net
Midland Basin	4,412	4,197	5,013	4,698	9,425	8,895
Delaware Basin	40	35	458	428	498	463

Total	4,452	4,232	5,471	5,126	9,923	9,358

As of March 31, 2026, we and Viper held interests in 44,552 gross (9,679 net) wells, including 1,863 gross (319 net) wells in which we have a non-operated working interest.

Outlook

In response to growing global oil supply constraints and the improved commodity pricing environment that began in March of 2026, we have increased our annual production guidance by 3% to approximately 972 MBOE/d, which we expect to achieve in part by working down our drilled but uncompleted well balance.

Results of Operations

Comparison of the Three Months Ended March 31, 2026, and December 31, 2025

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 periods indicated:


	Three Months Ended
	March 31, 2026		December 31, 2025
Revenues (In millions):
Oil sales	$	3,445	$	2,736
Natural gas sales	21		4
Natural gas liquid sales	359		293
Total oil, natural gas and natural gas liquid revenues	$	3,825	$	3,033

Production Data:
Oil (MBbls)	46,889		47,174
Natural gas (MMcf)	118,402		121,805
Natural gas liquids (MBbls)	21,519		21,684
Combined volumes (MBOE)(1)	88,142		89,159

Daily oil volumes (BO/d)	520,989		512,761
Daily combined volumes (BOE/d)	979,356		969,120

Average Prices:
Oil ($ per Bbl)	$	73.47	$	58.00
Natural gas ($ per Mcf)	$	0.18	$	0.03
Natural gas liquids ($ per Bbl)	$	16.68	$	13.51
Combined ($ per BOE)	$	43.40	$	34.02

Oil, hedged ($ per Bbl)(2)	$	72.53	$	57.07
Natural gas, hedged ($ per Mcf)(2)	$	1.90	$	1.03
Natural gas liquids, hedged ($ per Bbl)(2)	$	16.68	$	13.51
Average price, hedged ($ per BOE)(2)	$	45.21	$	34.88

(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.

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 periods indicated:


	Three Months Ended
	March 31, 2026		December 31, 2025
Oil (MBbls)	53	%	53	%
Natural gas (MMcf)	22		23
Natural gas liquids (MBbls)	25		24
	100	%	100	%


	Three Months Ended March 31, 2026				Three Months Ended December 31, 2025
	Midland Basin	Delaware Basin	Other	Total	Midland Basin	Delaware Basin	Other	Total
Production Data:
Oil (MBbls)	42,907	3,721	261	46,889	43,224	3,640	310	47,174
Natural gas (MMcf)	104,171	12,878	1,353	118,402	107,011	12,195	2,599	121,805
Natural gas liquids (MBbls)	19,591	1,804	124	21,519	19,970	1,623	91	21,684
Total (MBOE)	79,860	7,671	611	88,142	81,029	7,296	834	89,159

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 2026 increased by $792 million to $3.8 billion compared to the fourth quarter of 2025. The increase consisted of an additional $811 million attributable to higher average prices received primarily for our oil production, which was partially offset by a $19 million reduction attributable to two fewer days of production during the first quarter of 2026.

Net Sales of Purchased Oil. We enter 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 periods indicated:


	Three Months Ended
(In millions)	March 31, 2026		December 31, 2025
Sales of purchased oil	$	385	$	308
Purchased oil expense	393		306
Net sales of purchased oil	$	(8)	$	2

Other Revenues. The following table presents other insignificant revenue for the periods indicated:


	Three Months Ended
(In millions)	March 31, 2026		December 31, 2025
Other operating income	$	30	$	35

Lease Operating Expenses. The following table shows lease operating expenses for the periods indicated:


	Three Months Ended
	March 31, 2026				December 31, 2025
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
Lease operating expenses	$	547	$	6.21	$	527	$	5.91

Lease operating expenses increased for the first quarter of 2026 compared to the fourth quarter of 2025 primarily due to additional costs incurred on non-operated properties, for weather-related events in January 2026 and other individually insignificant changes.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the periods indicated:


	Three Months Ended
	March 31, 2026						December 31, 2025
(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	$	186	$	2.11	4.9	%	$	144	$	1.62	4.8	%
Ad valorem taxes	82		0.93		2.1		53		0.59		1.7
Total production and ad valorem expense	$	268	$	3.04	7.0	%	$	197	$	2.21	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 2025 to the first quarter of 2026.

Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes during the first quarter of 2026 compared to the fourth quarter of 2025 reflect a slight increase in expected tax rates for 2026 compared to 2025 as well as a $13 million adjustment recorded in the first quarter of 2026 for actual billings received related to prior years.

Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expenses for the periods indicated:


	Three Months Ended
	March 31, 2026				December 31, 2025
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
Gathering, processing and transportation	$	120	$	1.36	$	137	$	1.54

The decrease in gathering, processing and transportation expenses primarily reflects a $19 million reduction in transportation costs incurred to meet our minimum volume commitments on certain pipelines, partially offset by other individually insignificant changes.

Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the periods indicated:


	Three Months Ended
(In millions, except BOE amounts)	March 31, 2026		December 31, 2025
Depletion of proved oil and natural gas properties	$	1,267	$	1,363
Depreciation and amortization of other property and equipment	16		16
Other amortization	2		2
Asset retirement obligation accretion	8		8
Depreciation, depletion, amortization and accretion	$	1,293	$	1,389
Oil and natural gas properties depletion rate per BOE	$	14.37	$	15.29
Depreciation, depletion, amortization and accretion per BOE	$	14.67	$	15.58

The decrease in depletion of proved oil and natural gas properties of $96 million for the first quarter of 2026 as compared to the fourth quarter of 2025 primarily consists of an $81 million reduction from the decline in depletion rate following the ceiling test impairment recorded in the fourth quarter of 2025 and a $15 million reduction due to the slight decline in quarterly production volumes.

Impairment of Oil and Natural Gas Properties. The following table shows impairment of oil and natural gas properties for the periods indicated:


	Three Months Ended
(In millions)	March 31, 2026		December 31, 2025
Impairment of oil and natural gas properties	$	1,400	$	3,652

The non-cash ceiling test impairment charges in both the first quarter of 2026 and the fourth quarter of 2025 primarily resulted from the decline in SEC Prices applicable to each period. Impairment charges affect our results of operations but do not reduce our cash flow.

In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties, income tax rate assumptions and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices fall as compared to the commodity prices used in prior quarters, we may have material write-downs in subsequent quarters. We currently do not expect to record additional impairment of our assets in the second quarter of 2026.

General and Administrative Expenses. The following table shows the cash and non-cash general and administrative expenses incurred in the periods indicated:


	Three Months Ended
	March 31, 2026				December 31, 2025
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
General and administrative expenses	$	57	$	0.65	$	58	$	0.65
Non-cash stock-based compensation	22		0.25		20		0.22
Total general and administrative expenses	$	79	$	0.90	$	78	$	0.87

Other Operating Expenses, Net. The following table shows other operating expenses for the periods indicated:


	Three Months Ended
(In millions)	March 31, 2026		December 31, 2025


Other operating expenses, net	$	24	$	(128)

The change in other operating expenses, net during the first quarter of 2026 compared to the fourth quarter of 2025 was primarily due to (i) a reduction in the gain on sale of other property, plant and equipment of $140 million due largely to the fourth quarter of 2025 including the $167 million gain on the divestiture of the Company’s Environmental Disposal Systems, LLC subsidiary, (ii) a $13 million increase in impairment of certain midstream assets, and (iii) other insignificant activity.

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 periods indicated:


	Three Months Ended
(In millions)	March 31, 2026		December 31, 2025
Gain (loss) on derivative instruments, net(1)	$	117	$	192
Net cash received (paid) on settlements(1)	$	133	$	73

(1)The three months ended March 31, 2026, includes cash paid on interest rate swaps terminated prior to their contractual maturity of $27 million.

