chrd-20260630

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-Q


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

For the quarterly period ended June 30, 2026


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

For the transition period from to

Commission file number: 1-34776


Chord Energy Corporation (Exact name of registrant as specified in its charter)



Delaware						80-0554627
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

1001 Fannin Street, Suite 1500
Houston, Texas						77002
(Address of principal executive offices)						(Zip Code)


(281) 404-9500 (Registrant’s telephone number, including area code)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock, par value $0.01 per share

CHRD

The Nasdaq Stock Market LLC

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 (§232.405 of this chapter) 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.


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 ☒

Number of shares of the registrant’s common stock outstanding at August 3, 2026: 54,697,872 shares.

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TABLE OF CONTENTS


			Page
Glossary of Terms			1
PART I — FINANCIAL INFORMATION			3
Item 1. — Financial Statements (Unaudited)			4
Condensed Consolidated Balance Sheets at June 30, 2026 and December 31, 2025			4
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2026 and 2025			6
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three and Six Months Ended June 30, 2026 and 2025			7
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2026 and 2025			8
Notes to Condensed Consolidated Financial Statements			10



1. Organization and Summary of Significant Accounting Policies			10

2. Revenue Recognition			12
3. Inventory			12
4. Additional Balance Sheet Information			13
5. Fair Value Measurements			14
6. Derivative Instruments			15
7. Property, Plant and Equipment			18
8. Acquisitions			18

9. Investment in Equity Securities			20
10. Long-Term Debt			20
11. Asset Retirement Obligations			21
12. Income Taxes			21
13. Equity-Based Compensation			22
14. Stockholders’ Equity			23
15. Earnings Per Share			24
16. Commitments and Contingencies			24

17. Leases			25

Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations			26
Overview			29
Results of Operations			30
Liquidity and Capital Resources			36
Fair Value of Financial Instruments			39
Critical Accounting Policies and Estimates			39
Item 3. — Quantitative and Qualitative Disclosures About Market Risk			39
Item 4. — Controls and Procedures			41
PART II — OTHER INFORMATION			42
Item 1. — Legal Proceedings			42
Item 1A. — Risk Factors			42
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds			42

Item 5.— Other Information			42
Item 6. — Exhibits			43
SIGNATURES			44

GLOSSARY OF TERMS

The terms defined in this section are used throughout this Quarterly Report on Form 10-Q:

“ABR.” Alternate base rate.

“ARO.” Asset retirement obligations.

“ASC.” Accounting Standards Codification.

“ASU.” Accounting Standards Update.

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, natural gas liquids or fresh water.

“Bcf.” One billion cubic feet of natural gas.

“Boe.” Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of crude oil.

“Boepd.” Barrels of oil equivalent per day.

“Bopd.” Barrels of oil per day.

“British thermal unit.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DD&A.” Depreciation, depletion and amortization.

“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

“Economically producible.” A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

“FASB.” Financial Accounting Standards Board.

“Formation.” A layer of rock which has distinct characteristics that differ from nearby rock.

“G&A.” General and administrative.

“GAAP.” Generally accepted accounting principles in the United States.

“GPT.” Gathering, processing and transportation.

“ICE BRENT.” The Intercontinental Exchange Brent crude oil price index.

“MBbl.” One thousand barrels of crude oil, condensate, natural gas liquids or fresh water.

“MBoe.” One thousand barrels of oil equivalent.

“Mcf.” One thousand cubic feet of natural gas.

“MMBbl.” One million barrels of crude oil, condensate, natural gas liquids or fresh water.

“MMBtu.” One million British thermal units.

“MMcf.” One million cubic feet of natural gas.

“NGL.” Natural gas liquids.

“NYMEX.” The New York Mercantile Exchange.

“NYMEX WTI.” The New York Mercantile Exchange West Texas Intermediate crude oil price index.

“OPEC+.” The Organization of Petroleum Exporting Countries and other oil exporting nations.

“Plug.” A down-hole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.

“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production would exceed production expenses and taxes.

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“Proved reserves.” Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible crude oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“Reasonable certainty.” If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

“Reserves.” Estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development prospects to known 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.

“SEC.” The U.S. Securities and Exchange Commission.

“SOFR.” Secured overnight financing rate as administered by the Federal Reserve Bank of New York.

“Workover.” The repair or stimulation of an existing productive well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

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PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

Chord Energy Corporation

Condensed Consolidated Balance Sheets (Unaudited)


	June 30, 2026		December 31, 2025

	(In thousands, except share data)
ASSETS
Current assets
Cash and cash equivalents	$	611,568	$	189,531
Accounts receivable, net	1,338,031		1,116,685
Inventory	121,409		115,713
Prepaid expenses	29,201		33,767
Derivative instruments	49,588		77,312
Other current assets	5,274		5,061

Total current assets	2,155,071		1,538,069
Property, plant and equipment
Oil and gas properties (successful efforts method)	15,627,693		14,848,968
Other property and equipment	60,493		60,395
Less: accumulated depreciation, depletion and amortization	(4,349,525)		(3,572,834)
Total property, plant and equipment, net	11,338,661		11,336,529
Derivative instruments	10,091		8,366
Investment in equity securities	138,789		119,698
Long-term inventory	26,073		30,759
Operating right-of-use assets	10,463		12,749


Other assets	38,240		28,104
Total assets	$	13,717,388	$	13,074,274

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	151,908	$	41,795
Revenues and production taxes payable	817,402		618,258
Accrued liabilities	706,836		735,386

Accrued interest payable	28,193		28,594
Derivative instruments	16,070		—

Current operating lease liabilities	7,589		14,656
Other current liabilities	36,670		11,898

Total current liabilities	1,764,668		1,450,587
Long-term debt	1,481,357		1,479,581
Deferred tax liabilities	1,656,962		1,615,850
Asset retirement obligations	432,030		432,802
Derivative instruments	2,786		—
Operating lease liabilities	13,854		10,518
Other liabilities	8,392		4,982
Total liabilities	5,360,049		4,994,320

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	June 30, 2026		December 31, 2025

	(In thousands, except share data)
Commitments and contingencies (Note 16)
Stockholders’ equity
Common stock, $0.01 par value: 240,000,000 shares authorized, 67,249,231 shares issued and 55,197,317 shares outstanding at June 30, 2026; and 240,000,000 shares authorized, 67,150,747 shares issued and 56,762,243 shares outstanding at December 31, 2025	676		675
Treasury stock, at cost: 12,051,914 shares at June 30, 2026 and 10,388,504 shares at December 31, 2025	(1,524,300)		(1,304,092)
Additional paid-in capital	7,351,992		7,339,735
Retained earnings	2,528,971		2,043,636
Total stockholders’ equity	8,357,339		8,079,954
Total liabilities and stockholders’ equity	$	13,717,388	$	13,074,274

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Chord Energy Corporation

Condensed Consolidated Statements of Operations (Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025

	(In thousands, except per share data)
Revenues
Oil, NGL and gas revenues	$	1,494,284	$	950,266	$	2,644,873	$	2,053,690
Purchased oil and gas sales	678,401		230,294		1,193,447		341,916

Total revenues	2,172,685		1,180,560		3,838,320		2,395,606
Operating expenses
Lease operating expenses	267,839		256,966		512,748		490,040
Gathering, processing and transportation expenses	62,765		74,100		129,783		147,415
Purchased oil and gas expenses	671,661		231,745		1,181,493		343,113
Production taxes	125,878		68,965		212,589		143,607
Depreciation, depletion and amortization	409,237		376,997		793,452		726,806
General and administrative expenses	29,894		32,540		67,402		70,917
Impairment and exploration	2,687		541,940		5,250		543,923



Total operating expenses	1,569,961		1,583,253		2,902,717		2,465,821
Gain (loss) on sale of assets, net	(4)		(522)		339		4,993
Operating income (loss)	602,720		(403,215)		935,942		(65,222)
Other income (expense)
Net gain (loss) on derivative instruments	107,866		82,231		(133,605)		61,950
Net gain (loss) from investment in equity securities	1,143		(962)		23,972		(5,862)
Interest expense, net of capitalized interest	(26,663)		(18,788)		(53,259)		(34,606)
Loss on debt extinguishment	—		—		—		(3,494)
Other income, net	2,186		5,045		8,515		4,546
Total other income (expense), net	84,532		67,526		(154,377)		22,534
Income (loss) before income taxes	687,252		(335,689)		781,565		(42,688)
Income tax expense	(162,066)		(54,216)		(147,771)		(127,380)


Net income (loss)	$	525,186	$	(389,905)	$	633,794	$	(170,068)
Earnings (loss) per share (Note 15):
Basic	$	9.30	$	(6.71)	$	11.17	$	(2.89)



Diluted	$	9.28	$	(6.77)	$	11.14	$	(2.93)


Weighted average shares outstanding:
Basic	56,010		57,786		56,361		58,420
Diluted	56,605		57,786		56,909		58,501

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Chord Energy Corporation

Condensed Consolidated Statements of Changes in Stockholders’ Equity (Unaudited)


	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings		Total Stockholders’ Equity
	Shares	Amount		Shares	Amount

	(In thousands)
Balance as of December 31, 2025	56,762	$	675	10,388	$	(1,304,092)	$	7,339,735	$	2,043,636	$	8,079,954
Equity-based compensation and vestings	125	1		—	—		8,042		—		8,043
Tax withholdings on settlement of equity-based awards	(44)	—		—	—		(4,323)		—		(4,323)
Dividends	—	—		—	—		—		(74,571)		(74,571)
Share repurchases	(559)	—		559	(71,364)		—		—		(71,364)

Net income	—	—		—	—		—		108,608		108,608
Balance as of March 31, 2026	56,284	676		10,947	(1,375,456)		7,343,454		2,077,673		8,046,347

Equity-based compensation and vestings	19	—		—	—		8,772		—		8,772
Tax withholdings on settlement of equity-based awards	(2)	—		—	—		(234)		—		(234)
Dividends	—	—		—	—		—		(73,888)		(73,888)
Share repurchases	(1,104)	—		1,104	(148,844)		—		—		(148,844)

Net income	—	—		—	—		—		525,186		525,186
Balance as of June 30, 2026	55,197	$	676	12,051	$	(1,524,300)	$	7,351,992	$	2,528,971	$	8,357,339


	Common Stock			Treasury Stock			Additional Paid-in Capital		Retained Earnings		Total Stockholders’ Equity
	Shares	Amount		Shares	Amount

	(In thousands)
Balance as of December 31, 2024	60,071	$	673	6,897	$	(936,157)	$	7,336,091	$	2,301,655	$	8,702,262
Equity-based compensation and vestings	237	2		—	—		6,876		—		6,878
Tax withholdings on settlement of equity-based awards	(117)	(1)		—	—		(14,356)		—		(14,357)
Dividends	—	—		—	—		—		(77,429)		(77,429)
Share repurchases	(1,994)	—		1,994	(218,527)		—		—		(218,527)

Net income	—	—		—	—		—		219,837		219,837
Balance as of March 31, 2025	58,197	674		8,891	(1,154,684)		7,328,611		2,444,063		8,618,664

Equity-based compensation and vestings	141	1		—	—		6,121		—		6,122
Tax withholdings on settlement of equity-based awards	(83)	—		—	—		(7,437)		—		(7,437)
Dividends	—	—		—	—		—		(75,733)		(75,733)
Share repurchases	(606)	—		606	(55,487)		—		—		(55,487)






Net loss	—	—		—	—		—		(389,905)		(389,905)
Balance as of June 30, 2025	57,649	$	675	9,497	$	(1,210,171)	$	7,327,295	$	1,978,425	$	8,096,224

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Chord Energy Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)


