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Table of Contents

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, 2025
or

☐ | 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 |  | 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 ☒
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ý No ¨
Number of shares of the registrant’s common stock outstanding at August 1, 2025: 57,258,101 shares.

Table of Contents
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, 2025 and December 31, 2024 | 4
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2025 and 2024 | 6
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three and Six Months Ended June 30, 2025 and 2024 | 7
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2025 and 2024 | 8
Notes to Condensed Consolidated Financial Statements | 10
1. Organization and Summary of Significant Accounting Policies | 10
2. Revenue Recognition | 11
3. Inventory | 12
4. Additional Balance Sheet Information | 12
5. Fair Value Measurements | 13
6. Derivative Instruments | 15
7. Property, Plant and Equipment | 17
8. Acquisitions | 18
9. Investment in Unconsolidated Affiliate | 20
10. Long-Term Debt | 20
11. Asset Retirement Obligations | 21
12. Income Taxes | 22
13. Equity-Based Compensation | 22
14. Stockholders’ Equity | 23
15. Earnings Per Share | 25
16. Commitments and Contingencies | 25
17. Leases | 25
Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations | 26
Overview and Recent Developments | 29
Results of Operations | 30
Liquidity and Capital Resources | 36
Fair Value of Financial Instruments | 39
Critical Accounting Policies and Estimates | 40
Item 3. — Quantitative and Qualitative Disclosures About Market Risk | 40
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.
“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 natural gas or oil, 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.
“ESG.” Environmental, social and governance.
“FASB.” Financial Accounting Standards Board.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“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.
“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.
“MMBtu.” One million British thermal units.
“MMcf.” One million cubic feet of natural gas.
“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.
“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.
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“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.
“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.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Wellbore.” The hole drilled by the bit that is equipped for crude oil or gas production on a completed well. Also called well or borehole.
“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, 2025 |  | December 31, 2024
| (In thousands, except share data)
ASSETS |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 40,487 |  |  | $ | 36,950 |
Accounts receivable, net | 1,279,056 |  |  | 1,298,973 |
Inventory | 102,031 |  |  | 94,299 |
Prepaid expenses | 17,874 |  |  | 30,875 |
Derivative instruments | 82,069 |  |  | 35,944 |
Other current assets | 2,168 |  |  | 82,077 |
Total current assets | 1,523,685 |  |  | 1,579,118 |
Property, plant and equipment |  |  |
Oil and gas properties (successful efforts method) | 13,602,081 |  |  | 12,770,786 |
Other property and equipment | 59,938 |  |  | 58,158 |
Less: accumulated depreciation, depletion and amortization | (2,851,535) |  |  | (2,142,775) |
Total property, plant and equipment, net | 10,810,484 |  |  | 10,686,169 |
Derivative instruments | 7,962 |  |  | 5,629 |
Investment in unconsolidated affiliate | 131,603 |  |  | 142,201 |
Long-term inventory | 26,403 |  |  | 25,973 |
Operating right-of-use assets | 23,846 |  |  | 38,004 |
Goodwill | — |  |  | 530,616 |
Other assets | 22,613 |  |  | 24,297 |
Total assets | $ | 12,546,596 |  |  | $ | 13,032,007 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |
Current liabilities |  |  |
Accounts payable | $ | 74,043 |  |  | $ | 68,751 |
Revenues and production taxes payable | 681,508 |  |  | 752,742 |
Accrued liabilities | 760,652 |  |  | 732,296 |
Accrued interest payable | 18,586 |  |  | 4,693 |
Derivative instruments | 342 |  |  | 1,230 |
Advances from joint interest partners | 2,715 |  |  | 2,434 |
Current operating lease liabilities | 29,351 |  |  | 37,629 |
Other current liabilities | 9,438 |  |  | 84,203 |
Total current liabilities | 1,576,635 |  |  | 1,683,978 |
Long-term debt | 918,901 |  |  | 842,600 |
Deferred tax liabilities | 1,545,492 |  |  | 1,496,442 |
Asset retirement obligations | 392,742 |  |  | 282,369 |
Derivative instruments | 2,500 |  |  | 1,016 |
Operating lease liabilities | 8,234 |  |  | 15,190 |
Other liabilities | 5,868 |  |  | 8,150 |
Total liabilities | 4,450,372 |  |  | 4,329,745 |

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| June 30, 2025 |  | December 31, 2024
| (In thousands, except share data)
Commitments and contingencies (Note 16) |  |  |
Stockholders’ equity |  |  |
Common stock, $0.01 par value: 240,000,000 shares authorized, 67,146,139 shares issued and 57,649,136 shares outstanding at June 30, 2025; and 240,000,000 shares authorized, 66,967,779 shares issued and 60,070,893 shares outstanding at December 31, 2024 | 675 |  |  | 673 |
Treasury stock, at cost: 9,497,003 shares at June 30, 2025 and 6,896,886 shares at December 31, 2024 | (1,210,171) |  |  | (936,157) |
Additional paid-in capital | 7,327,295 |  |  | 7,336,091 |
Retained earnings | 1,978,425 |  |  | 2,301,655 |
Total stockholders’ equity | 8,096,224 |  |  | 8,702,262 |
Total liabilities and stockholders’ equity | $ | 12,546,596 |  |  | $ | 13,032,007 |

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,
| 2025 |  | 2024 |  | 2025 |  | 2024
| (In thousands, except per share data)
Revenues |  |  |  |  |  |  |
Oil, NGL and gas revenues | $ | 950,266 |  |  | $ | 902,667 |  |  | $ | 2,053,690 |  |  | $ | 1,650,829 |
Purchased oil and gas sales | 230,294 |  |  | 358,013 |  |  | 341,916 |  |  | 695,111 |
Total revenues | 1,180,560 |  |  | 1,260,680 |  |  | 2,395,606 |  |  | 2,345,940 |
Operating expenses |  |  |  |  |  |  |
Lease operating expenses | 256,966 |  |  | 176,647 |  |  | 490,040 |  |  | 335,853 |
Gathering, processing and transportation expenses | 74,100 |  |  | 63,130 |  |  | 147,415 |  |  | 117,114 |
Purchased oil and gas expenses | 231,745 |  |  | 356,356 |  |  | 343,113 |  |  | 692,118 |
Production taxes | 68,965 |  |  | 79,522 |  |  | 143,607 |  |  | 143,433 |
Depreciation, depletion and amortization | 376,997 |  |  | 227,928 |  |  | 726,806 |  |  | 396,822 |
General and administrative expenses | 32,540 |  |  | 82,077 |  |  | 70,917 |  |  | 107,789 |
Impairment and exploration | 541,940 |  |  | 1,485 |  |  | 543,923 |  |  | 7,639 |
Total operating expenses | 1,583,253 |  |  | 987,145 |  |  | 2,465,821 |  |  | 1,800,768 |
Gain (loss) on sale of assets, net | (522) |  |  | 15,486 |  |  | 4,993 |  |  | 16,788 |
Operating income (loss) | (403,215) |  |  | 289,021 |  |  | (65,222) |  |  | 561,960 |
Other income (expense) |  |  |  |  |  |  |
Net gain (loss) on derivative instruments | 82,231 |  |  | 4,608 |  |  | 61,950 |  |  | (22,969) |
Net gain (loss) from investment in unconsolidated affiliate | (962) |  |  | 5,862 |  |  | (5,862) |  |  | 22,158 |
Interest expense, net of capitalized interest | (18,788) |  |  | (12,208) |  |  | (34,606) |  |  | (19,800) |
Loss on debt extinguishment | — |  |  | — |  |  | (3,494) |  |  | — |
Other income | 5,045 |  |  | 4,081 |  |  | 4,546 |  |  | 6,907 |
Total other income (expense), net | 67,526 |  |  | 2,343 |  |  | 22,534 |  |  | (13,704) |
Income (loss) before income taxes | (335,689) |  |  | 291,364 |  |  | (42,688) |  |  | 548,256 |
Income tax expense | (54,216) |  |  | (78,003) |  |  | (127,380) |  |  | (135,541) |
Net income (loss) | $ | (389,905) |  |  | $ | 213,361 |  |  | $ | (170,068) |  |  | $ | 412,715 |
Earnings (loss) per share (Note 15): |  |  |  |  |  |  |
Basic | $ | (6.71) |  |  | $ | 4.36 |  |  | $ | (2.89) |  |  | $ | 9.12 |
Diluted | $ | (6.77) |  |  | $ | 4.25 |  |  | $ | (2.93) |  |  | $ | 8.87 |
Weighted average shares outstanding: |  |  |  |  |  |  |
Basic | 57,786 |  |  | 48,665 |  |  | 58,420 |  |  | 45,048 |
Diluted | 57,786 |  |  | 49,916 |  |  | 58,501 |  |  | 46,313 |

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, 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 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

| Common Stock |  | Treasury Stock |  | Additional Paid-in Capital |  | Retained Earnings |  | Total Stockholders’ Equity
Shares |  | Amount |  | Shares |  | Amount |
| (In thousands)
Balance as of December 31, 2023 | 41,250 |  |  | $ | 456 |  |  | 3,783 |  |  | $ | (493,289) |  |  | $ | 3,608,819 |  |  | $ | 1,960,638 |  |  | $ | 5,076,624 |
Equity-based compensation and vestings | 599 |  |  | 4 |  |  | — |  |  | — |  |  | 4,771 |  |  | — |  |  | 4,775 |
Tax withholdings on settlement of equity-based awards | (280) |  |  | (3) |  |  | — |  |  | — |  |  | (46,048) |  |  | — |  |  | (46,051) |
Dividends | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (137,541) |  |  | (137,541) |
Share repurchases | (193) |  |  | — |  |  | 193 |  |  | (29,999) |  |  | — |  |  | — |  |  | (29,999) |
Warrants exercised | 175 |  |  | 2 |  |  | — |  |  | — |  |  | 8,015 |  |  | — |  |  | 8,017 |
Net income | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 199,353 |  |  | 199,353 |
Balance as of March 31, 2024 | 41,551 |  |  | 459 |  |  | 3,976 |  |  | (523,288) |  |  | 3,575,557 |  |  | 2,022,450 |  |  | 5,075,178 |
Shares issued in Arrangement | 20,680 |  |  | 207 |  |  | — |  |  | — |  |  | 3,731,930 |  |  | — |  |  | 3,732,137 |
Equity-based compensation and vestings | 139 |  |  | 1 |  |  | — |  |  | — |  |  | 5,359 |  |  | — |  |  | 5,360 |
Tax withholdings on settlement of equity-based awards | (61) |  |  | — |  |  | — |  |  | — |  |  | (11,306) |  |  | — |  |  | (11,306) |
Dividends | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (124,708) |  |  | (124,708) |
Share repurchases | (365) |  |  | — |  |  | 365 |  |  | (61,747) |  |  | — |  |  | — |  |  | (61,747) |
Warrants exercised | 287 |  |  | 1 |  |  | — |  |  | — |  |  | 12,874 |  |  | — |  |  | 12,875 |
Net income | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 213,361 |  |  | 213,361 |
Balance as of June 30, 2024 | 62,231 |  |  | $ | 668 |  |  | 4,341 |  |  | $ | (585,035) |  |  | $ | 7,314,414 |  |  | $ | 2,111,103 |  |  | $ | 8,841,150 |