The decrease in gain on derivative instruments for the first quarter of 2026 compared to the fourth quarter of 2025 primarily reflects a $145 million loss on our oil contracts due primarily to the value of our unsettled roll swap and put contracts declining as market prices for oil increased compared to our contract prices. This loss was partially offset by a net $77 million gain attributable to our natural gas contracts, which was comprised of an $83 million increase in cash received on the settlement of contracts primarily due to favorable differentials on our basis swaps, partially offset by a $6 million net decrease in the value of our unsettled natural gas contracts.

See Note 12—Derivatives of the notes to the condensed consolidated financial statements for further details regarding our derivative instruments.

Other Income (Expense). The following table shows other income and expenses for the periods indicated:


	Three Months Ended
(In millions)	March 31, 2026		December 31, 2025
Interest expense, net	$	(63)	$	(78)
Other income (expense), net	$	7	$	302
Gain (loss) on extinguishment of debt, net	$	(1)	$	33

The decrease in interest expense, net for the first quarter of 2026 compared to the fourth quarter of 2025 primarily reflects $18 million in interest cost savings due to the repayment and termination of Viper’s 2025 Term Loan and a partial repayment of the 2025 Term Loan late in the fourth quarter of 2025 along with opportunistic repurchases of other senior notes and the net impact of other individually insignificant changes.

See Note 8—Debt and Note 16—Subsequent Events of the notes to the condensed consolidated financial statements for details regarding outstanding borrowings.

The decrease in other income for the first quarter of 2026 compared to the fourth quarter of 2025 was primarily due to the fourth quarter of 2025 including a gain of approximately $299 million recorded in connection with the EPIC Divestiture and other individually insignificant activity.

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 periods indicated:


	Three Months Ended
(In millions)	March 31, 2026		December 31, 2025
Provision for (benefit from) income taxes	$	32	$	(567)

The change in our income tax provision for the first quarter of 2026 compared to our income tax benefit in the fourth quarter of 2025 was primarily due to the increase in pre-tax income between the periods, which resulted largely from a reduction in the non-cash ceiling test impairment charge and an increase in our oil, natural gas and natural gas liquids revenues recorded in the first quarter of 2026 compared to the fourth quarter of 2025 as discussed above. See Note 11—Income Taxes of the notes to the condensed consolidated financial statements for further discussion of our income tax expense.

Comparison of the Three Months Ended March 31, 2026, and 2025

The following table sets forth selected operating data for the periods indicated:


	Three Months Ended March 31,
	2026		2025
Revenues (In millions):
Oil sales	$	3,445	$	3,039
Natural gas sales	21		212
Natural gas liquid sales	359		406
Total oil, natural gas and natural gas liquid revenues	$	3,825	$	3,657

Production Data:
Oil (MBbls)	46,889		42,835
Natural gas (MMcf)	118,402		100,578
Natural gas liquids (MBbls)	21,519		16,961
Combined volumes (MBOE)(1)	88,142		76,559

Daily oil volumes (BO/d)	520,989		475,944
Daily combined volumes (BOE/d)	979,356		850,656

Average Prices:
Oil ($ per Bbl)	$	73.47	$	70.95
Natural gas ($ per Mcf)	$	0.18	$	2.11
Natural gas liquids ($ per Bbl)	$	16.68	$	23.94
Combined ($ per BOE)	$	43.40	$	47.77

Oil, hedged ($ per Bbl)(2)	$	72.53	$	70.06
Natural gas, hedged ($ per Mcf)(2)	$	1.90	$	3.34
Natural gas liquids, hedged ($ per Bbl)(2)	$	16.68	$	23.94
Average price, hedged ($ per BOE)(2)	$	45.21	$	48.89

(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 periods indicated:


	Three Months Ended March 31,
	2026		2025
Oil (MBbls)	53	%	56	%
Natural gas (MMcf)	22		22
Natural gas liquids (MBbls)	25		22
	100	%	100	%


