Chord Energy (NASDAQ: CHRD) outlines reserves, cash returns and ESG focus
Filing Impact
Filing Sentiment
Form Type
10-K
Rhea-AI Filing Summary
Chord Energy Corporation is an independent oil and gas producer focused on the Williston Basin, with limited non-operated interests in the Marcellus Shale. Following its May 31, 2024 acquisition of Enerplus, the company reports integrated results through December 31, 2025.
As of year-end 2025, Chord held 1,302,921 net leasehold acres in the Williston Basin and operated 5,025 gross producing wells, with average 2025 production of 276,620 net Boepd. Independent engineers estimated 917.5 MMBoe of net proved reserves, 69% proved developed and 56% crude oil, yielding a PV-10 of $9.07 billion.
The company emphasizes capital discipline and shareholder returns, with a return of capital framework tied to leverage. It has a base dividend of $1.30 per share per quarter ($5.20 annualized) and a $1 billion share repurchase program, with $952.2 million remaining at December 31, 2025. Liquidity totaled $2,156.7 million, including $189.5 million in cash and $1,967.2 million of unused borrowing base capacity.
Chord highlights competitive strengths in its large, operated position in the Williston Basin, focus on free cash flow, and ESG initiatives, including substantial gas capture in North Dakota, emissions reduction planning and board-level oversight of safety and sustainability.
Positive
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Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________________
FORM 10-K
_______________________________________
| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the fiscal year ended December 31 , 2025
OR
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
Commission file number: 001-34776
(Exact name of registrant as specified in its charter) | ||
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||
| (Address of principal executive offices) | (Zip Code) | |||||||
( (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 | ||||||||||||
Securities Registered Pursuant to Section 12(g) of the Act:
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No ¨
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý
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 ý 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 ý No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or 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.
| ☒ | 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ý
Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $5,544,699,884
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 registrant’s common stock outstanding as of February 23, 2026: 56,842,530
_______________________________________
Documents Incorporated by Reference:
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CHORD ENERGY CORPORATION
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2025
TABLE OF CONTENTS
Glossary of Terms | 2 | |||||||
Cautionary Note Regarding Forward-Looking Statements | 5 | |||||||
Risk Factors Summary | 7 | |||||||
PART I | ||||||||
Item 1. | Business | 9 | ||||||
Item 1A. | Risk Factors | 28 | ||||||
Item 1B. | Unresolved Staff Comments | 49 | ||||||
Item 1C. | Cybersecurity | 49 | ||||||
Item 2. | Properties | 50 | ||||||
Item 3. | Legal Proceedings | 51 | ||||||
Item 4. | Mine Safety Disclosures | 51 | ||||||
PART II | ||||||||
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 52 | ||||||
Item 6. | [Reserved] | 53 | ||||||
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 54 | ||||||
Item 7A. | Quantitative and Qualitative Disclosures about Market Risk | 68 | ||||||
Item 8. | Financial Statements and Supplementary Data | 70 | ||||||
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 121 | ||||||
Item 9A. | Controls and Procedures | 121 | ||||||
Item 9B. | Other Information | 121 | ||||||
Item 9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 121 | ||||||
PART III | ||||||||
Item 10. | Directors, Executive Officers and Corporate Governance | 122 | ||||||
Item 11. | Executive Compensation | 122 | ||||||
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 122 | ||||||
Item 13. | Certain Relationships and Related Transactions, and Director Independence | 122 | ||||||
Item 14. | Principal Accountant Fees and Services | 122 | ||||||
PART IV | ||||||||
Item 15. | Exhibits, Financial Statement Schedules | 123 | ||||||
Item 16. | Form 10-K Summary | 126 | ||||||
Signatures | 127 | |||||||
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GLOSSARY OF TERMS
The terms defined in this section are used throughout this Annual Report on Form 10-K:
“ABR.” Alternate base rate.
“ARO.” Asset retirement obligations.
“ASC.” Accounting Standards Codification.
“ASU.” Accounting Standards Update.
“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, natural gas liquids or fresh water.
“Bcf.” One billion cubic feet of natural gas.
“Boe.” Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of crude oil.
“Boepd.” Barrels of oil equivalent per day.
“Bopd.” Barrels of oil per day.
“British thermal unit.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or crude oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“DD&A.” Depreciation, depletion and amortization.
“DAPL.” Dakota Access Pipeline.
“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Developed reserves.” Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of required equipment is relatively minor when compared to the cost of a new well.
“Development well.” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“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.
“Environmental assessment.” An environmental assessment, a study that can be required pursuant to federal law to assess the potential direct, indirect and cumulative impacts of a project.
“ESG.” Environmental, social and governance.
“Exploratory well.” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
“FASB.” Financial Accounting Standards Board.
“FDIC.” Federal Deposit Insurance Corporation.
“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.
“GHG(s).” Greenhouse Gas(es). Gases in the atmosphere known to trap heat, the most prevalent of which are carbon dioxide, methane, nitrous oxide and water vapor, among many others.
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“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval, which may include longer laterals and alternate shapes.
“MBbl.” One thousand barrels of crude oil, condensate, natural gas liquids or fresh water.
“MBoe.” One thousand barrels of oil equivalent.
“Mcf.” One thousand cubic feet of natural gas.
“MMBbl.” One million barrels of crude oil, condensate, natural gas liquids or fresh water.
“MMBoe.” One million barrels of oil equivalent.
“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.
“Possible reserves.” Additional reserves that are less certain to be recovered than probable reserves.
“Probable reserves.” Additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
“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.
“Proppant.” Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.
“Proved developed reserves.” Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
“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.
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“Proved undeveloped reserves” or “PUD reserves.” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
“PV-10.” When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.
“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.
“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
“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.
“Resource play.” An expansive contiguous geographical area with known accumulations of crude oil or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.
“SEC.” The U.S. Securities and Exchange Commission.
“SOFR.” Secured overnight financing rate as administered by the Federal Reserve Bank of New York.
“Spacing.” The distance between wells producing from the same reservoir.
“Standardized measure.” The present value of estimated future net cash flows from proved crude oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows.
“Turn-in-line” or “TIL” To turn a drilled and completed well online to begin sales.
“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.
“Well stimulation.” A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near-wellbore area. Stimulation in shale gas reservoirs typically takes the form of hydraulic fracturing treatments.
“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.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own crude oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
“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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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in or incorporated by reference into this Annual Report on Form 10-K, regarding, but not limited to, our strategic tactics, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report on Form 10-K, the words “aim,” “mission,” “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.
These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.
These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. In particular, the factors discussed below and detailed under “Part 1, Item 1A. Risk Factors,” “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report on Form 10-K 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.
We believe these factors and risks relate to forward-looking statements including, but not limited to, the following:
•crude oil, NGL and natural gas realized prices;
•uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil, NGL and natural gas;
•the actions taken by OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with production levels;
•changes in trade policies and regulations, including increases or change in duties, current and potentially new tariffs or quotas; and other similar measures, as well as the potential impact of retaliatory tariffs and other actions;
•war between Russia and Ukraine, military conflicts in the Red Sea Region and the wider Middle East and their effect on commodity prices;
•changes or uncertainty in general economic and geopolitical conditions;
•inflation rates and the impact of associated monetary policy responses, including fluctuating interest rates;
•logistical challenges and supply chain disruptions;
•our business strategy, including the continued implementation of our 4-mile well program;
•the geographic concentration of our operations;
•estimated future net reserves and present value thereof;
•timing and amount of future production of crude oil, NGL and natural gas;
•drilling and completion of wells;
•estimated inventory of wells remaining to be drilled and completed;
•costs of exploiting and developing our properties and conducting other operations;
•availability of drilling, completion and production equipment and materials;
•availability of qualified personnel;
•infrastructure for produced and flowback water gathering and disposal;
•gathering, transportation and marketing of crude oil, NGL and natural gas in the Williston Basin and other regions in the United States;
•the possible shutdown of the Dakota Access Pipeline;
•our ability to realize the anticipated benefits from acquisitions;
•property acquisitions and divestitures;
•integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness;
•the amount, nature and timing of capital expenditures;
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•availability and terms of capital;
•our financial strategic tactics, budget, projections, execution of business plan and operating results;
•cash flows and liquidity;
•our ability to pursue goals regarding capital management activities such as share repurchases, paying dividends on our common stock or additional means to return capital to shareholders;
•our ability to utilize net operating loss carryforwards or other tax attributes in future periods;
•our ability to comply with the covenants under our Credit Facility and other indebtedness;
•operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
•interruptions in service and fluctuations in tariff provisions of third-party connecting pipelines;
•potential disruptions arising from cybersecurity threats, terrorist attacks and any consequential or other hostilities;
•compliance with, and changes in, environmental, safety and other laws and regulations;
•execution of our sustainability initiatives;
•effectiveness of risk management activities;
•competition in the oil and gas industry;
•counterparty credit risk;
•incurring environmental liabilities;
•developments in the global economy as well as any public health crisis and resulting demand and supply for crude oil, NGL and natural gas;
•governmental regulation, including, but not limited to, that of the Federal Energy Regulatory Commission (“FERC”), and the taxation of the oil and gas industry;
•developments in crude oil-producing and natural gas-producing countries;
•integration of emerging technologies, including artificial intelligence and machine learning technologies for improving operational efficiency;
•consumer demand and preferences for, and governmental policies encouraging, fossil fuel alternatives;
•the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;
•uncertainty regarding future operating results;
•our ability to successfully forecast future operating results and manage activity levels with ongoing macroeconomic uncertainty;
•the impact of disruptions in the financial markets, including bank failures and the volatile interest rate environment;
•plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical; and
•certain factors discussed elsewhere in this Annual Report on Form 10-K.
In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise. You should not place undue reliance on these forward-looking statements. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
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Risk Factors Summary
The following is a summary of some of the principal risks that could materially adversely affect our business, financial condition and results of operations. You should read this summary together with the more detailed description of each risk factor contained in “Part I, Item 1A. Risk Factors.”
Risks related to the oil and gas industry and our business
•Global geopolitical tensions may create heightened volatility in crude oil, NGL and natural gas prices and could adversely affect our business, financial condition and results of operations.
•Adverse developments affecting the financial markets, such as bank failures, the potential for the Federal Reserve to increase interest rates or an extended period of elevated interest rates, as well as the potential for a U.S. government shutdown, could adversely affect our current and projected business operations, financial condition, results of operations and liquidity.
•A substantial or extended decline in commodity prices, for crude oil and, to a lesser extent, NGL and natural gas, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
•The ability or willingness of OPEC+ to set and maintain production levels has a significant impact on oil prices.
•Drilling for and producing crude oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. We use some of the latest available horizontal drilling and completion techniques, which involve risk and uncertainty in their application.
•Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate.
•The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services or the unavailability of sufficient transportation for our production could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
•Substantially all of our producing properties and operations are located in the Williston Basin, making us vulnerable to risks associated with operating in a concentrated geographic area.
•We depend upon a limited number of midstream providers for a large portion of our midstream services, and our failure to obtain and maintain access to the necessary infrastructure from these providers to successfully deliver crude oil, natural gas and NGL to market may adversely affect our earnings, cash flows and results of operations.
•The development of our PUD reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
•Drilling locations are scheduled to be drilled over several years and may not yield crude oil, NGL or natural gas in commercially viable quantities.
•Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed. Failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
•We are not the operator of all of our drilling locations, and, therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.
•Our operations are subject to federal, state (provincial in Canada) and local laws and regulations related to environmental and natural resources protection and occupational health and safety, which may expose us to significant costs and liabilities and may result in increased costs and additional operating restrictions or delays.
•Our financial results could be impacted by uncertainty in U.S. trade policy, including uncertainty surrounding changes in tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments.
•Failure to comply with federal, state and local laws and regulations could adversely affect our ability to produce, gather and transport our crude oil, NGL and natural gas and may result in substantial penalties.
•We expect to consider from time to time further strategic opportunities that may involve acquisitions, dispositions, investments in joint ventures, partnerships and other strategic alternatives that may enhance stockholder value, any of which may result in the use of a significant amount of our management resources or significant costs, and we may not be able to fully realize the potential benefit of such transactions.
•Stakeholder and market attention to matters related to corporate responsibility, including in the oil and gas industry, may impact our business and ability to secure financing.
•Our operations are subject to a series of risks arising out of the threat of climate change, energy conservation measures or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, restrictions on drilling and reduced demand for the crude oil and natural gas that we produce.
•Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of crude oil and natural gas wells and adversely affect our production.
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•Laws and regulations pertaining to the protection of threatened and endangered species or to critical habitat, wetlands and natural resources could delay, restrict or prohibit our operations and cause us to incur substantial costs that may have a material adverse effect on our development and production of reserves.
•Our ability to produce crude oil, NGL and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
•Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil, NGL and natural gas and secure and retain trained personnel.
•Seasonal weather conditions could adversely affect our ability to conduct drilling activities in some of the areas where we operate.
•We may be subject to risks in connection with acquisitions because of integration difficulties, uncertainties in evaluating recoverable reserves, well performance and potential liabilities and uncertainties in forecasting crude oil, NGL and natural gas prices and future development, production and marketing costs.
•We may incur losses as a result of title defects in the properties in which we invest.
•Disputes or uncertainties may arise in relation to our royalty obligations.
Risks related to our financial position
•Increased costs of capital could adversely affect our business.
•Our revolving credit facility and the indentures governing our senior unsecured notes contain operating and financial restrictions that may restrict our business and financing activities.
•Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil, NGL and natural gas reserves.
•Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes or fees may adversely affect our operations and cash flows.
•We may not be able to utilize all or a portion of our net operating loss carryforwards or other tax benefits to offset future taxable income for U.S. federal or state or Canadian federal tax purposes, which could adversely affect our financial position, results of operations and cash flows.
•The cost of servicing, and the ability to generate enough cash flows to meet our current or future debt obligations could adversely affect our business. Those risks could increase if we incur more debt.
Risks related to our common stock
•Our ability to declare and pay dividends is subject to certain considerations and limitations.
•Our amended and restated certificate of incorporation, as amended, and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
•The issuance of stock-based awards may dilute your holding of shares of our common stock.
General risk factors
•Involvement in legal, governmental and regulatory proceedings could result in substantial liabilities.
•Our profitability may be negatively impacted by inflationary pressures in the cost of labor, materials and services and general economic, business or industry conditions.
•Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations and could result in information theft or data corruption.
•We face risks associated with disruptive technologies, innovation and competition, including artificial intelligence.
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PART I
Item 1. Business
Overview
Chord Energy Corporation, a Delaware Corporation (together with our consolidated subsidiaries, the “Company,” “Chord,” “we,” “us,” or “our”), is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, NGL and natural gas primarily in the Williston Basin with limited non-operated interests in the Marcellus Shale. Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a fun and rewarding environment for our employees. We are ideally positioned to generate strong free cash flow and enhance return of capital, while being responsible stewards of the communities and environment where we operate.
On May 31, 2024, we acquired Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”) in a stock-and-cash transaction (such transaction, the “Arrangement”). The results of operations and reserves data presented herein report the results of legacy Chord from January 1, 2023 through May 30, 2024 and the results of Chord (including legacy Enerplus) from May 31, 2024 through December 31, 2025, unless otherwise noted.
As of December 31, 2025, we had 1,302,921 net leasehold acres in the Williston Basin, approximately all of which is held by production. We are currently exploiting significant resource potential from the Middle Bakken and Three Forks formations, which are present across a substantial portion of our acreage. We believe the locations, size and concentration of our acreage in the Williston Basin creates an opportunity for us to achieve cost, recovery and production efficiencies through the development of our project inventory. Our management team has a proven record of accomplishment in identifying, acquiring and executing large, repeatable development drilling programs and has substantial experience in the Williston Basin.
As of December 31, 2025, we had 5,025 gross (3,937.3 net) operated producing wells. Our working interest for producing wells averaged 78% in the wells we operate. During the year ended December 31, 2025, we had average daily production of 276,620 net Boepd. As of December 31, 2025, Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, estimated our net proved reserves to be 917.5 MMBoe, of which 69% were classified as proved developed and 56% were crude oil.
Business Strategy
Our operational and financial strategy is focused on rigorous capital discipline and generating significant, sustainable free cash flow by executing on the following strategic priorities:
•Maximize returns. We intend to efficiently execute our development program and optimize capital allocation, while evaluating our performance and focusing on continuous improvement. We have established a strong capital allocation framework with the objective of balancing stockholder returns and reinvestment of capital. We are focused on conservative capital allocation, delivering low reinvestment rates and returning significant capital to stockholders at mid-cycle oil prices. Since introducing our return of capital program in 2021, we have declared an aggregate amount of cash dividends to our stockholders of $61.19 per share of common stock and repurchased an aggregate amount of $1.3 billion shares of common stock.