	Six Months Ended June 30,
	2026		2025

	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	633,794	$	(170,068)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	793,452		726,806
Loss on debt extinguishment	—		3,494
Gain on sale of assets	(339)		(4,993)
Impairment	30		539,318
Deferred income taxes	41,113		49,050
Net (gain) loss on derivative instruments	133,605		(61,950)
Net (gain) loss from investment in equity securities	(23,972)		5,862
Equity-based compensation expenses	16,814		12,997

Settlement of asset retirement obligations	(17,935)		(13,671)
Deferred financing costs amortization and other	(12,048)		2,374
Working capital and other changes:
Change in accounts receivable, net	(243,018)		4,479
Change in inventory	(5,866)		(5,738)
Change in prepaid expenses	4,092		5,463
Change in accounts payable, interest payable and accrued liabilities	284,756		(20,031)
Change in other assets and liabilities, net	19,143		3,311
Net cash provided by operating activities	1,623,621		1,076,703
Cash flows from investing activities:
Capital expenditures	(755,502)		(704,388)
Acquisitions	(8,680)		(26,191)

Proceeds from divestitures	326		6,921

Derivative settlements	(88,750)		14,090


Contingent consideration received	25,000		25,000
Distributions from investment in equity securities	4,882		6,786
Contributions to investments	(7,851)		—
Net cash used in investing activities	(830,575)		(677,782)
Cash flows from financing activities:



Proceeds from revolving credit facility	85,000		2,435,000
Principal payments on revolving credit facility	(85,000)		(2,700,000)
Repayment and discharge of senior notes	—		(401,432)
Issuance of senior notes	—		750,000
Deferred financing costs	—		(13,443)
Repurchases of common stock	(217,677)		(274,014)


Tax withholding on vesting of equity-based awards	(4,557)		(21,793)
Dividends paid	(147,683)		(168,846)
Payments on finance lease liabilities	(1,092)		(856)




Net cash used in financing activities	(371,009)		(395,384)
Increase in cash and cash equivalents	422,037		3,537
Cash and cash equivalents:
Beginning of period	189,531		36,950
End of period	$	611,568	$	40,487

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	Six Months Ended June 30,
	2026		2025

	(In thousands)
Supplemental cash flow information:
Cash paid for income taxes	$	88,382	$	66,098
Supplemental non-cash transactions:
Change in accrued capital expenditures	$	3,380	$	(3,950)
Change in asset retirement obligations	3,491		100,632




Change in dividends payable	776		973

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Chord Energy Corporation

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Organization and Summary of Significant Accounting Policies

Chord Energy Corporation, a Delaware corporation (together with its consolidated subsidiaries, the “Company” or “Chord”), is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, NGL and natural gas primarily in the Williston Basin with limited non-operated interests in the Marcellus Shale.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the Condensed Consolidated Balance Sheet at December 31, 2025 is derived from audited financial statements. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for the fair statement of the Company’s financial position, have been included. Management has made certain estimates and assumptions that affect reported amounts in the unaudited condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

These interim financial statements have been prepared pursuant to the rules and regulations of the SEC regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by GAAP for complete consolidated financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2025 (“2025 Annual Report”).

Risks and Uncertainties

As a producer of crude oil, NGL and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGL and natural gas, which are cyclical and dependent upon numerous factors beyond the Company’s control such as economic, geopolitical, political and regulatory developments and competition from other energy sources. Energy markets experienced significant volatility during the first half of 2026, driven primarily by the escalation of conflict in the Middle East beginning in late February and the resulting disruptions to global oil and natural gas supply following the effective closure of the Strait of Hormuz to most commercial shipping. Continued geopolitical tensions, including the uncertain pace and durability of any diplomatic resolution between the United States and Iran and periodic actual and potential escalations in hostilities, uncertainty around OPEC+ production policy, including the withdrawal of the United Arab Emirates from OPEC+ effective in May 2026 and the withdrawal’s potential to reduce the group’s ability to coordinate global supply, and the potential economic outcomes of tariff and trade policy decisions of the U.S. or other governments create difficulty in predicting future impacts to commodity prices, which could affect the Company’s financial position, results of operations, cash flows, capital and operating costs, and the quantities of crude oil, NGL and natural gas reserves that may be economically produced.

Out-of-Period Adjustment

During the six months ended June 30, 2026, the Company recorded an out-of-period tax benefit in the amount of $41.8 million. See Note 12—Income Taxes.

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Significant Accounting Policies

There have been no material changes to the Company’s significant accounting policies and estimates from those disclosed in the 2025 Annual Report, except as described below.

Equity Method Investments

The Company accounts for investments in entities over which it has the ability to exercise significant influence, but not control, using the equity method of accounting in accordance with FASB ASC 323-10, Investments—Equity Method and Joint Ventures. Significant influence is generally evidenced by ownership of 20% or more of the investee's voting stock; however, significant influence may also be established through other means, including representation on the investee's board of directors, regardless of the level of ownership interest held. Under the equity method, the investment is initially recorded at cost and subsequently adjusted each period for additional investments, distributions and the Company's proportionate share of the investee's net earnings or losses, which is recognized in the Company's Condensed Consolidated Statement of Operations. The Company assesses equity method investments for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. If the Company determines that a loss in the value of any of the investments is other-than-temporary, it writes down the investments to its estimated fair value.

During the three months ended June 30, 2026, the Company acquired an 8.5% ownership interest in a private specialty chemicals company, which is reflected within other long-term assets on the Condensed Consolidated Balance Sheets. The Company has applied the equity method of accounting as it has established significant influence through its contractual right to designate a member of the investee’s board of directors. The Company's board designee is an employee of the Company; accordingly, the Company's investment in and commercial arrangements with the investee are considered related party transactions under FASB ASC 850-10, Related Party Disclosures.

Recent Accounting Pronouncements

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 (“ASU 2024-03”). This standard requires that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating this ASU to determine its impact on the Company’s financial statement disclosures.

In July 2025, the FASB issued ASU 2025-05, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets (“ASU 2025-05”). This standard amends the guidance for measuring expected credit losses on accounts receivable and contract assets. The amendments are intended to clarify the application of the current expected credit loss model to short-term receivables and contract assets, and to provide additional guidance on the use of historical loss information and forecasts in estimating expected credit losses. ASU 2025-05 is effective for annual and interim reporting periods beginning after December 15, 2025, with early adoption permitted. The Company adopted this ASU effective January 1, 2026, and the adoption did not have a material impact on the Company’s condensed consolidated financial statements.

In December 2025, the FASB issued ASU 2025-10, Government Grants (Topic 832): Accounting for Government Grants Received by Business Entities (“ASU 2025-10”). This standard establishes guidance for how a business entity accounts for government grants, distinguishing between grants related to assets and grants related to income. The standard also requires enhanced disclosures regarding the nature, terms, and amounts of government grants recognized in the financial statements. ASU 2025-10 is effective for annual and interim reporting periods beginning after December 15, 2026, with early adoption permitted.

The Company early adopted ASU 2025-10 prospectively effective April 1, 2026, coinciding with its receipt of its first government grant of this nature. The Company elected the cost accumulation approach for grants related to the acquisition or construction of property, plant and equipment. Under this approach, monetary government grants that reimburse the Company for capital expenditures are recognized as a reduction of the cost basis of the related asset when the grant's recognition criteria are met. The resulting net cost basis is subsequently depreciated over the asset's useful life, and no separate subsequent measurement or presentation guidance is applied to the grant, as it is not separately identifiable from the carrying value of the related asset. The adoption of ASU 2025-10 did not have a material impact on the Company's condensed consolidated financial statements.

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In May 2026, the FASB issued ASU 2026-02, Environmental Credits and Environmental Credit Obligations (Topic 818) (“ASU 2026-02”). This standard establishes guidance for how a business entity accounts for environmental credits and environmental credit obligations. The standard also requires enhanced disclosures regarding the nature, terms, and amounts of environmental credits and obligations recognized in the financial statements. ASU 2026-02 is effective for annual and interim reporting periods beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating this ASU to determine its impact on the Company's consolidated financial statements.

2. Revenue Recognition

Revenues from contracts with customers were as follows for the periods presented:


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025

	(In thousands)
Crude oil revenues	$	1,414,957	$	878,928	$	2,411,253	$	1,835,064
Purchased crude oil sales	669,009		224,835		1,179,606		328,706
NGL and natural gas revenues	79,327		71,338		233,620		218,626
Purchased natural gas sales	9,392		5,459		13,841		13,210

Total revenues	$	2,172,685	$	1,180,560	$	3,838,320	$	2,395,606

The Company records revenue when the performance obligations under the terms of its customer contracts are satisfied. For sales of commodities, the Company records revenue in the month the production or purchased product is delivered to the purchaser. However, settlement statements and payments are typically not received for 20 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. In certain cases, the Company is required to estimate these revenues during a reporting period and record any differences between the estimated revenues and actual revenues in the following reporting period. Differences between estimated revenues and actual revenues have historically not been significant. For the three and six months ended June 30, 2026 and 2025, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.

3. Inventory

The Company’s inventory balances are comprised of the following:


	June 30, 2026		December 31, 2025

	(In thousands)
Inventory
Equipment and materials	$	60,912	$	61,582
Crude oil inventory	60,497		54,131
Total inventory	121,409		115,713
Long-term inventory
Linefill in third-party pipelines	26,073		30,759
Total long-term inventory	26,073		30,759
Total	$	147,482	$	146,472

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4. Additional Balance Sheet Information

The following table sets forth certain balance sheet amounts comprised of the following:


	June 30, 2026		December 31, 2025

	(In thousands)
Accounts receivable, net
Trade and other accounts	$	1,087,288	$	894,309
Joint interest accounts	264,819		233,919

Total accounts receivable	1,352,107		1,128,228
Less: allowance for credit losses	(14,076)		(11,543)
Total accounts receivable, net	$	1,338,031	$	1,116,685

Revenues and production taxes payable
Royalties payable and revenue suspense	$	764,406	$	583,475

Production taxes payable	52,996		34,783
Total revenues and production taxes payable	$	817,402	$	618,258

Accrued liabilities
Accrued oil and gas marketing	$	213,215	$	235,111
Accrued capital costs	263,660		260,280
Accrued lease operating expenses	126,758		121,306
Accrued general and administrative expenses	29,587		45,607

Current portion of asset retirement obligations	50,677		49,117
Accrued dividends	1,005		859
Other accrued liabilities	21,934		23,106
Total accrued liabilities	$	706,836	$	735,386

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5. Fair Value Measurements

In accordance with the FASB’s authoritative guidance on fair value measurements, certain of the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 11—Asset Retirement Obligations) and properties acquired in a business combination (See Note 8—Acquisitions) or upon impairment (see Note 7—Property, Plant and Equipment), at fair value on a non-recurring basis.

Financial Assets and Liabilities

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following tables set forth by level, within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:


	Fair value at June 30, 2026
	Level 1		Level 2		Level 3		Total

	(In thousands)
Assets:
Commodity derivative contracts (see Note 6)	$	—	$	59,679	$	—	$	59,679

Investment in equity securities (see Note 9)	138,789		—		—		138,789
Total assets	$	138,789	$	59,679	$	—	$	198,468
Liabilities:
Commodity derivative contracts (see Note 6)	$	—	$	18,856	$	—	$	18,856
Total liabilities	$	—	$	18,856	$	—	$	18,856


	Fair value at December 31, 2025
	Level 1		Level 2		Level 3		Total

	(In thousands)
Assets:
Commodity derivative contracts (see Note 6)	$	—	$	85,678	$	—	$	85,678
Investment in equity securities (see Note 9)	119,698		—		—		119,698
Total assets	$	119,698	$	85,678	$	—	$	205,376
Liabilities:
Commodity derivative contracts (see Note 6)	$	—	$	—	$	—	$	—
Total liabilities	$	—	$	—	$	—	$	—

Commodity derivative contracts. The Company enters into commodity derivative contracts to manage risks related to changes in crude oil and natural gas prices. The Company’s commodity derivative contracts are valued by a third-party preparer based on an income approach. The significant inputs used are commodity prices, discount rate and the contract terms of the derivative instruments. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the fair value hierarchy. The Company compares the valuation performed by the third-party preparer to counterparty valuation statements to assess the reasonableness of its valuation. The determination of the fair value also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the market credit spread of the Company or similarly rated public issuers. The credit risk adjustments to the fair value of the Company’s net derivative assets and liabilities were not material for the periods presented. See Note 6—Derivative Instruments for additional information.