	Three Months Ended March 31, 2026				Three Months Ended March 31, 2025
	Midland Basin	Delaware Basin	Other	Total	Midland Basin	Delaware Basin	Other	Total
Production Data:
Oil (MBbls)	42,907	3,721	261	46,889	39,341	3,460	34	42,835
Natural gas (MMcf)	104,171	12,878	1,353	118,402	90,341	9,961	276	100,578
Natural gas liquids (MBbls)	19,591	1,804	124	21,519	15,769	1,155	37	16,961
Total (MBOE)	79,860	7,671	611	88,142	70,167	6,275	117	76,559

Our oil, natural gas and natural gas liquids revenues for the three months ended March 31, 2026, increased by $168 million, or 5%, to $3.8 billion from the same period in 2025. This net increase consisted of an additional $434 million from the 15% growth in our combined production volumes, partially offset by a net reduction of $266 million primarily due to lower average prices received for our natural gas and natural gas liquids production for the three months ended March 31, 2026.

Approximately 37% of the increase in our combined production volumes was attributable to the Double Eagle Acquisition and 31% was attributable to Viper’s Sitio Acquisition. The remainder of production growth is largely attributable to new wells added between periods.

Net Sales of Purchased Oil. We enter 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 periods indicated:


	Three Months Ended March 31,
(In millions)	2026		2025
Sales of purchased oil	$	385	$	374
Purchased oil expense	393		382
Net sales of purchased oil	$	(8)	$	(8)

Other Revenues. The following table shows the other insignificant revenues for the periods indicated:


	Three Months Ended March 31,
(In millions)	2026		2025
Other operating income	$	30	$	17

Lease Operating Expenses. The following table shows lease operating expenses for the periods indicated:


	Three Months Ended March 31,
	2026				2025
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
Lease operating expenses	$	547	$	6.21	$	408	$	5.33

Lease operating expenses increased for the three months ended March 31, 2026, compared to the same period in 2025 primarily due to (i) the first quarter of 2025 including a $38 million reduction in cost estimates related to producing properties acquired in the Endeavor Acquisition, (ii) an additional $27 million in water services costs following the divestiture of the Company’s Environmental Disposal Systems, LLC subsidiary in the fourth quarter of 2025, (iii) $24 million of costs attributable to operating wells acquired in the Double Eagle Acquisition, (iv) a $21 million increase in workover costs, (v) an additional $11 million in costs due to an increase in legacy production, and (vi) an increase in various other weather related costs due to a winter storm in January 2026.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the periods indicated:


	Three Months Ended March 31,
	2026						2025
(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	$	186	$	2.11	4.9	%	$	171	$	2.23	4.7	%
Ad valorem taxes	82		0.93		2.1		57		0.75		1.5
Total production and ad valorem expense	$	268	$	3.04	7.0	%	$	228	$	2.98	6.2	%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of revenue from sales of oil, natural gas and natural gas liquids remained consistent in the first quarter of 2026 compared 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 for the three months ended March 31, 2026, compared to the same period in 2025 increased by $25 million, primarily due to taxes incurred on properties acquired in the Double Eagle Acquisition and Viper’s Sitio Acquisition.

Gathering, Processing and Transportation Expense. The following table shows gathering, processing and transportation expenses for the periods indicated:


	Three Months Ended March 31,
	2026				2025
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
Gathering, processing and transportation	$	120	$	1.36	$	111	$	1.45

Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the periods indicated:


	Three Months Ended March 31,
(In millions, except BOE amounts)	2026		2025
Depletion of proved oil and natural gas properties	$	1,267	$	1,065
Depreciation and amortization of other property and equipment	16		23
Other amortization	2		—
Asset retirement obligation accretion	8		9
Depreciation, depletion, amortization and accretion	$	1,293	$	1,097
Oil and natural gas properties depletion rate per BOE	$	14.37	$	13.91
Depreciation, depletion, amortization and accretion per BOE	$	14.67	$	14.33

The increase in depletion of proved oil and natural gas properties of $202 million for the three months ended March 31, 2026, compared to the same period in 2025 consists of $161 million from growth in production volumes and $41 million attributable to an increase in the depletion rate from the addition of higher value leasehold costs and proved reserves from the Double Eagle Acquisition and, to a lesser extent, Viper’s Sitio Acquisition subsequent to the first quarter of 2025.