Our scale and high-quality assets in the Williston Basin allow us to generate significant, sustainable cash flow to support maximizing returns at mid-cycle oil prices. We expect that our business strategy will continue to provide sizable cash flow generation which will enable us to return capital to our stockholders and continue to pursue acquisitions that add to or lengthen our inventory, while maintaining a strong balance sheet. We have a return of capital program designed to provide peer-leading, sustainable stockholder returns. The return of capital plan includes a base cash dividend of $1.30 per share per quarter ($5.20 per share annualized) and a $1 billion share repurchase program, which the Board of Directors authorized during the third quarter of 2025.
As of December 31, 2025, we had $952.2 million remaining under this share repurchase program. We plan to return capital through the base dividend payout, supplemented by opportunistic share repurchases and variable dividends.
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We expect to return a certain percentage of adjusted free cash flow (“Adjusted FCF”) each quarter, with the targeted percentage based on free cash flow generated during the previous quarter and projected leverage (defined as the ratio of (i) the sum of our aggregate outstanding debt, less cash and cash equivalents held as of the balance sheet date, to (ii) our estimated earnings before interest, taxes, depreciation and amortization for the next twelve months at $65/Bbl WTI and $3/MMBtu Henry Hub, excluding the impact of commodity derivative instruments) under the following framework:
•Below 0.5x leverage: | 75%+ of Adjusted FCF | ||||
•Below 1.0x leverage: | 50%+ of Adjusted FCF | ||||
•>1.0x leverage: | Base dividend+ ($5.20 per share annualized) | ||||
•Financial strength. Our management team is focused on maintaining a solid risk management process to preserve a strong balance sheet and protect our cash generation capabilities. Recognizing the oil and gas industry is cyclical, our business is designed to navigate challenging environments while preserving sufficient liquidity in an effort to be opportunistic in low commodity price cycles.
As of December 31, 2025, we had $2,156.7 million of liquidity available, including $189.5 million of cash and cash equivalents and $1,967.2 million of unused borrowing base capacity available under the Credit Facility (defined in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”).
•Commitment to excellence. We are focused on creating a durable organization that generates strong financial returns and sustainable free cash flow through commodity cycles. We believe we have an attractive inventory that is resilient to commodity price fluctuations, which supports the sustainable generation of free cash flow. Our management team is focused on the continuous improvement of our operations and overall cost structure and has robust experience in successfully operating cost-efficient development programs. The magnitude and concentration of our acreage within the Williston Basin allows us to capture economies of scale, including the ability to drill longer lateral lengths for developmental wells, the ability to drill multiple wells from a single drilling pad into multiple formations, the ability to utilize centralized production and crude oil, natural gas and water fluid handling facilities and infrastructure, and reduce the time and cost of rig mobilization.
We have extensive engineering, operational, geologic and subsurface technical knowledge. Our technical team has access to an abundance of digital well log, seismic, completion, production and other subsurface information, which is analyzed in order to accurately and efficiently characterize the anticipated performance of our oil and gas reservoirs. We leverage many technologies in support of data gathering, information analysis and production optimization. Data management and reporting practices improve the availability, accuracy and analysis of our information in a cycle of continuous improvement. Emerging technologies are evaluated on a regular basis, ensuring we are implementing the best technologies for our business needs.
Our team is focused on employing leading drilling and completions techniques to optimize overall project economics. We continuously evaluate our internal drilling and completions results and monitor the results of other operators to improve our operating practices. We continue to optimize our completion designs based on geology and well spacing.
We foster a culture of innovation and continuous improvement, constantly looking for ways to strengthen our organizational agility and adaptability. Management, with oversight from the Board of Directors, is focused on enterprise risk management (“ERM”), which seeks to establish guidelines and policies for appropriate risk assessment and risk management, including exposure to safety risk, financial risk, commodity price risk and cybersecurity risk. The Audit and Reserves Committee of our Board of Directors reviews our cybersecurity guidelines and policies and receives updates on cybersecurity matters at least semi-annually. In addition, we have established cybersecurity practices that are guided by the National Institute of Standards and Technology, require quarterly cybersecurity training of our employees and receive an annual audit and penetration assessment by a third party. Our ERM program allows us to have a better enterprise-view of risks, improve our risk response and preparedness and better incorporate risk mitigation around existing and emerging risks into our strategic plans.
•Responsible stewards. We seek to maintain a culture of continuous improvement in ESG practices as outlined here in this Annual Report on Form 10-K and in our Sustainability Report. We strive to provide reliable, safe and affordable energy in a responsible manner against the backdrop of an evolving energy landscape. The key tenets of our ESG philosophy are to always put safety first, minimize our environmental impact, reduce our emissions intensity, promote an inclusive, merit-based culture, align executive compensation with long-term value creation and stockholder interests, and support programs that benefit the communities in which we operate.
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From a safety standpoint, our corporate, field and environmental, health and safety teams are continually assessing and enhancing best practices and training to minimize the likelihood and severity of safety incidents among employees and contractors. Our goal is to create an environment where everyone on a Chord location is safe. We work to always put safety first, to be diligent and never complacent. We expect the same of any service provider or partner that works with us.
We continue to make strides in reducing Scope 1 GHG emissions, and in particular methane emissions. To help maintain the trend of continuous improvement, our cross-functional emissions reduction team has developed a more robust process to identify and prioritize emissions reduction opportunities, through the creation of a Marginal Abatement Cost Curve (“MACC”). A MACC is a decision-making tool that ranks emissions reduction options based on their cost-effectiveness and potential impact, allowing us to prioritize the most efficient strategies for potential emissions reduction. We have developed a MACC to help guide our carbon management investments.
We continue to strive to align our Scope 1 and Scope 2 disclosures towards various frameworks, including the Task Force on Climate-related Financial Disclosures (“TCFD”), the Sustainability Accounting Standards Board's (“SASB”) Extractives & Minerals Processing Sector: Oil & Gas - Exploration and Production Standard, the Global Reporting Initiative (“GRI”) Standard for Oil and Gas, and the American Exploration and Production Council (“AXPC”) ESG Metrics Framework. We also are proficient in capturing the natural gas that we produce, and, as of December 31, 2025, we were capturing substantially all of our natural gas production in North Dakota.
We provide leadership training and educational and professional development programs for employees at every level of the organization. We have also made meaningful investments in safety training programs that benefit our employees and contractors. We are deeply involved in the communities in which we work and deploy our financial resources, time and talent to support a number of charitable organizations.
We have a short-tenured and highly capable Board of Directors that is comprised of experienced energy industry professionals with a variety of diverse perspectives and that is 82% independent. In 2024, the Board of Directors established the Safety and Sustainability Committee, which is charged with overseeing our ESG strategies, policies and goals. For more information about our ESG and corporate responsibility efforts, please see the “Sustainability” page of our website and the Proxy Statement that we will file for our 2026 Annual Meeting of Stockholders.
Competitive Strengths
We have a number of competitive strengths that we believe will help us successfully execute our business strategies:
•Substantial leasehold position and existing production in one of North America’s leading unconventional crude oil resource plays. We believe that our Williston Basin acreage represents a premier position in a top oil basin in the United States that will continue to provide significant free cash flow generation. As of December 31, 2025, we had 1,302,921 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin, approximately all of which is held by production. As of December 31, 2025, approximately 56% of our 917.5 MMBoe estimated net proved reserves were comprised of crude oil. We believe we have a large project inventory of potential drilling locations that we have not yet drilled, the majority of which are operated by us.
•Operating control over the majority of our portfolio. In order to maintain control over our asset portfolio, we have established a leasehold position comprised largely of properties that we expect to operate. As of December 31, 2025, 89% of our estimated net proved reserves were attributable to properties that we operate. In 2026, we plan to TIL approximately 135 to 165 gross operated wells with an average working interest of approximately 75%. Controlling operations enables us to optimize capital allocation and control the pace of development of our assets to manage our reinvestment rates in line with our broader strategic objectives. Additionally, operational control allows us to materially benefit from proactively managing our cost structure across our portfolio. We believe that maintaining operational control over the majority of our acreage allows us to better pursue our strategies of enhancing returns through operational, cost and capital efficiencies and allows us to better manage infrastructure investment to drive down operating costs and optimize price realizations.
•Balance sheet among best-in-class. We believe a strong balance sheet provides us flexibility through volatile price environments and allows us to generate significant, sustainable free cash flow and corporate-level returns. We have no near-term debt maturities, are focused on rigorous capital discipline and have a hedging program to minimize downside risk.
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•Incentivized management team with proven operating and acquisition skills. Our senior management team has extensive expertise in the oil and gas industry with an average of 25 years of industry experience. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven record of accomplishment in identification, acquisition and execution of large, repeatable development drilling programs. In addition, a substantial majority of our executive officers’ overall compensation is in long-term equity-based incentive awards, and we have implemented leading management compensation practices aligned with stockholders, which we believe provides our executive officers with significant incentives to grow the value of our business and return capital to stockholders.
Exploration and Production Operations
Estimated net proved reserves
Our estimated net proved reserves and related PV-10 at December 31, 2025, 2024 and 2023 are based on reports independently prepared by NSAI, our independent reserve engineers. NSAI evaluated 100% of the reserves and discounted values at December 31, 2025, 2024 and 2023 in accordance with the rules and regulations of the SEC applicable to companies involved in crude oil, NGL and natural gas producing activities. Our estimated net proved reserves and related standardized measure of discounted future net cash flows (“Standardized Measure”) and PV-10 do not include probable or possible reserves and were determined using the preceding 12 month unweighted arithmetic average of the first-day-of-the-month index prices for crude oil and natural gas (the “SEC Price”), which were held constant throughout the life of the properties. See “Item 8. Financial Statements and Supplementary Data—Note 23—Supplemental Oil and Gas Reserve Information — Unaudited” for additional information about our estimated net proved reserves.
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The following table summarizes our estimated net proved reserves based upon the SEC Price:
| At December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Estimated proved reserves: | |||||||||||||||||
| Crude oil (MMBbls) | 514.7 | 503.4 | 368.4 | ||||||||||||||
| NGL (MMBbls) | 174.1 | 167.2 | 138.2 | ||||||||||||||
| Natural gas (Bcf) | 1,372.1 | 1,274.7 | 777.9 | ||||||||||||||
| Total estimated proved reserves (MMBoe) | 917.5 | 883.0 | 636.2 | ||||||||||||||
| Percent crude oil | 56 | % | 57 | % | 58 | % | |||||||||||
| Estimated proved developed reserves: | |||||||||||||||||
| Crude oil (MMBbls) | 314.5 | 317.7 | 241.4 | ||||||||||||||
| NGL (MMBbls) | 127.1 | 125.8 | 105.7 | ||||||||||||||
| Natural gas (Bcf) | 1,127.9 | 1,053.3 | 640.2 | ||||||||||||||
| Total estimated proved developed reserves (MMBoe) | 629.6 | 619.1 | 453.8 | ||||||||||||||
| Percent proved developed | 69 | % | 70 | % | 71 | % | |||||||||||
| Estimated proved undeveloped reserves: | |||||||||||||||||
| Crude oil (MMBbls) | 200.2 | 185.7 | 127.0 | ||||||||||||||
| NGL (MMBbls) | 47.0 | 41.4 | 32.5 | ||||||||||||||
| Natural gas (Bcf) | 244.2 | 221.4 | 137.8 | ||||||||||||||
| Total estimated proved undeveloped reserves (MMBoe) | 288.0 | 264.0 | 182.4 | ||||||||||||||
Standardized Measure (GAAP) (in millions)(1) | $ | 7,450.6 | $ | 8,354.2 | $ | 6,990.6 | |||||||||||
PV-10 (Non-GAAP) (in millions)(2): | |||||||||||||||||
| Proved developed PV-10 | $ | 6,409.1 | $ | 7,519.9 | $ | 6,572.4 | |||||||||||
| Proved undeveloped PV-10 | 2,663.3 | 2,742.7 | 1,956.1 | ||||||||||||||
| Total PV-10 (Non-GAAP) | $ | 9,072.4 | $ | 10,262.6 | $ | 8,528.5 | |||||||||||
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(1)Standardized Measure represents the present value of estimated future net cash flows from proved crude oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows.
(2)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable financial measure under GAAP, because it does not include the effect of income taxes on discounted future net cash flows. See “Reconciliation of Standardized Measure to PV-10” below.
Reconciliation of Standardized Measure to PV-10
PV-10 is derived from Standardized Measure, which is the most directly comparable financial measure under GAAP. PV-10 is equal to Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and gas properties. PV-10, however, is not a substitute for Standardized Measure. Our PV-10 measure and Standardized Measure do not purport to represent the fair value of our crude oil and natural gas reserves.
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The following table provides a reconciliation of Standardized Measure to PV-10:
| At December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Standardized Measure of discounted future net cash flows | $ | 7,450.6 | $ | 8,354.2 | $ | 6,990.6 | |||||||||||
| Add: present value of future income taxes discounted at 10% | 1,621.8 | 1,908.4 | 1,537.9 | ||||||||||||||
| PV-10 | $ | 9,072.4 | $ | 10,262.6 | $ | 8,528.5 | |||||||||||
Independent petroleum engineers
Our estimated net proved reserves and PV-10 at December 31, 2025, 2024 and 2023 are based on reports independently prepared by NSAI, our independent reserve engineers, by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revised June 2019) (the “Estimating and Auditing Standards”) and definitions and current guidelines established by the SEC. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699.
Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Richard B. Talley, Jr. and Mr. Edward C. Roy III. Mr. Talley, a Licensed Professional Engineer in the State of Texas (No. 102425), has been practicing as a petroleum engineering consultant at NSAI since 2004 and has over 5 years of prior industry experience. He graduated from University of Oklahoma in 1998 with a Bachelor of Science degree in Mechanical Engineering and from Tulane University in 2001 with a Master of Business Administration degree. Mr. Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 2364), has been practicing as a petroleum geoscience consultant at NSAI since 2008 and has over 11 years of prior industry experience. He graduated from Texas Christian University in 1992 with a Bachelor of Science degree in Geology and from Texas A&M University in 1998 with a Master of Science degree in Geology. Both technical principals meet or exceed the education, training and experience requirements set forth in the Estimating and Auditing Standards. In addition, both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations, as well as applying SEC and other industry reserves definitions and guidelines.
Technology used to establish proved reserves
In accordance with rules and regulations of the SEC applicable to companies involved in crude oil and natural gas producing activities, proved reserves are those quantities of crude oil and natural 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. The term “reasonable certainty” means deterministically, the quantities of crude oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the Estimating and Auditing Standards. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.
Based on the current stage of field development, production performance, the development plans provided by us to NSAI and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.
A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the evaluation of all reserves categories. Performance-based methodology primarily includes (i) production diagnostics, (ii) decline-curve analysis and (iii) model-based analysis (if necessary, based on the availability of data). Production diagnostics include data quality control, identification of flow regimes and characteristic well performance behavior. Analysis was performed for all well groupings (or type-curve areas).
Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well
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performance and complex situations sourced by the nature of unconventional reservoirs. The methodology used for the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production history and appropriate reserves definitions.
Internal controls over reserves estimation process
We employ NSAI as the independent preparer for 100% of our reserves. We maintain an internal staff of petroleum engineers who work closely with the independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished for the reserves estimation process. Our Senior Director, Corporate Planning & Reserves is responsible for overseeing the preparation of the reserves estimates under the supervision of our Executive Vice President and Chief Financial Officer. Our Senior Director, Corporate Planning & Reserves has more than 15 years of broad reservoir engineering experience in the oil and gas industry, focused across conventional and unconventional evaluation and development projects, including corporate reserves estimations. He holds a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines and is a member of the Society of Petroleum Engineers.
Throughout each fiscal year, our technical team meets with the independent reserve engineers to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to the following:
•Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in our reserves database;
•Review of working interests and net revenue interests in our reserves database against our well ownership system;
•Review of historical realized prices and differentials from index prices as compared to the differentials used in our reserves database;
•Review of updated capital costs prepared by our operations team;
•Review of internal reserve estimates by well and by area by our internal reservoir engineers;
•Discussion of material reserve variances among our internal reservoir engineers;
•Review of the reserves report by members of our senior management team, including our President & Chief Executive Officer; Executive Vice President & Chief Operating Officer; Executive Vice President, Chief Strategy Officer & Chief Commercial Officer; Executive Vice President & Chief Financial Officer and Senior Director, Corporate Planning & Reserves; and
•Review of our reserves estimation process and the reserves report by our Audit and Reserves Committee and NSAI on an annual basis.
Production, price and cost history
We produce and market crude oil, NGL and natural gas, which are commodities. The prices that we receive for the crude oil, NGL and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, access to markets, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of crude oil, NGL or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. Please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business” for additional information on risks associated with commodity prices. Please also see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Market Conditions” for additional information on market demand.