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,
| 2025 |  | 2024
| (In thousands)
Cash flows from operating activities: |  |  |
Net income (loss) | $ | (170,068) |  |  | $ | 412,715 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |  |
Depreciation, depletion and amortization | 726,806 |  |  | 396,822 |
Loss on debt extinguishment | 3,494 |  |  | — |
Gain on sale of assets | (4,993) |  |  | (16,788) |
Impairment | 539,318 |  |  | 3,919 |
Deferred income taxes | 49,050 |  |  | 70,699 |
Net (gain) loss on derivative instruments | (61,950) |  |  | 22,969 |
Net (gain) loss from investment in unconsolidated affiliate | 5,862 |  |  | (22,158) |
Equity-based compensation expenses | 12,997 |  |  | 10,130 |
Deferred financing costs amortization and other | (11,297) |  |  | 7,343 |
Working capital and other changes: |  |  |
Change in accounts receivable, net | 4,479 |  |  | (69,496) |
Change in inventory | (5,738) |  |  | (5,557) |
Change in prepaid expenses | 5,463 |  |  | 17,262 |
Change in accounts payable, interest payable and accrued liabilities | (20,031) |  |  | 3,065 |
Change in other assets and liabilities, net | 3,311 |  |  | 36,649 |
Net cash provided by operating activities | 1,076,703 |  |  | 867,574 |
Cash flows from investing activities: |  |  |
Capital expenditures | (704,388) |  |  | (538,733) |
Acquisitions | (26,191) |  |  | (645,971) |
Proceeds from divestitures | 6,921 |  |  | 20,876 |
Derivative settlements | 14,090 |  |  | (16,339) |
Contingent consideration received | 25,000 |  |  | 25,000 |
Distributions from investment in unconsolidated affiliate | 6,786 |  |  | 4,591 |
Net cash used in investing activities | (677,782) |  |  | (1,150,576) |
Cash flows from financing activities: |  |  |
Proceeds from revolving credit facility | 2,435,000 |  |  | 825,000 |
Principal payments on revolving credit facility | (2,700,000) |  |  | (250,000) |
Repayment and discharge of senior notes | (401,432) |  |  | — |
Issuance of senior notes | 750,000 |  |  | — |
Deferred financing costs | (13,443) |  |  | — |
Repurchases of common stock | (274,014) |  |  | (93,745) |
Tax withholding on vesting of equity-based awards | (21,793) |  |  | (57,357) |
Dividends paid | (168,846) |  |  | (281,681) |
Payments on finance lease liabilities | (856) |  |  | (834) |
Proceeds from warrants exercised | — |  |  | 21,010 |
Net cash provided by (used in) financing activities | (395,384) |  |  | 162,393 |
Increase (decrease) in cash and cash equivalents | 3,537 |  |  | (120,609) |
Cash and cash equivalents: |  |  |
Beginning of period | 36,950 |  |  | 317,998 |
End of period | $ | 40,487 |  |  | $ | 197,389 |

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| Six Months Ended June 30,
| 2025 |  | 2024
| (In thousands)
Supplemental non-cash transactions: |  |  |
Change in accrued capital expenditures | $ | (3,950) |  |  | $ | 24,389 |
Change in asset retirement obligations | 100,632 |  |  | 3,476 |
Non-cash consideration exchanged in Merger | — |  |  | 3,732,137 |
Dividends payable | 973 |  |  | 19,502 |

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. Summary of Significant Accounting Policies
Chord Energy Corporation (together with its consolidated subsidiaries, the “Company” or “Chord”) is an independent exploration and production (“E&P”) company with quality and sustainable long-lived assets primarily located in the Williston Basin.
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, 2024 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, 2024 (“2024 Annual Report”).
Enerplus Arrangement
On February 21, 2024, the Company entered into an arrangement agreement (the “Arrangement Agreement”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), and Spark Acquisition ULC, an unlimited liability company organized and existing under the laws of the Province of Alberta, Canada and a wholly-owned subsidiary of the Company, pursuant to which, among other things, the Company agreed to acquire Enerplus in a stock-and-cash transaction (such transaction, the “Arrangement”). Enerplus was an independent North American oil and gas E&P company domiciled in Canada with substantially all of its producing assets in the Williston Basin of North Dakota, with limited non-operated interests in the Marcellus Shale. The transaction was effected by way of a plan of arrangement under the Business Corporations Act (Alberta). The Arrangement was completed on May 31, 2024.
The Arrangement has been accounted for under the acquisition method of accounting in accordance with the FASB ASC 805, Business Combinations (“ASC 805”). Chord was treated as the acquirer for accounting purposes. Under the acquisition method of accounting, the assets and liabilities of Enerplus have been recorded at their respective fair values as of the acquisition date on May 31, 2024. As provided under ASC 805, the purchase price allocation was subject to change for up to one year after May 31, 2024. As of June 30, 2025, the purchase price allocation was finalized. See Note 8—Acquisitions for additional information.
Risks and Uncertainties
As a producer of crude oil, NGLs and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGLs and natural gas, which are dependent upon numerous factors beyond the Company’s control such as economic, geopolitical, political and regulatory developments and competition from other energy sources. Recent volatility in the energy markets during the second quarter of 2025 has led to a decrease in the price of crude oil as a result of increased production levels by OPEC+, ongoing trade and tariff negotiations between the United States and other governments and retaliatory measures taken by such other governments. Further declines in prices for crude oil and, to a lesser extent, NGLs and natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows, the quantities of crude oil, NGL and natural gas reserves that may be economically produced and the Company’s access to capital. The Company will continue to monitor these developments and evaluate the implications for the recoverability of its oil and gas properties in future interim periods.
As a result of a decrease in the price of the Company’s common stock during the three months ended June 30, 2025, which was impacted by declines in crude oil and natural gas prices over that same period, the Company performed a goodwill impairment test as of June 30, 2025. The impairment test indicated that the fair value of the Company’s reporting unit was less than its carrying value, and that there was no remaining implied fair value attributable to goodwill. Based on these results, the Company recognized a non-cash impairment charge of $539.3 million within impairment and exploration expenses on the Condensed Consolidated Statements of Operations during the three and six months ended June 30, 2025 to reduce the carrying value of goodwill to zero as of June 30, 2025.
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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 2024 Annual Report.
Recent Accounting Pronouncements
In December 2023, the FASB issued ASU 2023-09 “Income Taxes (Topic 740): Improvements to Income Tax Disclosures” (“ASU 2023-09”). This standard expands the disclosure requirements for income taxes, specifically relating to the effective tax rate reconciliation and additional disclosures on income taxes paid. ASU 2023-09 is effective for annual reporting periods beginning January 1, 2025, with early adoption permitted. The Company has adopted this ASU effective for its annual disclosures beginning after January 1, 2025, and plans to apply the amendments retrospectively to all prior periods presented in the annual disclosures of its consolidated financial statements.
In November 2024, the FASB issued ASU No. 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. Early adoption is permitted. The Company is currently evaluating this ASU to determine its impact on the Company’s annual financial statement disclosures.
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,
| 2025 |  | 2024 |  | 2025 |  | 2024
| (In thousands)
Crude oil revenues | $ | 878,928 |  |  | $ | 848,104 |  |  | $ | 1,835,064 |  |  | $ | 1,526,955 |
Purchased crude oil sales | 224,835 |  |  | 346,721 |  |  | 328,706 |  |  | 673,368 |
NGL and natural gas revenues | 71,338 |  |  | 54,563 |  |  | 218,626 |  |  | 123,874 |
Purchased NGL and natural gas sales | 5,459 |  |  | 11,292 |  |  | 13,210 |  |  | 21,743 |
Total revenues | $ | 1,180,560 |  |  | $ | 1,260,680 |  |  | $ | 2,395,606 |  |  | $ | 2,345,940 |

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, 2025 and 2024, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
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3. Inventory
The following table sets forth the Company’s inventory balances for the periods presented:

| June 30, 2025 |  | December 31, 2024
| (In thousands)
Inventory |  |  |
Equipment and materials | $ | 50,597 |  |  | $ | 47,121 |
Crude oil inventory | 51,434 |  |  | 47,178 |
Total inventory | 102,031 |  |  | 94,299 |
Long-term inventory |  |  |
Linefill in third-party pipelines | 26,403 |  |  | 25,973 |
Total long-term inventory | 26,403 |  |  | 25,973 |
Total | $ | 128,434 |  |  | $ | 120,272 |

4. Additional Balance Sheet Information
The following table sets forth certain balance sheet amounts comprised of the following:

| June 30, 2025 |  | December 31, 2024
| (In thousands)
Accounts receivable, net |  |  |
Trade and other accounts | $ | 1,010,342 |  |  | $ | 1,029,343 |
Joint interest accounts | 282,586 |  |  | 283,696 |
Total accounts receivable | 1,292,928 |  |  | 1,313,039 |
Less: allowance for credit losses | (13,872) |  |  | (14,066) |
Total accounts receivable, net | $ | 1,279,056 |  |  | $ | 1,298,973 |
Revenues and production taxes payable |  |  |
Royalties payable and revenue suspense | $ | 632,109 |  |  | $ | 706,674 |
Production taxes payable | 49,399 |  |  | 46,068 |
Total revenue and production taxes payable | $ | 681,508 |  |  | $ | 752,742 |
Accrued liabilities |  |  |
Accrued oil and gas marketing | $ | 296,563 |  |  | $ | 203,899 |
Accrued capital costs | 248,877 |  |  | 252,827 |
Accrued lease operating expenses | 134,202 |  |  | 148,837 |
Accrued general and administrative expenses | 34,787 |  |  | 61,319 |
Current portion of asset retirement obligations | 19,848 |  |  | 26,065 |
Accrued dividends | — |  |  | 16,062 |
Other accrued liabilities | 26,375 |  |  | 23,287 |
Total accrued liabilities | $ | 760,652 |  |  | $ | 732,296 |

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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 and properties acquired in a business combination or upon impairment, 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, 2025
| Level 1 |  | Level 2 |  | Level 3 |  | Total
| (In thousands)
Assets: |  |  |  |  |  |  |
Commodity derivative contracts (see Note 6) | $ | — |  |  | $ | 66,331 |  |  | $ | — |  |  | $ | 66,331 |
Contingent consideration (see Note 6) | — |  |  | 23,700 |  |  | — |  |  | 23,700 |
Investment in unconsolidated affiliate (see Note 9) | 131,603 |  |  | — |  |  | — |  |  | 131,603 |
Total assets | $ | 131,603 |  |  | $ | 90,031 |  |  | $ | — |  |  | $ | 221,634 |
Liabilities: |  |  |  |  |  |  |
Commodity derivative contracts (see Note 6) | $ | — |  |  | $ | 2,842 |  |  | $ | — |  |  | $ | 2,842 |
Total liabilities | $ | — |  |  | $ | 2,842 |  |  | $ | — |  |  | $ | 2,842 |

| Fair value at December 31, 2024
| Level 1 |  | Level 2 |  | Level 3 |  | Total
| (In thousands)
Assets: |  |  |  |  |  |  |
Commodity derivative contracts (see Note 6) | $ | — |  |  | $ | 18,793 |  |  | $ | — |  |  | $ | 18,793 |
Contingent consideration (see Note 6) | — |  |  | 22,780 |  |  | — |  |  | 22,780 |
Investment in unconsolidated affiliate (see Note 9) | 142,201 |  |  | — |  |  | — |  |  | 142,201 |
Total assets | $ | 142,201 |  |  | $ | 41,573 |  |  | $ | — |  |  | $ | 183,774 |
Liabilities: |  |  |  |  |  |  |
Commodity derivative contracts (see Note 6) | $ | — |  |  | $ | 2,246 |  |  | $ | — |  |  | $ | 2,246 |
Total liabilities | $ | — |  |  | $ | 2,246 |  |  | $ | — |  |  | $ | 2,246 |