Impairment of Oil and Natural Gas Properties. The following table shows impairment of oil and natural gas properties for the periods indicated:


	Three Months Ended March 31,
(In millions)	2026		2025
Impairment of oil and natural gas properties	$	1,400	$	—

The non-cash ceiling test impairment charge of $1.4 billion for the three months ended March 31, 2026 primarily resulted from the decline in SEC Prices during the preceding twelve months.

General and Administrative Expenses. The following table shows the cash and non-cash general and administrative expenses incurred in the periods indicated:


	Three Months Ended March 31,
	2026				2025
(In millions, except per BOE amounts)	Amount		Per BOE		Amount		Per BOE
General and administrative expenses	$	57	$	0.65	$	55	$	0.72
Non-cash stock-based compensation	22		0.25		18		0.24
Total general and administrative expenses	$	79	$	0.90	$	73	$	0.96

Other Operating Expenses, Net. The following table shows the other operating expenses for the periods indicated:


	Three Months Ended March 31,
(In millions)	2026		2025

Other operating expenses, net	$	24	$	76

The decrease in other operating expenses for the three months ended March 31, 2026, compared to the same period in 2025 primarily resulted from a $33 million reduction in merger and transaction costs due to the first quarter of 2025 including costs incurred for the Endeavor Acquisition and other individually insignificant transactions, and a $17 million decrease in midstream service expense following the divestiture of the Company’s Environmental Disposal Systems, LLC subsidiary in the fourth quarter of 2025.


	Three Months Ended March 31,
(In millions)	2026		2025
Gain (loss) on derivative instruments, net(1)	$	117	$	226
Net cash received (paid) on settlements(1)	$	133	$	85

(1)The three months ended March 31, 2026, includes cash paid on interest rate swaps terminated prior to their contractual maturity of $27 million.

The decrease in gain on derivative instruments for the three months ended March 31, 2026, compared to the same period in 2025 reflects (i) a $132 million decrease in the gain on our oil contracts primarily due to reductions in the value of unsettled put and roll swap contracts, (ii) an $11 million net loss on our interest rate derivatives, which were terminated prior to their maturity, and (iii) other insignificant activity. These losses were partially offset by a net gain of $36 million on our natural gas contracts, comprised of an $80 million increase in cash received on the settlement of contracts primarily due to favorable differentials on our basis swaps and a $44 million net decrease in the value of our unsettled contracts due primarily to unfavorable movements in our basis swap differentials, partially offset by lower market prices compared to contract prices on our costless collars.

See Note 12—Derivatives of the notes to the condensed consolidated financial statements for further details regarding our derivative instruments.

Other Income (Expense). The following table shows other income and expenses for the periods indicated:


	Three Months Ended March 31,
(In millions)	2026		2025
Interest expense, net	$	(63)	$	(40)
Other income (expense), net	$	7	$	35

Gain (loss) on extinguishment of debt, net	$	(1)	$	—

Interest expense, net increased by $23 million for the three months ended March 31, 2026, compared to the same period in 2025. This increase primarily consisted of (i) $22 million of additional interest expense related to the 2035 Notes and the 2025 Term Loan, (ii) a net increase of $9 million related to Viper’s issuance of its 4.900% Senior Notes due 2030 and 5.700% Senior Notes due 2035 and Viper’s redemption of its 5.375% Senior Notes due 2027 and 7.375% Senior Notes due 2031, and (iii) a $6 million reduction in interest income, which reduces interest expense. These increases were partially offset by a $13 million reduction in interest expense following the repayment of $900 million in borrowings on a previously outstanding term loan in May 2025 and other individually insignificant changes.