The following table sets forth information regarding our crude oil, NGL and natural gas production, realized prices and production costs for the periods presented.
The Arrangement was accounted for as of May 31, 2024. Accordingly, the results of operations presented herein report the results of Chord prior to the closing of the Arrangement on May 31, 2024 and the results of Chord (including legacy Enerplus) from May 31, 2024 through December 31, 2025. For additional information on price calculations, please see information set forth in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Net production volumes: | |||||||||||||||||
| Crude oil (MBbls) | 56,500 | 48,479 | 36,427 | ||||||||||||||
| NGL (MBbls) | 19,149 | 16,338 | 13,047 | ||||||||||||||
| Natural gas (MMcf) | 151,903 | 122,193 | 82,953 | ||||||||||||||
| Oil equivalents (MBoe) | 100,966 | 85,182 | 63,300 | ||||||||||||||
| Average daily production (Boepd) | 276,620 | 232,737 | 173,425 | ||||||||||||||
| Average sales prices: | |||||||||||||||||
| Crude oil, without derivative settlements (per Bbl) | $ | 62.78 | $ | 73.67 | $ | 77.85 | |||||||||||
Crude oil, with derivative settlements(1) (per Bbl) | 63.59 | 73.69 | 70.92 | ||||||||||||||
| NGL, without derivative settlements (per Bbl) | 7.22 | 9.92 | 13.62 | ||||||||||||||
NGL, with derivative settlements(1) (per Bbl) | 7.22 | 9.92 | 13.84 | ||||||||||||||
| Natural gas, without derivative settlements (per Mcf) | 1.40 | 0.84 | 1.43 | ||||||||||||||
Natural gas, with derivative settlements(1) (per Mcf) | 1.51 | 0.84 | 1.35 | ||||||||||||||
| Average costs (per Boe): | |||||||||||||||||
| Lease operating expenses | 9.73 | 9.68 | 10.41 | ||||||||||||||
| Gathering, processing and transportation expenses | 2.88 | 3.14 | 2.85 | ||||||||||||||
| Production taxes | 2.89 | 3.91 | 4.11 | ||||||||||||||
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(1)Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes. The effect of derivative settlements includes the gains or losses on commodity derivatives for contracts ending within the periods presented.
Acreage
The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2025. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.
| Gross | Net | ||||||||||
| Developed acres | 2,402,451 | 1,256,495 | |||||||||
| Undeveloped acres | 174,162 | 78,184 | |||||||||
| Total acres | 2,576,613 | 1,334,679 | |||||||||
Our total net leasehold position shown in the table above includes 1,302,921 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin. At December 31, 2025, our total acreage that is held by production increased to 1,324,535 net acres from 1,283,462 net acres at December 31, 2024.
The following table sets forth the number of gross and net undeveloped acres as of December 31, 2025 that will expire over the next three years unless production is established on the acreage prior to the expiration dates:
| Undeveloped acres expiring | |||||||||||
| Gross | Net | ||||||||||
| Year ending December 31, | |||||||||||
| 2026 | 2,126 | 1,597 | |||||||||
| 2027 | 426 | 240 | |||||||||
| 2028 | 742 | 470 | |||||||||
We have not assigned any PUD reserves to locations scheduled to be drilled after lease expiration.
Productive wells
As of December 31, 2025, we had 10,528 (4,415.0 net) total gross productive wells, of which 5,025 gross (3,937.3 net) productive wells were operated by us. Substantially all of our productive wells as of December 31, 2025 were horizontal wells.
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Drilling and completion activity
The following table summarizes the number of gross and net wells completed during the periods presented, regardless of when drilling was initiated.
| Year ended December 31, | |||||||||||||||||||||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||
| Development wells: | |||||||||||||||||||||||||||||||||||
Oil(1) | 242 | 107.7 | 189 | 103.9 | 111 | 66.9 | |||||||||||||||||||||||||||||
Gas(2) | 65 | 1.4 | 2 | 0.1 | — | — | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Total development wells | 307 | 109.1 | 191 | 104.0 | 111 | 66.9 | |||||||||||||||||||||||||||||
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(1)All completed oil wells are located in the Williston Basin.
(2)All completed gas wells are located within our non-operated interests in the Marcellus Shale.
During the years ended December 31, 2025, 2024 and 2023, there were no exploratory wells completed.
As of December 31, 2025, we had 105 gross (82.4 net) wells in the process of being drilled or completed, which included 88 gross operated wells waiting on completion and no gross non-operated wells drilling or completing.
As of December 31, 2025, we had four operated rigs running, and we expect to run four to five operated rigs during the majority of 2026.
Description of properties
As of December 31, 2025, our operations were focused in the North Dakota and Montana areas of the Williston Basin targeting the Middle Bakken and Three Forks formations. We are the top producer in the Williston Basin, and we have the largest acreage position of any operator in the Williston Basin. We focus our operations in the Williston Basin because of its high oil content, multiple producing horizons, substantial resource potential and management’s previous professional history in the basin. In addition, the Williston Basin provides a unique opportunity to efficiently drill and develop long laterals across large connected blocks that can improve capital efficiency and well-level returns. The Williston Basin also generally has established infrastructure and access to materials and services.
Marketing
We principally sell our crude oil, NGL and natural gas production to refiners, marketers and other purchasers that have access to nearby pipeline and rail facilities. In an effort to improve price realizations, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGL and natural gas to a broad array of potential purchasers. We sell a significant amount of our crude oil production through bulk sales at delivery points on crude oil gathering systems to a variety of purchasers at prevailing market prices under short-term contracts that normally provide for us to receive a market-based price, which incorporates regional differentials that include, but are not limited to, transportation costs. These gathering systems, which typically originate at the wellhead and are connected to multiple pipeline and rail facilities, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of December 31, 2025, substantially all of our gross operated crude oil and natural gas production was connected to gathering systems. In addition, from time to time we may enter into third-party purchase and sales transactions to, among other things, improve price realizations, optimize transportation costs, blend to meet pipeline specifications or to cover production shortfalls. We also enter into various sales contracts for a portion of our portfolio at fixed differentials. We believe that the loss of any individual purchaser would not have a long-term material adverse impact on our financial position or results of operations, as alternative customers and markets for the sale of our products are readily available in the areas in which we operate.
Our marketing of crude oil, NGL and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business.”
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Delivery commitments
As of December 31, 2025, we had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 40.6 MMBbl of crude oil, 10.6 MMBbl of NGL, 335.6 Bcf of natural gas and 12.0 MMBbl of water within specified timeframes. We are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. We believe that for the substantial majority of these agreements, our future production will be adequate to meet our delivery commitments or that we can purchase sufficient volumes of crude oil, NGL and natural gas from third parties to satisfy our minimum volume commitments.
Competition
There is a high degree of competition in the oil and gas industry for acquiring properties, obtaining investment capital, securing oil field goods and services, marketing crude oil, NGL and natural gas products and attracting and retaining qualified personnel. Certain of our competitors possess and employ financial, technical and personnel resources greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and gas properties and exploratory prospects, better sustain production in periods of low commodity prices and evaluate, bid for and purchase a greater number of properties and prospects than our resources permit. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation or regulation enacted by state, local and U.S. government bodies and their associated agencies, especially with regard to environmental protection and climate-related policies. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or the resultant effects on our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing crude oil, NGL and natural gas and our larger competitors may be able to better absorb the burden of such legislation and regulation, which would also adversely affect our competitive position. See “Regulation” below as well as Item 1A. Risk Factors within this Annual Report on Form 10-K for more information on and the potential associated risks resulting from existing and future legislation and regulation of our industry.
Additionally, the unavailability or high cost of drilling rigs, completion crews or other equipment and services could delay or adversely affect our development and exploration operations. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to obtain necessary capital as well as evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil, NGL and natural gas and secure and retain trained personnel.”
In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources, such as wind, solar, nuclear, coal, hydrogen and biofuels as well as the impact of climate change activism, fuel conservation measures and governmental requirements for renewable energy sources, could adversely affect our revenues. See “Item 1A. Risk Factors—Our operations are subject to a series of risks arising out of the threat of climate change, energy conservation measures or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, restrictions on drilling and reduced demand for the crude oil and natural gas that we produce.”
Title to Properties
As is customary in the oil and gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant title defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with general industry standards. Prior to completing an acquisition of producing crude oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and gas properties are subject to customary royalty and other interests, liens to secure borrowings under our revolving credit facility, and liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect our carrying value of the properties. Please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—Risks related to the oil and gas industry and our business—We may incur losses as a result of title defects in the properties in which we invest.”
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Seasonality
Winter weather conditions and lease stipulations can limit or temporarily halt our drilling, completion and producing activities and other oil and gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting our drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.
Regulation
Our E&P operations are substantially affected by extensive federal, tribal, regional, state and local laws and regulations. In particular, our operations are subject to laws and regulations related to well permitting, drilling and completion, and to the production, transportation and sale of crude oil, NGL and natural gas. Such laws and regulations are frequently amended or reinterpreted. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, federal agencies, state and local governments and the courts.
The regulatory burden on our industry increases the cost of doing business and affects profitability. Historically, our compliance costs with applicable laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations; however, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement may occur and, thus, there can be no assurance that such costs will not be material in the future. We cannot predict when or whether any such proposals may become effective and we are unable to predict the future costs or impact of compliance.
Regulation of production
The production of crude oil, NGL, and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Such statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own and operate properties in North Dakota and Montana, which have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of crude oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations. The failure to comply with these rules and regulations can result in substantial penalties.
Regulation of transportation of oil
Our sales of oil are affected by the availability, terms and cost of transportation of such oil. The interstate transportation of oil by pipeline is subject to U.S. federal regulation, including regulation of terms, conditions and rates, primarily by the FERC pursuant to the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products, be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. Intrastate oil pipeline transportation rates are generally subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state.
We sell a significant amount of our crude oil production through gathering systems connected to rail facilities. The transportation of Bakken crude oil is subject to extensive federal regulation by the U.S. Pipeline and Hazardous Materials Safety Administration (“PHMSA”). In the past several years, transportation safety regulators have increased scrutiny with respect to crude oil testing, accurate hazard classification and railroad tank car standards. While we do not currently own or operate rail transportation facilities or rail cars, costs incurred by the railroad industry to comply with these enhanced standards may increase our costs of doing business or limit our ability to transport and sell our crude oil at favorable prices.
Regulation of transportation of natural gas
The transportation of natural gas in interstate commerce is regulated by FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. FERC regulates interstate natural gas pipeline transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. The regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
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Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines. Changes in law and to FERC and state utility commission policies and regulations also may result in increased regulation of our business and operations, and we cannot predict what future action FERC or any state utility commission will take.
Regulation of sales of crude oil, NGL, and natural gas
The prices at which we sell crude oil, NGL, and natural gas are not currently subject to federal regulation and, for the most part, are not subject to state regulation. FERC, however, regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. Similarly, the price we receive from the sale of oil and NGL is affected by the cost of transporting those products to market. In addition, while sales by producers of natural gas and all sales of crude oil, condensate and NGL can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
With regard to our physical sales of energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission (“CFTC”) and the Federal Trade Commission (“FTC”). Should we violate these laws and regulations, we may be subject to civil penalties imposed by regulatory agencies, as well as related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Environmental and occupational health and safety regulation
Our exploration, development and production operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may restrict the rate of crude oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and affects profitability.
Any new laws or regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that result in more stringent and costly well construction, drilling, operating conditions, monitoring and reporting obligations, water management or completion activities, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our customers. We may also experience a delay in obtaining or be unable to obtain required permits, which may interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. Moreover, accidental spills or other releases may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such spills or releases, including any third-party claims for damage to property, natural resources or persons. While, historically, our compliance costs with these laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations, there can be no assurance that such costs will not be material in the future as a result of such existing laws and regulations or any new laws and regulations, or that such future compliance will not have a material adverse effect on our business and operating results. Some or all of such increased compliance costs may not be recoverable from insurance.
The following is a summary of the more significant existing environmental and occupational health and safety laws, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous substances and wastes
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These classes of persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances released at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.
We are also subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes that impose strict requirements on the generation, storage, treatment, transportation, disposal and cleanup of hazardous and nonhazardous wastes. Under the authority of the EPA, most states administer some or all of the provisions of RCRA,
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sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate ordinary industrial wastes that may be regulated as hazardous wastes. RCRA currently exempts certain drilling fluids, produced waters and other wastes associated with exploration, development and production of crude oil and natural gas from regulation as hazardous wastes. These wastes are instead regulated under RCRA’s less stringent nonhazardous waste provisions, state laws or other federal laws. There have been efforts from time to time to remove this exclusion, which removal could significantly increase our and our customers operating costs, and it is possible that certain crude oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future.
We currently own or lease, and have in the past owned or leased, properties that have been used to explore and produce crude oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons, hazardous substances and wastes may have been released on, under or from the properties owned or leased by us or on, under or from, other locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons, hazardous substances and wastes were not under our control. These properties and the substances disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, to clean up contaminated property (including contaminated groundwater) and to perform remedial plugging or pit closure operations to prevent future contamination.
Air emissions
The federal Clean Air Act (the “CAA”) and comparable state laws and regulations restrict the emission of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Obtaining permits has the potential to restrict, delay or cancel the development or expansion of crude oil and natural gas projects. Over the next several years, we may be required to incur capital expenditures for air pollution control equipment or other air emissions-related issues. If the EPA were to adopt more stringent air quality standards, state implementation of the revised standard or any other new legal requirements could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, significantly increase our capital expenditures and operating costs and reduce demand for the crude oil and natural gas that we produce, which could adversely impact our business.
Environmental protection and natural gas flaring initiatives
We recognize the environmental and financial risks associated with air emissions, particularly with respect to flaring of natural gas from our operated well sites and are focused on reducing these emissions, consistent with applicable requirements.
The NDIC has issued orders and pursued other regulatory initiatives to implement legally enforceable “gas capture percentage goals” targeting the capture of natural gas produced in the state, commencing in 2014. As of November 1, 2020, the enforceable gas capture percentage goal is 91%. The NDIC requires operators to develop and implement Gas Capture Plans to maintain consistency with the agency’s gas capture percentage goals, but it maintains the flexibility to exclude certain gas volumes from consideration in calculating compliance with the state’s gas capture percentage goals. Wells must continue to meet or exceed the NDIC’s gas capture percentage goals on a statewide, county, per-field, or per-well basis. Failure of an operator to comply with the applicable goal at maximum efficiency rate may result in the imposition of monetary penalties and restrictions on production from subject wells. In September 2020, the NDIC revised the gas capture policy to allow several additional exceptions for companies that flare natural gas under certain circumstances, such as gas plant outages or delays in securing a right-of-way for pipeline construction. As of December 31, 2025, we were capturing substantially all of our natural gas production in North Dakota. While we were satisfying the applicable gas capture percentage goals as of December 31, 2025, there is no assurance that we will remain in compliance in the future or that such future satisfaction of such goals will not have a material adverse effect on our business and results of operations.
Climate change
The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, climate-related disclosure obligations, and regulations that directly limit GHG emissions. Our operations are subject to a series of regulatory, political, litigation, financial and physical risks associated with the production and processing of fossil fuels and emissions of GHGs. The Trump Administration has indicated that it is not pursuing a climate change policy in line with the Biden Administration and is instead focused on growth in the energy sector. The Trump Administration’s priorities, orders and actions are rapidly evolving and have and likely will continue to place less emphasis on concerns regarding climate change.
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In recent years the U.S. Congress has considered legislation to reduce emissions of GHGs, including methane. For example, the Inflation Reduction Act of 2022 (the “IRA”) appropriated significant federal funding for renewable energy initiatives and, for the first time ever, imposed a fee on methane emissions from certain facilities. The methane emissions fee provision of the IRA took effect in 2024, and the EPA published rules in 2024 to facilitate the determination and payment of this methane charge. However, in March 2025, the Trump Administration implemented a Congressional Review Act disapproval of the methane charge rule, and rescinded many executive orders issued under the Biden Administration concerning climate change initiatives. Several states, though none in the areas where we operate, have implemented, of their own accord or in coordination with their neighbor states, regional initiatives and programs limiting, monitoring or otherwise regulating GHG emissions.
In addition, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules and regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and gas system sources, and impose standards for reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. Recent actions by the Trump Administration seek to eliminate, delay or reduce GHG emissions-related requirements.