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 swaps and collars 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 records an adjustment to the fair value of its net derivative assets and liabilities for the counterparty nonperformance risk related to these contracts, and these adjustments were not material for the periods presented. See Note 6—Derivative Instruments for additional information.
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Contingent consideration. In connection with the 2021 divestiture of certain oil and gas properties, the Company is 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 exceeds $60 per barrel for such year (the “Contingent Consideration”). The fair value of the Contingent Consideration is determined by a third-party preparer using a Monte Carlo simulation model and Ornstein-Uhlenbeck pricing process. The significant inputs used are NYMEX WTI forward price curve, volatility, mean reversion rate and counterparty credit risk adjustment. The Company determined these were Level 2 fair value inputs that are substantially observable in active markets or can be derived from observable data. In each of January 2024 and 2025, the Company received $25.0 million related to the 2023 and 2024 earn-out payments, respectively. See Note 6—Derivative Instruments for additional information.
Investment in unconsolidated affiliate. 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, 2025 and December 31, 2024, respectively. See Note 9—Investment in Unconsolidated Affiliate 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.
No impairment expense was recorded on proved oil and gas properties during the three or six months ended June 30, 2025. The Company will continue to evaluate the recoverability of the carrying value of its oil and gas properties as a result of a future material or extended decline in the price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services.
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:
•Enerplus Arrangement. On May 31, 2024, the Company completed the Arrangement with Enerplus. The assets acquired and liabilities assumed were recorded at fair value as of May 31, 2024. In addition, the Company recorded goodwill as a result of the Enerplus Arrangement. Goodwill is subject to an annual impairment evaluation as described in Note 2—Summary of Significant Accounting Policies—Goodwill in the 2024 Annual Report.
See Note 8—Acquisitions for additional information.
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Goodwill Impairment. The Company tests goodwill for impairment annually on October 1 or whenever events or changes in circumstances indicate that the fair value of its reporting unit may have been reduced below its carrying value. The decline in the Company’s market capitalization during the second quarter, which was impacted by a decline in crude oil and natural gas prices, indicated that it was more likely than not that the fair value of the Company’s reporting unit was less than its carrying value, which warranted a goodwill impairment test as of June 30, 2025. The fair value of the Company’s reporting unit was determined using an income approach analysis based on the Company’s net discounted future cash flows. The discounted cash flows are based on management’s expectations for the future and unobservable inputs and assumptions, which include estimates of future oil and gas production from the Company’s reserve report, commodity prices based on sales contract terms or forward pricing assumptions as of the date of the estimate (adjusted for basis differentials), operating and development costs, and a discount rate based on the Company’s weighted-average cost of capital (all of which are designated as Level 3 inputs within the fair value hierarchy). The impairment test performed by the Company indicated that the fair value of its reporting unit was less than its carrying value, and that there was no remaining implied fair value attributable to goodwill. Based on these results, the Company recognized a non-cash impairment charge of $539.3 million within impairment and exploration expenses on the Condensed Consolidated Statements of Operations during the three and six months ended June 30, 2025, to reduce the carrying value of goodwill to zero as of June 30, 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, and its 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 and two-way and three-way collars 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. 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.
At June 30, 2025, 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 |  | 2025 |  | Two-way collar |  |  |  | 3,036,000 |  |  | Bbls |  |  |  |  |  |  |  | $ | 64.55 |  |  | $ | 76.76 |
Crude oil |  | 2025 |  | Three-way collar |  |  |  | 1,104,000 |  |  | Bbls |  |  |  |  |  | $ | 52.50 |  |  | $ | 67.50 |  |  | $ | 81.37 |
Crude oil |  | 2025 |  | Fixed price swaps |  |  |  | 1,840,000 |  |  | Bbls |  | $ | 70.03 |  |  |  |  |  |  |  |  |
Crude oil |  | 2026 |  | Three-way collar |  |  |  | 4,138,000 |  |  | Bbls |  |  |  |  |  | $ | 51.09 |  |  | $ | 65.93 |  |  | $ | 77.61 |
Crude oil |  | 2026 |  | Two-way collar |  |  |  | 1,001,000 |  |  | Bbls |  |  |  |  |  |  |  | $ | 63.65 |  |  | $ | 71.71 |
Crude oil |  | 2026 |  | Fixed price swaps |  |  |  | 1,275,000 |  |  | Bbls |  | $ | 66.56 |  |  |  |  |  |  |  |  |
Crude oil |  | 2027 |  | Three-way collar |  |  |  | 677,500 |  |  | Bbls |  |  |  |  |  | $ | 50.00 |  |  | $ | 61.33 |  |  | $ | 72.92 |
Natural gas |  | 2025 |  | Two-way collar |  |  |  | 4,140,000 |  |  | MMBtu |  |  |  |  |  |  |  | $ | 4.00 |  |  | $ | 4.87 |
Natural gas |  | 2025 |  | Fixed price swaps |  |  |  | 20,700,000 |  |  | MMBtu |  | $ | 3.99 |  |  |  |  |  |  |  |  |
Natural gas |  | 2026 |  | Two-way collar |  |  |  | 12,247,500 |  |  | MMBtu |  |  |  |  |  |  |  | $ | 3.78 |  |  | $ | 4.53 |
Natural gas |  | 2026 |  | Fixed price swaps |  |  |  | 16,432,500 |  |  | MMBtu |  | $ | 3.84 |  |  |  |  |  |  |  |  |
Natural gas |  | 2027 |  | Fixed price swaps |  |  |  | 3,620,000 |  |  | MMBtu |  | $ | 4.02 |  |  |  |  |  |  |  |  |

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Subsequent to June 30, 2025, the Company entered into the following commodity derivative contracts:

|  |  |  |  |  |  |  |  |  | Weighted Average Prices
Commodity |  | Settlement Period |  | Derivative Instrument |  | Volumes |  | Fixed-Price Swaps |  |  |  | Floor |  | Ceiling
Crude oil |  | 2025 |  | Fixed price swaps |  | 368,000 |  |  | Bbls |  | $ | 67.26 |  |  |  |  |  |  |
Crude oil |  | 2026 |  | Two-way collars |  | 69,000 |  |  | Bbls |  |  |  |  |  | $ | 60.00 |  |  | $ | 64.25 |
Crude oil |  | 2026 |  | Fixed-price swaps |  | 273,000 |  |  | Bbls |  | $ | 65.75 |  |  |  |  |  |  |
Crude oil |  | 2027 |  | Two-way collars |  | 546,000 |  |  | Bbls |  |  |  |  |  | $ | 60.00 |  |  | $ | 66.12 |

Transportation derivative contract. The Company had a contract that provided for the transportation of crude oil through a buy/sell structure from North Dakota to Cushing, Oklahoma. The contract required the purchase and sale of fixed volumes of crude oil through July 2024 as specified in the agreement. The Company determined that this contract qualified as a derivative and did not elect the “normal purchase normal sale” exclusion. As of June 30, 2024, the term of this contract expired. The Company recorded the changes in fair value of this contract within GPT expenses on the Company’s Condensed Consolidated Statements of Operations. Settlements on this contract are reflected as operating activities on the Company’s Condensed Consolidated Statements of Cash Flows and represent cash payments to the counterparty for transportation of crude oil or the net settlement of contract liabilities if the transportation was not utilized, as applicable.
Contingent consideration. The Company bifurcated the Contingent Consideration from the host contract and accounted for it separately at fair value. The Contingent Consideration is marked-to-market each reporting period, with changes in fair value recorded in the other income (expense) section of the Company’s Condensed Consolidated Statements of Operations as a net gain or loss on derivative instruments. The estimated fair value of the Contingent Consideration was classified as a current derivative asset of $23.7 million and $22.8 million on the Condensed Consolidated Balance Sheet at June 30, 2025 and December 31, 2024, respectively. See Note 5—Fair Value Measurements for additional information.
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 |  | 2025 |  | 2024 |  | 2025 |  | 2024
|  |  |  | (In thousands)
Commodity derivatives |  | Net gain (loss) on derivative instruments |  | $ | 81,991 |  |  | $ | 3,954 |  |  | $ | 61,030 |  |  | $ | (26,997) |
Commodity derivatives (buy/sell transportation contract) |  | Gathering, processing and transportation expenses(1) |  | — |  |  | (2,647) |  |  | — |  |  | (5,877) |
Contingent consideration |  | Net gain (loss) on derivative instruments(2) |  | 240 |  |  | 654 |  |  | 920 |  |  | 4,028 |

__________________
(1)The change in the fair value of the transportation derivative contract was recorded in GPT expenses as a loss for the three and six months ended June 30, 2024.
(2)The change in the fair value of the Contingent Consideration was recorded in net (gain) loss on derivative instruments as a gain for the three and six months ended June 30, 2025 and 2024.
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.
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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, 2025
Derivative Instrument |  | Balance Sheet Location |  | Gross Amount |  | Gross Amount Offset |  | Net Amount
|  |  |  | (In thousands)
Derivatives assets: |  |  |  |  |  |  |  |
Commodity derivatives |  | Derivative instruments — current assets |  | $ | 85,317 |  |  | $ | (26,948) |  |  | $ | 58,369 |
Contingent consideration |  | Derivative instruments — current assets |  | 23,700 |  |  | — |  |  | 23,700 |
Commodity derivatives |  | Derivative instruments — non-current assets |  | 24,293 |  |  | (16,331) |  |  | 7,962 |
Total derivatives assets |  | $ | 133,310 |  |  | $ | (43,279) |  |  | $ | 90,031 |
Derivatives liabilities: |  |  |  |  |  |  |  |
Commodity derivatives |  | Derivative instruments — current liabilities |  | $ | 27,290 |  |  | $ | (26,948) |  |  | $ | 342 |
Commodity derivatives |  | Derivative instruments — non-current liabilities |  | 18,831 |  |  | (16,331) |  |  | 2,500 |
Total derivatives liabilities |  | $ | 46,121 |  |  | $ | (43,279) |  |  | $ | 2,842 |
|  |  |  | December 31, 2024
Derivative Instrument |  | Balance Sheet Location |  | Gross Amount |  | Gross Amount Offset |  | Net Amount
|  |  |  | (In thousands)
Derivatives assets: |  |  |  |  |  |  |  |
Commodity derivatives |  | Derivative instruments — current assets |  | $ | 33,579 |  |  | $ | (20,415) |  |  | $ | 13,164 |
Contingent consideration |  | Derivative instruments — current assets |  | 22,780 |  |  | — |  |  | 22,780 |
Commodity derivatives |  | Derivative instruments — non-current assets |  | 31,676 |  |  | (26,047) |  |  | 5,629 |
Total derivatives assets |  | $ | 88,035 |  |  | $ | (46,462) |  |  | $ | 41,573 |
Derivatives liabilities: |  |  |  |  |  |  |  |
Commodity derivatives |  | Derivative instruments — current liabilities |  | $ | 21,645 |  |  | $ | (20,415) |  |  | $ | 1,230 |
Commodity derivatives |  | Derivative instruments — non-current liabilities |  | 27,063 |  |  | (26,047) |  |  | 1,016 |
Total derivatives liabilities |  | $ | 48,708 |  |  | $ | (46,462) |  |  | $ | 2,246 |

7. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment for the periods presented:

| June 30, 2025 |  | December 31, 2024
| (In thousands)
Proved oil and gas properties | $ | 12,788,093 |  |  | $ | 11,923,792 |
Less: Accumulated depletion | (2,822,286) |  |  | (2,115,428) |
Proved oil and gas properties, net | 9,965,807 |  |  | 9,808,364 |
Unproved oil and gas properties | 813,988 |  |  | 846,994 |
Other property and equipment | 59,938 |  |  | 58,158 |
Less: Accumulated depreciation | (29,249) |  |  | (27,347) |
Other property and equipment, net | 30,689 |  |  | 30,811 |
Total property, plant and equipment, net | $ | 10,810,484 |  |  | $ | 10,686,169 |