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Investment in equity securities. The Company owns common units in Energy Transfer LP (“Energy Transfer”) which are accounted for using the fair value option under FASB ASC 825-10, Financial Instruments. The fair value of the Company’s investment in Energy Transfer was determined using Level 1 inputs based upon the quoted market price of Energy Transfer’s publicly traded common units at June 30, 2026 and December 31, 2025, respectively. See Note 9—Investment in Equity Securities for additional information.

Non-Financial Assets and Liabilities

The fair value of the Company’s non-financial assets and liabilities measured on a non-recurring basis are determined using valuation techniques that include Level 3 inputs.

Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, environmental and regulatory environments.

Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials), estimates of future operating and development costs and a risk-adjusted discount rate.

Business Combinations. The Company records the fair value of the oil and gas properties acquired using an income approach based on the net discounted future cash flows from the oil and gas properties and related assets acquired. The inputs utilized in the valuation of the oil and gas properties acquired included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the properties’ reserve reports, commodity prices based on forward pricing assumptions (adjusted for basis differentials), operating and development costs, expected future development plans for the properties and the utilization of a discount rate based on a market-based weighted-average cost of capital. The Company also recorded ARO assumed in this acquisition at fair value. The inputs utilized in valuing the assumed ARO were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of the acquisition date, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs. This valuation technique was used in the following business combination:

•2025 Williston Basin Acquisition. On October 31, 2025, the Company completed the 2025 Williston Basin Acquisition (defined in Note 8—Acquisitions). The assets acquired and liabilities assumed were recorded at fair value as of October 31, 2025.

6. Derivative Instruments

Commodity derivative contracts. The Company utilizes derivative financial instruments to manage risks related to changes in commodity prices. The Company’s crude oil contracts settle monthly based on the average NYMEX WTI, while crude oil basis swaps settle monthly based on the average fixed differential between NYMEX WTI and the ICE BRENT index price. Natural gas contracts settle monthly based on the average NYMEX Henry Hub natural gas index price.

The Company utilizes derivative financial instruments including fixed-price swaps, two-way and three-way collars, and basis swaps to manage risks related to changes in commodity prices. The Company’s fixed-price swaps are designed to establish a fixed price for the volumes under contract. Two-way collars are designed to establish a minimum price (floor) and a maximum price (ceiling) for the volumes under contract. Three-way collars are designed to establish a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) for the volumes under contract. A basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relation to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the volumes under contract. The Company may, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts.

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At June 30, 2026, the Company had the following outstanding commodity derivative contracts:


Commodity	Settlement Period	Derivative Instrument	Volumes			Weighted Average Prices
					Fixed Price Swaps			Sub-Floor			Floor			Ceiling

Crude oil	2026	Three-way collar	4,278,000	Bbls					$	56.56		$	73.33		$	87.02
Crude oil	2026	Two-way collar	3,933,000	Bbls								$	67.49		$	76.76
Crude oil	2026	Fixed price swaps	2,852,000	Bbls		$	66.82
Crude oil	2027	Three-way collar	7,969,500	Bbls					$	49.65		$	64.80		$	78.12
Crude oil	2027	Two-way collar	816,000	Bbls								$	60.00		$	65.82
Crude oil	2027	Fixed price swaps	906,000	Bbls		$	69.82
Crude oil	2028	Three-way collar	1,092,000	Bbls					$	49.58		$	65.00		$	78.26
Natural gas	2026	Two-way collar	6,440,000	MMBtu								$	3.82		$	4.33
Natural gas	2026	Fixed price swaps	14,720,000	MMBtu		$	3.93

Natural gas	2027	Two-way collar	4,525,000	MMBtu								$	3.75		$	4.18
Natural gas	2027	Fixed price swaps	11,840,000	MMBtu		$	3.94
Natural gas	2028	Fixed price swaps	1,820,000	MMBtu		$	3.56

At June 30, 2026, the Company had the following outstanding crude oil basis swaps:


Index	Settlement Period	Volumes		Weighted Average Differential(1)


NYMEX WTI - ICE BRENT	2026	2,576,000	Bbls	$	(5.44)

____________________

(1)The weighted average differential represents the average fixed differential to NYMEX WTI as stated in the related contracts, which is compared to the ICE BRENT index price. If NYMEX WTI combined with the fixed differential as stated in each contract is lower than the ICE BRENT index price at any settlement date, the Company receives the difference. Conversely, if NYMEX WTI combined with the fixed differential as stated in each contract is higher than the ICE BRENT index price, the Company pays the difference.

Subsequent to June 30, 2026 through August 3, 2026, the Company entered into the following commodity derivative contracts:


					Weighted Average Prices
Commodity	Settlement Period	Derivative Instrument	Volumes		Sub-Floor		Floor		Ceiling

Crude oil	2026	Two-way collar	184,000	Bbls			$	73.25	$	84.35
Crude oil	2027	Three-way collar	276,000	Bbls	$	50.00	$	67.92	$	79.47
Crude oil	2027	Two-way collar	726,000	Bbls			$	68.67	$	77.51
Crude oil	2028	Three-way collar	365,000	Bbls	$	50.00	$	66.06	$	78.69

Contingent consideration. In connection with the Company’s 2021 divestiture of certain oil and gas properties, the Company was entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI exceeded $60 per barrel for such year (the “Contingent Consideration”). In each of January 2024, 2025 and 2026, the Company received $25.0 million related to the 2023, 2024 and 2025 earn-out payments, respectively. There are no earn-out payments remaining as of June 30, 2026.

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The following table summarizes the location and amounts of gains and losses from the Company’s derivative instruments recorded in the Company’s Condensed Consolidated Statements of Operations for the periods presented:


		Three Months Ended June 30,				Six Months Ended June 30,
Derivative Instrument	Statements of Operations Location	2026		2025		2026		2025

		(In thousands)
Commodity derivatives	Net gain (loss) on derivative instruments	$	107,866	$	81,991	$	(133,605)	$	61,030

Contingent consideration	Net gain (loss) on derivative instruments	—		240		—		920

In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Condensed Consolidated Balance Sheets.

The following table summarizes the location and fair value of all outstanding derivative instruments recorded in the Company’s Condensed Consolidated Balance Sheets:


		June 30, 2026
Derivative Instrument	Balance Sheet Location	Gross Amount		Gross Amount Offset		Net Amount

		(In thousands)
Derivatives assets:
Commodity derivatives	Derivative instruments — current assets	$	116,099	$	(66,511)	$	49,588

Commodity derivatives	Derivative instruments — non-current assets	36,052		(25,961)		10,091

Total derivatives assets		$	152,151	$	(92,472)	$	59,679

Derivatives liabilities:
Commodity derivatives	Derivative instruments — current liabilities	$	82,581	$	(66,511)	$	16,070

Commodity derivatives	Derivative instruments — non-current liabilities	28,747		(25,961)		2,786

Total derivatives liabilities		$	111,328	$	(92,472)	$	18,856

		December 31, 2025
Derivative Instrument	Balance Sheet Location	Gross Amount		Gross Amount Offset		Net Amount

		(In thousands)
Derivatives assets:
Commodity derivatives	Derivative instruments — current assets	$	93,850	$	(16,538)	$	77,312

Commodity derivatives	Derivative instruments — non-current assets	24,413		(16,047)		8,366

Total derivatives assets		$	118,263	$	(32,585)	$	85,678

Derivatives liabilities:
Commodity derivatives	Derivative instruments — current liabilities	$	16,538	$	(16,538)	$	—
Commodity derivatives	Derivative instruments — non-current liabilities	16,047		(16,047)		—


Total derivatives liabilities		$	32,585	$	(32,585)	$	—

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7. Property, Plant and Equipment

The following table sets forth the Company’s property, plant and equipment for the periods presented:


	June 30, 2026		December 31, 2025

	(In thousands)
Proved oil and gas properties	$	14,913,188	$	14,127,286
Less: Accumulated depletion	(4,316,217)		(3,541,219)
Proved oil and gas properties, net	10,596,971		10,586,067
Unproved oil and gas properties	714,505		721,682
Other property and equipment	60,493		60,395
Less: Accumulated depreciation	(33,308)		(31,615)
Other property and equipment, net	27,185		28,780
Total property, plant and equipment, net	$	11,338,661	$	11,336,529

8. Acquisitions

2025 Acquisition

On September 15, 2025, a wholly-owned subsidiary of the Company entered into a definitive agreement to acquire certain developed and undeveloped oil and gas assets located in the Williston Basin from XTO Energy Inc. and affiliates (collectively, “XTO”), subsidiaries of Exxon Mobil Corporation, for total cash consideration of $550.0 million, subject to customary purchase price adjustments (the “2025 Williston Basin Acquisition”). The effective date of the 2025 Williston Basin Acquisition was September 1, 2025.

On October 31, 2025, the Company completed the 2025 Williston Basin Acquisition for total cash consideration of $542.2 million, including a cash deposit of $55.0 million to XTO upon execution of the purchase and sale agreement and $487.2 million paid to XTO at closing (subject to customary purchase price adjustments). The Company funded the 2025 Williston Basin Acquisition with proceeds from the issuance of the 2030 Senior Notes (defined in Note 10—Long-Term Debt) and cash on hand. The 2025 Williston Basin Acquisition was accounted for as a business combination and was recorded under the acquisition method of accounting in accordance with FASB ASC 805, Business Combinations. The post-acquisition operating results and pro forma revenue and earnings for the 2025 Williston Basin Acquisition were not material to the Company’s condensed consolidated financial statements and have therefore not been presented.

Purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the 2025 Williston Basin Acquisition at their fair value of $540.4 million. The allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no goodwill or bargain purchase gain being recognized. Determining the fair value of the assets and liabilities of the 2025 Williston Basin Acquisition required judgment and certain assumptions to be made. See Note 5—Fair Value Measurements for additional information.

The tables below present the total consideration transferred and its allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on October 31, 2025. As of June 30, 2026, the purchase price was finalized.


	Purchase Price Consideration
	(In thousands)
Cash consideration transferred	$	540,353

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	Purchase Price Allocation

	(In thousands)
Assets acquired:
Oil and gas properties (successful efforts method)	$	555,322
Other property and equipment	235
Inventory	2,185
Total assets acquired	$	557,742

Liabilities assumed:
Asset retirement obligations	$	16,473
Revenue and production taxes payable	916
Total liabilities assumed	$	17,389

Net assets acquired	$	540,353

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9. Investment in Equity Securities

As of June 30, 2026 and December 31, 2025, the fair value of the Company’s investment in Energy Transfer was $138.8 million and $119.7 million, respectively, which represented less than 5% of Energy Transfer’s issued and outstanding common units. The carrying amount of the Company’s investment in Energy Transfer is recorded to investment in equity securities on the Condensed Consolidated Balance Sheets.

During the three and six months ended June 30, 2026, the Company recorded a net gain of $1.1 million and $24.0 million, respectively, on its investment in Energy Transfer, comprised of an unrealized loss for the change in fair value of the investment of $1.3 million and an unrealized gain of $19.1 million, respectively, and a realized gain for cash distributions received of $2.4 million and $4.9 million, respectively. During the three and six months ended June 30, 2025, the Company recorded a net loss of $1.0 million and $5.9 million, respectively, on its investment in Energy Transfer, comprised of an unrealized loss for the change in the fair value of its investment of $3.3 million and $10.6 million, respectively, partially offset by a realized gain for cash distributions received of $2.4 million and $4.7 million, respectively.