In recent years, there has been considerable focus on the regulation of methane emissions from the oil and gas sector. Amendments to the 2016 Subpart OOOO performance standards for methane, volatile organic compound (“VOC”) and sulfur dioxide emissions have resulted in presumptive standards for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring technologies, the capture and control of emissions by 95% through capture and control systems, zero-emission requirements for specific components and equipment, so-called green well completion requirements and the establishment of a “super emitter” response program which would allow certified third parties to report large emission events to the EPA, triggering additional investigation, reporting and repair obligations, among other more stringent operational and maintenance requirements. Fines and penalties for violations of these rules could be substantial. The Company is currently taking steps to comply with requirements that became effective during 2024 and those that phase in over time. In July 2025, the EPA proposed to extend most of the compliance deadlines by 18 months. Litigation is pending concerning these recently adopted final rules. Separately, the Bureau of Land Management (“BLM”) has also proposed rules to limit venting, flaring, and methane leaks for oil and gas operations on federal lands. At this time, we cannot predict the ultimate compliance costs or impact of these regulatory requirements, any such requirements have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows.
At the international level, the United Nations (“UN”) -sponsored Paris agreement (“Paris Agreement”) requires member states to submit non-binding, individually determined reduction goals known as Nationally Determined Contributions every five years after 2020. However, the full impact of, and any legislation or regulation promulgated to fulfill the United States’ commitments thereunder, is uncertain at this time, given President Trump’s decision in January 2025 to again withdraw the United States from the Paris Agreement. It is unclear what additional initiatives may be adopted or implemented that may have adverse effects on our operations.
Any new or proposed federal or state policies eliminating support for or restricting the development activities of the oil and gas sector while incentivizing or subsidizing alternative energy sources could reduce demand for our products, increase our operating costs or otherwise have an adverse impact on our financial performance. Executive orders and other actions by the Trump Administration rescind or call into question the extent to which such policies will proceed.
Litigation risks are also increasing, as a number of states, municipalities and other plaintiffs have sought to bring suit against various oil and gas companies in state or federal court, alleging, among other things, that such energy companies created public nuisances by producing fuels that contributed to climate change and its effects, such as rising sea levels, and therefore, are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. The Company is not currently a defendant in any of these lawsuits, but it could be named in actions in the future making similar allegations. Should the Company be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to causation or contribution to the asserted damage, or to other mitigating factors. Involvement in such a case could have adverse reputational impacts and an unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Additionally, our access to capital may be impacted by climate change policies. Stockholders and bondholders currently invested in fossil fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel energy-related sectors. Certain institutional investors who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and have shifted their investment practices to favor “clean” energy sources, such as wind and solar, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. Additionally, there is also a risk that financial institutions will be pressured or required to adopt policies that have the effect of reducing the capital provided to the
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fossil fuel sector. The SEC issued a rule that would mandate extensive disclosure of climate risks, including financial impacts, physical and transition risks, climate-related governance and strategy, and GHG emissions, for all U.S.-listed public companies. However, the SEC has stayed the final rule pending the resolution of consolidated legal challenges and subsequently voted to withdraw its defense of the litigation. States may also pass laws imposing more expansive disclosure requirements for climate-related risks. For example, the State of California will require large U.S. companies doing business in California to make broad-based climate-related disclosures in 2026, pending certain litigation, and other states are also considering similar measures. Separately, the SEC released its final rule on other climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient. Although these rules are currently stayed pending judicial review, if implemented as previously proposed, these rules would significantly increase our climate-related disclosure obligations. New laws, regulations or enforcement initiatives related to the disclosure of climate-related risks could lead to reputational or other harm with customers, regulators, lenders, investors or other stakeholders and increase litigation risks. Any material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could impact our business and operations.
Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical and climatic effects on supply chains, assets or operations through storms, drought, floods, sea level rise, changing meteorological conditions and other events or conditions and our ability to mitigate these events is limited and subject to the effectiveness of our disaster and facility preparedness.
Water discharges
The Federal Water Pollution Control Act (the “CWA”) and analogous state laws impose strict controls on the discharge of pollutants into state waters and waters of the United States (“WOTUS”), including produced water and other oil and gas wastes. The discharge of pollutants is prohibited except in accordance with a permit. The CWA also regulates the discharge of dredge and fill material. The scope of WOTUS is subject to ongoing legal challenges and regulatory changes, including the Supreme Court’s 2023 decision in Sackett v. EPA and a subsequent proposed rule in November 2025. Changes to the scope of CWA jurisdiction could increase our costs, cause delays in obtaining permits, and restrict our operations. Non-compliance can result in significant administrative, civil, and criminal penalties.
The Oil Pollution Act of 1990 (the “OPA”) amends the CWA and sets minimum standards for prevention, containment and cleanup of crude oil spills. The OPA applies to vessels, offshore facilities and onshore facilities, including E&P facilities that may affect WOTUS. Under the OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for crude oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from crude oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of crude oil into WOTUS.
Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These injection wells are regulated pursuant to the federal Safe Drinking Water Act (the “SDWA”) Underground Injection Control (the “UIC”) program and analogous state laws. The UIC program requires permits from the EPA or analogous state agency for disposal wells that we operate, establishes minimum standards for injection well operations and restricts the types and quantities of fluids that may be injected. Any leakage from the subsurface portions of the injection wells may cause degradation of fresh water, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages and personal injuries. Moreover, any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations, which costs could be material.
Additionally, federal and state regulators have investigated a purported link between underground injection and seismic activity. This has led to, or could lead to, new requirements or restrictions on the use of disposal wells, potentially increasing our operating costs. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or our customers.
Hydraulic fracturing activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from unconventional formations, including shales. The hydraulic fracturing process is typically regulated by state crude oil and natural gas commissions or similar agencies, but federal agencies have asserted regulatory authority over certain aspects of the process. Regulations imposing more stringent standards on hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, wellbore integrity and handling of flowback water have varied under prior
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administrations, and litigation challenging those rules resulted in rescission in federal courts. Appeals to those decisions are on-going, but with little activity in the last several years.
In addition, some states, including North Dakota and Montana where we primarily operate, have adopted, and other states may adopt, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. For example, both North Dakota and Montana require operators to disclose chemical ingredients and water volumes used in hydraulic fracturing activities, subject to certain trade-secret exceptions. If new or more stringent federal, state or local legal restrictions or bans relating to the hydraulic fracturing process are adopted in areas where we operate, or in the future plan to operate, we could incur potentially significant added costs to comply with such requirements, experience restrictions, delays or curtailment in the pursuit of exploration, development or production activities and may even be limited or precluded from drilling wells or limited in the volume that we are ultimately able to produce from our reserves.
Increased regulation and attention given to hydraulic fracturing may lead to greater opposition to, and litigation concerning, crude oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to added delays, restrictions or cancellations in our operations or increased operating costs in our production of crude oil and natural gas. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
Endangered Species Act considerations
The federal Endangered Species Act (the “ESA”) and comparable state laws may restrict exploration, development and production activities that may affect endangered and threatened species or their habitats. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”) and to bald and golden eagles under the Bald and Golden Eagle Protection Act. Some of our operations are located in areas that are designated as habitat for endangered or threatened species, and our development plans have been impacted on occasion by certain endangered or threatened species, including the Dakota Skipper and the Golden Eagle. If endangered or threatened species are located in areas of the underlying properties where we want to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed by seasonal or permanent restrictions or require the performance of extensive studies or implementation of costly mitigation practices.
Moreover, the U.S. Fish and Wildlife Service may make changes to the list of species as endangered or threatened under the ESA and litigation with respect to the listing or non-listing of certain species as endangered or threatened may result in greater protections for non-protected or lesser-protected species. The issuance of more stringent conservation measures or land, water, or resource use restrictions could result in operational delays and decreased production and revenue for us.
Operations on federal lands
Performance of crude oil and natural gas E&P activities on federal lands, including Indian lands and lands administered by the BLM, are subject to detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government. These regulations may result in significant costs associated with the removal of tangible equipment and other restorative actions. Additionally, under certain circumstances, the BLM may require operations on federal leases to be suspended or terminated.
Crude oil, NGL, and natural gas operations on federal lands are subject to increasing regulatory attention. The former Biden Administration has explored various means to curtail oil and natural gas activities on federal lands and the Trump Administration now seeks to increase such activities. Following passage of the IRA, several DOI recommendations, including an increased royalty rate, minimum bid limits and a significant reduction in total available acreage, were required to be implemented as part of the IRA and have been subsequently incorporated in recent lease sales.
Additionally, oil and natural gas operations and related infrastructure projects on federal lands may be impacted by recent changes to the National Environmental Policy Act (“NEPA”) implementing regulations. NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs (“BIA”), to evaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment. The Council on Environmental Quality (the “CEQ”) has historically had rules that govern NEPA review. In March 2025, in response to court decisions, CEQ rescinded its NEPA regulations and directed agencies to review and update their NEPA rules and procedures.
Operations on federal lands also face litigation risks. For example, legal challenges have been filed relating to federal leasing decisions, such as for failure to adequately assess the impact of GHG emissions resulting from production on federal lands.
Depending on any mitigation strategies recommended in such environmental assessments or environmental impact statements, we could incur added costs, which could be material, and be subject to delays, limitations or prohibitions in the scope of crude oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt our or our customers’ E&P activities. Approximately 6% of our net acreage position in the Williston Basin is federal mineral acreage, which is spread across our acreage position, and any portion of a well on federal land requires a permit.
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Employee health and safety
We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state regulations require that information be maintained concerning hazardous materials used or produced in our operations. Certain of this information must be provided to employees, state and local government authorities, or citizens.
Human Capital Resources
Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a fun and rewarding environment for our employees. We seek to foster a culture of innovation and continuous improvement and are constantly looking for ways to strengthen our organizational agility and adaptability.
To execute our strategy in the highly competitive oil and gas industry we need to attract, develop, and retain a highly effective, talented, and engaged workforce. Our ability to do so depends on a number of factors, including an available pool of qualified talent, compelling compensation and benefits plans, and an energizing environment committed to helping employees develop and grow. As of February 13, 2026, we employed 676 full-time employees and we also utilize independent contractors to perform various field and corporate services as needed. Our current hiring plans focus on advancing talent attraction in our primary operating locations of Houston, Texas and Williston, North Dakota. We believe that the knowledge transfer plans we have in place are appropriate, and that we will continue to have the human capital necessary to operate our business safely while executing on our strategic priorities. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages and consider our relations with our employees to be satisfactory.
Health and safety
We are committed to protecting the health and safety of our employees, contractors on our job sites, and the communities in which we operate. We seek to improve our procedures to maintain our safety culture. For example, our environmental, health and safety teams regularly monitor and update our recommended safety practices with feedback and input from our field personnel under a management of change process framework. We operate our worksites under a stop work authority program pursuant to which every person on our worksites is empowered to halt operations to address a potential safety issue. We have developed a comprehensive safety management system that includes recurring risk assessment, hazard recognition and mitigation training, emergency response preparedness training, protective measures including adequate personal protective equipment, life-saving rules, onboarding processes, contractor safety management, partner surveys, comprehensive audits, semi-annual safety summits, executive-level reviews of incidents and ad-hoc safety stand-downs. In addition, safety training is provided to all employees, and, in order to reinforce accountability, safety performance is integrated into our annual compensation program. We seek to partner only with contractors and vendors who share our commitment to safety.
Compensation and benefits
The goal of our total rewards program is to attract, retain, and motivate employees through a competitive and comprehensive total rewards package. Our total rewards program considers both corporate and personal performance goals and aims to increase employee focus on key performance drivers while also seeking to maintain and improve overall well-being and deepen commitment to our collective success. We do this by ensuring employees at Chord are competitively compensated and rewarded for their performance, which enables us to attract, motivate and retain high level talent while delivering strong performance to achieve our business strategy. Our intent is to ensure the compensation and benefits provided as part of our total rewards program are fair and equitable across positions and locations, market competitive, based on merit, consistent with our values and transparent to our employees.
The core elements of our compensation program include base pay, short-term incentives and long-term incentive opportunities for employees at all levels of the Company. In addition, we offer benefits that include retirement plan dollar matching, health insurance for employees and their families, income protection and disability coverage, paid time off, volunteer time off, parental leave, flexible work schedules, financial wellness tools and resources and emotional well-being services, such as an Employee Assistance Program. We participate in annual peer benchmarking to ensure we remain competitive across all components of our compensation and benefit programs.
Training, development and career opportunities
Our team of talented employees possess a broad set of skills including engineering, geology, production, marketing, land, supply chain, health and human safety, human resources, finance, accounting, information technology and legal. Many of our employees work in disciplines that require highly specialized skills and subject-matter expertise, underpinning our ability to deliver on our strategic priorities. We are committed to the personal and professional development of our employees, with the
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belief that a greater level of knowledge, skill and ability benefits the employee and fosters a more creative, innovative, efficient, and therefore competitive organization. We empower our employees to develop the skills they need to perform in their current jobs while also developing skills and experiences to support their longer-term growth. We provide our employees with programs that support their learning and development, which are designed to build and strengthen employees’ abilities, including leadership trainings, development of professional competencies, safety trainings and information and technology trainings.
Community Involvement
We strive to make a positive impact in the communities where we operate. Our charitable initiatives include sponsoring technical training programs in our local communities, engineering scholarships, environmental and wildlife rehabilitation programs, Habitat for Humanity projects, mental health programs, and educational programs like OneGoal and Junior Achievement. We actively promote and support employee volunteerism and philanthropy as a core part of our community engagement efforts.
Workforce dynamics
We prioritize diversity of thought, constructive debate, and engaged leadership, aiming to attract, develop, and retain a highly effective and engaged workforce. We believe a workforce that brings varied backgrounds and experiences enriches the Company with unique perspectives and ideas. We actively support our workforce through a thorough and merit-based talent identification process.
Our Vice President of Human Resources is responsible for overseeing all human capital management programs. Our Compensation and Human Resources Committee reviews the Company’s development and implementation of our human capital management practices, policies, strategies and goals, including those related to the recruitment, development and retention of personnel, talent management and other employment practices. In addition, the Board of Directors believes it is important for directors to possess a diverse array of backgrounds, skills and achievements. When considering new candidates, the Nominating and Governance Committee, with input from the Board of Directors, takes these factors into account as set forth in its charter and our Corporate Governance Guidelines.
We are an equal opportunity employer and do not discriminate on the basis of any characteristic protected by applicable law, including race, religion, color, national origin, sex, gender, age, marital status, veteran status or disability status. We engage with individuals with disabilities to provide reasonable accommodations that may allow them to participate in the job application or interview process, to perform essential job functions and to receive other benefits and privileges of employment.
In addition, we seek to work with business partners who do not engage in prohibited discrimination in hiring or in their employment practices, and who make decisions about hiring, salary, benefits, training opportunities, work assignments, advancement, discipline, termination, retirement and other employment decisions based on job and business-related criteria. To maintain a diverse and inclusive workforce, we maintain a robust compliance program supported by an annual certification by all employees to our Code of Business Conduct and Ethics Policy.
Offices
Our principal corporate office is located in Houston, Texas at 1001 Fannin Street. We own field offices in the North Dakota communities of Williston, Ray, New Town, Watford City, Keene, Mandaree and Dickinson.
Available Information
We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. Our filings with the SEC are available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.
We make available on our website at http://www.chordenergy.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. We also use our website as a means of disclosing additional information, including for complying with our disclosure obligations under the SEC’s Regulation FD (Fair Disclosure). Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K.
Other information, such as presentations, the charters of the Audit and Reserves Committee, Compensation and Human Resources Committee, Nominating and Governance Committee, and Safety and Sustainability Committee and the Code of Business Conduct and Ethics Policy, are available on our website, http://www.chordenergy.com, under “Investors — Corporate Governance” and in print to any stockholders who provide a written request to the Corporate Secretary at 1001 Fannin Street, Suite 1500, Houston, Texas 77002.
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Our Code of Business Conduct and Ethics Policy applies to all directors, officers and employees, including the Chief Executive Officer and Chief Financial Officer. Within the time period required by the SEC and The Nasdaq Stock Market LLC (the “Nasdaq”), as applicable, we will post on our website any modification to the Code of Business Conduct and Ethics Policy and any waivers applicable to senior officers who are defined in the Code of Business Conduct and Ethics, as required by the Sarbanes-Oxley Act of 2002.
We also make available Sustainability Reports and other sustainability documents on our website, which contain various performance highlights relating to ESG and human capital measures. Information contained in our Sustainability Reports, and other documents, are not incorporated by reference into, and do not constitute a part of, this Annual Report on Form 10-K.
References to the Company’s website in this Form 10-K are provided as a convenience and do not constitute, and should not be deemed, an incorporation by reference of the information contained on, or available through, the website, and such information should not be considered part of this Form 10-K.
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Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, results of operations or cash flows could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.
Risks related to the oil and gas industry and our business
Global geopolitical tensions may create heightened volatility in crude oil, NGL and natural gas prices and could adversely affect our business, financial condition and results of operations.