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8. Acquisitions
2024 Acquisition
On May 31, 2024, the Company completed the Arrangement with Enerplus and issued 20,680,097 shares of common stock and paid $375.8 million of cash to Enerplus shareholders. Also on May 31, 2024, and pursuant to the Arrangement Agreement, the Company (i) paid cash to settle Enerplus equity-based compensation awards, (ii) paid cash to satisfy and discharge in full the Enerplus credit facility and (iii) paid a cash retention bonus to Enerplus employees.
Purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the Arrangement at their estimated fair value on May 31, 2024 of $4.1 billion. Goodwill was recognized as a result of the Arrangement, none of which is deductible for income tax purposes, and is primarily attributable to additional operational and financial synergies expected to be realized from the combined operations. Determining the fair value of the assets and liabilities of Enerplus required judgement 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 estimated fair value of identifiable assets acquired and liabilities assumed, and the resulting goodwill as of the acquisition date of May 31, 2024. Since the acquisition date, the Company recorded adjustments to the purchase price allocation to recognize an increase in inventory acquired of $9.2 million and an increase in accrued liabilities assumed of $8.7 million, with a corresponding net decrease to goodwill totaling $0.5 million. As of May 31, 2025, the purchase price allocation was finalized.

|  | Purchase Price Consideration
|  | (In thousands)
Common stock issued to Enerplus shareholders(1) |  | $ | 3,732,137 |
Cash paid to Enerplus shareholders(1) |  | 375,813 |
Cash paid to settle Enerplus equity-based compensation awards(2) |  | 102,393 |
Cash paid to settle Enerplus credit facility(3) |  | 395,000 |
Cash paid for retention bonus to Enerplus employees(4) |  | 5,920 |
Total consideration transferred |  | $ | 4,611,263 |

__________________
(1)The Company issued 20,680,097 shares of common stock (the “Share Consideration”) and paid $375.8 million of cash (the “Cash Consideration”) to Enerplus shareholders. Enerplus shareholders received, for each Enerplus common share issued and outstanding, 0.10125 shares of common stock as Share Consideration and $1.84 per share of cash as Cash Consideration. The fair value of the common stock issued was based on the opening price of the Company’s common stock on May 31, 2024 of $180.47. See Note 17—Stockholders’ Equity in the 2024 Annual Report for additional information.
(2)Each Enerplus outstanding equity-based compensation award became fully vested upon completion of the Arrangement on May 31, 2024. See Note 17—Stockholders’ Equity in the 2024 Annual Report for additional information.
(3)On May 31, 2024, the Company fully satisfied all obligations under the Enerplus credit facility, and the Enerplus credit facility was concurrently terminated. See Note 13—Long-Term Debt in the 2024 Annual Report for additional information.
(4)In connection with the Arrangement, employees of Enerplus were paid a retention bonus upon the closing of the Arrangement totaling $5.9 million.
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|  | Purchase Price Allocation
|  | (In thousands)
Assets acquired: |  |
Cash and cash equivalents |  | $ | 239,921 |
Accounts receivable, net |  | 281,492 |
Inventory |  | 14,878 |
Prepaid expenses |  | 16,323 |
Oil and gas properties (successful efforts method) |  | 5,253,860 |
Other property and equipment |  | 6,812 |
Long-term inventory |  | 8,636 |
Operating right-of-use assets |  | 42,954 |
Other assets |  | 1,049 |
Total assets acquired |  | $ | 5,865,925 |
Liabilities assumed: |  |
Accounts payable |  | $ | 1,965 |
Revenues and production taxes payable |  | 199,706 |
Accrued liabilities |  | 195,034 |
Current portion of long-term debt |  | 60,063 |
Current operating lease liabilities |  | 27,420 |
Deferred tax liabilities |  | 1,179,200 |
Asset retirement obligations |  | 115,056 |
Operating lease liabilities |  | 15,534 |
Total liabilities assumed |  | $ | 1,793,978 |
Net assets acquired |  | $ | 4,071,947 |
Goodwill |  | 539,316 |
Purchase price consideration |  | $ | 4,611,263 |

Unaudited pro forma financial information. Summarized below are the condensed consolidated results of operations for the period presented, on an unaudited pro forma basis, as if the Arrangement had occurred on January 1, 2023. The information presented below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the Arrangement, including transaction costs incurred by the Company. In connection with the Arrangement, the Company incurred merger-related costs of $54.7 million and $62.8 million for the three and six months ended June 30, 2024, respectively, which were recorded to general and administrative expenses on the Condensed Consolidated Statements of Operations. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Arrangement occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results. The pro forma results of operations do not include any future cost savings or other synergies that may result from the Arrangement or any estimated costs that have not yet been incurred by the Company to integrate the Enerplus assets.

|  | Three Months Ended June 30, |  | Six Months Ended June 30,
|  | 2024 |  | 2024
|  | (In thousands) |  |
Revenues |  | $ | 1,529,346 |  |  | $ | 2,947,425 |
Net income |  | 315,626 |  |  | 574,643 |

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9. Investment in Unconsolidated Affiliate
As of June 30, 2025 and December 31, 2024, the fair value of the Company’s investment in Energy Transfer was $131.6 million and $142.2 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 unconsolidated affiliate on the Condensed Consolidated Balance Sheet.
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 fair value of the 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. During the three and six months ended June 30, 2024, the Company recorded a net gain of $5.9 million and $22.2 million, respectively, on its investment in Energy Transfer, comprised of an unrealized gain for the change in the fair value of its investment of $3.6 million and $17.6 million respectively, and a realized gain for cash distributions received of $2.3 million and $4.6 million, respectively.
10. Long-Term Debt
The Company’s long-term debt consists of the following:

| June 30, 2025 |  | December 31, 2024
| (In thousands)
Senior secured revolving line of credit | $ | 180,000 |  |  | $ | 445,000 |
2033 Senior Notes | 750,000 |  |  | — |
2026 Senior Notes(1) | — |  |  | 400,000 |
Less: unamortized deferred financing costs | (11,099) |  |  | (2,400) |
Total long-term debt, net | $ | 918,901 |  |  | $ | 842,600 |

__________________
(1)On March 14, 2025, the Company’s obligations were satisfied and discharged, and the 2026 Senior Notes were redeemed on June 1, 2025.
Senior secured revolving line of credit. As of June 30, 2025, the Company had a senior secured revolving credit facility (the “Credit Facility”) among Oasis Petroleum North America LLC, the Company, Chord Energy LLC, Enerplus, the other guarantors party thereto, each of the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent and issuing bank. The Credit Facility matures on July 1, 2027. In February 2025, the Company completed its semi-annual borrowing base redetermination, setting the borrowing base at $2.75 billion, and increasing the aggregate amount of elected commitments from $1.5 billion to $2.0 billion. The next scheduled redetermination is expected to occur in or around October 2025.
At June 30, 2025, the Company had $180.0 million borrowings outstanding and $29.9 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $1.8 billion. At December 31, 2024, the Company had $445.0 million borrowings outstanding and $30.8 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $1.0 billion.
During the three and six months ended June 30, 2025, the weighted average interest rate incurred on borrowings on the Credit Facility was 6.56% and 6.47%, respectively. During the three and six months ended June 30, 2024, the weighted average interest rate was 7.53% for both periods. The Company was in compliance with the financial covenants under the Credit Facility at June 30, 2025. 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. In addition, Term SOFR Loans are also subject to a 0.1% credit spread adjustment. The unused borrowing base is subject to a commitment fee ranging between 0.375% to 0.500%.
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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. 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 Consolidated Statement of Operations over the term of the 2033 Senior Notes.
Interest on the 2033 Senior Notes is payable semi-annually on March 15 and September 15 of each year. 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 indenture governing the 2033 Senior Notes contains customary events of default as well as cross-default provisions with other indebtedness of Chord and its restricted subsidiaries.
As of June 30, 2025, the fair value of the 2033 Senior Notes, which are traded among qualified institutional investors and represent a Level 1 fair value measurement, was $766.2 million.
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”). Interest on the 2026 Senior Notes was payable semi-annually on June 1 and December 1 of each year. Concurrent with the issuance of the 2033 Senior Notes on March 13, 2025, the Company paid an aggregate of $409.1 million, including $7.7 million of accrued interest, to purchase $366.3 million of outstanding 2026 Senior Notes tendered in a concurrent tender offer and to satisfy and discharge the remaining $33.7 million of outstanding 2026 Senior Notes, which were redeemed on June 1, 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.
As of December 31, 2024, the fair value of the 2026 Senior Notes, which were traded among qualified institutional investors and represented a Level 1 fair value measurement, was $399.9 million.
11. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO during the six months ended June 30, 2025 (in thousands):

| (In thousands)
Balance at December 31, 2024 | $ | 308,434 |
Liabilities incurred during period | 1,949 |
Liabilities settled during period | (13,671) |
Liabilities settled through divestitures | (82) |
Accretion expense during period | 17,276 |
Revisions to estimates | 98,683 |
Balance at June 30, 2025 | $ | 412,589 |

The Company’s ARO includes plugging and abandonment liabilities for its oil and gas properties in the United States and Canada. At June 30, 2025, the revisions to estimates of $98.7 million included in the table above were due to updates in the plugging and abandonment cost estimates of the Company’s wells in North Dakota. Accretion expense is included in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statements of Operations. At June 30, 2025, the current portion of the total ARO balance was $19.8 million and is included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.
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12. Income Taxes
The Company’s effective tax rate was (16.2)% and (298.4)% for the three and six months ended June 30, 2025, respectively, as compared to an effective tax rate of 26.8% and 24.7% for the three and six months ended June 30, 2024, respectively.
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 effective tax rate for the three months ended June 30, 2024 was higher than the statutory federal rate of 21% primarily as a result of state income taxes and Canadian losses for which no benefit is recognized. The effective tax rate for the six months ended June 30, 2024 was higher than the statutory federal rate of 21% primarily as a result of state income taxes.
On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law, which includes tax reform provisions that amend, eliminate and extend tax rules under the Inflation Reduction Act and Tax Cuts and Jobs Act. The most significant impact to the Company of the OBBBA at this time is the permanent reinstatement of 100% bonus depreciation on qualified property. The Company is currently evaluating the full effects of the legislation on its effective tax rate and cash tax position, but the Company expects that the legislation will likely not have a significant negative impact on its consolidated financial statements. As the legislation was signed into law after the close of the second quarter, the impacts are not included in the Company’s operating results for the three and six months ended June 30, 2025.
13. Equity-Based Compensation
The Company has granted RSUs, PSUs and LSUs (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. 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. During the three and six months ended June 30, 2024, the Company recognized $5.4 million and $10.1 million in equity-based compensation expenses related to equity-classified awards, respectively. Equity-based compensation expenses related to liability-classified awards were not material for the three and six months ended June 30, 2025 and 2024.
Pursuant to the Arrangement Agreement, at the effective time of the Arrangement, all Enerplus equity-based compensation awards became fully vested and paid in cash. The fair value of the equity-classified awards that vested on May 31, 2024 was $102.4 million.
Restricted stock units. Restricted stock units (“RSUs”) are contingent shares that generally vest on either a cliff or graded basis over a one-year, three-year or four-year period (as applicable) and are subject to a service condition. During the six months ended June 30, 2025, the Company granted 198,094 RSUs to employees and non-employee directors of the Company with a weighted average grant date fair value of $118.58 per share.
Performance share units. During the six months ended June 30, 2025, the Company granted PSUs that include (i) total stockholder return (“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 applicable performance period on December 31, 2027, subject to the level of achievement with respect to certain performance goals.
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 300% 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, 2025, the Company granted (i) 24,730 Absolute TSR PSUs to employees of the Company with a weighted average grant date fair value of $170.38 per share and (ii) 74,219 Relative TSR PSUs to employees of the Company with a weighted average grant date fair value of $136.18 per share.
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Fair value assumptions. The aggregate grant date fair value of the PSUs was 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, solely for Relative TSR PSUs, (vi) 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.
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 granted during the six months ended June 30, 2025:

| Absolute and Relative TSR PSUs
| Six Months Ended June 30, 2025 |  |
Forecast period (years) | 3 |  |
Risk-free interest rate | 4.3% |  |  |  |  |  |
Implied equity volatility | 33% |  |
Stock price on date of grant | $122.11 |  |  |  |  |  |