10. Long-Term Debt

The Company’s long-term debt consists of the following:


	June 30, 2026		December 31, 2025

	(In thousands)
Senior secured revolving line of credit	$	—	$	—
2030 Senior Notes	750,000		750,000
2033 Senior Notes	750,000		750,000

Less: unamortized deferred financing costs	(18,643)		(20,419)


Total long-term debt, net	$	1,481,357	$	1,479,581

Senior secured revolving line of credit. The Company has a senior secured revolving credit facility (the “Credit Facility”) that matures on November 3, 2029. The Credit Facility’s borrowing base is subject to redetermination semi-annually, on or about April 1 and October 1. The most recent redetermination was completed in May 2026 and reaffirmed the borrowing base and the aggregate elected commitment at $2.75 billion and $2.0 billion, respectively. The next redetermination is scheduled for October 2026.

At June 30, 2026, the Company had no borrowings outstanding and $30.4 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $1,969.6 million. At December 31, 2025, the Company had no borrowings outstanding and $32.8 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $1,967.2 million.

During both the three and six months ended June 30, 2026, the weighted average interest rate incurred on borrowings on the Credit Facility was 7.50%. During the three and six months ended June 30, 2025, the weighted average interest rate was 6.56% and 6.47%, respectively. The Company was in compliance with the financial covenants under the Credit Facility at June 30, 2026. The fair value of the Credit Facility approximates its carrying value since borrowings under the Credit Facility bear interest at variable rates, which are tied to current market rates.

Borrowings are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan, an ABR Loan or a Swingline Loan (each as defined in the Credit Facility). The Company incurs interest on outstanding loans at their respective interest rates plus a margin rate ranging between 1.75% to 2.75% for Term SOFR Loans and 0.75% to 1.75% for ABR Loans or Swingline Loans. The unused borrowing base is subject to a commitment fee ranging between 0.375% to 0.500%.

2030 Senior Notes. On September 30, 2025, the Company issued in a private placement $750.0 million of 6.000% senior unsecured notes due October 1, 2030 (the “2030 Senior Notes”). The 2030 Senior Notes were issued at par and resulted in proceeds of $739.6 million, after deducting underwriters’ discounts, commissions and other expenses. Interest on the 2030 Senior Notes is payable semi-annually on April 1 and October 1 of each year, beginning April 1, 2026. The proceeds were used (i) to fund the 2025 Williston Basin Acquisition and to pay related costs and expenses, (ii) to pay fees and expenses associated with the offering of the 2030 Senior Notes and (iii) for general corporate purposes, including repayment of a portion of the borrowings outstanding under the Credit Facility. In connection with the issuance of the 2030 Senior Notes, the Company recorded deferred financing costs of $10.4 million, which are amortized to interest expense on the Company’s Condensed Consolidated Statement of Operations over the term of the 2030 Senior Notes. As of June 30, 2026, the fair value of the 2030 Senior Notes, which are traded among qualified institutional investors and represent a Level 1 fair value measurement, was $753.2 million.

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2033 Senior Notes. On March 13, 2025, the Company issued in a private placement $750.0 million of 6.750% senior unsecured notes due March 15, 2033 (the “2033 Senior Notes”). The 2033 Senior Notes were issued at par and resulted in proceeds of $738.8 million, after deducting underwriters’ discounts, commissions and other expenses. Interest on the 2033 Senior Notes is payable semi-annually on March 15 and September 15 of each year, which began on September 15, 2025. The proceeds were used to repurchase the 2026 Senior Notes (as defined below) tendered in a concurrent tender offer, to satisfy and discharge the remaining 2026 Senior Notes not tendered in the concurrent tender offer (which were redeemed on June 1, 2025) and to repay a portion of the borrowings outstanding under the Credit Facility. In connection with the issuance of the 2033 Senior Notes, the Company recorded deferred financing costs of $11.6 million, which are amortized to interest expense on the Company’s Condensed Consolidated Statement of Operations over the term of the 2033 Senior Notes. As of June 30, 2026, the fair value of the 2033 Senior Notes, which are traded among qualified institutional investors and represent a Level 1 fair value measurement, was $761.1 million.

The 2030 Senior Notes and the 2033 Senior Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Chord Guarantors”). These guarantees are full and unconditional and joint and several among the Chord Guarantors, subject to certain customary release provisions. The indentures governing the 2030 Senior Notes and the 2033 Senior Notes contain customary events of default as well as cross-default provisions with other indebtedness of Chord and its restricted subsidiaries.

2026 Senior Notes. At December 31, 2024, the Company had $400.0 million of 6.375% senior unsecured notes outstanding due June 1, 2026 (the “2026 Senior Notes”). Concurrent with the issuance of the 2033 Senior Notes on March 13, 2025, the purchase and satisfaction and discharge of the 2026 Senior Notes resulted in a loss on debt extinguishment of $3.5 million, primarily including the write-off of unamortized debt issuance costs of $2.1 million and a premium paid to redeem a portion of the 2026 Senior Notes totaling $1.1 million.

11. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the six months ended June 30, 2026:


	(In thousands)

Balance at December 31, 2025	$	481,919
Liabilities incurred during period	3,810

Liabilities settled during period	(17,935)
Liabilities settled through divestitures	(320)
Accretion expense during period	15,233


Balance at June 30, 2026	$	482,707

The Company’s ARO includes plugging and abandonment liabilities for its oil and gas properties in the United States and Canada. Accretion expense is included in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statements of Operations. At June 30, 2026, the current portion of the total ARO balance was $50.7 million, and is included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.

12. Income Taxes

The Company’s effective tax rate was 23.6% and 18.9% for the three and six months ended June 30, 2026, respectively, as compared to an effective tax rate of (16.2)% and (298.4)% for the three and six months ended June 30, 2025, respectively.

The effective tax rate for the three months ended June 30, 2026 was higher than the statutory federal rate of 21% primarily as a result of state income taxes. The effective tax rate for the six months ended June 30, 2026 was lower than the statutory federal rate of 21% primarily as a result of the identification of an error in the tax provision for the three and six months ended June 30, 2025 pertaining to the impact of goodwill impairment on the Company’s deferred taxes on unremitted earnings. As a result, the Company recognized an additional income tax benefit of $41.8 million during the six months ended June 30, 2026, with a corresponding decrease to deferred tax liabilities. The Company determined that this misstatement was not material to any of its previously issued financial statements nor is it expected to be material to the results for the full year ending December 31, 2026.

The effective tax rate for the three and six months ended June 30, 2025 was lower than the statutory federal rate of 21% primarily as a result of the impact of goodwill impairment.

The Company paid income taxes of $67.4 million and $88.4 million during the three and six months ended June 30, 2026, respectively, and $32.1 million and $66.1 million during the three and six months ended June 30, 2025, respectively.

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13. Equity-Based Compensation

The Company has granted RSUs, PSUs, and MSUs (each as defined below), as well as phantom unit awards under its equity compensation plans.

Equity-based compensation expenses are recognized in general and administrative expenses on the Company’s Condensed Consolidated Statements of Operations. The Company recognized $8.8 million and $16.8 million in equity-based compensation expenses related to equity-classified awards during the three and six months ended June 30, 2026, respectively. During the three and six months ended June 30, 2025, the Company recognized $6.1 million and $13.0 million in equity-based compensation expenses related to equity-classified awards, respectively. Equity-based compensation expenses related to liability-classified awards were $3.2 million for the six months ended June 30, 2026, and not material for the three months ended June 30, 2026 or the three and six months ended June 30, 2025.

Restricted stock units. Restricted stock units (“RSUs”) are contingent shares that generally vest on either a cliff or graded basis over a one-year or three-year period (as applicable) and are subject to a service condition. During the six months ended June 30, 2026, the Company granted 287,780 RSUs to employees and non-employee directors of the Company with a weighted average grant date fair value of $98.76 per share.

Market stock units. During the six months ended June 30, 2026, the Company granted Market Stock Units (“MSUs”), which are eligible to vest and become earned at the end of the three-year performance period, which begins on January 1 of the initial grant year and ends on December 31 of the third year, subject to the level of achievement with respect to certain performance goals.

The MSUs are subject to time-based service requirements and market conditions based on the total stockholder return (“TSR”) achieved by the Company during the performance period. Depending on the Company’s TSR, award recipients may earn between 0% and 200% of the number of MSUs originally granted. Any earned MSUs will be settled in shares of the Company’s common stock.

During the six months ended June 30, 2026, the Company granted 24,131 MSUs to certain employees of the Company with a weighted average grant date fair value of $128.29 per share.

Performance share units. During the six months ended June 30, 2026, the Company granted PSUs that include (i) absolute TSR PSUs (“Absolute TSR PSUs”) and (ii) relative TSR PSUs (“Relative TSR PSUs” and collectively with the Absolute TSR PSUs, the “PSUs”), which are eligible to vest and become earned at the end of the three-year performance period which begins on January 1 of the initial grant year and ends on December 31 of the third year.

The Absolute TSR PSUs are subject to time-based service requirements and market conditions based on the TSR achieved by the Company during the performance period. Depending on the Company’s TSR, award recipients may earn between 0% and 200% of the target number of Absolute TSR PSUs originally granted.

The Relative TSR PSUs are subject to time-based service requirements and market conditions based on a comparison of the TSR achieved by the Company against the TSR achieved by the members of a defined peer group at the end of the performance period. Depending on the Company’s TSR performance relative to the TSR performance of the members of the defined peer group, award recipients may earn between 0% and 200% of the target number of Relative TSR PSUs originally granted.

Any earned PSUs will be settled in shares of the Company’s common stock for up to 100% of the target number of PSUs subject to each applicable award, with any remaining earned PSUs that exceed the target number of PSUs subject to the award being settled in cash based on the fair market value of a share of the Company’s common stock on the applicable payment date. The PSUs are bifurcated and classified as equity-based and liability-based awards based on the probability of achieving various target performance thresholds.

During the six months ended June 30, 2026, the Company granted (i) 30,299 Absolute TSR PSUs to certain employees of the Company with a weighted average grant date fair value of $101.14 per share and (ii) 90,912 Relative TSR PSUs to employees of the Company with a weighted average grant date fair value of $114.53 per share.

Fair value assumptions. The aggregate grant date fair value of the PSUs and MSUs were determined by a third-party valuation specialist using a Monte Carlo simulation model which uses a probabilistic approach for estimating the fair value of the awards. The key valuation inputs were: (i) the forecast period, (ii) risk-free interest rate, (iii) the yield curve associated with the Company’s credit rating, (iv) implied equity volatility, (v) stock price on the date of grant and (vi) solely for Relative TSR PSUs, correlation coefficient. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to the performance period. Implied equity volatility is derived by solving for an asset volatility and equity volatility based on the leverage of the Company and each of its peers. For the Relative TSR PSUs, the correlation coefficient measures the strength of the linear relationship between and amongst the Company and its peers based on historical stock price data.

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The following table summarizes the assumptions used in the Monte Carlo simulation model to determine the grant date fair value and associated equity-based compensation expenses for the PSUs and MSUs granted during the six months ended June 30, 2026:


	Absolute and Relative TSR PSUs	Absolute TSR MSUs


Forecast period (years)	3	3
Risk-free interest rate	3.7%	3.7%
Implied equity volatility	33%	33%

Stock price on date of grant	$95.53	$95.53

Phantom unit awards. Phantom unit awards represent the right to receive a cash payment equal to the fair market value of one share of common stock upon vesting and vest on a graded basis over a three-year period and are subject to a service condition. During the six months ended June 30, 2026, the Company granted 21,970 phantom unit awards to employees with a weighted average grant date fair value of $95.63 per share.