Oil and gas prices are impacted by geopolitical tensions and conflict, such as conflicts between Russia and Ukraine, hostilities in the Middle East and political and military developments in South America. Although the length, impact and outcome of the military conflicts between Russia and Ukraine and elsewhere in the Middle East are highly unpredictable, these conflicts could lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability and other material and adverse effects on macroeconomic conditions. It is not possible at this time to predict or determine the ultimate consequence of these regional conflicts. These conflicts and their broader impacts could have a lasting impact on the short- and long-term operations and financial condition of our business and the global economy.
Adverse developments affecting the financial markets, such as bank failures, the potential for the Federal Reserve to increase interest rates or an extended period of elevated interest rates, as well as the potential for a U.S. government shutdown, could adversely affect our current and projected business operations, financial condition, results of operations and liquidity.
Events involving limited liquidity, defaults, non-performance or other adverse developments that affect financial institutions, transactional counterparties or other companies in the financial services industry or the financial services industry generally, or concerns or rumors about any events of these kinds or other similar risks, have in the past and may in the future lead to market-wide liquidity problems. The failure of a bank, or events involving limited liquidity, defaults, non-performance or other adverse conditions in the financial markets impacting the financial institutions with which we conduct business, or concerns or rumors about such events, may lead to disruptions in access to our bank deposits, impair the ability of the banks participating in our current or future credit agreements from honoring their commitments to us or otherwise adversely impact our liquidity and financial performance. We regularly maintain domestic cash deposits in FDIC-insured banks, which exceed the FDIC insurance limits. There can be no assurance that our deposits in excess of the FDIC or other comparable insurance limits will be backstopped by the U.S. or applicable foreign government, or that any bank or financial institution with which we do business will be able to obtain needed liquidity from other banks, government institutions or by acquisition in the event of a failure or liquidity crisis.
Disruptions to the broader economy and financial markets, including the Federal Reserve’s actions with respect to interest rates and the timing of any anticipated decrease in rates or government shutdowns may also reduce our ability to access capital or result in such capital being available on less favorable terms. Higher interest rates or costs and tighter financial and operating covenants may make it more difficult to acquire financing on acceptable terms or at all. Any of these impacts, or any other impacts resulting from the factors described above or other related or similar factors, could have material adverse impacts on our liquidity, financial condition, results of operations and cash flows.
A substantial or extended decline in commodity prices, for crude oil and, to a lesser extent, NGL and natural gas, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The prices we receive for our crude oil and, to a lesser extent, NGL and natural gas, heavily influence our revenue, profitability, cash flow from operations, access to capital and future rate of growth. Crude oil, NGL and natural gas are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil, NGL and natural gas have been volatile, including declines and volatility during 2025. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:
•worldwide and regional economic and political conditions impacting the global supply and demand for crude oil, NGL and natural gas;
•the actions by the members of 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;
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•the price and quantity of imports of foreign crude oil, NGL and natural gas;
•political conditions in or affecting other crude oil, NGL and natural gas producing countries, including the current conflicts in and among the Middle East and conditions in South America, China, India and Russia;
•the level of global exploration and production;
•the level of global crude oil, NGL and natural gas inventories;
•events that impact global market demand, including impacts from wars, conflicts and global health epidemics and concerns;
•localized supply and demand fundamentals and regional, domestic and international transportation availability;
•the ability to continue to access critical transportation infrastructure such as DAPL, rail, and other regional outlets;
•the ability for the United States to continue to export crude oil, natural gas, and NGL;
•weather conditions and natural disasters;
•domestic and foreign governmental laws, regulations and policies, including, among others, the IRA, environmental requirements and the discouragement of the use of fuels that emit GHGs and encouragement of the use of alternative energy sources;
•speculation as to future commodity prices and the speculative trading of crude oil, NGL and natural gas futures contracts;
•changing consumer or market preferences, stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of crude oil, NGL and natural gas and related infrastructure;
•price and availability of competitors’ supplies of crude oil, NGL and natural gas;
•technological advances affecting energy consumption; and
•the price and availability of alternative fuels.
Substantially all of our crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and our NGL production is sold to purchasers under long-term (more than 12-month) contracts at market-based prices. Low crude oil, NGL and natural gas prices will reduce our cash flows, borrowing ability, the present value of our reserves and our ability to develop future reserves. See below “Risks related to our financial position—Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil, NGL and natural gas reserves.” Low crude oil, NGL and natural gas prices may also reduce the amount of crude oil, NGL and natural gas that we can produce economically and may affect our proved reserves. See also “Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” below.
The ability or willingness of OPEC+ to set and maintain production levels has a significant impact on oil prices.
OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions or inaction of OPEC+ members have a significant impact on global oil supply and pricing. For example, OPEC+ nations have previously agreed to take measures, including production cuts and increases, in an effort to achieve certain global supply or demand targets or to achieve certain crude oil price outcomes. There can be no assurance that OPEC+ members will continue to agree to future production cuts, moderating future production or other actions to support and stabilize oil prices, and they may take actions that have the effect of reducing oil prices. Uncertainty regarding future actions to be taken by OPEC+ members could lead to increased volatility in the price of crude oil, which could adversely affect our business, financial condition, results of operations and cash flows.
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Drilling for and producing crude oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. We use some of the latest available horizontal drilling and completion techniques, which involve risk and uncertainty in their application.
Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our crude oil and natural gas E&P activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable crude oil, NGL or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” below. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in planned expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
•shortages of or delays in obtaining equipment and qualified personnel;
•facility or equipment malfunctions and/or failure;
•unexpected operational events, including accidents;
•pressure or irregularities in geological formations;
•adverse weather or climatic conditions, such as blizzards, ice storms, wildfires, floods and prolonged drought conditions;
•reductions in crude oil, NGL and natural gas prices;
•inflation in exploration and drilling costs;
•disruptions in our supply chain for raw materials, chemicals and equipment;
•delays imposed by or resulting from compliance with regulatory requirements, including permits;
•proximity to and capacity of transportation facilities;
•contractual disputes;
•title problems; and
•limitations in the market for crude oil, NGL and natural gas.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore contribute to maximizing returns. Risks that we face while drilling include, but are not limited to, the following:
•spacing of wells to maximize production rates and recoverable reserves;
•landing the wellbore in the desired drilling zone;
•staying in the desired drilling zone while drilling horizontally through the formation;
•running the casing the entire length of the wellbore; and
•the ability to run tools and other equipment consistently through the wellbore.
Risks that we face while completing our wells include, but are not limited to, the following:
•the ability to fracture stimulate the planned number of stages;
•the ability to run tools the entire length of the wellbore during completion operations;
•the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage; and
•protecting nearby producing wells from the impact of fracture stimulation.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or crude oil, NGL and natural gas prices decline, the return on our investment for certain projects may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and gas properties, and the value of our undeveloped acreage could decline in the future.
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Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating crude oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. See “Item 1. Business—Exploration and Production Operations” and “Item 8. Financial Statements and Supplementary Data—Note 23—Supplemental Oil and Gas Reserve Information — Unaudited” for additional information about our estimated crude oil and natural gas reserves and the PV-10 and Standardized Measure as of December 31, 2025, 2024 and 2023.
In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by our independent reserve engineers, estimates of crude oil, NGL and natural gas reserves are inherently imprecise.
Actual future production, crude oil, NGL and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. In addition, we may adjust estimates of net proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.
You should not assume that the present value of future net revenues from our estimated net proved reserves is the current market value of our estimated net crude oil and natural gas reserves. In accordance with SEC requirements, we based the estimated discounted future net revenues from our estimated net proved reserves on the unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months without giving effect to derivative transactions. Actual future net revenues from our oil and gas properties will be affected by factors such as:
•actual prices we receive for crude oil, NGL and natural gas;
•actual cost of development and production expenditures;
•the amount and timing of actual production; and
•changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing and amount of actual future net revenues from estimated net proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report on Form 10-K. Any significant future price changes will have a material effect on the quantity and present value of our estimated net proved reserves.
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If crude oil, NGL and natural gas prices decline, or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties.
We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. In addition, we assess our unproved properties periodically for impairment on a prospect-by-prospect basis based on remaining lease terms, drilling results or future plans to develop acreage. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and gas properties, which may result in a decrease in the amount available under our revolving credit facility.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services or the unavailability of sufficient transportation for our production could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
Our industry is cyclical, and from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment, supplies and personnel are substantially greater, and their availability to us may be limited. Additionally, these services may not be available on commercially reasonable terms.
Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services or the unavailability of sufficient transportation for our production could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital plan, which could have a material adverse effect on our business, financial condition or results of operations. Additionally, compliance with new or emerging legal requirements that affect midstream operations in North Dakota or Montana may reduce the availability of transportation for our production.
Substantially all of our producing properties and operations are located in the Williston Basin, making us vulnerable to risks associated with operating in a concentrated geographic area.
Our producing properties are geographically concentrated in the Williston Basin in northwestern North Dakota and northeastern Montana. As a result, we may be disproportionately exposed to the impact of economics in the Williston Basin or delays or interruptions of production from those wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of crude oil, NGL or natural gas produced from the wells in those areas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic crude oil- and natural gas-producing areas such as the Williston Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Our crude oil, NGL and natural gas are sold in a limited number of geographic markets, and each has a generally fixed amount of storage and processing capacity. As a result, if such markets become oversupplied with crude oil, NGL and/or natural gas, it could have a material negative effect on the prices we receive for our products and therefore an adverse effect on our financial condition and results of operations. Variances in quality may also cause differences in the value received for our products.
Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. The impact of regional economics or delays or interruptions of production in an area could have a material adverse effect on our financial condition and results of operations.
Our operations on the Fort Berthold Indian Reservation of the Three Affiliated Tribes in North Dakota are subject to various federal, state, local and tribal regulations and laws, any of which may increase our costs and have an adverse impact on our ability to effectively conduct our operations.
Various federal agencies within the U.S. Department of the Interior (the “Department of the Interior”), particularly the BIA and the Office of Natural Resource Revenue, along with the Three Affiliated Tribes of the Fort Berthold Indian Reservation (“MHA Nation”), promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation. In addition, the MHA Nation is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, approvals and other conditions that apply to lessees, operators and contractors conducting operations on the Fort Berthold Indian Reservation. Lessees and operators conducting operations on tribal lands may be subject to the MHA Nation’s court system. The Department of the Interior previously issued an official opinion stating that the minerals beneath the Missouri River riverbed located on the Fort Berthold Indian Reservation belong to the MHA Nation and not the State of North Dakota, overturning a 2020 Trump-agency decision that gave the State of North Dakota ownership.
The case is currently on remand before the D.C. Federal District Court. The parties previously filed dispositive motions, including motions for summary judgment, but the Court denied these dispositive motions and ruled that factual determinations would need to be made, and would require a trial and full evidentiary record, in order to rule on the riverbed ownership and
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related issues. The parties are currently required to file a joint status report, informing the Court of the time that would be required for expert testimony and exhibit production, beyond what has already been filed with the prior motions. On January 30, 2026, however, the federal defendants filed a motion to extend the timeline on the joint status report by 90 days to allow sufficient time for an internal review. The Court denied the request and ordered the parties to submit their joint status report by February 17, 2026. The ultimate outcome of this litigation, and any resolution between the parties, is uncertain and cannot be predicted. One or more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.
We depend upon a limited number of midstream providers for a large portion of our midstream services, and our failure to obtain and maintain access to the necessary infrastructure from these providers to successfully deliver crude oil, natural gas and NGL to market may adversely affect our earnings, cash flows and results of operations.
Our delivery of crude oil, NGL and natural gas depends upon the availability, proximity and capacity of pipelines, other transportation facilities and gathering and processing facilities primarily owned by a limited number of midstream service providers. The capacity of transmission, gathering and processing facilities may be insufficient to accommodate potential production from existing and new wells, which may result in substantial discounts in the prices we receive for our crude oil, NGL and natural gas or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Our ability to secure access to pipeline infrastructure on favorable economic terms could affect our competitive position. In addition, midstream service providers could change or impose more stringent specifications on the quality of our production they are willing to accept, including the gravity and sulfur content of our crude oil and the Btu content of our natural gas. If the total mix of product fails to meet the applicable product quality specification, these midstream service providers may refuse to accept all or a part of the production we deliver, or we may be required to deliver production to meet such quality specifications that yields a lower realized price.
Access to midstream assets may be unavailable due to market conditions or mechanical or other reasons. A lack of access to needed infrastructure, or an extended interruption of access to or service from our or a midstream provider’s pipelines and facilities for any reason, including vandalism, sabotage or cyber-attacks on such pipelines and facilities or service interruptions, could result in adverse consequences to us, such as delays in producing and selling our crude oil, NGL and natural gas.
Our dependence on midstream service providers for transmission, gathering and processing services makes us dependent on them in order to get our crude oil, NGL and natural gas to market. To the extent these services are delayed or unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Additionally, we may be subject to price increases from time to time, including in connection with renewals. Our failure to obtain these services on acceptable terms could materially harm our business.
Our business depends on third-party transportation and processing facilities and other assets that are owned by third parties.
The marketability of our crude oil, NGL and natural gas depends in part on the availability, proximity and capacity of pipeline systems, processing facilities, and rail transportation assets owned by third parties. The lack of available capacity on these systems and facilities, whether as a result of proration, growth in demand outpacing growth in capacity, physical damage, scheduled maintenance, legal or other reasons such as suspension of service due to legal challenges (see below regarding DAPL), could result in a substantial increase in costs, declines in realized commodity prices, the shut-in of producing wells or the delay or discontinuance of development plans for our properties. The negative effects arising from these and similar circumstances may last for an extended period of time. In many cases, operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, concerns about the safety and security of oil and gas transportation by pipeline may result in public opposition to pipeline development and increased regulation of pipelines by PHMSA, and therefore less capacity to transport our products by pipeline.
The impact of pending and future legal proceedings on the systems, pipelines and facilities that we rely on can affect our ability to market our products and have a negative impact on realized pricing. In July 2020, the operator of DAPL was ordered by a U.S. District court to halt oil flow and empty the pipeline within 30 days while an environmental impact study (“EIS”) is completed. Also, in July 2020, the U.S. Court of Appeals for the District of Columbia Circuit issued a temporary administrative stay while the court considers the merits of a longer-term emergency stay order through the appeals process. On January 26, 2021, the U.S. Court of Appeals for the District of Columbia Circuit upheld the U.S. District court’s ruling that an EIS is needed and also reaffirmed its earlier decision which allows DAPL to operate through the EIS process. The owners of DAPL appealed the lower court decision to the U.S. Supreme Court in September 2021; however, the appeal was rejected on February 22, 2022. The Corps released its draft EIS on September 8, 2023, which it made available for public comments. The Corps initially established a deadline of November 13, 2023 for public comments and, on October 31, 2023, the deadline for public comments was extended to December 13, 2023. The Corps did not identify a preferred alternative among the five actions analyzed (including granting the requested easement with conditions as originally issued) in the draft EIS. Three of the five alternative actions considered would require the abandonment, removal or reroute of the segment of DAPL at issue. The Corps
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completed the final EIS in December 2025 and formal decision by the Corps is expected during the first quarter of 2026; however, we cannot guarantee when the Corps may ultimately complete these actions. We regularly use DAPL in addition to other outlets to market our crude oil to end markets. Our risk is not concentrated at DAPL as we have alternative outlets to sell our crude oil production using multiple modes of transportation; however, in the event DAPL were to cease operating, we would anticipate Williston Basin crude oil prices to weaken materially before improving as the market adapts to rail transportation.
Limited takeaway capacity can result in significant discounts to our realized prices.
The crude oil business environment has historically been characterized by periods when crude oil production has surpassed local transportation and refining capacity, resulting in substantial discounts in the price received for crude oil versus prices quoted for NYMEX WTI crude oil. In the past, there have been periods when this discount has substantially increased due to the production of crude oil in the area increasing to a point that it temporarily surpasses the available pipeline transportation, rail transportation and refining capacity in the area. Expansions of both rail and pipeline facilities have reduced the prior constraint on crude oil transportation out of the Williston Basin and improved basin differentials received at the lease. See “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information about our realized crude oil prices and average price differentials relative to NYMEX WTI for the years ended December 31, 2025, 2024 and 2023.
Additionally, the refining capacity in the U.S. Gulf Coast is insufficient to refine all of the light sweet crude oil being produced in the United States. The United States imports heavy crude oil and exports light crude oil to utilize the U.S. Gulf Coast refineries that have more heavy refining capacity. If light sweet crude oil production remains at current levels or continues to increase, demand for our light crude oil production could result in widening price discounts to the world crude oil prices and potential shut-in or reduction of production due to a lack of sufficient markets despite the lift on prior restrictions on the exporting of crude oil and natural gas from the United States.