Leveraged stock units. Leveraged stock units (“LSUs”) are contingent shares granted to certain employees that cliff vest over a three-year and four-year period and are subject to a service condition. All LSUs were fully vested as of June 30, 2025.
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, 2025, the Company granted 11,790 phantom unit awards to employees with a weighted average grant date fair value of $121.89 per share.
14. Stockholders’ Equity
Authorized Shares of Common Stock
On May 14, 2024, Chord stockholders approved an amendment to the Amended and Restated Certificate of Incorporation to increase the number of authorized shares of common stock from 120,000,000 to 240,000,000 in connection with the Arrangement. This amendment became effective on May 31, 2024.
Issuance of Common Stock
Pursuant to the Arrangement Agreement, each Enerplus common share issued and outstanding immediately prior to the effective time of the Arrangement was converted into the right to receive 0.10125 shares of Chord common stock, par value $0.01 per share. As a result of the completion of the Arrangement on May 31, 2024, the Company issued 20,680,097 shares of common stock to Enerplus shareholders.
Dividends
The following table summarizes the Company’s fixed and variable dividends declared for the six months ended June 30, 2025 and 2024:

|  | Rate per Share |  |
|  | Base |  | Variable |  |  |  | Total |  | Total Dividends Declared
|  |  |  |  |  |  |  |  |  | (In thousands)
Q2 2025 |  | $ | 1.30 |  |  | $ | — |  |  |  |  | $ | 1.30 |  |  | $ | 75,733 |
Q1 2025 |  | 1.30 |  |  | — |  |  |  |  | 1.30 |  |  | 77,429 |
Total |  | $ | 2.60 |  |  | $ | — |  |  |  |  | $ | 2.60 |  |  | $ | 153,162 |
Q2 2024 |  | $ | 1.25 |  |  | $ | 1.69 |  |  |  |  | $ | 2.94 |  |  | $ | 124,708 |
Q1 2024 |  | 1.25 |  |  | 2.00 |  |  |  |  | 3.25 |  |  | 137,541 |
Total |  | $ | 2.50 |  |  | $ | 3.69 |  |  |  |  | $ | 6.19 |  |  | $ | 262,249 |

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Total dividends declared in the table above includes $0.6 million and $1.5 million associated with dividend equivalent rights on unvested equity-based compensation awards for the three and six months ended June 30, 2025, respectively, and $1.9 million and $4.3 million for the three and six months ended June 30, 2024, respectively.
On August 6, 2025, the Company declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on September 8, 2025 to shareholders of record as of August 21, 2025.
Share Repurchase Program
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 accrued excise tax of $2.5 million. As of June 30, 2025, there was $321.2 million of capacity remaining under the Company’s $750.0 million share repurchase program. Subsequent to June 30, 2025, the Company repurchased 423,902 shares of common stock at a weighted average price of $106.54 per common share for a total cost of $45.2 million.
During the six months ended June 30, 2024, the Company repurchased 558,579 shares of common stock at a weighted average price of $164.23 per common share for a total cost of $91.7 million, under its previous repurchase program, which was replaced by its current $750.0 million share repurchase program.
In August 2025, the Board of Directors authorized a new share repurchase program of up to $1.0 billion of the Company’s common stock, which replaced the Company’s previous $750.0 million share repurchase program. 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.
Warrants
As of June 30, 2025, the Company had 888,738 warrants outstanding with an exercise price of $133.70 per share that expire on September 1, 2025.
During the three and six months ended June 30, 2025, there were four warrants exercised, and during the three and six months ended June 30, 2024, there were 650,695 and 1,070,851 warrants exercised, respectively.
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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,
| 2025 |  | 2024 |  | 2025 |  | 2024
| (In thousands, except per share data)
Net income (loss) | $ | (389,905) |  |  | $ | 213,361 |  |  | $ | (170,068) |  |  | $ | 412,715 |
Distributed and undistributed earnings allocated to participating securities | 2,312 |  |  | (1,032) |  |  | 1,425 |  |  | (1,824) |
Net income (loss) attributable to common stockholders (basic) | (387,593) |  |  | 212,329 |  |  | (168,643) |  |  | 410,891 |
Reallocation of distributed and undistributed earnings allocated to participating securities | (3,604) |  |  | 10 |  |  | (2,687) |  |  | 17 |
Net income (loss) attributable to common stockholders (diluted) | $ | (391,197) |  |  | $ | 212,339 |  |  | $ | (171,330) |  |  | $ | 410,908 |
Weighted average common shares outstanding: |  |  |  |  |  |  |
Basic weighted average common shares outstanding | 57,786 |  |  | 48,665 |  | 58,420 |  |  | 45,048 |
Dilutive effect of share-based awards | — |  |  | 375 |  |  | 81 |  |  | 438 |
Dilutive effect of warrants | — |  |  | 876 |  |  | — |  |  | 827 |
Diluted weighted average common shares outstanding | 57,786 |  |  | 49,916 |  |  | 58,501 |  |  | 46,313 |
Basic earnings (loss) per share | $ | (6.71) |  |  | $ | 4.36 |  |  | $ | (2.89) |  |  | $ | 9.12 |
Diluted earnings (loss) per share | $ | (6.77) |  |  | $ | 4.25 |  |  | $ | (2.93) |  |  | $ | 8.87 |
Anti-dilutive weighted average common shares: |  |  |  |  |  |  |
Potential common shares | 1,067 |  |  | 1,818 |  |  | 980 |  |  | 2,028 |

For the three and six months ended June 30, 2025 and 2024, the diluted earnings (loss) per share calculation excludes the impact of unvested share-based awards and outstanding warrants that were anti-dilutive.
16. Commitments and Contingencies
As of June 30, 2025, the Company’s material off-balance sheet arrangements and transactions include $29.9 million in outstanding letters of credit issued under the Credit Facility and $91.6 million in net surety bond exposure issued as financial assurance on certain agreements.
As of June 30, 2025, there have been no material changes to the Company’s commitments and contingencies disclosed in Note 21 — Commitments and Contingencies in the 2024 Annual Report.
17. Leases
No material changes have occurred to the Company’s lease portfolio for the periods presented. Refer to the 2024 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, 2024 (“2024 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”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding 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. 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.
Forward-looking statements may include statements about:
•crude oil, NGLs 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, NGLs 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 agree on and comply with supply limitations;
•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, war between Hamas and Israel and conflict between Iran and Israel, with the potential for escalation of hostilities across the surrounding countries in the Middle East, and their effect on commodity prices;
•changes in general economic and geopolitical conditions;
•inflation rates and the impact of associated monetary policy responses, including increased interest rates;
•logistical challenges and supply chain disruptions;
•our business strategy;
•the geographic concentration of our operations;
•estimated future net reserves and present value thereof;
•timing and amount of future production of crude oil, NGLs 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;
•gathering, transportation and marketing of crude oil, NGLs and natural gas in the Williston Basin and other regions in the United States;
•the possible shutdown of the Dakota Access Pipeline;
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•incurring significant transaction and other costs in connection with the Arrangement (as defined in the “Results of Operations” section of Item 2 below) in excess of those anticipated;
•the ultimate timing, outcome and results of integrating the operations of Chord and Enerplus;
•failure to realize the anticipated benefits or synergies from the Arrangement in the timeframe expected or at all;
•property acquisitions and divestitures;
•integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness, including the Arrangement;
•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 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 Agreement 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 effects arising from cybersecurity threats, terrorist attacks and any consequential or other hostilities;
•compliance with, and changes in, environmental, safety and other laws and regulations, including the Inflation Reduction Act of 2022 and provisions under the newly enacted One Big Beautiful Bill Act;
•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 as well as any public health crisis and resulting demand and supply for crude oil, NGLs and natural gas;
•governmental regulation and the taxation of the oil and gas industry;
•developments in crude oil-producing and natural gas-producing countries;
•technology;
•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 elevated 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 2024 Annual Report and in our other filings with the SEC.
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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. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in crude oil, NGL and natural gas prices, climatic and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, inflation, changing trade policies, the proximity to and capacity of transportation facilities and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. 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 (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. Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We are ideally positioned to enhance return of capital and generate strong free cash flow, 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. Prices for crude oil, NGLs and natural gas have experienced significant fluctuations in recent years, including sustained decreases during 2025, and may continue to fluctuate widely or continue to decrease in the future due to a combination of macro-economic factors that impact the supply and demand for crude oil, NGLs and natural gas. The potential for continued volatility in our markets, economic uncertainty and unfavorable oil and gas market dynamics, including the recent OPEC+ announcement to increase oil production levels, U.S. tariffs and potential retaliatory tariffs, may have an adverse impact on our future business operations, financial condition and liquidity. Recent volatility in the energy markets during the second quarter of 2025 has led to a decrease in the price of crude oil. Further decline in the price of crude oil, or a sustained depression of the price of crude oil for an extended period of time, could have a material adverse effect on our financial position, results of operations, cash flows, the quantities of crude oil, NGL and natural gas reserves that may be economically produced and our access to capital.
At June 30, 2025, we assessed goodwill for impairment and recognized a non-cash impairment charge of $539.3 million. See “Item 1. Financial Statements (Unaudited)—Note 5—Fair Value Measurements” for additional information.
While we are unable to predict future commodity prices, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur at current price levels as it is more likely than not that the fair value of our oil and gas properties will continue to exceed its carrying value. We will continue to evaluate the recoverability of the carrying value of our oil and gas properties as a result of a future material or extended decline in the current price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services.
In an effort to improve price realizations from the sale of our crude oil, NGLs and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGLs 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, 2025, substantially all of our gross operated crude oil and natural gas production were connected to gathering systems.
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Results of Operations
Comparability of Financial Statements
On May 31, 2024, we acquired Enerplus Corporation (“Enerplus”) in a stock-and-cash transaction (“the “Arrangement”). Enerplus was an independent North American oil and gas E&P company domiciled in Canada with substantially all of its producing assets in the Williston Basin of North Dakota, with limited non-operated interests in the Marcellus Shale. The results of operations presented below relate to the periods ended June 30, 2025, March 31, 2025 and June 30, 2024. The results reported for the three and six months ended June 30, 2025 and the three months ended March 31, 2025 reflect the consolidated results of Chord, including combined operations with Enerplus, while the results reported for the six months ended June 30, 2024 reflect the consolidated results of Chord, including the impact from the business combination with Enerplus beginning on May 31, 2024, unless otherwise noted.
Operational and Financial Highlights
•Production volumes averaged 281,858 Boepd (56% oil), including crude oil volumes of 156,734 Bopd in the second quarter of 2025.
•E&P and other capital expenditures (excluding capitalized interest) were $355.6 million in the second quarter of 2025.
•Lease operating expenses (“LOE”) were $10.02 per Boe in the second quarter of 2025.
•Net cash provided by operating activities was $419.8 million and net loss was $389.9 million in the second quarter of 2025.
Shareholder Return Highlights
•Paid $1.30 per share base cash dividend on June 9, 2025.
•Repurchased $55.0 million of common stock in the second quarter of 2025.
▪In August 2025, the Board of Directors authorized a new $1.0 billion share repurchase program.
•Declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on September 8, 2025 to shareholders of record as of August 21, 2025.
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 crude oil, NGL and natural gas revenues for the six months ended June 30, 2025 increased compared to the six months ended June 30, 2024 due to the Arrangement, which closed on May 31, 2024 and expanded our operations primarily in the Williston Basin. Our purchased oil and gas sales are derived from the sale of crude oil, NGLs 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, NGL 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 sales and purchases with the same counterparty 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, 2025 |  | Three Months Ended March 31, 2025 |  | Six Months Ended June 30, 2025 |  | Six Months Ended June 30, 2024
Revenues (in thousands) |  |  |  |  |  |  |
Crude oil revenues | $ | 878,928 |  |  | $ | 956,138 |  |  | $ | 1,835,064 |  |  | $ | 1,526,955 |
NGL revenues | 28,569 |  |  | 61,345 |  |  | 89,914 |  |  | 84,016 |
Natural gas revenues | 42,769 |  |  | 85,942 |  |  | 128,712 |  |  | 39,858 |
Purchased oil and gas sales | 230,294 |  |  | 111,622 |  |  | 341,916 |  |  | 695,111 |
Total revenues | $ | 1,180,560 |  |  | $ | 1,215,047 |  |  | $ | 2,395,606 |  |  | $ | 2,345,940 |
Production data |  |  |  |  |  |  |
Crude oil (MBbls) | 14,263 |  |  | 13,835 |  |  | 28,098 |  |  | 19,763 |
NGLs (MBbls) | 4,926 |  |  | 4,325 |  |  | 9,251 |  |  | 6,814 |
Natural gas (MMcf)(1) | 38,759 |  |  | 37,303 |  |  | 76,063 |  |  | 45,618 |
Oil equivalents (MBoe) | 25,649 |  |  | 24,377 |  |  | 50,026 |  |  | 34,180 |
Average daily production (Boepd) | 281,858 |  |  | 270,855 |  |  | 276,387 |  |  | 187,802 |
Average daily crude oil production (Bopd) | 156,734 |  |  | 153,720 |  |  | 155,235 |  |  | 108,588 |
Average sales prices |  |  |  |  |  |  |
Crude oil (per Bbl) |  |  |  |  |  |  |
Average sales price | $ | 61.62 |  |  | $ | 69.11 |  |  | $ | 65.31 |  |  | $ | 77.26 |
Effect of derivative settlements(2) | 0.96 |  |  | (0.03) |  |  | 0.47 |  |  | (0.26) |
Average realized price after the effect of derivative settlements(2) | $ | 62.58 |  |  | $ | 69.08 |  |  | $ | 65.78 |  |  | $ | 77.00 |
NGLs (per Bbl) |  |  |  |  |  |  |
Average sales price | $ | 5.80 |  |  | $ | 14.18 |  |  | $ | 9.72 |  |  | $ | 12.33 |
Effect of derivative settlements(2) | — |  |  | — |  |  | — |  |  | — |
Average realized price after the effect of derivative settlements(2) | $ | 5.80 |  |  | $ | 14.18 |  |  | $ | 9.72 |  |  | $ | 12.33 |
Natural gas (per Mcf) |  |  |  |  |  |  |
Average sales price(1) | $ | 1.10 |  |  | $ | 2.30 |  |  | $ | 1.69 |  |  | $ | 0.87 |
Effect of derivative settlements(2) | 0.01 |  |  | 0.01 |  |  | 0.01 |  |  | — |
Average realized price after the effect of derivative settlements(1)(2) | $ | 1.11 |  |  | $ | 2.31 |  |  | $ | 1.70 |  |  | $ | 0.87 |