14. Stockholders’ Equity

Dividends

The following table summarizes the Company’s dividends declared for the six months ended June 30, 2026 and 2025:



	Base Dividend Rate per Share		Total Dividends Declared

	(In thousands, except per share data)


Q2 2026	$	1.30	$	73,888
Q1 2026	1.30		74,571
Total	$	2.60	$	148,459



Q2 2025	$	1.30	$	75,733
Q1 2025	1.30		77,429
Total	$	2.60	$	153,162

Total dividends declared in the table above include $0.9 million and $1.9 million associated with dividend equivalent rights on unvested equity-based compensation awards for the three and six months ended June 30, 2026, respectively, and $0.6 million and $1.5 million for the three and six months ended June 30, 2025, respectively.

On August 5, 2026, the Company declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on September 4, 2026 to shareholders of record as of August 20, 2026.

Share Repurchase Program

In August 2025, the Board of Directors authorized a share repurchase program of up to $1.0 billion of the Company’s common stock, which replaced the Company’s previous share repurchase programs. The Company has repurchased, and may repurchase in the future, shares pursuant to a Rule 10b5-1 trading plan under the Securities Exchange Act of 1934, as amended, which permits the Company to repurchase shares at times that may otherwise be prohibited under its insider trading policy. The share repurchase program does not require the Company to make purchases within a particular time frame.

During the six months ended June 30, 2026, the Company repurchased 1,663,410 shares of common stock at a weighted average price of $131.14 per common share for a total cost of $218.1 million, excluding accrued excise tax of $2.1 million. As of June 30, 2026, there was $734.0 million of capacity remaining under the Company’s $1.0 billion share repurchase program. Subsequent to June 30, 2026 through August 3, 2026, the Company repurchased 521,792 shares of common stock at a weighted average price of $127.61 per common share for a total cost of $66.6 million.

During the six months ended June 30, 2025, the Company repurchased 2,600,117 shares of common stock at a weighted average price of $104.41 per common share for a total cost of $271.5 million, excluding excise tax of $2.5 million, under its previous share repurchase programs.

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15. Earnings Per Share

The Company calculates earnings per share under the two-class method. The Company has granted RSUs to non-employee directors which include non-forfeitable rights to dividends and are therefore considered “participating securities.” Accordingly, the Company computes earnings per share under the two-class earnings allocation method, which computes earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings.

Basic earnings per share amounts have been computed as (i) net income (ii) less distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of basic shares outstanding for the periods presented. Diluted earnings per share amounts have been computed as (i) basic net income attributable to common stockholders (ii) plus the reallocation of distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of diluted shares outstanding for the periods presented. The Company calculates diluted earnings per share under both the two-class method and treasury stock method and reports the more dilutive of the two calculations.

The following table summarizes the basic and diluted earnings per share for the periods presented:


	Three Months Ended June 30,				Six Months Ended June 30,


	2026		2025		2026		2025

	(In thousands, except per share data)
Net income (loss)	$	525,186	$	(389,905)	$	633,794	$	(170,068)
Distributed and undistributed earnings allocated to participating securities	(4,243)		2,312		(4,432)		1,425
Net income (loss) attributable to common stockholders (basic)	520,943		(387,593)		629,362		(168,643)
Reallocation of distributed and undistributed earnings allocated to participating securities	4,243		(3,604)		4,432		(2,687)
Net income (loss) attributable to common stockholders (diluted)	$	525,186	$	(391,197)	$	633,794	$	(171,330)

Weighted average common shares outstanding:
Basic weighted average common shares outstanding	56,010		57,786		56,361		58,420
Dilutive effect of share-based awards	595		—		548		81

Diluted weighted average common shares outstanding	56,605		57,786		56,909		58,501

Basic earnings (loss) per share	$	9.30	$	(6.71)	$	11.17	$	(2.89)
Diluted earnings (loss) per share	$	9.28	$	(6.77)	$	11.14	$	(2.93)

Anti-dilutive weighted average common shares:
Potential common shares	160		1,067		182		980

For the three and six months ended June 30, 2026, the diluted earnings per share calculation excludes the impact of unvested share-based awards that were anti-dilutive. For the three and six months ended June 30, 2025, the diluted earnings per share calculation excludes the impact of unvested share-based awards and outstanding warrants that were anti-dilutive. There were no remaining warrants as of June 30, 2026, as all previously outstanding warrants expired on September 1, 2025.

16. Commitments and Contingencies

Included below is a discussion of various future commitments of the Company as of June 30, 2026. The commitments under these arrangements are not recorded in the accompanying Condensed Consolidated Balance Sheets. The amounts disclosed represent undiscounted cash flows on a gross basis and no inflation elements have been applied. As of June 30, 2026, the Company’s material off-balance sheet arrangements and transactions include $30.4 million in outstanding letters of credit issued under the Credit Facility and $119.1 million in net surety bond exposure issued as financial assurance on certain agreements.

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Volume commitment agreements. As of June 30, 2026, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 77.6 MMBbl of crude oil, 9.2 MMBbl of NGL, 272.5 Bcf of natural gas and 11.0 MMBbl of water within specified timeframes.

As of June 30, 2026, the undiscounted estimable future commitments under these volume commitment agreements are as follows:


	(In thousands)
Year 1	$	125,930
Year 2	111,881
Year 3	75,296
Year 4	58,961
Year 5	58,646
Thereafter	122,567
	$	553,281

The future commitments under certain agreements cannot be estimated and are therefore excluded from the table above as they are based on fixed differentials relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for the production month.

The Company enters into long-term contracts to provide production flow assurance in oversupplied areas with limited infrastructure, which provides for optimization of transportation and processing costs. As properties are undergoing development activities, the Company may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. The Company recognizes any monthly deficiency payments in the period in which the under delivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred.

As of June 30, 2026, there have been no material changes to the Company’s contingencies disclosed in Note 20—Commitments and Contingencies in the 2025 Annual Report.

17. Leases

No material changes have occurred to the Company’s lease portfolio for the periods presented in this Quarterly Report on Form 10-Q. Refer to the 2025 Annual Report for more information on the Company’s leases.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2025 (“2025 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding, but not limited to, our strategic tactics, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plans” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed under “Part II, Item 1A. Risk Factors” in this Quarterly Report on Form 10-Q could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. Without limiting the generality of the foregoing, certain statements incorporated by reference or included in this Quarterly Report on Form 10-Q constitute forward-looking statements.

We believe these factors and risks relate to forward-looking statements including, but not limited to, the following:

•crude oil, NGL and natural gas realized prices;

•uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil, NGL and natural gas;

•the actions taken by OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to continue to control supply and to agree on and comply with production levels;

•changes in trade policies and regulations, including increases or change in duties, current and potentially new tariffs or quotas; and other similar measures, as well as the potential impact of retaliatory tariffs and other actions;

•war between Russia and Ukraine, military conflicts in the Red Sea Region, Iran, and the wider Middle East and their effect on commodity prices;

•changes or uncertainty in general economic and geopolitical conditions;

•inflation rates and the impact of associated monetary policy responses, including fluctuating interest rates;

•logistical challenges and supply chain disruptions, including as a result of conflicts;

•our business strategy, including the continued implementation of our 4-mile well program;

•the geographic concentration of our operations;

•estimated future net reserves and present value thereof;

•timing and amount of future production of crude oil, NGL and natural gas;

•drilling and completion of wells;

•estimated inventory of wells remaining to be drilled and completed;

•costs of exploiting and developing our properties and conducting other operations;

•availability of drilling, completion and production equipment and materials;

•availability of qualified personnel;

•infrastructure for produced and flowback water gathering and disposal;

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•gathering, transportation and marketing of crude oil, NGL and natural gas in the Williston Basin and other regions in the United States;

•the possible shutdown of the Dakota Access Pipeline;

•our ability to realize the anticipated benefits from acquisitions;

•property acquisitions and divestitures;

•integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness;

•the amount, nature and timing of capital expenditures;

•availability and terms of capital;

•our financial strategic tactics, budget, projections, execution of business plan and operating results;

•cash flows and liquidity;

•our ability to pursue goals regarding capital management activities such as share repurchases, paying dividends on our common stock or additional means to return capital to shareholders;

•our ability to utilize net operating loss carryforwards or other tax attributes in future periods;

•our ability to comply with the covenants under our Credit Facility and other indebtedness;

•operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•interruptions in service and fluctuations in tariff provisions of third-party connecting pipelines;

•potential disruptions arising from cybersecurity threats, terrorist attacks and any consequential or other hostilities;

•compliance with, and changes in, environmental, safety and other laws and regulations;

•execution of our sustainability initiatives;

•effectiveness of risk management activities;

•competition in the oil and gas industry;

•counterparty credit risk;

•incurring environmental liabilities;

•developments in the global economy and resulting demand and supply for crude oil, NGL and natural gas;

•governmental regulation, including, but not limited to, that of the Federal Energy Regulatory Commission (“FERC”), and the taxation of the oil and gas industry;

•developments in crude oil-producing and natural gas-producing countries;

•integration of emerging technologies, including artificial intelligence and machine learning technologies for improving operational efficiency;

•consumer demand and preferences for, and governmental policies encouraging, fossil fuel alternatives;

•the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;

•uncertainty regarding future operating results;

•our ability to successfully forecast future operating results and manage activity levels with ongoing macroeconomic uncertainty;

•the impact of disruptions in the financial markets, including bank failures and the volatile interest rate environment;

•plans, objectives, expectations and intentions contained in this Quarterly Report on Form 10-Q that are not historical; and

•certain factors discussed elsewhere in this Quarterly Report on Form 10-Q, in our 2025 Annual Report and in our other filings with the SEC.

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In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise. You should not place undue reliance on these forward-looking statements. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Overview

Chord Energy Corporation, a Delaware corporation (together with its consolidated subsidiaries, the “Company,” “Chord,” “we,” “us,” or “our”), is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, NGL and natural gas primarily in the Williston Basin with limited non-operated interests in the Marcellus Shale. Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a fun and rewarding environment for our employees. We are ideally positioned to generate strong free cash flow and enhance return of capital, while being responsible stewards of the communities and environment where we operate.

Market Conditions and Commodity Prices

Our revenue, profitability and ability to return cash to shareholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Energy markets experienced significant volatility during the first half of 2026, driven primarily by the escalation of conflict in the Middle East beginning in late February and the resulting disruptions to global oil and natural gas supply following the effective closure of the Strait of Hormuz to most commercial shipping. Continued geopolitical tensions, including the uncertain pace and durability of any diplomatic resolution between the United States and Iran and periodic actual and potential escalations in hostilities, uncertainty around OPEC+ production policy, including the withdrawal of the United Arab Emirates from OPEC+ effective in May 2026 and the withdrawal’s potential to reduce the group’s ability to coordinate global supply, and the potential economic outcomes of tariff and trade policy decisions of the U.S. or other governments create difficulty in predicting future impacts to commodity prices, which could affect our financial position, results of operations, cash flows, capital and operating costs, and the quantities of crude oil, NGL and natural gas reserves that may be economically produced.

In an effort to improve price realizations from the sale of our crude oil, NGL and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGL and natural gas to a broader array of potential purchasers. We enter into crude oil, NGL and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single customer would have a material adverse effect on our results of operations or cash flows.

Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of June 30, 2026, substantially all of our gross operated crude oil and natural gas production were connected to gathering systems. Our market optionality on these crude oil gathering systems allows us to shift volumes between pipeline and, to a lesser extent, rail markets in order to optimize price realizations. Expansions of both pipeline and rail facilities in the Williston Basin have reduced prior constraints on crude oil takeaway capacity and improved our price differentials received at the lease.