The development of our PUD reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
Approximately 31% of our estimated net proved reserves were classified as PUD as of December 31, 2025. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The future development of our PUD reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecasts as well as access to liquidity sources, such as capital markets, our revolving credit facility and derivative contracts. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 of our estimated PUD reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.
Unless we replace our crude oil, NGL and natural gas reserves, our reserves and production will decline, which could adversely affect our business, financial condition and results of operations.
Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our estimated net proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil, NGL and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations could be adversely affected.
Our business is subject to operating risks that could result in substantial losses or liability claims, and we may not be insured for, or our insurance may be inadequate to protect us against these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our E&P activities are subject to all the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:
•environmental hazards, such as natural gas leaks, crude oil and produced water spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gas, such as hydrogen sulfide, or other pollutants into the environment;
•abnormally pressured formations;
•shortages of, or delays in, obtaining water for hydraulic fracturing activities;
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•supply chain disruptions which could delay or halt our development projects;
•mechanical difficulties, such as stuck oilfield drilling and service tools and casing failure;
•personal injuries and death; and
•natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
•injury or loss of life;
•damage to and destruction of property, natural resources and equipment;
•pollution and other environmental damage;
•regulatory investigations and penalties;
•suspension of our operations; and
•repair and remediation costs.
Insurance against all operational risk is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Also, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Drilling locations are scheduled to be drilled over several years and may not yield crude oil, NGL or natural gas in commercially viable quantities.
Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present or, if present, whether crude oil, NGL or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of crude oil, NGL or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Williston Basin may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.
Our potential drilling locations are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These potential drilling locations, including those without PUD reserves, represent a significant part of our execution strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, crude oil, NGL and natural gas prices, costs and drilling results. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations. See also “Risks related to our financial position—Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil, NGL and natural gas reserves.”
Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil, NGL or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, PUD reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional PUD reserves as we pursue our drilling program.
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Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed. Failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
As of December 31, 2025, approximately all of our total net acreage in the Williston Basin was held by production. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. In the Williston Basin, our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of December 31, 2025, we had an aggregate of 1,597 net acres expiring in 2026, 160 net acres expiring in 2027 and 470 net acres expiring in 2028 in the Williston Basin. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil, NGL and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business. We did not record any impairment charges on unproved properties during the years ended December 31, 2025, 2024 and 2023.
We are not the operator of all of our drilling locations, and, therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.
We may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated by others. As a result, we may have limited ability to exercise influence over the operations or future development of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:
•the timing and amount of capital expenditures;
•the operator’s expertise and financial resources;
•approval of other participants in drilling wells;
•the operator’s ability to obtain permits;
•selection of technology; and
•the rate of production of reserves, if any.
This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition.
Our operations are subject to federal, state (provincial in Canada) and local laws and regulations related to environmental and natural resources protection and occupational health and safety, which may expose us to significant costs and liabilities and may result in increased costs and additional operating restrictions or delays.
Our operations are subject to stringent federal, tribal, regional, state (provincial in Canada) and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations and services. The trend of more expansive and stringent environmental and occupational health and safety legislation and regulations applied to the oil and gas industry could continue, resulting in material increases in our costs of doing business and consequently affecting profitability. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on these environmental and occupational health and safety matters. Compliance with existing environmental and occupational safety and health laws, regulations, executive orders and other regulatory initiatives, or any other such new legal requirements, could, among other things, require us or our customers to install new or modified emission controls on equipment or processes, incur longer permitting timelines and incur significantly increased capital or operating expenditures, which costs may be material. One or more of these developments that impact us, our service providers or our customers could have a material adverse effect on our business, results of operations and financial condition and reduce demand for our products.
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Our financial results could be impacted by uncertainty in U.S. trade policy, including uncertainty surrounding changes in tariffs, trade agreements or other trade restrictions imposed by the U.S. or other governments.
Our ability to conduct business can be impacted by changes in tariffs, changes or repeals of trade agreements or the imposition of other trade restrictions or retaliatory actions imposed by various governments. For example, during 2025, the Trump Administration enacted and modified tariffs on certain foreign imports into the United States, and trade and tariff policies continued to evolve throughout the year. The scope, duration and economic impact of existing tariffs, as well as the potential for additional changes or retaliatory measures by other governments, remain uncertain and unpredictable. Other effects of these changes, including responsive actions from governments and the unpredictability of U.S. governmental action and response, could also have significant impacts on our financial results. We cannot predict what further action may be taken with respect to tariffs or trade relations between the U.S. and other governments, and any further changes in U.S. or international trade policy could have an adverse impact on our business.
Failure to comply with federal, state and local laws and regulations could adversely affect our ability to produce, gather and transport our crude oil, NGL and natural gas and may result in substantial penalties.
Our operations are substantially affected by federal, state and local laws and regulations, particularly as they relate to the regulation of crude oil, NGL and natural gas production and transportation. These laws and regulations include regulation of crude oil, NGL and natural gas exploration and production and related operations, including a variety of activities related to the drilling of wells, and the interstate transportation of crude oil, NGL and natural gas by federal agencies such as FERC, as well as state agencies. We may incur substantial costs in order to maintain compliance with these laws and regulations. Due to recent incidents involving the release of crude oil, NGL and natural gas and fluids as a result of drilling activities in the United States, there have been a variety of regulatory initiatives at the federal and state levels to restrict crude oil, NGL and natural gas drilling operations in certain locations. Any increased regulation or suspension of crude oil, NGL and natural gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arise out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on our business, financial condition and results of operations. With regard to our physical purchases and sales of energy commodities, we must also comply with anti-market manipulation laws and related regulations enforced by FERC, the CFTC and the FTC. To the lesser extent we are a shipper on interstate pipelines, we must comply with the FERC-approved tariffs of such pipelines and with federal policies related to the use of interstate pipeline capacity. Should we fail to comply with all applicable statutes, rules, regulations and orders of FERC, the CFTC or the FTC, we could be subject to substantial penalties and fines.
We expect to consider from time to time further strategic opportunities that may involve acquisitions, dispositions, investments in joint ventures, partnerships and other strategic alternatives that may enhance stockholder value, any of which may result in the use of a significant amount of our management resources or significant costs, and we may not be able to fully realize the potential benefit of such transactions.
We expect to continue to consider acquisitions, dispositions, investments in joint ventures, partnerships and other strategic alternatives with the objective of maximizing stockholder value. Our Board of Directors and our management may from time to time be engaged in evaluating potential transactions and other strategic alternatives. In addition, from time to time, we may engage financial advisors, enter into non-disclosure agreements, conduct discussions, and undertake other actions that may result in one or more transactions. Although there would be uncertainty that any of these activities or discussions would result in definitive agreements or the completion of any transaction, we may devote a significant amount of our management resources to analyzing and pursuing such a transaction, which could negatively impact our operations, and may impair our ability to retain and motivate key personnel. In addition, we may incur significant costs in connection with seeking such transactions or other strategic alternatives regardless of whether the transaction is completed. In the event that we consummate an acquisition, disposition, partnership or other strategic transaction in the future, we cannot be certain that we would fully realize the potential benefit of such a transaction and cannot predict the impact that such strategic transaction might have on our operations or stock price. Any potential transaction would be dependent upon a number of factors that may be beyond our control, including, among other factors, pricing volatility, market conditions, industry trends, regulatory limitations and the interest of third parties in us and our assets. There can be no assurance that the exploration of strategic alternatives will result in any specific action or transaction. Further, any such strategic alternative may not ultimately lead to increased stockholder value. We do not undertake to provide updates or make further comments regarding the evaluation of strategic alternatives, unless otherwise required by law.
Stakeholder and market attention to matters related to corporate responsibility, including in the oil and gas industry, may impact our business and ability to secure financing.
Businesses across all industries are facing scrutiny from some stakeholders related to corporate responsibility and ESG practices. Further, there are a number of state-level anti-ESG initiatives in the U.S. that may conflict with other regulatory requirements or various stakeholders’ expectations. Businesses that ignore evolving investor or stakeholder expectations and
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standards, which are continuing to evolve, or businesses that are perceived to have not responded appropriately to the growing concern for issues related to ESG, corporate responsibility or in some instances anti-ESG sentiment, regardless of whether there is a legal requirement to do so, may suffer from reputational damage, and the business, financial condition and/or stock price of such business entity could be materially and adversely affected. Attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary disclosures related to ESG or corporate responsibility, mandatory disclosures and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased legislative and judicial scrutiny, investigations and litigation, reputational damage and negative impacts on our access to capital markets. To the extent that societal pressures or political or other factors are involved, it is possible that we could be subject to additional governmental investigations, private litigation or activist campaigns as stockholders may attempt to effect changes to our business or governance practices.
In response to regulatory requirements or stakeholder expectations and industry standards, we may elect to seek out various voluntary ESG targets in the future, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we elected to pursue such targets and were able to achieve the desired target levels, such achievement may have been accomplished as a result of entering into various contractual arrangements. In addition, voluntary disclosures regarding ESG matters, as well as any ESG disclosures currently required or required in the future, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures. Moreover, failure or a perception (whether or not valid) of failure to implement ESG strategies related to corporate responsibility or achieve ESG goals or commitments, including any GHG emission reduction or carbon intensity goals or commitments, could result in private litigation and damage our reputation, cause investors or consumers to lose confidence in us and negatively impact our operations. Notwithstanding our election to pursue aspirational ESG-related targets in the future, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG-related goals or conversely to abandon ESG related goals. We cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles. Additionally, interest on the part of investors and regulators in factors related to ESG and corporate responsibility and stakeholders’ demand for, and scrutiny of, disclosure related to ESG and corporate responsibility has also increased the risk that companies could be perceived as, or accused of, making inaccurate or misleading statements regarding their claims related to corporate responsibility, goal, targets, efforts or initiatives, often referred to as “greenwashing.” Such perception or accusation could damage our reputation and result in litigation or regulator actions.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Companies in the energy industry, and in particular those focused on oil or natural gas extraction, often do not score as well under such assessments compared to companies in other industries. While we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and services, we cannot guarantee that such participation or certification will have the intended results on our ESG profile. Unfavorable ESG ratings and activism directed at shifting funding away from companies with energy-related assets could lead to increased negative sentiment toward us, our customers and our industry.
These negative sentiments and responses to initiatives aimed at limiting climate change and reducing air pollution could lead to the diversion of investment to other industries, which could result in downward pressure on the stock prices of oil and gas companies, including ours, and limit our access to and increase costs of capital for potential acquisitions or development projects, all of which could impact our future financial results. Additionally, to the extent matters related to corporate responsibility negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations.
See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on ESG and climate-related concerns.
Our operations are subject to a series of risks arising out of the threat of climate change, energy conservation measures or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, restrictions on drilling and reduced demand for the crude oil and natural gas that we produce.
The threat of climate change continues to attract considerable attention in the United States and foreign countries. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. As a result, our operations are subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emissions of GHGs. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on the threat of climate change, restriction of GHG emissions and related legal and policy developments. The adoption and implementation of any international, federal, regional or state legislation, executive actions, regulations or other regulatory and policy initiatives that impose more stringent standards for GHG emissions from the oil and gas industry or otherwise restrict the
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areas in which this industry may produce crude oil and natural gas or generate GHG emissions, or require enhanced disclosure of such GHG emissions and other climate-related information, could result in increased compliance costs, which if passed on to the customer could result in increased fossil fuels consumption costs and thereby reduce demand for crude oil and natural gas. Similarly, international, federal, state and local laws and policy initiatives supporting, incentivizing or preferring alternative forms of energy to fossil fuels could result in increased competition or reduce demand for our products. Additionally, political, financial and litigation risks may result in us restricting, delaying or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes or impairing the ability to continue to operate in an economic manner. The occurrence of one or more of these developments could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Outbreak of infectious diseases could materially adversely affect our business.
We face risks related to pandemics, epidemics, outbreaks or other public health events (such as the COVID-19 pandemic) that are outside of our control and could significantly disrupt our operations and adversely affect our business and financial condition. In response to any future public health crisis, there may be wide-ranging actions taken by international, federal, state and local public health and governmental authorities to contain and combat the outbreak and spread of such public health crisis in regions across the United States and the world.
In addition, future public health events may adversely affect our operations or the health of our workforce and the workforces of our customers and service providers by rendering employees or contractors unable to work or access the appropriate facilities for an indefinite period of time. Our personnel could be impacted by these pandemic diseases or ultimately lead to a reduction in our workforce productivity or increased medical costs or insurance premiums as a result of these health risks.
Impact from public health crises will depend on the actions taken by authorities to contain it or treat its impact and the availability and acceptance of vaccines, all of which are beyond our control. These potential impacts, while uncertain and difficult to predict, may negatively affect our business, including, without limitation, our operating results, financial position and liquidity, the duration of any potential disruption of our business, how and the degree to which the pandemic may impact our customers, supply chain and distribution network, the health of our employees, the productivity and sustainability of our workforce, our insurance premiums, costs attributable to our emergency measures, payments from customers and uncollectible accounts, limitations on travel, the availability of industry experts and qualified personnel and the market for our securities.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of crude oil and natural gas wells and adversely affect our production.
Hydraulic fracturing continues to be controversial in certain parts of the United States, resulting in increased scrutiny and regulation of the hydraulic fracturing process, including by federal and state agencies and local municipalities. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on these hydraulic fracturing matters. The adoption of any federal, state or local laws or the implementation of regulations or issuance of executive orders restricting hydraulic fracturing activities or locations or suspending or delaying the performance of hydraulic fracturing on federal properties or other locations could potentially result in an increase in our compliance costs, and a decrease in the completion rate of our new crude oil and natural gas wells, which could have a material adverse effect on our liquidity, results of operations and financial condition. Restrictions, delays or bans on hydraulic fracturing could also reduce the amount of crude oil, NGL and natural gas that we are ultimately able to produce in commercial quantities, which adversely impacts our revenues and profitability.
Laws and regulations pertaining to the protection of threatened and endangered species or to critical habitat, wetlands and natural resources could delay, restrict or prohibit our operations and cause us to incur substantial costs that may have a material adverse effect on our development and production of reserves.
The federal ESA and comparable state laws were established to protect endangered and threatened species. Under the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the MBTA.
See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on endangered species protection regulations. Some of our operations are conducted in areas where protected species or their habitats are known to exist, including those of the Dakota Skipper and Golden Eagle, and from time to time our development plans have been impacted in these areas. We may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and we may be delayed, restricted or prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. Additionally, the designation of previously unprotected species or the re-designation of under-protected species as threatened or endangered in areas where we conduct operations could cause us to incur increased costs arising from
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species-protection measures or could result in delays, restrictions or prohibitions on our development and production activities that could have a material adverse effect on our ability to develop and produce reserves.
Our ability to produce crude oil, NGL and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Water is an essential component of shale crude oil, NGL and natural gas production during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third-party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third-party businesses with more senior contractual or permitting rights to the water. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our E&P operations and have a corresponding adverse effect on our business, financial condition and results of operations. Additionally, operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These injection wells are regulated pursuant to the UIC program established under the SDWA. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on seismicity matters. Compliance with current and future environmental laws, executive orders, regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing activities, the injection of waste streams into disposal wells or any inability to secure transportation and access to disposal wells with sufficient capacity to accept all of our flowback and produced water on economic terms may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted but that could be materially adverse to our business and results of operations.
Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil, NGL and natural gas and secure and retain trained personnel.
Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, market crude oil, NGL and natural gas and secure equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may also see corporate consolidations among our competitors, which could significantly alter industry conditions and competition within the industry.
We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining qualified personnel and raising additional capital, which could have a material adverse effect on our business.
The loss of senior management or technical personnel could adversely affect our operations.
To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
Seasonal weather conditions could adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Our crude oil, NGL and natural gas operations could be adversely affected by seasonal weather conditions. In the Williston Basin, drilling and other crude oil, NGL and natural gas activities cannot be conducted as effectively during the winter months. Severe winter weather conditions limit and may temporarily halt our ability, or the ability of our suppliers and service providers, to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. See “Item 1. Business—Regulation—
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Environmental and occupational health and safety regulation” for more discussion on the threat of climate change and the resulting impacts to weather patterns and conditions.
We may be subject to risks in connection with acquisitions because of integration difficulties, uncertainties in evaluating recoverable reserves, well performance and potential liabilities and uncertainties in forecasting crude oil, NGL and natural gas prices and future development, production and marketing costs.
We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:
•recoverable reserves;
•future crude oil, NGL and natural gas prices and their appropriate differentials;
•development and operating costs;
•potential for future drilling and production;
•validity of the seller’s title to the properties, which may be less than expected at the time of signing the purchase agreement; and
•potential environmental and other liabilities, together with associated litigation of such matters.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities or title defects in excess of the amounts claimed by us before closing and acquire properties on an “as is” basis. Indemnification from the sellers will generally be effective only during a limited time period after the closing and subject to certain dollar limitations and minimums. We may not be able to collect on such indemnification because of disputes with the sellers or their inability to pay. Moreover, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results of operations or cash flows.