____________________
(1)For the three months ended June 30, 2025 and March 31, 2025, natural gas production volume from the Marcellus Shale was 11,821 MMcf and 11,563 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $2.49 per Mcf and $4.71 per Mcf for the three months ended June 30, 2025 and March 31, 2025, respectively. For the six months ended June 30, 2025 and 2024, natural gas production volume from the Marcellus Shale was 23,384 MMcf and 3,764 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $3.59 per Mcf and $1.66 per Mcf for the six months ended June 30, 2025 and 2024, 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, 2025 as compared to three months ended March 31, 2025
Crude oil revenues. Our crude oil revenues decreased $77.2 million to $878.9 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The decrease was primarily due to a decrease of $103.6 million due to lower crude oil realized prices quarter over quarter, partially offset by an increase of $26.4 million due to higher crude oil production volumes sold quarter over quarter. Average crude oil sales prices, without derivative settlements, decreased by $7.49 per barrel quarter over quarter to an average of $61.62 per barrel for the three months ended June 30, 2025 primarily due to a decrease in NYMEX WTI.
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NGL revenues. Our NGL revenues decreased $32.8 million to $28.6 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The decrease was primarily due to lower realized NGL prices quarter over quarter resulting in a $36.3 million decrease, partially offset by an increase of $3.5 million due to higher NGL production volumes sold quarter over quarter. Average NGL sales prices, without derivative settlements, decreased by $8.38 per barrel quarter over quarter to an average of $5.80 per barrel for the three months ended June 30, 2025 primarily due to decreases in the corresponding NGL product index prices.
Natural gas revenues. Our natural gas revenues decreased $43.2 million to $42.8 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The decrease was primarily due to lower natural gas realized prices quarter over quarter resulting in a $44.8 million decrease, partially offset by an increase of $1.6 million due to higher natural gas production volumes sold quarter over quarter. Average natural gas sales prices, without derivative settlements, decreased by $1.20 per Mcf quarter over quarter to $1.10 per Mcf for the three months ended June 30, 2025 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 $118.7 million to $230.3 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold quarter over quarter, partially offset by decreased crude oil prices over the same period.
Six months ended June 30, 2025 as compared to six months ended June 30, 2024
Crude oil revenues. Our crude oil revenues increased $308.1 million to $1.8 billion for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. Our crude oil revenues increased $491.4 million due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, crude oil revenues decreased $235.0 million due to lower crude oil realized prices, partially offset by an increase of $51.7 million due to higher crude oil production volumes sold. Average crude oil sales prices, without derivative settlements, decreased by $11.95 per barrel period over period to an average of $65.31 per barrel for the six months ended June 30, 2025 due to decreases in NYMEX WTI and widening in-basin differentials period over period.
NGL revenues. Our NGL revenues increased $5.9 million to $89.9 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. Our NGL revenues increased $3.8 million due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, NGL revenues increased $6.1 million due to higher NGL production volumes sold, partially offset by a decrease of $4.0 million due to lower realized NGL prices period over period. Average NGL sales prices, without derivative settlements, decreased by $2.61 per barrel period over period to an average of $9.72 per barrel for the six months ended June 30, 2025 primarily due to decreases in the corresponding NGL product index prices and widening differentials period over period.
Natural gas revenues. Our natural gas revenues increased $88.9 million to $128.7 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. Our natural gas revenues increased $69.0 million due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, natural gas revenues increased $20.2 million primarily due to higher average natural gas realized prices. Average natural gas sales prices, without derivative settlements, increased by $0.82 per Mcf period over period to $1.69 per Mcf for the six months ended June 30, 2025 primarily due to increases in index prices period over period.
Purchased oil and gas sales. Purchased oil and gas sales decreased $353.2 million to $341.9 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. This decrease was primarily due to a decrease in the volume of crude oil purchased and subsequently sold period over period, coupled with decreased crude oil prices over the same period.
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Expenses and other income (expense)
Certain operating expenses, including LOE, GPT expenses and DD&A, increased for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 due to the Arrangement, which closed on May 31, 2024 and expanded our operations primarily in the Williston Basin.
The following table summarizes our operating expenses and other income (expense) for the periods presented:

| Three Months Ended June 30, 2025 |  | Three Months Ended March 31, 2025 |  | Six Months Ended June 30, 2025 |  | Six Months Ended June 30, 2024
| (In thousands, except per Boe of production data)
Operating expenses |  |  |  |  |  |  |
Lease operating expenses | $ | 256,966 |  |  | $ | 233,074 |  |  | $ | 490,040 |  |  | $ | 335,853 |
Gathering, processing and transportation expenses | 74,100 |  |  | 73,314 |  |  | 147,415 |  |  | 117,114 |
Purchased oil and gas expenses | 231,745 |  |  | 111,368 |  |  | 343,113 |  |  | 692,118 |
Production taxes | 68,965 |  |  | 74,642 |  |  | 143,607 |  |  | 143,433 |
Depreciation, depletion and amortization | 376,997 |  |  | 349,809 |  |  | 726,806 |  |  | 396,822 |
General and administrative expenses | 32,540 |  |  | 38,377 |  |  | 70,917 |  |  | 107,789 |
Impairment and exploration | 541,940 |  |  | 1,983 |  |  | 543,923 |  |  | 7,639 |
Total operating expenses | 1,583,253 |  |  | 882,567 |  |  | 2,465,821 |  |  | 1,800,768 |
Gain (loss) on sale of assets, net | (522) |  |  | 5,516 |  |  | 4,993 |  |  | 16,788 |
Operating income (loss) | (403,215) |  |  | 337,996 |  |  | (65,222) |  |  | 561,960 |
Other income (expense) |  |  |  |  |  |  |
Net gain (loss) on derivative instruments | 82,231 |  |  | (20,281) |  |  | 61,950 |  |  | (22,969) |
Net gain (loss) from investment in unconsolidated affiliate | (962) |  |  | (4,900) |  |  | (5,862) |  |  | 22,158 |
Interest expense, net of capitalized interest | (18,788) |  |  | (15,818) |  |  | (34,606) |  |  | (19,800) |
Loss on debt extinguishment | — |  |  | (3,494) |  |  | (3,494) |  |  | — |
Other income (expense) | 5,045 |  |  | (501) |  |  | 4,546 |  |  | 6,907 |
Total other income (expense), net | 67,526 |  |  | (44,994) |  |  | 22,534 |  |  | (13,704) |
Income (loss) before income taxes | (335,689) |  |  | 293,002 |  |  | (42,688) |  |  | 548,256 |
Income tax expense | (54,216) |  |  | (73,165) |  |  | (127,380) |  |  | (135,541) |
Net income (loss) | $ | (389,905) |  |  | $ | 219,837 |  |  | $ | (170,068) |  |  | $ | 412,715 |
Costs and expenses (per Boe of production) |  |  |  |  |  |  |
Lease operating expenses | $ | 10.02 |  |  | $ | 9.56 |  |  | $ | 9.80 |  |  | $ | 9.83 |
Gathering, processing and transportation expenses | 2.89 |  |  | 3.01 |  |  | 2.95 |  |  | 3.43 |
Production taxes | 2.69 |  |  | 3.06 |  |  | 2.87 |  |  | 4.20 |