In an effort to reduce inflationary pressures that emerged in the broader economy, central banks have in the past raised interest rates. During the first half of 2026, higher energy and commodity prices contributed to a renewed rise in U.S. inflation, and the U.S. Federal Reserve held its benchmark interest rate steady. Higher interest rates generally reduce economic activity levels, which have and could in the future again result in lower commodity prices due to reduced demand for crude oil, NGL and natural gas. To the extent we and our relevant markets experience high inflation, we may see cost increases in our operations, including increases in equipment and labor costs, and as a result our revenues, estimates of future reserves, borrowing base calculations and impairment assessments could be negatively impacted.

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Results of Operations

Operational and Financial Highlights

•Production volumes averaged 286,447 Boepd (58% oil), including average daily crude oil volumes of 165,436 Bopd in the second quarter of 2026.

•Capital expenditures (excluding capitalized interest) were $416.7 million in the second quarter of 2026.

•Lease operating expenses (“LOE”) were $10.28 per Boe in the second quarter of 2026.

•Net cash provided by operating activities was $1,116.2 million and net income was $525.2 million for the second quarter of 2026.

Shareholder Return Highlights

•Paid $1.30 per share base cash dividend on June 5, 2026.

•Repurchased $147.4 million of common stock (excluding accrued excise taxes) in the second quarter of 2026.

•Declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on September 4, 2026 to shareholders of record as of August 20, 2026.

Net Income (Loss)

We had net income of $525.2 million and $633.8 million for the three and six months ended June 30, 2026, respectively, primarily due to increased realized oil prices and production volumes and net impacts from derivative instruments, compared to net losses of $389.9 million and $170.1 million for the three and six months ended June 30, 2025, respectively, primarily due to a non-cash impairment charge on our goodwill recorded during the second quarter of 2025. Additional impacts on net income from increases and decreases in certain revenues and expenses are further explained below.

Revenues

Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold and/or changes in commodity prices. Our purchased oil and gas sales are derived from the sale of crude oil and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending to meet pipeline specifications or to cover production shortfalls. Revenues and expenses from crude oil and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the counterparty. In certain cases, we enter into related purchases and sales with one or more counterparties in contemplation of one another, and these transactions are recorded on a net basis.

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The following table summarizes our revenues, production and average realized prices for the periods presented:


	Three Months Ended June 30, 2026		Three Months Ended March 31, 2026		Six Months Ended June 30, 2026		Six Months Ended June 30, 2025
Revenues (in thousands)
Crude oil revenues	$	1,414,957	$	996,296	$	2,411,253	$	1,835,064
NGL revenues	44,596		38,222		82,818		89,914
Natural gas revenues	34,731		116,071		150,802		128,712
Purchased oil and gas sales	678,401		515,046		1,193,447		341,916

Total revenues	$	2,172,685	$	1,665,635	$	3,838,320	$	2,395,606
Production data
Crude oil (MBbls)	15,055		14,222		29,277		28,098
NGL (MBbls)	4,823		4,413		9,236		9,251
Natural gas (MMcf)(1)	37,129		37,023		74,152		76,063
Oil equivalents (MBoe)	26,067		24,805		50,872		50,026
Average daily production (Boepd)	286,447		275,615		281,061		276,387
Average daily crude oil production (Bopd)	165,436		158,027		161,752		155,235
Average sales prices
Crude oil (per Bbl)
Average sales price	$	93.99	$	70.05	$	82.36	$	65.31
Effect of derivative settlements(2)	(7.05)		(0.48)		(3.86)		0.47
Average realized price after the effect of derivative settlements(2)	$	86.94	$	69.57	$	78.50	$	65.78
NGL (per Bbl)
Average sales price	$	9.25	$	8.66	$	8.97	$	9.72
Effect of derivative settlements(2)	—		—		—		—
Average realized price after the effect of derivative settlements(2)	$	9.25	$	8.66	$	8.97	$	9.72
Natural gas (per Mcf)
Average sales price(1)	$	0.94	$	3.14	$	2.03	$	1.69
Effect of derivative settlements(2)	0.35		(0.32)		0.02		0.01
Average realized price after the effect of derivative settlements(1)(2)	$	1.29	$	2.82	$	2.05	$	1.70

____________________

(1)For the three months ended June 30, 2026 and March 31, 2026, natural gas production volume from the Marcellus Shale was 10,637 MMcf and 11,745 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $2.10 per Mcf and $6.40 per Mcf for the three months ended June 30, 2026 and March 31, 2026, respectively. For the six months ended June 30, 2026 and June 30, 2025, natural gas production volume from the Marcellus Shale was 22,382 MMcf and 23,384 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $4.36 per Mcf and $3.59 per Mcf for the six months ended June 30, 2026 and June 30, 2025, respectively.

(2)The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending in the periods presented. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.

Three months ended June 30, 2026 as compared to three months ended March 31, 2026

Crude oil revenues. Our crude oil revenues increased $418.7 million to $1,415.0 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The increase was primarily due to higher crude oil average realized prices quarter over quarter resulting in a $340.4 million increase, coupled with an increase of $78.3 million due to higher crude oil production volumes sold quarter over quarter. Average crude oil sales prices, without derivative settlements, increased by $23.94 per barrel quarter over quarter to an average of $93.99 per barrel for the three months ended June 30, 2026 primarily due to an increase in the average NYMEX WTI quarter over quarter.

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NGL revenues. Our NGL revenues increased $6.4 million to $44.6 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The increase was primarily due to higher NGL production volumes sold quarter over quarter resulting in a $3.8 million increase, coupled with an increase of $2.6 million due to higher average realized NGL prices quarter over quarter. Average NGL sales prices, without derivative settlements, increased by $0.59 per barrel quarter over quarter to an average of $9.25 per barrel for the three months ended June 30, 2026 primarily due to increases in the corresponding NGL product index prices for butane, pentane and propane.

Natural gas revenues. Our natural gas revenues decreased $81.3 million to $34.7 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The decrease was primarily due to lower natural gas average realized prices quarter over quarter resulting in an $81.4 million decrease quarter over quarter. Average natural gas sales prices, without derivative settlements, decreased by $2.20 per Mcf quarter over quarter to $0.94 per Mcf for the three months ended June 30, 2026 primarily due to the seasonality of warmer weather resulting in lower index prices quarter over quarter.

Purchased oil and gas sales. Purchased oil and gas sales increased $163.4 million to $678.4 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. This increase was primarily due to higher crude oil prices quarter over quarter, partially offset by a decrease in the volume of crude oil purchased and subsequently sold quarter over quarter.

Six months ended June 30, 2026 as compared to six months ended June 30, 2025

Crude oil revenues. Our crude oil revenues increased $576.2 million to $2,411.3 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase was primarily due to higher crude oil average realized prices period over period resulting in a $479.1 million increase, coupled with an increase of $97.1 million due to higher crude oil production volumes sold period over period. Average crude oil sales prices, without derivative settlements, increased by $17.05 per barrel period over period to an average of $82.36 per barrel for the six months ended June 30, 2026 primarily due to an increase in the average NYMEX WTI period over period.

NGL revenues. Our NGL revenues decreased $7.1 million to $82.8 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The decrease was primarily due to lower average realized NGL prices period over period resulting in a $7.0 million decrease period over period. Average NGL sales prices, without derivative settlements, decreased by $0.75 per barrel period over period to an average of $8.97 per barrel for the six months ended June 30, 2026 primarily due to decreases in the corresponding NGL product index prices.

Natural gas revenues. Our natural gas revenues increased $22.1 million to $150.8 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase was primarily due to higher natural gas average realized prices period over period resulting in a $26.0 million increase, partially offset by a decrease of $3.9 million due to lower natural gas production volumes sold period over period. Average natural gas sales prices, without derivative settlements, increased by $0.34 per Mcf period over period to $2.03 per Mcf for the six months ended June 30, 2026 primarily due to increases in the corresponding natural gas index prices period over period.

Purchased oil and gas sales. Purchased oil and gas sales increased $851.5 million to $1,193.4 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold period over period, coupled with increased crude oil prices over the same period.

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Expenses and other income (expense)

The following table summarizes our operating expenses and other income (expense) for the periods presented:


	Three Months Ended June 30, 2026		Three Months Ended March 31, 2026		Six Months Ended June 30, 2026		Six Months Ended June 30, 2025

	(In thousands, except per Boe of production data)
Operating expenses
Lease operating expenses	$	267,839	$	244,909	$	512,748	$	490,040
Gathering, processing and transportation expenses	62,765		67,018		129,783		147,415
Purchased oil and gas expenses	671,661		509,832		1,181,493		343,113
Production taxes	125,878		86,711		212,589		143,607
Depreciation, depletion and amortization	409,237		384,215		793,452		726,806
General and administrative expenses	29,894		37,508		67,402		70,917
Impairment and exploration	2,687		2,563		5,250		543,923

Total operating expenses	1,569,961		1,332,756		2,902,717		2,465,821
Gain (loss) on sale of assets, net	(4)		343		339		4,993
Operating income (loss)	602,720		333,222		935,942		(65,222)
Other income (expense)
Net gain (loss) on derivative instruments	107,866		(241,471)		(133,605)		61,950
Net gain (loss) from investment in equity securities	1,143		22,829		23,972		(5,862)
Interest expense, net of capitalized interest	(26,663)		(26,596)		(53,259)		(34,606)
Loss on debt extinguishment	—		—		—		(3,494)
Other income, net	2,186		6,329		8,515		4,546
Total other income (expense), net	84,532		(238,909)		(154,377)		22,534
Income (loss) before income taxes	687,252		94,313		781,565		(42,688)
Income tax benefit (expense)	(162,066)		14,295		(147,771)		(127,380)
Net income (loss)	$	525,186	$	108,608	$	633,794	$	(170,068)


Costs and expenses (per Boe of production)
Lease operating expenses	$	10.28	$	9.87	$	10.08	$	9.80
Gathering, processing and transportation expenses	2.41		2.70		2.55		2.95
Production taxes	4.83		3.50		4.18		2.87

Three months ended June 30, 2026 as compared to three months ended March 31, 2026

Lease operating expenses. LOE increased $22.9 million to $267.8 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The increase was primarily due to higher variable costs of $10.0 million, higher fixed costs of $9.6 million and higher workover costs of $6.6 million, partially offset by a decrease in operating costs from our non-operated assets of $3.3 million quarter over quarter. The same factors contributed to an increase in LOE per Boe, which increased $0.41 per Boe quarter over quarter to $10.28 per Boe for the three months ended June 30, 2026.

Gathering, processing and transportation expenses. GPT expenses decreased $4.3 million to $62.8 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The decrease was primarily due to an $8.8 million change in the non-cash valuation adjustment on our cumulative pipeline imbalance position, partially offset by an increase in crude oil production volumes transported of $3.1 million and a net increase in natural gas and NGL gathering, processing and transportation fees of $1.4 million quarter over quarter. Excluding the non-cash valuation adjustment, GPT expenses increased $0.04 per Boe quarter over quarter to $2.83 per Boe for the three months ended June 30, 2026 primarily due to higher natural gas and NGL gathering, processing and transportation fees.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $161.8 million to $671.7 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. This increase was primarily due to higher crude oil prices quarter over quarter, partially offset by a decrease in the volume of crude oil purchased and subsequently sold quarter over quarter.

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Production taxes. Production taxes increased $39.2 million to $125.9 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026 primarily due to higher crude oil revenues quarter over quarter. The production tax rate as a percentage of crude oil, NGL and natural gas revenues of 8.4% for the three months ended June 30, 2026 increased from 7.5% for the three months ended March 31, 2026 primarily due to higher crude oil revenues quarter over quarter coupled with natural gas comprising a smaller percentage of total sales relative to the prior period.

Depreciation, depletion and amortization. DD&A expense increased $25.0 million to $409.2 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The increase was primarily driven by higher production volumes of $21.2 million, coupled with an increase in accretion expense of $3.8 million related to plugging and abandonment charges.