See Note 8—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, 2026, decreased compared to the same period in 2025, primarily due to the first quarter of 2025 including $42 million of proceeds received from an equity method investee divesting its assets. This decrease was partially offset by a $7 million increase in income from equity method investees and other individually insignificant items.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the periods indicated:


	Three Months Ended March 31,
(In millions)	2026		2025
Provision for (benefit from) income taxes	$	32	$	403

The decrease in our income tax provision for the three months ended March 31, 2026, compared to the same period in 2025 was primarily due to the decrease in pre-tax income resulting largely from the non-cash ceiling test impairment charge recorded in the first quarter of 2026, partially offset by additional revenues from oil, natural gas and natural gas liquids as discussed above.

See Note 11—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 the Revolving Credit Facility and term loan agreements, 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, 2026, we had approximately $2.6 billion of liquidity consisting of $146 million in standalone cash and cash equivalents and $2.5 billion available under our credit facility. At March 31, 2026, we had approximately $749 million of senior notes maturing in the next 12 months.

Future cash flows are subject to a number of variables, including the level of our oil and natural gas production and the volatility of commodity prices. Further, significant additional capital expenditures will be required to more fully develop our 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, 2025. 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 12—Derivatives of the notes to the condensed consolidated financial statements of this report. 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, 2026, and 2025 are presented below:


	Three Months Ended March 31,
	2026		2025
	(In millions)
Net cash provided by (used in) operating activities	$	1,828	$	2,355
Net cash provided by (used in) investing activities	(658)		(1,653)
Net cash provided by (used in) financing activities	(1,100)		1,175
Net increase (decrease) in cash	$	70	$	1,877

Operating Activities

The decrease in operating cash flows for the three months ended March 31, 2026, compared to the same period in 2025 primarily resulted from (i) an increase in the change in accounts receivable of $773 million due primarily to higher prices received for our oil and natural gas sales in March 2026, (ii) higher cash operating expenses, excluding purchased oil expense, of approximately $138 million, (iii) changes in other working capital accounts including taxes payable and accounts payable and accrued liabilities due to the timing of when payments are made. These were partially offset by (i) a decrease of $259 million in cash paid for taxes, (ii) $181 million in additional revenues, excluding sales of purchased oil, and (iii) an increase of $48 million in cash received on settlements of derivatives. 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, 2026, was for drilling and completion costs incurred in conjunction with our development program as well as the acquisition of properties and equipment. These cash expenditures were partially offset by the proceeds from the Viper Non-Permian Divestiture. See Note 4—Acquisitions and Divestitures for further discussion of the Viper Non-Permian Divestiture.

The majority of our net cash used in investing activities during the three months ended March 31, 2025, 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,
	2026		2025
	(In millions)
Operated drilling and completion additions to oil and natural gas properties(1)	$	(784)	$	(864)
Non-operated additions to oil and natural gas properties and other	(149)		(78)

Total	$	(933)	$	(942)

(1) See “—Transactions and Recent Developments—Upstream Operations” above for additional detail on wells drilled and turned to production during the three months ended March 31, 2026.

Financing Activities

During the three months ended March 31, 2026, net cash used in financing activities was primarily attributable to (i) $645 million of repurchases as part of our and Viper’s share repurchase programs, (ii) $500 million for the repayment of the Viper 2025 Term Loan, (iii) $295 million of dividends paid to stockholders, (iv) $120 million in dividends paid to non-controlling interest, (v) $85 million in repayments on our credit facilities, net of borrowings, and (vi) various other individually insignificant costs. These cash outflows were partially offset by $589 million in proceeds from the Secondary Offering.

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 5.550% senior notes due in 2035 and $1.2 billion in proceeds from Viper’s public offering of Class A common stock. 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 under our credit facilities, net of borrowings, (iv) $95 million in dividends paid to non-controlling interest, and (v) various other individually insignificant costs.

Capital Resources

Our working capital requirements are primarily supported by our cash and cash equivalents and available borrowings under the Revolving Credit Facility. We may draw on the Revolving Credit Facility to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us, 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 debt and equity 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

Diamondback’s Revolving Credit Facility

As of March 31, 2026, our Revolving Credit Facility, which matures on June 12, 2030, had a maximum credit amount available of $2.5 billion, with no outstanding borrowings and $2.5 billion available for future borrowings.