Three months ended June 30, 2025 as compared to three months ended March 31, 2025
Lease operating expenses. LOE increased $23.9 million to $257.0 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The increase was primarily due to increased workover activity of $16.2 million and higher variable costs of $7.0 million quarter over quarter. LOE per Boe increased $0.46 per Boe quarter over quarter to $10.02 per Boe for the three months ended June 30, 2025 primarily due to the increase in workover activity.
Purchased oil and gas expenses. Purchased oil and gas expenses increased $120.4 million to $231.7 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025 primarily due to an increase in the volume of crude oil purchased and subsequently sold quarter over quarter, partially offset by decreased crude oil prices over the same period.
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Production taxes. Production taxes decreased $5.7 million to $69.0 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The decrease was primarily due to the impact of lower crude oil revenues quarter over quarter. The production tax rate as a percentage of crude oil, NGL and natural gas revenues of 7.3% for the three months ended June 30, 2025 increased from 6.8% for the three months ended March 31, 2025 primarily as a result of higher extraction tax exemptions for certain wells within the three months ended March 31, 2025 coupled with natural gas comprising a smaller percentage of total sales relative to the prior quarter.
Depreciation, depletion and amortization. DD&A expense increased $27.2 million to $377.0 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The increase was primarily driven by higher production volumes of $19.9 million quarter over quarter coupled with increased accretion expense of $7.3 million related to plugging and abandonment charges.
General and administrative expenses. G&A expenses decreased $5.8 million to $32.5 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The decrease was primarily attributable to lower employee compensation expenses of $6.1 million and a decrease in merger-related costs of $2.2 million, partially offset by various cost increases related to other G&A expenses of $4.2 million. Merger-related costs for the three months ended June 30, 2025 and March 31, 2025 were $2.9 million and $5.1 million, respectively, and were primarily comprised of severance and advisory expenses related to the Arrangement in both periods.
Impairment and exploration. As a result of a decrease in the price of our common stock during the three 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 three months ended June 30, 2025. There were no impairment charges during the three months ended March 31, 2025.
Gain (loss) on sale of assets, net. During the three months ended June 30, 2025 and March 31, 2025, we recorded a net loss of $0.5 million and a net gain of $5.5 million, respectively, on sales of assets primarily related to the divestiture of certain non-core oil and gas properties within each quarter.
Derivative instruments. We recorded a $82.2 million net gain on derivative instruments for the three months ended June 30, 2025, which was comprised of a net gain of $82.0 million associated with our commodity derivative contracts and an unrealized gain of $0.2 million associated with a contract that includes contingent consideration. The net gain of $82.0 million on commodity derivative contracts included an unrealized gain of $67.9 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 $14.1 million on settled commodity derivative contracts. During the three months ended March 31, 2025, we recorded a $20.3 million net loss on derivative instruments, which was comprised of a net loss of $21.0 million associated with our commodity derivative contracts, partially offset by an unrealized gain of $0.7 million associated with a contract that included contingent consideration. The net loss of $21.0 million on commodity derivative contracts included an unrealized loss of $20.7 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 of $0.3 million on settled commodity derivative contracts.
Investment in unconsolidated affiliate. We recorded a $1.0 million net loss related to our investment in Energy Transfer LP (“Energy Transfer”) for the three months ended June 30, 2025, which included an unrealized loss of $3.3 million as a result of a decrease in the fair value of the investment during the quarter, partially offset by a gain of $2.4 million for a cash distribution from Energy Transfer during the quarter. During the three months ended March 31, 2025, we recorded a $4.9 million net loss related to our investment in Energy Transfer due to an unrealized loss of $7.3 million as a result of a decrease in the fair value of the investment during the quarter, partially offset by a gain of $2.4 million for a cash distribution from Energy Transfer during the quarter.
Interest expense, net of capitalized interest. Interest expense increased $3.0 million to $18.8 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The increase was primarily due to the issuance of $750.0 million of 6.750% senior unsecured notes due March 15, 2033 (the “2033 Senior Notes”) in March 2025, partially offset with lower borrowings on the Credit Facility (defined below) during the quarter coupled with the purchase and satisfaction and discharge of the $400.0 million 6.375% senior unsecured notes outstanding due June 1, 2026 (the “2026 Senior Notes”) in March 2025. For the three months ended June 30, 2025, the weighted average borrowings outstanding under the Credit Facility were $238.0 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.56%. For the three months ended March 31, 2025, the weighted average borrowings outstanding under the Credit Facility were $383.4 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.4%. Interest capitalized during the three months ended June 30, 2025 and March 31, 2025 was $1.1 million for each period.
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Loss on debt extinguishment. On March 13, 2025, we paid an aggregate of $409.1 million to purchase and satisfy and discharge the 2026 Senior Notes, resulting in a loss on debt extinguishment of $3.5 million for the three months ended March 31, 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.
Income tax expense. Our effective tax rate was recorded at (16.2)% and 25.0% of pre-tax income (loss) for the three months ended June 30, 2025 and March 31, 2025, respectively. The effective tax rate for the three 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. The effective tax rate for the three months ended March 31, 2025 was higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes and deferred taxes on unremitted earnings.
Six months ended June 30, 2025 as compared to six months ended June 30, 2024
Lease operating expenses. LOE increased $154.2 million to $490.0 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. The increase was primarily driven by our expanded operations after the Arrangement contributing $115.3 million of additional LOE period over period, as well as increased workover costs of $24.5 million and increased fixed costs of $19.4 million primarily due to new wells brought online during the six months ended June 30, 2025. LOE per Boe decreased $0.03 per Boe period over period to $9.80 per Boe for the six months ended June 30, 2025 primarily due to operational synergies achieved through the Arrangement.
Gathering, processing and transportation expenses. GPT expenses increased $30.3 million to $147.4 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. The increase was primarily due to our expanded operations after the Arrangement contributing $48.2 million of additional GPT expenses. This increase was partially offset by lower transportation rates of $12.8 million, primarily due to several contracts expiring during the year ended December 31, 2024, and lower fair value losses of $5.9 million attributable to the completion of a derivative transportation contract in June 2024. GPT expenses decreased $0.48 per Boe period over period to $2.95 per Boe for the six months ended June 30, 2025 primarily due to lower transportation rates and fair value losses period over period.
Purchased oil and gas expenses. Purchased oil and gas expenses decreased $349.0 million to $343.1 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 primarily due to a decrease in the volume of crude oil purchased and subsequently sold period over period coupled with decreased crude oil prices over the same period.
Production taxes. Production taxes increased $0.2 million to $143.6 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. The increase was primarily due to a $46.0 million increase in production taxes attributable to our expanded operations after the Arrangement. This increase was largely offset by decreases in crude oil revenues period over period due to lower crude oil prices and a reduction in the production tax rate during the six months ended June 30, 2025 primarily due to a non-recurring refund 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 decreased from 8.7% for the six months ended June 30, 2024 to 7.0% for the six months ended June 30, 2025 primarily due to the non-recurring refund coupled with natural gas comprising a larger percentage of total sales relative to the prior period.
Depreciation, depletion and amortization. DD&A expense increased $330.0 million to $726.8 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. The increase was primarily due to $186.4 million of additional depletion expense due to a higher depletion rate period over period, coupled with $134.7 million of additional DD&A expense related to an overall increase in production volumes, mainly due to our expanded operations after the Arrangement as well as an increase in accretion of $8.7 million. Accretion expense increased primarily due to higher plugging and abandonment expenses and incremental accretion related to properties acquired in the Arrangement. The depletion rate increased $2.84 per Boe period over period to $14.13 per Boe for the six months ended June 30, 2025 primarily due to the purchase consideration allocated to the fair value of the oil and gas properties acquired in the Arrangement.
General and administrative expenses. G&A expenses decreased $36.9 million to $70.9 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 primarily due to lower merger-related costs of $54.7 million. Merger-related costs for the six months ended June 30, 2025 and 2024 were $8.1 million and $62.8 million, respectively, and were primarily comprised of severance, legal and advisory expenses related to the Arrangement. This decrease in merger-related costs was partially offset by an increase in costs associated with a larger organization after the Arrangement of $17.8 million.
Impairment and exploration. Impairment and exploration expenses increased $536.3 million to $543.9 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024 primarily due to the impairment of our goodwill. During the six months ended June 30, 2025, we recorded an impairment charge on our goodwill of $539.3 million as a result of the decrease in the price of our common stock during the three months ended June 30, 2025, which was impacted by a decline in crude oil and natural gas prices over that same period. During the six months ended June 30, 2024, we recorded a lower of cost or net realizable value write down of oil-in-tank inventory of $3.9 million.
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Gain (loss) on sale of assets, net. During the six months ended June 30, 2025 and 2024, we recorded a net gain on sale of assets of $5.0 million and $16.8 million, respectively, primarily related to the divestiture of certain non-core oil and gas properties within each period.
Derivative instruments. 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. During the six months ended June 30, 2024, we recorded a $23.0 million net loss on derivative instruments, which was comprised of a net loss of $27.0 million associated with our commodity derivative contracts, partially offset by an unrealized gain of $4.0 million associated with a contract that included contingent consideration. The net loss of $27.0 million on commodity derivative contracts included an unrealized loss of $21.7 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 and a realized loss of $5.3 million on settled commodity derivative contracts.
Investment in unconsolidated affiliate. We recorded a $5.9 million net loss related to our investment in Energy Transfer for the six months ended June 30, 2025, 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 cash distributions from Energy Transfer during the period. During the six months ended June 30, 2024, we recorded a net gain of $22.2 million related to our investment in Energy Transfer, which included an unrealized gain of $17.6 million as a result of an increase in the fair value of the investment during the period, coupled with a gain of $4.6 million for cash distributions from Energy Transfer during the period.
Interest expense, net of capitalized interest. Interest expense increased $14.8 million to $34.6 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. The increase is primarily due to higher borrowings outstanding on the Credit Facility (defined below) period over period and the issuance of the 2033 Senior Notes in March 2025, partially offset by the purchase and satisfaction and discharge of the 2026 Senior Notes in March 2025. For 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 6.5%. During the six months ended June 30, 2024, the weighted average borrowings outstanding under the Credit Facility were $229.9 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.5%. Interest capitalized during the six months ended June 30, 2025 and June 30, 2024 was $2.2 million and $1.9 million, respectively.
Loss on debt extinguishment. On March 13, 2025, we paid an aggregate of $409.1 million to purchase and satisfy and discharge 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.
Income tax expense. Our effective tax rate was recorded at (298.4)% and 24.7% of pre-tax income (loss) for the six months ended June 30, 2025 and 2024, respectively. Our 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. The effective tax rate for the six months ended June 30, 2024 was higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes.
Liquidity and Capital Resources
As of June 30, 2025, we had $1,830.6 million of liquidity available, including $40.5 million in cash and cash equivalents and $1,790.1 million of aggregate unused borrowing capacity available under the Credit Facility (defined below). During the six months ended June 30, 2025, our primary sources of liquidity were from cash flows from operations, available borrowing capacity under the Credit Facility, proceeds from the issuance of the 2033 Senior Notes 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, debt repayments, share repurchases and working capital requirements.
Our cash flows depend on many factors, including the price of crude oil, NGLs 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.
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Capital availability will be 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 U.S. Federal Reserve decreased interest rates during the fourth quarter of 2024, however the potential for such rates to decrease further or to remain elevated for an extended period of time has created additional economic uncertainty. Although we are unable to predict future interest rates, this 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.
Enerplus Arrangement. In connection with the consummation of the Arrangement on May 31, 2024, we paid $375.8 million, or $1.84 per Enerplus common share, to Enerplus shareholders. In addition, we paid $395.0 million to settle Enerplus’ revolving bank credit facility balance, $102.4 million to settle all outstanding Enerplus equity-based compensation awards and $5.9 million in retention bonuses paid to Enerplus employees.
Also in connection with the Arrangement, we incurred certain costs for advisory, legal and other third-party fees which were recorded to G&A expenses on the Condensed Consolidated Statements of Operations. During the three and six months ended June 30, 2025, we incurred merger-related costs of $2.9 million and $8.1 million, respectively, primarily related to severance costs and legal and advisory services.
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.
As of June 30, 2025, our commodity derivative contracts cover 5,980 MBbls of our crude oil production and 24,840,000 MMBtu of our natural gas production for 2025, 6,414 MBbls of our crude oil production and 28,680,000 MMBtu of our natural gas production for 2026 and 678 MBbls of our crude oil production and 3,620,000 MMBtu of our natural gas production for 2027. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” for additional information.
Subsequent to June 30, 2025, we entered into the following commodity derivative contracts:

|  |  |  |  |  |  |  |  |  | Weighted Average Prices
Commodity |  | Settlement Period |  | Derivative Instrument |  | Volumes |  | Fixed-Price Swaps |  |  |  | Floor |  | Ceiling
Crude oil |  | 2025 |  | Fixed-price swaps |  | 368,000 |  |  | Bbls |  | $ | 67.26 |  |  |  |  |  |  |
Crude oil |  | 2026 |  | Two-way collars |  | 69,000 |  |  | Bbls |  |  |  |  |  | $ | 60.00 |  |  | $ | 64.25 |
Crude oil |  | 2026 |  | Fixed-price swaps |  | 273,000 |  |  | Bbls |  | $ | 65.75 |  |  |  |  |  |  |
Crude oil |  | 2027 |  | Two-way collars |  | 546,000 |  |  | Bbls |  |  |  |  |  | $ | 60.00 |  |  | $ | 66.12 |