Significant acquisitions and other strategic transactions may involve other risks, including:
•diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
•the challenge and cost of integrating acquired and expanded operations, including those related to information management and other technology systems, permitting and other regulatory matters, and business cultures with those of our operations while carrying on our ongoing business;
•difficulty associated with coordinating geographically separate organizations or coordinating teams among various assets;
•an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and
•the challenge of attracting and retaining personnel associated with acquired operations.
The process of integrating assets from acquisitions and other strategic transactions could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. The success of an acquisition will depend, in part, on our ability to realize anticipated opportunities from combining the acquired assets or operations with those of ours. Even if we successfully integrate the assets acquired, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, in oil and gas industry conditions, by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, failure to retain key personnel, an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations and stock price may be adversely affected.
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We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring crude oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of crude oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.
Prior to the drilling of a crude oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in the title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. There is no assurance that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
Disputes or uncertainties may arise in relation to our royalty obligations.
Our production is subject to royalty obligations which may be prescribed by government regulation or by contract. These royalty obligations may be subject to changes in interpretation as business circumstances change and the law in jurisdictions in which we operate continues to evolve. Such changes in interpretation could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, such changes in interpretation could result in legal or other proceedings. Please see “Involvement in legal, governmental and regulatory proceedings could result in substantial liabilities” for a discussion of risks related to such proceedings.
Risks related to our financial position
Increased costs of capital could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates to combat inflation or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned operating results.
Our revolving credit facility and the indentures governing our senior unsecured notes contain operating and financial restrictions that may restrict our business and financing activities.
Our revolving credit facility and the indentures governing our senior unsecured notes contain a number of restrictive covenants that impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:
•sell assets, including equity interests in our subsidiaries;
•pay distributions on, redeem or repurchase our common stock or redeem or repurchase our debt;
•make investments;
•incur or guarantee additional indebtedness or issue preferred stock;
•create or incur certain liens;
•make certain acquisitions and investments;
•redeem or prepay other debt;
•enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
•consolidate, merge or transfer all or substantially all of our assets;
•engage in transactions with affiliates;
•create unrestricted subsidiaries;
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•enter into sale and leaseback transactions; and
•engage in certain business activities.
As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
Our ability to comply with some of the covenants and restrictions contained in our revolving credit facility and the indentures governing our senior unsecured notes may be affected by events beyond our control. If market or other economic conditions deteriorate or if crude oil, NGL and natural gas prices decline substantially or for an extended period of time from their current levels, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our revolving credit facility, our senior unsecured notes or any future indebtedness could result in an event of default under which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations.
If an event of default occurs and remains uncured, the lenders under our revolving credit facility:
•would not be required to lend any additional amounts to us;
•could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;
•may have the ability to require us to apply all of our available cash to repay these borrowings; or
•may prevent us from making debt service payments under our other agreements.
A payment default or an acceleration under our revolving credit facility could result in an event of default and an acceleration under the indentures for our senior unsecured notes. If the indebtedness under our senior unsecured notes were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. Our obligations under our revolving credit facility are collateralized by perfected first priority liens and security interests on substantially all of our oil and gas assets, including mortgage liens on oil and gas properties having at least 85% of the reserve value as determined by reserve reports. If we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets.
Our derivative activities could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of crude oil, NGL and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our crude oil, NGL and natural gas production, including two-way and three-way collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.
Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:
•production is less than the volume covered by the derivative instruments;
•the counterparty to the derivative instrument defaults on its contract obligations; or
•there is an increase in the differential between the underlying price in the derivative instrument and actual price received.
In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for crude oil and natural gas.
Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil, NGL and natural gas reserves.
Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of crude oil, NGL and natural gas reserves. Based upon our anticipated five-year development plan and current costs, we project that we will incur capital costs of approximately $3.0 billion to develop our PUD reserves. Please see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for more information about our capital expenditures. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, inflation in costs, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
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We intend to finance our future capital expenditures primarily through cash flows provided by operating activities; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of additional debt or equity securities or the sale of non-strategic assets. The issuance of additional debt or equity may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions or to pay dividends. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under our revolving credit facility will be automatically reduced by an amount equal to 25% of the aggregate principal amount of such debt securities, unless otherwise waived.
Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:
•our estimated net proved reserves;
•the level of crude oil, NGL and natural gas we are able to produce from existing wells and new projected wells;
•the prices at which our crude oil, NGL and natural gas are sold;
•regulatory and third-party approvals;
•the costs of developing and producing our crude oil and natural gas production;
•our ability to acquire, locate and produce new reserves;
•the ability and willingness of our banks to lend; and
•our ability to access the equity and debt capital markets.
If the borrowing base under our revolving credit facility or our revenues decrease as a result of low crude oil, NGL or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.
The inability of one or more of our customers or affiliates to meet their obligations to us may adversely affect our financial results.
Our principal exposures to credit risk are through receivables resulting from the sale of our crude oil, NGL and natural gas production, which we market to energy marketing companies, other producers, power generators, local distribution companies, refineries and affiliates, and joint interest receivables.
We are subject to credit risk due to the concentration of our crude oil, NGL and natural gas receivables with several significant customers. This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. We do not require all of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. See “Part II. Item 8.—Financial Statements and Supplementary Data—Note 19—Significant Concentrations” for additional information on significant concentrations with major customers.
Joint interest receivables arise from billing entities who own a 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 year ended December 31, 2025, changes in our estimate of expected credit losses were not material.
In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. At December 31, 2025, we had commodity derivatives in place with 15 counterparties and a total net commodity derivative asset of $85.7 million.
Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes or fees may adversely affect our operations and cash flows.
From time to time, U.S. federal and state level and Canadian federal and provincial legislation has been proposed that would, if enacted into law, make significant changes to U.S. and Canadian tax laws, including to certain key U.S. federal and state and Canadian federal income tax provisions currently available to oil and natural gas exploration and development companies. Such
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legislative changes have included, but have not been limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies and (v) an increase in the U.S. and Canadian federal income tax rate applicable to corporations such as us. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on oil and natural gas extraction. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes or fees on natural gas and oil extraction could adversely affect our operations and cash flows.
We may not be able to utilize all or a portion of our net operating loss carryforwards or other tax benefits to offset future taxable income for U.S. federal or state or Canadian federal tax purposes, which could adversely affect our financial position, results of operations and cash flows.
We may be limited in the portion of our net operating loss carryforwards (“NOLs”) that we can use in the future to offset taxable income for U.S. federal and state and Canadian federal income tax purposes. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be assured.
Under Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”), if a corporation experiences an “ownership change,” any NOLs, losses or deductions attributable to a “net unrealized built-in loss” and other tax attributes (“Tax Benefits”) could be substantially limited, and timing of the usage of such Tax Benefits could be substantially delayed. A corporation generally will experience an ownership change if one or more stockholders (or group of stockholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a testing period (generally, a rolling three-year period). Determining the limitations under Section 382 is technical and highly complex, and no assurance can be given that upon further analysis our ability to take advantage of our NOLs or other Tax Benefits may be limited to a greater extent than we currently anticipate.
We experienced an ownership change as a result of the merger of equals with Whiting Petroleum Corporation (“Whiting”) on July 1, 2022 (the “Merger”). In addition, Whiting experienced an ownership change as a result of a prior restructuring under Chapter 11 of the Bankruptcy Code. Accordingly, our ability to utilize our NOLs and other Tax Benefits (including Whiting’s NOLs and other Tax Benefits) is subject to a limitation under Section 382. If we experience a subsequent ownership change, our NOLs and other Tax Benefits may be further limited. We may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot predict or control that could result in further limitations being placed on our ability to utilize our NOLs and other Tax Benefits. Any such ownership changes and resulting limitations under Section 382 may result in us paying more taxes than if we were able to utilize our NOLs and other Tax Benefits, which could adversely affect our financial position, results of operations and cash flows.
The cost of servicing, and the ability to generate enough cash flows to meet our current or future debt obligations could adversely affect our business. Those risks could increase if we incur more debt.
As of December 31, 2025, we had no outstanding borrowings and $32.8 million of outstanding letters of credit under our revolving credit facility, $750.0 million of 6.000% senior unsecured notes outstanding and $750.0 million 6.750% senior unsecured notes outstanding. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. If crude oil, NGL and natural gas prices decline substantially or for an extended period of time from their current levels, we may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, and borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.
In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties. If we were to take on additional future debt, a substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by selling assets, reducing or delaying capital investments, seeking to raise additional capital or refinancing or restructuring our debt. We may or may not be able to complete any such steps on satisfactory terms. In addition, our revolving credit facility borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings under our revolving credit facility due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. Any ability to generate sufficient cash flows to satisfy our debt obligations or contractual commitments, or to refinance our debt on commercially reasonable terms, could materially and adversely affect our financial condition and results of operations.
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Risks related to our common stock
Our ability to declare and pay dividends is subject to certain considerations and limitations.
Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. Certain covenants in our revolving credit facility and the indentures governing our senior unsecured notes may limit our ability to pay dividends. We can provide no assurance that we will continue to pay dividends at the current rate or at all.
Our amended and restated certificate of incorporation, as amended, and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our amended and restated certificate of incorporation, as amended, authorizes our Board of Directors to issue preferred stock without stockholder approval. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
•advance notice provisions for stockholder proposals and nominations for elections to the Board of Directors to be acted upon at meetings of stockholders; and
•limitations on the ability of our stockholders to call special meetings.
Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our Board of Directors.
The issuance of stock-based awards may dilute your holding of shares of our common stock.
As of December 31, 2025, a total of 2,736,689 shares of common stock were available for future issuance under our equity incentive plans. The exercise of stock-based awards, including any stock options that we may grant in the future, warrants, and the sale of shares of our common stock underlying any such options or warrants, could have an adverse effect on the market for our common stock, including the price that an investor could obtain for their shares.
The market price of our common stock is subject to volatility.
The liquidity for our common shares has been below historical levels, and the market price of our common stock could be subject to wide fluctuations. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. The market price of our common stock can be affected by numerous factors, many of which are beyond our control. These factors include, among other things, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products or services, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions, such as an economic slowdown or recession, and other factors that may affect our future results.
General risk factors
Involvement in legal, governmental and regulatory proceedings could result in substantial liabilities.
Like other similarly-situated oil and gas companies, we are from time to time involved in various legal, governmental and regulatory proceedings in the ordinary course of business including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. The outcome of such matters often cannot be predicted with certainty. If our efforts to defend ourselves in legal, governmental and regulatory matters are not successful, it is possible the outcome of one or more such proceedings could result in substantial liability, penalties, sanctions, judgments, consent decrees or orders requiring a change in our business practices, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Judgments and estimates to determine accruals related to legal, governmental and regulatory proceedings could
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change from period to period, and such changes could be material. See “Item 1. Business—Regulation” for more discussion on the regulations to which we are subject and a discussion of various risks regarding our business as a result of such regulations.
Our profitability may be negatively impacted by inflationary pressures in the cost of labor, materials and services and general economic, business or industry conditions.
The U.S. economy has experienced significant inflation since 2021 stemming from, among other things, supply chain disruptions, wage increases associated with a low U.S. unemployment rate and governmental stimulus or fiscal policies adopted in response to the COVID-19 pandemic. Although U.S. inflation rates have moderated, we cannot predict any future trends in the rate of inflation. Elevated interest rates for prolonged periods and the state of the general economy have brought uncertainty to the near-term economic outlook and could increase the cost of future financing efforts. High levels of inflation could further raise our costs for labor, materials and services, due to a combination of factors, including: (i) global supply chain disruptions resulting in limited availability of certain materials and equipment (including drill pipe, casing and tubing), (ii) increased demand for fuel and steel, (iii) increased demand for services coupled with a limited availability of service providers and (iv) labor shortages, which would negatively impact our profitability and cash flows. We seek to mitigate these inflationary impacts by reviewing our pricing agreements on a regular basis and entering into agreements with our service providers to manage costs and availability of certain services that are utilized in our operations. It is difficult to predict whether such inflationary pressures will have a materially negative impact to our overall financial and operating results in the near future; however, such inflationary pressures are not expected to materially impact our overall liquidity position, cash requirements or financial position, or the ability to conduct our day-to-day drilling, completion and production activities.
Concerns over global economic conditions, changes in tariffs and trade agreements, energy costs, geopolitical issues, inflation and the availability and cost of credit in the European, Asian and U.S. markets contribute to economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of crude oil, NGL and natural gas, volatility in consumer confidence and job markets, may result in an economic slowdown or recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which crude oil, NGL and natural gas from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our business, results of operations and financial condition.
Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations and could result in information theft or data corruption.
The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as supervisory control and data acquisition (“SCADA”) now control large scale processes that can include multiple sites and long distances, such as crude oil and natural gas pipelines. We depend on digital technology, including information systems and related infrastructure as well as third-party cloud applications and services, to process and record financial and operating data and to communicate with our employees and business partners. Our business partners, including vendors, service providers and financial institutions, are also dependent on digital technology.
Terrorist attacks or cyber-attacks may significantly affect the energy industry, including our operations and those of our potential customers and third-party vendors, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. A cyber-attack could include gaining unauthorized access to our or third-party digital systems or data for purposes of misappropriating assets or sensitive information, corrupting data or causing operational disruption. SCADA-based systems are potentially vulnerable to targeted cyber-attacks due to their critical role in operations. We, or our business partners, may rely upon outdated information technology (“IT”) or software systems that may be at a higher risk of error, failure and cyber breach. Techniques used in cyber-attacks often range from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain access. Cyber-attacks may also be performed in a manner that does not require gaining unauthorized access, such as by causing denial-of-service attacks. In addition, certain cyber incidents, such as unauthorized surveillance or a data breach, may remain undetected for an extended period.
A cyber incident or technological failure involving our information systems or data and related infrastructure, or that of our business partners, including any vendor or service provider, could disrupt our business plans and negatively impact our operations in the following ways, among others:
•supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;
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•delays in delivering or failure to deliver product at the tailgate of our facilities, resulting in a loss of revenues;
•operational disruption resulting in loss of revenues;
•events of non-compliance that could lead to costly investigations and regulatory fines and/or penalties, class action litigation; and
•business interruptions that could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our units.
Our implementation of various controls and processes designed to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, despite our or our third-party partners’ security measures there can be no assurance that such measures will be sufficient to protect our IT systems from hacking, or other unauthorized system access, ransomware attacks, employee error, malfeasance, system error, faulty password management or other irregularities.
Moreover, as the sophistication, severity and volume of cyber-attacks continue to increase, we may be required to expend significant additional resources to further enhance our digital security and IT infrastructure or to remediate vulnerabilities, including through the use of artificial intelligence, and we may face difficulties in timely detecting or containing incidents or fully anticipating or implementing adequate preventive measures or mitigating potential harm. These costs may include making organizational changes, deploying additional personnel and protection technologies, training employees, and engaging third party experts and consultants. These efforts may come at the potential cost of revenues and human resources that could be utilized to continue to enhance our product offerings, and such increased costs and diversion of resources may adversely affect our operating margins. A cyber incident could ultimately result in investigations, liability under data privacy laws, regulatory penalties, damage to our reputation or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material adverse effect on our financial condition, liquidity or results of operations or the integrity of the systems, processes and data needed to run our business. A cyber incident could also give rise to potential costs and consequences that cannot be estimated or predicted. For example, the SEC has adopted rules requiring the disclosure of cybersecurity incidents that we determine to be “material,” to be made within four business days of such determination, which can be complex, requiring a number of assumptions based on several factors. It is possible that the SEC may not agree with our determinations, which could result in investigations, fines, civil litigation or damage to our reputation.
Destructive forms of protests and opposition by extremists and other disruptions, including acts of sabotage or eco-terrorism, against crude oil, NGL and natural gas development and production or midstream processing or transportation activities could potentially result in damage or injury to persons, property or the environment or lead to extended interruptions of our operations. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
Ineffective internal controls could impact our business and financial results.
Our internal controls over financial reporting may not prevent or detect misstatements because of their inherent limitations, including the possibility of human error, the circumvention or overriding of controls, or fraud. Even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. If we fail to maintain the adequacy of our internal controls, including any failure to implement required new or improved controls, or if we experience difficulties in their implementation, our business and financial results could be harmed, and we could fail to meet our financial reporting obligations.
We face risks associated with disruptive technologies, innovation and competition, including artificial intelligence.