Viper’s Revolving Credit Facility

The Viper Revolving Credit Facility, which matures on June 12, 2030, provides for a commitment amount of $1.5 billion. As of March 31, 2026, the Viper Revolving Credit Facility had $20 million in outstanding borrowings and approximately $1.5 billion available for future borrowings.

For additional discussion of our revolving credit facilities as of March 31, 2026, see Note 8—Debt 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 the Revolving Credit Facility, 2025 Term Loan and senior notes, (iii) payments of other contractual obligations, and (iv) cash used to pay for dividends and repurchases of securities.

2026 Capital Spending Plan

In order to capitalize on higher oil prices, we have made the decision to work down our drilled but uncompleted well inventory to bring incremental barrels to the market immediately and add two or three rigs to maintain a healthy backlog of projects to maintain operational flexibility in 2026. As a result, our board of directors has approved an increase of 4% to our 2026 capital budget guidance to approximately $3.90 billion, which includes $3.31 billion for operated horizontal drilling and completions.

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.

Debt Instruments

As of March 31, 2026, our debt, including the debt of Viper, consisted of approximately $13.5 billion in aggregate outstanding principal amount of senior notes, $550 million in aggregate outstanding borrowings under the 2025 Term Loan Agreement, and $20 million in aggregate outstanding borrowings under revolving credit facilities.

In April 2026, we (i) repaid in full the $550 million in outstanding borrowings and terminated the 2025 Term Loan, and (ii) completed a tender offer to repurchase an aggregate principal amount of $777 million of our senior notes, which consisted of $283 million of the 4.400% Senior Notes due 2051 and $494 million of the 4.250% Senior Notes due 2052 for total cash consideration, including accrued interest paid, of approximately $632 million, at an average of 81.1% of par value.

Return of Capital Commitment

Beginning in the second quarter of 2026, our board of directors approved the removal of our minimum 50% return of capital quarterly commitment to allow the Company more discretion in the allocation of Free Cash Flow. Further, on April 29, 2026, our board of directors declared a base cash dividend for the first quarter of 2026 of $1.10 per share of common stock.

On July 31, 2025, our board of directors approved an increase in our common stock repurchase program, from $6.0 billion to $8.0 billion, excluding the 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations enacted as part of the IRA. Since the inception of the stock repurchase program through May 1, 2026, we have repurchased an aggregate of 41.7 million shares of our common stock for a total cost of $5.9 billion, which includes $814 million for the repurchase of 5.0 million shares from SGF, excluding excise tax, leaving approximately $2.1 billion for future repurchases under such stock repurchase program.

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. Repurchases may be executed in privately negotiated or open-market transactions, consistent with Rule 10b-18 under the Securities Exchange Act of 1934 and other applicable requirements. All shares repurchased will be retired. See Note 9—Stockholders’ Equity and Earnings (Loss) Per Share of the notes to the condensed consolidated financial statements for further discussion of our stock repurchase program.

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 the 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, 2026		December 31, 2025
Summarized Balance Sheets:	(In millions)
Assets:
Current assets	$	1,193	$	844
Property and equipment, net	$	18,367	$	19,670
Other noncurrent assets	$	192	$	142
Liabilities:
Current liabilities	$	3,738	$	3,304
Intercompany accounts payable, non-guarantor subsidiary	$	7,116	$	6,970
Long-term debt	$	11,546	$	11,540
Other noncurrent liabilities	$	1,899	$	2,186


	Three Months Ended March 31, 2026
Summarized Statement of Operations:	(In millions)
Revenues	$	1,774
Income (loss) from operations(1)	$	(902)
Net income (loss)	$	(834)

(1)During the three months ended March 31, 2026, the Company recorded a noncash impairment that is reflected in the summarized results of the guarantor group. This impairment is not indicative of cash flows available for debt service.

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, 2025.

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.

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