General and administrative expenses. G&A expenses decreased $7.6 million to $29.9 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The decrease was primarily attributable to a decrease in equity-based compensation expenses of $3.7 million due to the impact of our stock price on the fair value of our liability-based awards, coupled with a decrease of $2.5 million due to lower current expected credit losses and various cost decreases related to other G&A expenses of $1.4 million quarter over quarter.

Derivative instruments. We recorded a $107.9 million net gain on derivative instruments for the three months ended June 30, 2026, which included an unrealized gain of $201.0 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, partially offset by a realized loss on settled commodity derivative contracts of $93.1 million. During the three months ended March 31, 2026, we recorded a $241.5 million net loss on derivative instruments, which included an unrealized loss of $223.0 million related to the change in fair value of our commodity derivative contracts primarily driven by an upward shift in the futures curve for forecasted commodity prices, coupled with a realized loss on settled commodity derivative contracts of $18.5 million.

Investment in equity securities. We recorded a $1.1 million net gain related to our investment in Energy Transfer LP (“Energy Transfer”) for the three months ended June 30, 2026, which included a gain of $2.4 million for a cash distribution from Energy Transfer during the quarter, partially offset by an unrealized loss of $1.3 million as a result of a decrease in the fair value of the investment during the quarter. During the three months ended March 31, 2026, we recorded a $22.8 million net gain related to our investment in Energy Transfer, which included an unrealized gain of $20.4 million as a result of an increase in the fair value of the investment during the quarter, coupled with a gain of $2.4 million for a cash distribution from Energy Transfer during the quarter.

Income tax benefit (expense). Our effective tax rate was recorded at 23.6% and (15.2)% of pre-tax income for the three months ended June 30, 2026 and March 31, 2026, respectively. The effective tax rate for the three months ended June 30, 2026 was higher than the statutory federal rate of 21% primarily as a result of state income taxes. The effective tax rate for the three months ended March 31, 2026 was lower than the statutory federal rate of 21% primarily as a result of the identification of an error in the tax provision for the three and six months ended June 30, 2025 pertaining to the impact of goodwill impairment on our deferred taxes on unremitted earnings, which resulted in an additional income tax benefit of $41.8 million in the first quarter of 2026, with a corresponding decrease to deferred tax liabilities.

Six months ended June 30, 2026 as compared to six months ended June 30, 2025

Lease operating expenses. LOE increased $22.7 million to $512.7 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase was primarily due to increased activity and operating costs from our non-operated assets of $25.7 million, coupled with higher variable costs of $4.7 million, partially offset by lower fixed costs of $7.5 million. The same factors contributed to an increase in LOE per Boe, which increased $0.28 per Boe period over period to $10.08 per Boe for the six months ended June 30, 2026.

Gathering, processing and transportation expenses. GPT expenses decreased $17.6 million to $129.8 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The decrease was primarily due to a $15.1 million change in the non-cash valuation adjustment on our cumulative pipeline imbalance position, coupled with lower natural gas and NGL gathering, processing and transportation fees of $7.4 million period over period, partially offset by an increase in crude oil production volumes transported of $4.3 million period over period. Excluding the non-cash valuation adjustment, GPT expenses decreased $0.10 per Boe period over period to $2.81 per Boe for the six months ended June 30, 2026 primarily due to lower natural gas and NGL gathering, processing and transportation fees.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $838.4 million to $1,181.5 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold period over period, coupled with increased crude oil prices over the same period.

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Production taxes. Production taxes increased $69.0 million to $212.6 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase was primarily due to higher crude oil revenues period over period, coupled with a $19.4 million decrease in refunds period over period related to certain North Dakota wells receiving an extraction tax exemption. The production tax rate as a percentage of crude oil, NGL and natural gas revenues increased from 7.0% for the six months ended June 30, 2025 to 8.0% for the six months ended June 30, 2026 primarily due to increased crude oil revenues and fewer wells qualifying for the extraction tax exemption relative to the prior period.

Depreciation, depletion and amortization. DD&A expense increased $66.6 million to $793.5 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase was primarily driven by $51.3 million of additional depletion expense due to a higher depletion rate period over period, coupled with increased production volumes of $17.7 million period over period, partially offset by a decrease in accretion expense of $1.9 million. The depletion rate increased $1.11 per Boe period over period to $15.24 per Boe for the six months ended June 30, 2026 primarily due to a decrease in proved developed reserves period over period.

General and administrative expenses. G&A expenses decreased $3.5 million to $67.4 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The decrease was primarily attributable to merger-related costs of $8.1 million incurred during 2025 related to the arrangement agreement we entered into to acquire Enerplus Corporation during 2024, coupled with a decrease of $3.9 million primarily attributable to various cost savings related to other G&A expenses, partially offset by an increase of $5.8 million in equity-based compensation costs and higher current expected credit losses of $2.7 million period over period.

Impairment and exploration. There were no significant impairment charges during the six months ended June 30, 2026. As a result of a decrease in the price of our common stock during the six months ended June 30, 2025, which was impacted by a decline in crude oil and natural gas prices over that same period, we recorded an impairment charge on our goodwill of $539.3 million for the six months ended June 30, 2025.

Gain (loss) on sale of assets, net. During the six months ended June 30, 2025, we recorded a net gain on sale of assets of $5.0 million, primarily related to the divestiture of certain non-core oil and gas properties.

Derivative instruments. During the six months ended June 30, 2026, we recorded a $133.6 million net loss on derivative instruments, which included a realized loss of $111.6 million on settled commodity derivative contracts, coupled with an unrealized loss of $22.0 million related to the change in fair value of our commodity derivative contracts primarily driven by an upward shift in the futures curve for forecasted oil commodity prices. During the six months ended June 30, 2025, we recorded a $62.0 million net gain on derivative instruments, which was comprised of a net gain of $61.0 million associated with our commodity derivative contracts and an unrealized gain of $0.9 million associated with a contract that includes contingent consideration. The net gain of $61.0 million on commodity derivative contracts included an unrealized gain of $47.2 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices and a realized gain of $13.8 million on settled commodity derivative contracts.

Investment in equity securities. We recorded a $24.0 million gain related to our investment in Energy Transfer for the six months ended June 30, 2026, which included an unrealized gain of $19.1 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $4.9 million for a cash distribution from Energy Transfer during the period. For the six months ended June 30, 2025, we recorded a net loss of $5.9 million related to our investment in Energy Transfer, which included an unrealized loss of $10.6 million as a result of a decrease in the fair value of the investment during the period, partially offset by a gain of $4.7 million for a cash distribution from Energy Transfer during the period.

Interest expense, net of capitalized interest. Interest expense increased $18.7 million to $53.3 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The increase is primarily due to additional interest expense period over period on our senior unsecured notes of $35.0 million as a result of the issuance of the 2033 Senior Notes (defined below) and the 2030 Senior Notes (defined below) during 2025. This increase was partially offset by an $8.6 million decrease in interest expense on the Credit Facility (defined below) period over period and a $7.7 million decrease resulting from the repayment of the 2026 Senior Notes (defined below) during March 2025. For the six months ended June 30, 2026, the weighted average borrowings outstanding under the Credit Facility were $2.2 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.50%. During the six months ended June 30, 2025, the weighted average borrowings outstanding under the Credit Facility were $310.3 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.47%.

Loss on debt extinguishment. On March 13, 2025, we paid an aggregate of $409.1 million to purchase and satisfy and discharge $400.0 million of 6.375% senior unsecured notes outstanding due June 1, 2026 (the “2026 Senior Notes”), resulting in a loss on debt extinguishment of $3.5 million for the six months ended June 30, 2025. The loss primarily included the write-off of unamortized debt issuance costs of $2.1 million and a premium paid to redeem a portion of the 2026 Senior Notes of $1.1 million.

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Income tax benefit (expense). Our effective tax rate was recorded at 18.9% of pre-tax income and (298.4)% of pre-tax loss for the six months ended June 30, 2026 and 2025, respectively. Our effective tax rate for the six months ended June 30, 2026 was lower than the statutory federal rate of 21% primarily as a result of the identification of an error in the tax provision for the three and six months ended June 30, 2025 pertaining to the impact of goodwill impairment on our deferred taxes on unremitted earnings. As a result, we recognized an additional income tax benefit of $41.8 million during the six months ended June 30, 2026, with a corresponding decrease to deferred tax liabilities. The effective tax rate for the six months ended June 30, 2025 was lower than the statutory federal rate of 21% primarily as a result of the impact of the goodwill impairment charge recorded during the same period.

Liquidity and Capital Resources

As of June 30, 2026, we had $2,581.2 million of liquidity available, including $1,969.6 million of aggregate unused borrowing capacity available under the Credit Facility (defined below) and $611.6 million in cash and cash equivalents. During the six months ended June 30, 2026, our primary sources of liquidity were from cash flows from operations, available borrowing capacity under the Credit Facility, and cash on hand. During the same period, our primary liquidity requirements were capital expenditures for the development of oil and gas properties, dividend payments, share repurchases, and working capital requirements.

Our cash flows depend on many factors, including the price of crude oil, NGL and natural gas and the success of our development and exploration activities as well as future acquisitions. Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, obligations associated with outstanding commodity derivative contracts that settle in a loss position and obligations associated with our leases. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to stockholders through dividend payouts, supplemented by opportunistic share repurchases. On a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

Capital availability is affected by prevailing conditions in our industry, the global economy, the global banking and financial markets, stakeholder scrutiny of sustainability matters and other factors, many of which are beyond our control. The uncertain path of future interest rates creates additional economic uncertainty. During the first half of 2026, higher energy and commodity prices contributed to a renewed rise in U.S. inflation, and the U.S. Federal Reserve held its benchmark interest rate steady. Although we are unable to predict future interest rates, any resulting disruption to the broader economy and financial markets may reduce our ability to access capital or result in such capital being available on less favorable terms, which could in the future negatively affect our liquidity. We believe, however, we have adequate liquidity to fund our capital expenditures and meet our contractual obligations during the next 12 months and the foreseeable future.

Commodity derivative contracts. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the impact of changes in crude oil, NGL and natural gas prices on our production, which mitigates our exposure to crude oil, NGL and natural gas price declines; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices. See Note 6—Derivative Instruments and “Item 3. Quantitative and Qualitative Disclosures about Market Risk” for additional information.

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Commitments. We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGL, natural gas and water within specified time frames, the majority of which are five years or less. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. The estimable future commitments under these agreements were $553.3 million as of June 30, 2026. We believe that for the substantial majority of these agreements our future production will be adequate to meet our delivery commitments or that we will be able to purchase sufficient volumes of crude oil, NGL and natural gas from third parties to satisfy our minimum volume commitments. See “Item 1. Financial Statements (Unaudited)—Note 16—Commitments and Contingencies” and “Item 8. Financial Statements and Supplementary Data—Note 20—Commitments and Contingencies” in our 2025 Annual Report for additional information on our volume delivery commitments.

Long-term debt

Our long-term debt consists of a senior secured revolving line of credit that is generally used to support our working capital requirements, $750.0 million of 6.000% senior unsecured notes and $750.0 million of 6.750% senior unsecured notes.

Senior secured revolving line of credit. As of June 30, 2026, we had a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $2.75 billion and an aggregate amount of elected commitments of $2.0 billion that is due November 3, 2029. We had no net borrowings outstanding and $30.4 million of outstanding letters of credit, resulting in an unused borrowing base capacity of $1,969.6 million as of June 30, 2026. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. The semi-annual redetermination of our borrowing base was completed in May 2026, which reaffirmed the borrowing base and the aggregate elected commitment at $2.75 billion and $2.0 billion, respectively. The next redetermination is scheduled for October 2026.

For the six months ended June 30, 2026, the weighted average interest rate incurred on borrowings under the Credit Facility was 7.50% compared to 6.47% for the six months ended June 30, 2025.