Commitments. We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGLs, 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 $485.1 million as of June 30, 2025. 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, NGLs and natural gas from third parties to satisfy our minimum volume commitments. See “Item 8. Financial Statements and Supplementary Data—Note 21—Commitments and Contingencies” in our 2024 Annual Report for additional information on our volume delivery commitments.
Long-term debt
Revolving credit facility. As of June 30, 2025, we had a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $2.75 billion and elected commitments of $2.0 billion that is due July 1, 2027. As of June 30, 2025, we had $180.0 million borrowings outstanding and $29.9 million of outstanding letters of credit, resulting in an unused borrowing capacity of $1,790.1 million. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. As of June 30, 2025, we were in compliance with the financial covenants under the Credit Facility. See “Item 1. Financial Statements (Unaudited)—Note 10—Long-Term Debt” for additional information.
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2033 Senior Notes. On March 13, 2025, we issued the 2033 Senior Notes in a private placement. Interest on the 2033 Senior Notes is payable semi-annually on March 15 and September 15 of each year. The 2033 Senior Notes were issued at par and resulted in proceeds of $738.8 million, after deducting underwriters’ discounts, commissions and other expenses. The proceeds were used to repurchase the 2026 Senior Notes 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, we recorded deferred financing costs of $11.6 million.
2026 Senior Notes. As of December 31, 2024, we had $400.0 million of the 2026 Senior Notes outstanding. Interest on the 2026 Senior Notes was payable semi-annually on June 1 and December 1 of each year. Concurrent with the issuance of the 2033 Senior Notes on March 13, 2025, we paid an aggregate of $409.1 million, including $7.7 million of accrued interest, to purchase $366.3 million of outstanding 2026 Senior Notes tendered in a concurrent tender offer and to satisfy and discharge the remaining $33.7 million of outstanding 2026 Senior Notes, which were redeemed on June 1, 2025. 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, 2025 and 2024 are presented below:

| Six Months Ended June 30, |
| 2025 |  | 2024 |
| (In thousands) |
Net cash provided by operating activities | $ | 1,076,703 |  |  | $ | 867,574 |  |
Net cash used in investing activities | (677,782) |  |  | (1,150,576) |  |
Net cash provided by (used in) financing activities | (395,384) |  |  | 162,393 |  |
Increase (decrease) in cash and cash equivalents | $ | 3,537 |  |  | $ | (120,609) |  |

Cash flows provided by operating activities
Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes and operating costs. Net cash provided by operating activities was $1,076.7 million for the six months ended June 30, 2025. The increase in net cash provided by operating activities of $209.1 million as compared to the six months ended June 30, 2024 was primarily due to our expanded operations from the Arrangement, including an increase in oil, NGL and natural gas revenues, partially offset by increases in LOE and GPT expenses. This increase was also driven by lower merger-related costs, offset by changes in our working capital. 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) decreased net cash flows from operating activities by $12.5 million and $18.1 million during the six months ended June 30, 2025 and 2024, respectively. Changes in working capital associated with our capital expenditure activities and settlement of outstanding commodity derivative instruments impact our cash flows from investing activities.
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 $1.8 billion at June 30, 2025, and excludes current hedge assets, which were $82.1 million at June 30, 2025. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $0.3 million at June 30, 2025.
Cash flows used in investing activities
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. Net cash used in investing activities for the six months ended June 30, 2024 of $1,150.6 million was primarily attributable to the Arrangement, including $395.0 million paid to settle Enerplus’ revolving bank credit facility balance, $375.8 million paid to Enerplus shareholders, $102.4 million paid to settle Enerplus’ equity awards and $5.9 million in retention bonuses paid to Enerplus employees, partially offset by cash acquired in the Arrangement of $239.9 million. Net cash used in investing activities during the six months ended June 30, 2024 also included capital expenditures of $538.7 million and the settlement of derivative contracts of $16.3 million, partially offset by the receipt of the 2023 contingent consideration earn-out payment of $25.0 million and proceeds from divestitures of certain non-core oil and gas properties of $20.9 million.
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Cash flows provided by (used in) financing activities
For the six months ended June 30, 2025, net cash used in financing activities of $395.4 million was primarily attributable to 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 primarily in connection with the issuance of the 2033 Senior Notes and repayments under the Credit Facility of $2.7 billion, partially offset by borrowings of $2.4 billion, 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. Net cash provided by financing activities for the six months ended June 30, 2024 of $162.4 million was primarily attributable to borrowings under the credit facility of $575.0 million, net of repayments of $250.0 million, in connection with the Arrangement and proceeds from the exercise of outstanding warrants of $21.0 million, partially offset by dividends paid to shareholders of $281.7 million, payments to repurchase our common stock of $93.7 million, and income tax withholdings on vested equity-based compensation awards of $57.4 million.
Capital Expenditures
Expenditures for the acquisition and development of oil and gas properties are the primary use of our capital resources. Our capital expenditures are summarized in the following table for the period presented:

| Three Months Ended |  |  |  | Six Months Ended
| March 31, 2025 |  | June 30, 2025 |  |  |  |  |  | June 30, 2025
| (In thousands)
E&P | $ | 354,781 |  |  | $ | 354,470 |  |  |  |  |  |  | $ | 709,251 |
Other capital expenditures | 658 |  |  | 1,119 |  |  |  |  |  |  | 1,777 |
Total E&P and other capital expenditures | 355,439 |  |  | 355,589 |  |  |  |  |  |  | 711,028 |
Capitalized interest | 1,079 |  |  | 1,109 |  |  |  |  |  |  | 2,188 |
Acquisitions | 17,876 |  |  | 8,315 |  |  |  |  |  |  | 26,191 |
Total capital expenditures(1) | $ | 374,394 |  |  | $ | 365,013 |  |  |  |  |  |  | $ | 739,407 |

(1)Total capital expenditures reflected in the table above differs from the amounts shown in the statements of cash flows in our unaudited condensed consolidated financial statements because amounts reflected in the table include changes in accruals, while the amounts presented in the statements of cash flows are presented on a cash basis.
Dividends
On August 6, 2025, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on September 8, 2025 to shareholders of record as of August 21, 2025. See “Item 1. Financial Statements (Unaudited)—Note 14—Stockholders’ Equity” for additional information.
See “Part I. Item 1.—Business—Business Strategy” in our 2024 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, 2025, we 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 under our $750.0 million share repurchase program. In August 2025, our Board of Directors authorized a new share repurchase program of up to $1.0 billion of the common stock, which replaces the existing $750 million share repurchase program. As of June 30, 2025, there was $321.2 million of capacity remaining under our $750.0 million share repurchase program.
During the six months ended June 30, 2024, we repurchased 558,579 shares of common stock under a previous share repurchase program at a weighted average price of $164.23 per common share for a total cost of $91.7 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.
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Critical Accounting Policies and Estimates
There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2024 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 2024 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, NGLs 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, NGLs and natural gas have been volatile, especially over the last several years, 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, NGLs 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.
The fair value of our unrealized crude oil derivative positions at June 30, 2025 was a net asset position of $61.9 million. A 10% increase in crude oil prices would reduce the fair value of this unrealized derivative asset position by approximately $54.5 million, while a 10% decrease in crude oil prices would increase the fair value of this unrealized derivative asset position by approximately $56.4 million. The fair value of our unrealized natural gas derivative positions at June 30, 2025 was a net liability position of $0.1 million. A 10% increase in natural gas prices would decrease the fair value of this unrealized derivative liability position by approximately $22.8 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative liability position by approximately $16.5 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.
In addition, in connection with the 2021 divestiture of certain oil and gas properties, we are 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 crude oil exceeds $60 per barrel for such year. As of June 30, 2025, the fair value of this contingent consideration was $23.7 million. In each of January 2024 and 2025, we received $25.0 million related to the 2023 and 2024 earn-out payments, respectively. See “Item 1. Financial Statements (Unaudited)—Note 6—Derivative Instruments” for additional information.
Interest rate risk. At June 30, 2025, we had $750.0 million of senior unsecured notes at a fixed interest rate of 6.750% per annum. At June 30, 2025, we had $180.0 million borrowings and $29.9 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, 2025, if interest rates were to increase by 100 basis points on the Credit Facility, the impact on the Company’s annual interest expense would not be material. 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.
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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 three and six months ended June 30, 2025, our credit losses on joint interest receivables were immaterial. 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.
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, 2025. 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, 2025.
Changes in internal control over financial reporting
On May 31, 2024, we completed the Arrangement. As part of the ongoing integration, we are in the process of incorporating the controls and related procedures of Enerplus. Other than incorporating Enerplus’ controls, there were no changes in internal control over financial reporting that occurred during the quarter ended June 30, 2025 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 2024 Annual Report. There have been no material changes in our risk factors from those described in our 2024 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, 2025:

Period |  | Total Number of Shares Exchanged(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)(3)
April 1 – April 30, 2025 |  | 573,025 |  |  | $ | 90.68 |  |  | 494,344 |  |  | $ | 331,154,738 |
May 1 – May 31, 2025 |  | 116,455 |  |  | 89.91 |  |  | 111,277 |  |  | 321,155,191 |
June 1 – June 30, 2025 |  | — |  |  | — |  |  | — |  |  | 321,155,191 |
Total |  | 689,480 |  |  | $ | 90.55 |  |  | 605,621 |  |  |

___________________
(1)During the second quarter of 2025, we withheld 83,859 shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.
(2)During the second quarter of 2025, we repurchased 605,621 shares of our common stock at a weighted average price of $90.80 per common share for a total cost of $55.0 million, excluding accrued excise tax of $0.5 million, under our publicly announced share repurchase program.
(3)Our Board of Directors had previously authorized a share repurchase program of up to $750 million of our common stock. In August 2025, the Board of Directors authorized a new share repurchase program covering up to $1.0 billion of common stock, which replaces the existing $750 million share repurchase program.
Item 5. — Other Information
Rule 10b5-1 trading arrangements. During the fiscal quarter ended June 30, 2025, 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
2.1 |  | Arrangement Agreement, dated as of February 21, 2024, by and among Chord Energy Corporation, Spark Acquisition ULC and Enerplus Corporation (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on February 26, 2024, and incorporated herein by reference).
3.1 |  | Fifth Amended and Restated Bylaws of Chord Energy Corporation (filed as Exhibit 3.5 to the Company’s Annual Report on Form 10-K on February 27, 2025, and incorporated herein by reference).
10.1 |  | Chord Energy Corporation Nonqualified Deferred Compensation Plan, effective as of April 1, 2025 (filed as Exhibit 4.6 to the Company’s Registration Statement on Form S-8 on June 20, 2025, and incorporated herein by reference).
10.2 |  | Chord Energy Corporation Nonqualified Deferred Compensation Plan Adoption Agreement, effective as of April 1, 2025 (filed as Exhibit 4.7 to the Company’s Registration Statement on Form S-8 on June 20, 2025, and incorporated herein by reference).
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.

___________________
(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.

|  |  |  |  |  |  | CHORD ENERGY CORPORATION
Date: | August 7, 2025 |  | By: |  | /s/ Daniel E. Brown
|  |  |  |  |  |  | Daniel E. Brown
|  |  |  |  |  |  | President and Chief Executive Officer (Principal Executive Officer)

|  |  |  |  | By: |  | /s/ Richard N. Robuck
|  |  |  |  |  |  | Richard N. Robuck
|  |  |  |  |  |  | Executive Vice President and Chief Financial Officer (Principal Financial Officer)

|  |  |  |  | By: |  | /s/ Lara J. Kroll
|  |  |  |  |  |  | Lara J. Kroll
|  |  |  |  |  |  | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)

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