We were in compliance with the financial covenants in the Credit Facility at June 30, 2026. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information.

Senior unsecured notes. As of June 30, 2026, we had $750.0 million of 6.000% senior unsecured notes (the “2030 Senior Notes”) that mature on October 1, 2030 and $750.0 million of 6.750% senior unsecured notes (the “2033 Senior Notes”) that mature on March 15, 2033. Interest on the 2030 Senior Notes is payable semi-annually on April 1 and October 1 of each year, and interest on the 2033 Senior Notes is payable semi-annually on March 15 and September 15 of each year. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information.

Cash Flows

Our cash flows for the six months ended June 30, 2026 and 2025 are presented below:


	Six Months Ended June 30,
	2026		2025

	(In thousands)
Net cash provided by operating activities	$	1,623,621	$	1,076,703
Net cash used in investing activities	(830,575)		(677,782)
Net cash used in financing activities	(371,009)		(395,384)
Increase in cash and cash equivalents	$	422,037	$	3,537

Cash flows provided by operating activities

Our net cash flows provided by operating activities are primarily impacted by commodity prices, production volumes and operating costs. Net cash provided by operating activities was $1,623.6 million for the six months ended June 30, 2026. The increase in net cash provided by operating activities of $546.9 million as compared to the six months ended June 30, 2025 was primarily due to an increase in crude oil and natural gas revenues primarily due to higher crude oil and natural gas average realized prices and working capital changes, partially offset by increases in our production taxes and LOE. See “Results of Operations” above for additional information.

Working Capital. Our working capital is primarily impacted by the factors discussed above, coupled with the timing of cash receipts and disbursements. Changes in working capital (as reflected in the Condensed Consolidated Statements of Cash Flows) increased net cash flows from operating activities by $59.1 million during the six months ended June 30, 2026 and decreased net cash flows from operating activities by $12.5 million during the six months ended June 30, 2025. Changes in working capital associated with our capital expenditure activities and settlements of outstanding commodity derivative instruments impact our cash flows from investing activities.

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The Credit Facility includes a requirement that we maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. For purposes of the Current Ratio, the Credit Facility’s definition of total current assets includes unused commitments under the Credit Facility, which were $1,969.6 million at June 30, 2026, and excludes current hedge assets, which were $49.6 million at June 30, 2026. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, of which there were $16.1 million at June 30, 2026.

Cash flows used in investing activities

For the six months ended June 30, 2026, net cash used in investing activities of $830.6 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $755.5 million, settlement of derivative contracts of $88.8 million and acquisitions and leasehold costs of $8.7 million, partially offset by the receipt of the 2025 contingent consideration earn-out payment of $25.0 million. For the six months ended June 30, 2025, net cash used in investing activities of $677.8 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $704.4 million and $26.2 million paid primarily for acreage in the Williston Basin, partially offset by the receipt of the 2024 contingent consideration earn-out payment of $25.0 million and the settlement of derivative contracts of $14.1 million.

Cash flows used in financing activities

For the six months ended June 30, 2026, the net cash used in financing activities of $371.0 million was primarily attributable to payments to repurchase our common stock of $217.7 million, dividends paid to shareholders of $147.7 million, repayments under the Credit Facility of $85.0 million, offset by borrowings under the Credit Facility of $85.0 million. For the six months ended June 30, 2025, net cash used in financing activities of $395.4 million was primarily attributable to the repayments of the 2026 Senior Notes totaling $401.4 million, payments to repurchase our common stock of $274.0 million, dividends paid to shareholders of $168.8 million, payments for income tax withholdings on vested equity-based compensation awards of $21.8 million, payment of debt issuance costs of $13.4 million made primarily in connection with the issuance of the 2033 Senior Notes and repayments under the Credit Facility of $2,700.0 million, partially offset by borrowings under the Credit Facility of $2,435.0 million, resulting in net repayments under the Credit Facility of $265.0 million. These uses of cash were partially offset by proceeds from the issuance of the 2033 Senior Notes of $750.0 million.

Capital Expenditures

Our capital expenditures are summarized in the following table for the periods presented:


	Three Months Ended				Six Months Ended
	March 31, 2026		June 30, 2026			June 30, 2026
	(In thousands)
E&P(1)	$	330,571	$	402,316		$	732,887
Midstream	14,203		14,241			28,444
Other(2)	113		191			304


Capitalized interest	933		899			1,832


Total capital expenditures(3)	$	345,820	$	417,647		$	763,467

__________________

(1)E&P capital expenditures include approximately $0.7 million and $3.7 million of non-operated capital expenditures related to certain non-operated divested assets that were reimbursable for the three and six months ended June 30, 2026, respectively.

(2)Other capital expenditures include items such as corporate and administrative capital.

(3)Total capital expenditures reflected in the table above differ from the amounts for capital expenditures shown in the statements of cash flows in our condensed consolidated financial statements because amounts reflected in the table above include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis.

Acquisitions

Acquisitions and leasehold costs were $3.7 million and $8.7 million for the three and six months ended June 30, 2026, respectively.

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Dividends

On August 5, 2026, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on September 4, 2026 to shareholders of record as of August 20, 2026. See “Item 1. Financial Statements (Unaudited)—Note 14—Stockholders’ Equity” for additional information.

See “Part I. Item 1.—Business—Business Strategy” in our 2025 Annual Report for additional information regarding our strategy on future dividend payments. Future dividend payments will depend on the Company’s earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that the Board of Directors deems relevant.

Share Repurchase Program

During the six months ended June 30, 2026, we repurchased 1,663,410 shares of common stock at a weighted average price of $131.14 per common share for a total cost of $218.1 million under our $1.0 billion share repurchase program authorized by our Board of Directors in August 2025. As of June 30, 2026, there was $734.0 million of capacity remaining under this share repurchase program.

During the six months ended June 30, 2025, we repurchased 2,600,117 shares of common stock under a previous share repurchase program at a weighted average price of $104.41 per common share for a total cost of $271.5 million.

Fair Value of Financial Instruments

See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” for additional information on our derivative instruments and their related fair value measurements. See also “Item 3. Quantitative and Qualitative Disclosures about Market Risk” below.

Critical Accounting Policies and Estimates

There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2025 Annual Report.

Item 3. — Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks, including commodity price risk, interest rate risk, counterparty and customer risk and inflation risk. We address these risks through a program of risk management, including the use of derivative instruments.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in crude oil, NGL and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk derivative instruments were entered into for hedging purposes, rather than for speculative trading. The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2025 Annual Report, as well as with the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

Commodity price exposure risk. We are exposed to market risk as the prices of crude oil, NGL and natural gas fluctuate as a result of a variety of factors, including changes in supply and demand and the macroeconomic environment, all of which are typically beyond our control. The markets for crude oil, NGL and natural gas have been volatile over the last several years, with heightened volatility over the past year, and these prices will likely continue to be volatile in the future. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a portion of our future production. In addition, entering into derivative instruments could limit the benefit we would receive from increases in the prices for crude oil, NGL and natural gas. We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on our unaudited Condensed Consolidated Balance Sheets. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” and “Note 6—Derivative Instruments” for additional information regarding our derivative instruments.

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The fair value of our unrealized crude oil derivative positions at June 30, 2026 was a net asset position of $35.3 million. A 10% increase in crude oil prices would reduce the fair value of this unrealized derivative asset position by approximately $105.5 million, while a 10% decrease in crude oil prices would increase the fair value of this unrealized derivative asset position by approximately $99.3 million. The fair value of our unrealized natural gas derivative positions at June 30, 2026 was a net asset position of $18.9 million. A 10% increase in natural gas prices would reduce the fair value of this unrealized derivative asset position by approximately $13.9 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative asset position by approximately $9.2 million. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Market Conditions and Commodity Prices,” for further discussion on the commodity price environment. See “Item 1. Financial Statements (Unaudited)—Note 6—Derivative Instruments” for additional information regarding our derivative instruments.

Interest rate risk. At June 30, 2026, we had $750.0 million of senior unsecured notes at a fixed interest rate of 6.000% per annum and $750.0 million of senior unsecured notes at a fixed interest rate of 6.750% per annum. At June 30, 2026, we had no borrowings and $30.4 million of outstanding letters of credit issued under the Credit Facility. Borrowings under the Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan, an ABR Loan or a Swingline Loan (each as defined in the Credit Facility). As of June 30, 2026, there were no borrowings outstanding under our Credit Facility; therefore, a 100-basis point increase in interest rates would have no impact on our annual interest expense. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information on the interest incurred on the Credit Facility.

We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the six months ended June 30, 2026, our credit losses on joint interest receivables were $2.5 million. We had no credit losses on joint interest receivables for the three months ended June 30, 2026. We are also subject to credit risk due to the concentration of our crude oil, NGL and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial position and related financial results.

We monitor our exposure to counterparties on crude oil, NGL and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil, NGL and natural gas sales receivables owed to us. Historically, our credit losses on crude oil, NGL and natural gas sales receivables have been immaterial.

In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. All of the counterparties on our derivative instruments currently in place are lenders under the Credit Facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other lenders under the Credit Facility, which also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts.

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Item 4. — Controls and Procedures

Evaluation of disclosure controls and procedures

As required by Rule 13a-15(b) of the Exchange Act, management, under the supervision and with the participation of our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2026. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2026.

Changes in internal control over financial reporting

There were no changes in internal control over financial reporting that occurred during the quarter ended June 30, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. — Legal Proceedings

See “Part I, Item 1. — Financial Statements (Unaudited)—Note 16—Commitments and Contingencies,” which is incorporated herein by reference, for a discussion of material legal proceedings.

Item 1A. — Risk Factors

Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report on Form 10-Q and in our other SEC filings could have a material impact on our business, financial position, results of operations or cash flows. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information in “Part I. Item 1A. Risk Factors” in our 2025 Annual Report. There have been no material changes in our risk factors from those described in our 2025 Annual Report.

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

Unregistered sales of equity securities. There were no sales of unregistered equity securities during the period covered by this report.

Issuer purchases of equity securities. The following table contains information about our acquisition of equity securities during the three months ended June 30, 2026:


Period	Total Number of Shares Exchanged or Purchased(1)(2)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2)	Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs(2)
April 1 – April 30, 2026	—	$	—	—	$	881,431,900
May 1 – May 31, 2026	415,380	140.79		413,768	823,185,145
June 1 – June 30, 2026	690,578	129.09		690,578	734,036,116
Total	1,105,958	$	133.48	1,104,346

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(1)During the second quarter of 2026, we withheld 1,612 shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.

(2)In August 2025, our Board of Directors authorized a new share repurchase program covering up to $1.0 billion of common stock with no expiration date. During the second quarter of 2026, we repurchased 1,104,346 shares of our common stock at a weighted average price of $133.47 per common share for a total cost of $147.4 million, excluding accrued excise tax of $1.4 million, under this share repurchase program.

Item 5. — Other Information

Rule 10b5-1 trading arrangements. During the fiscal quarter ended June 30, 2026, none of our directors or officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

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Item 6. — Exhibits


Exhibit No.						Description of Exhibit



31.1(a)						Sarbanes-Oxley Section 302 certification of Principal Executive Officer.

31.2(a)						Sarbanes-Oxley Section 302 certification of Principal Financial Officer.

32.1(b)						Sarbanes-Oxley Section 906 certification of Principal Executive Officer.

32.2(b)						Sarbanes-Oxley Section 906 certification of Principal Financial Officer.

101.INS(a)						XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH(a)						XBRL Schema Document.

101.CAL(a)						XBRL Calculation Linkbase Document.

101.DEF(a)						XBRL Definition Linkbase Document.

101.LAB(a)						XBRL Label Linkbase Document.

101.PRE(a)						XBRL Presentation Linkbase Document.

104(a)						Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

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(a)Filed herewith.

(b)Furnished herewith.

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SIGNATURES

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