Increasingly, E&P companies are leveraging artificial intelligence, including but not limited to generative artificial intelligence, to streamline business operations. Failure to effectively integrate artificial intelligence tools into our business operations could result in an inability to maintain a competitive edge among industry peers. In particular, such failure could result in an inability to meet industry needs as well as a loss in market share. Further, navigating continually evolving legal and regulatory requirements associated with implementing artificial intelligence tools may require significant resources to help ensure compliance with U.S. law.
Presently, we employ a limited array of artificial intelligence technology in our business, the use of which introduces us to certain risks including dependency on accurate intelligence performance, potential security breaches, challenges in regulatory compliance, ethical considerations, potential workforce disruption, the risk of intellectual property infringement, and other emerging technology risks. It is conceivable that we might integrate further artificial intelligence solutions into our information systems in the future, potentially assuming a more critical role in our operations over time. While we have established policies governing the use of artificial technology, and we safeguard our assets, including intellectual property and sensitive information, we cannot ensure that our employees, contractors or other agents would adhere to those policies. In addition, the
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legal and regulatory landscape related to artificial intelligence is constantly evolving and therefore remains uncertain and may be inconsistent from jurisdiction to jurisdiction. Our obligations to comply with the evolving legal and regulatory landscape could entail significant costs or limit our ability to incorporate certain artificial intelligence capabilities into our operations. Failure or perceived failure by us to address these risks adequately may negatively impact our operations, reputation and financial performance. Additionally, other unforeseen risks stemming from our use and development of artificial intelligence tools and technology may arise in the future that could adversely affect our business, financial condition and results of operations.
Item 1B. Unresolved Staff Comments
None.
Item 1C. Cybersecurity
Cybersecurity Risk Management and Strategy
We maintain a cybersecurity program overseen by the Vice President, Information Technology that uses a risk-based methodology to support the security, confidentiality, integrity and availability of our information. The security of our field infrastructure and corporate network is a priority for our business. We recognize the importance of assessing, identifying and managing material risks associated with cybersecurity threats. Our cybersecurity program utilizes a combination of automated tools, manual processes and third-party assessments with the goal of identifying and assessing potential cybersecurity risks. These risks may include, among other things, operational risks, unauthorized access to systems and data stored on them, intellectual property theft, fraud, extortion, harm to employees, customers or business partners, violation of privacy or security laws and other litigation and legal risk and reputational risks.
We have endeavored to implement policies, standards and technical controls based on the National Institute of Standards and Technology framework with the aim of protecting our networks, applications and data. We seek to assess, identify and manage cybersecurity risks through the processes described below:
•Risk Assessment: We have implemented a multi-layered system designed to protect and monitor data and cybersecurity risk. Periodic assessments of our cybersecurity safeguards are conducted both internally and by independent third-party cybersecurity vendors. Additionally, our internal audit department conducts regular audits designed to identify, assess and manage cybersecurity risks, and we endeavor to update cybersecurity infrastructure, procedures, policies and education programs in response to audit findings.
•Incident Identification and Response: We have implemented a monitoring and detection system that is designed to help promptly detect cybersecurity incidents. While processes are in place to minimize the chance of a successful cyberattack, we have established incident response procedures designed to address a cybersecurity threat that may occur despite these safeguards. The response procedures are designed to identify, analyze, contain and remediate any such cybersecurity incidents that occur. In the event of any breach or cybersecurity incident, we have a cross-functional enterprise-wide incident response plan, which includes the involvement of our executive management team, established incident levels, and associated notification procedures, including escalation procedures upon discovery of cybersecurity risks to our Board of Directors, outside counsel and law enforcement, if deemed material or appropriate. Further, we conduct periodic incident response tabletop exercises and planned incident response drills with various members of our management team that are designed to refine and update our incident response processes.
•Cybersecurity Training and Awareness: We maintain a formal information security training program for all employees and contractors that includes training on matters such as phishing, social engineering techniques, and email security best practices. We have implemented a requirement that all employees and contractors participate in information security training at least quarterly and have deployed internal phishing campaigns to measure the effectiveness of the training program.
•Access Controls: Our access controls are designed to provide users with access consistent with the principle of least privilege, which requires that users be given no more access than necessary to complete their job functions. We have also implemented a multi-factor authentication process for employees accessing company information.
•Systems and Processes: We use a combination of tools designed to detect cybersecurity incidents. We use firewalls and protection software in addition to working with a third-party cybersecurity vendor to scan internal and external networks for threat and intrusion detection. Our cybersecurity team periodically tests our controls through penetration tests, vulnerability scans and attack simulations.
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We engage third-party vendors and consultants throughout our business as needed. We recognize that third-party service providers introduce cybersecurity risks. In an effort to mitigate these risks, we conduct due diligence prior to engaging with any third-party service provider to evaluate the third-party provider’s cybersecurity capabilities, and maintain an ongoing monitoring process throughout the relationship to encourage continued compliance with our requirements and standards . For new cloud-based third-party providers, we review their cybersecurity practices in an effort to attempt to verify compliance with our cybersecurity standards. This process is documented through our Cloud Services Assessment. Additionally, we endeavor to include cybersecurity requirements in our contracts with third-party providers and endeavor to require them to adhere to our cybersecurity standards and protocols. Further, we require any third-party service providers with access to personally identifiable information to enter into data processing services agreements and adhere to our policies and standards. However, we are subject to the risk that our third-party providers and vendors may not fully comply with all of our policies and standards.
We have integrated the above cybersecurity risk management processes into our overall ERM program. Cybersecurity risks are understood to be significant business risks, and as such, are considered an important component of our enterprise-wide risk management approach.
Cybersecurity Governance and Oversight
The Board of Directors has primary oversight of risks from cybersecurity threats. The Board of Directors delegates oversight of risk, including reviews of cybersecurity and data protection and compliance with cybersecurity policies, to the Audit and Reserves Committee.
The Vice President, Information Technology
Management is responsible for assessing and managing cybersecurity risk. Specifically, the Vice President, Information Technology, is responsible for overseeing the prevention, mitigation, detection and remediation of cybersecurity incidents. Our Vice President, Information Technology, has over 20 years of experience, including prior industry experience consulting on various IT matters and developing and testing IT general controls and cybersecurity risk management programs. We maintain an internal staff of IT professionals who support our cybersecurity program and engage with third-party service providers to support specific areas of our cybersecurity risk mitigation and response.
The Vice President, Information Technology, works closely with other management positions, including our Chief Financial Officer, our Chief Strategy Officer & Chief Commercial Officer and our General Counsel, to help us maintain an effective incident response communication plan and understanding of our cybersecurity risk management processes. Our cybersecurity incident response plan provides processes for escalation if there is an emerging cybersecurity incident, including timely notice to our Board of Directors if the incident is deemed material or as otherwise appropriate.
Item 2. Properties
The information required by Item 2. is contained in Item 1. Business.
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Item 3. Legal Proceedings
See “Part II, Item 8. Financial Statements and Supplementary Data—Note 20—Commitments and Contingencies,” which is incorporated herein by reference, for a discussion of material legal proceedings.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market for Registrant’s Common Equity. Our common stock is listed on the Nasdaq under the symbol “CHRD”.
Dividends. In 2025, we paid an aggregate amount of base cash dividends of $5.20 per share of common stock. On February 25, 2026, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 27, 2026 to stockholders of record as of March 12, 2026.
In August 2025, the Board of Directors authorized a share repurchase program of up to $1.0 billion, which replaced the $750 million share repurchase program the Board of Directors had previously authorized in October 2024. See “Part I. Item 1. Business—Business Strategy—Maximize returns” for additional information on the return of capital plan.
Future dividend payments will depend on our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applicable to the payment of dividends and other considerations that our Board of Directors deems relevant. See “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividends” for more information.
Holders. As of February 13, 2026, the number of record holders of our common stock was 305. Based on inquiry, management believes that the number of beneficial owners of our common stock as of February 13, 2026 was approximately 142,269.
On February 13, 2026, the last sale price of our common stock, as reported on the Nasdaq, was $102.02 per share.
Unregistered Sales of Equity Securities. There were no sales of unregistered equity securities during the year ended December 31, 2025.
Securities Authorized for Issuance Under Equity Compensation Plans. Information concerning securities authorized for issuance under our equity compensation plans will be disclosed in our definitive proxy statement for our 2026 Annual Meeting of Stockholders.
Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities during the three months ended December 31, 2025:
| Period | Total Number of Shares Purchased(1)(2) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2)(3) | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs(2) | ||||||||||||||||||||||
October 1 – October 31, 2025 | — | $ | — | — | $ | 962,166,903 | ||||||||||||||||||||
November 1 – November 30, 2025 | — | — | — | 962,166,903 | ||||||||||||||||||||||
December 1 – December 31, 2025 | 103,057 | 97.01 | 103,057 | 952,169,220 | ||||||||||||||||||||||
___________________
(1)During the fourth quarter of 2025, we withheld no shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.
(2)During the fourth quarter of 2025, we repurchased 103,057 shares of common stock at a weighted average price of $97.01 per common share for a total cost of $10.0 million, under our publicly announced share repurchase program.
(3)In October 2024, our Board of Directors had previously authorized a share repurchase program of up to $750 million of our common stock. In August 2025, our Board of Directors authorized a new share repurchase program covering up to $1.0 billion of common stock, which replaced the existing $750 million share repurchase program.
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Stock Performance Graph. The following performance graph and related information is “furnished” with the SEC and shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically request that such information be treated as “soliciting material” or specifically incorporate such information by reference into such a filing.
The performance graph shown below compares the cumulative total return to our common stockholders as compared to the cumulative total returns on the Standard and Poor’s 500 Index (“S&P 500”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P 500 O&G E&P”) for the period of December 31, 2020 through December 31, 2025. The comparison was prepared based upon the following assumptions:
1.$100 was invested in our common stock, the S&P 500 and the S&P 500 O&G E&P on December 31, 2020 at the closing price on such date; and
2.Dividends were reinvested.
Item 6. [Reserved]
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Item 7. 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 our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. In addition, the following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. See “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this report for an explanation of these types of statements.
For discussion related to changes in financial condition and results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 27, 2025.
Overview
Chord Energy Corporation, a Delaware corporation (together with our consolidated subsidiaries, the “Company,” “Chord,” “we,” “us,” or “our”), is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, NGL and natural gas primarily in the Williston Basin with limited non-operated interests in the Marcellus Shale. On May 31, 2024, we acquired Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”) in a stock-and-cash transaction (such transaction, the “Arrangement”). Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a fun and rewarding environment for our employees. We are ideally positioned to generate strong free cash flow and enhance return of capital, while being responsible stewards of the communities and environment where we operate.
Recent Developments
2025 Williston Basin Acquisition
On September 15, 2025, we entered into a definitive agreement to acquire certain developed and undeveloped oil and gas assets located in the Williston Basin from XTO Energy Inc. and affiliates (collectively, “XTO”), subsidiaries of Exxon Mobil Corporation, for total cash consideration of $550.0 million, subject to customary purchase price adjustments (the “2025 Williston Basin Acquisition”).
On October 31, 2025, we completed the 2025 Williston Basin Acquisition for total cash consideration of $542.2 million, including a cash deposit of $55.0 million to XTO upon execution of the purchase and sale agreement and $487.2 million paid to XTO at closing (including customary preliminary purchase price adjustments). We funded the 2025 Williston Basin Acquisition with proceeds from the issuance of the 2030 Senior Notes (defined in “Liquidity and Capital Resources—Long-Term Debt” below) and cash on hand. The effective date of the 2025 Williston Basin Acquisition was September 1, 2025.
Market Conditions
Our revenue, profitability and ability to return cash to stockholders depend substantially on factors beyond our control, such as economic, geopolitical, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil, NGL 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, NGL and natural gas. The potential for continued volatility in our markets, economic uncertainty and unfavorable oil and gas market dynamics, including OPEC+ announcements during 2025 regarding increased oil production targets and U.S. tariffs and potential retaliatory tariffs, may have an adverse impact on our future business operations, financial condition and liquidity.
During 2025, the energy markets were marked by heightened volatility that led to frequent and unpredictable changes in crude oil prices. Throughout the year, prices fluctuated considerably, with periods of both decline and recovery. The average NYMEX WTI declined 14% during the year ended December 31, 2025, compared to the prior year, and overall conditions remain unstable. Market conditions during the year were adversely influenced by elevated production levels from OPEC+, ongoing trade and tariff negotiations between the United States and other governments, and retaliatory measures taken by such other governments. Further declines 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, as well as our access to capital. For example, 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 declines in crude oil and natural gas prices over that same period, we assessed goodwill for impairment and recognized a
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non‑cash impairment charge of $539.3 million. See “Item 8. Financial Statements and Supplementary Data—Note 6—Fair Value Measurements” for additional information.
In an effort to reduce inflationary pressures that emerged in the broader economy, central banks began to aggressively raise interest rates in 2022. After peaking in 2023, interest rates began to trend downward during 2024 and 2025. Although U.S. inflation rates have shown signs of moderating, higher interest rates generally reduce economic activity levels, which have and could in the future again result in lower commodity prices due to reduced demand for crude oil, NGL and natural gas (see “Item 7A. —Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information). The uncertainties resulting from the potential economic outcomes of monetary policy decisions of central banks as well as tariff and trade policy decisions of the U.S. or other governments, coupled with the geopolitical risks associated with the continued military conflicts in the Red Sea Region and the wider Middle East and the recent developments in relations between the United States and Venezuela, make it difficult to predict future impacts to commodity prices.
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 in the near future at current price levels; however, we would 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 price of crude oil, NGL or natural gas or a material increase in the costs of labor, materials or services. See “Part I, Item 1A. Risk Factors—If crude oil, NGL and natural gas prices decline, or for an extended period of time remain at depressed levels, we may be required to take write-downs of the carrying values of our oil and gas properties” for additional information.
In an effort to improve price realizations from the sale of our crude oil, NGL and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGL and natural gas to a broader array of potential purchasers. We enter into crude oil, NGL and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single customer would have a material adverse effect on our results of operations or cash flows. Please see “Part I, Item 1. Business—Exploration and Production Operations—Marketing.”
Our average net realized crude oil prices and average price differentials are shown in the tables below for the periods presented:
| 2025 | Year Ended December 31, 2025 | ||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | ||||||||||||||||||||||||||
Average realized crude oil prices ($/Bbl)(1) | $ | 69.11 | $ | 61.62 | $ | 63.59 | $ | 56.90 | $ | 62.78 | |||||||||||||||||||
Average price differential ($/Bbl)(2) | $ | (2.30) | $ | (2.15) | $ | (1.41) | $ | (2.24) | $ | (2.02) | |||||||||||||||||||
Average price differential percentage(2) | (3.3) | % | (3.5) | % | (2.2) | % | (3.9) | % | (3.2) | % | |||||||||||||||||||
| 2024 | Year Ended December 31, 2024 | ||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | ||||||||||||||||||||||||||
Average realized crude oil prices ($/Bbl)(1) | $ | 75.32 | $ | 78.89 | $ | 73.51 | $ | 68.79 | $ | 73.67 | |||||||||||||||||||
Average price differential ($/Bbl)(2) | $ | (1.71) | $ | (1.41) | $ | (1.51) | $ | (1.49) | $ | (1.52) | |||||||||||||||||||
Average price differential percentage(2) | (2.3) | % | (1.8) | % | (2.1) | % | (2.2) | % | (2.1) | % | |||||||||||||||||||
__________________
(1)Realized crude oil prices do not include the effect of derivative contract settlements.
(2)Price differential reflects the difference between our realized crude oil prices and NYMEX WTI.
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 December 31, 2025, substantially all of our gross operated crude oil production was connected to gathering systems. Our market optionality on these crude oil gathering systems allows us to shift volumes between pipeline and, to a lesser extent, rail markets in order to optimize price realizations. Expansions of both pipeline and rail facilities in the Williston Basin has reduced prior constraints on crude oil takeaway capacity and improved our price differentials received at the lease.
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Results of Operations
Comparability of Financial Statements
The results of operations presented below relate to the periods ended December 31, 2025 and 2024. The results reported for the year ended December 31, 2025 reflect the consolidated results of Chord, while the results reported for the year ended December 31, 2024 reflect the consolidated results of Chord, including combined operations with Enerplus beginning on May 31, 2024, unless otherwise noted.
For a discussion of the changes related to the financial condition and results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024, filed with the SEC on February 27, 2025.
Operational and Financial Highlights
•Production volumes averaged 276,620 Boepd (56% oil) for the year ended December 31, 2025.
•Lease operating expenses (“LOE”) were $9.73 per Boe for the year ended December 31, 2025.
•Capital expenditures (excluding capitalized interest) were $1,357.9 million for the year ended December 31, 2025.
•Net cash provided by operating activities was $2,040.7 million and net income was $44.5 million for the year ended December 31, 2025.
•Estimated net proved reserves were 917.5 MMBoe as of December 31, 2025, with a Standardized Measure of $7.5 billion and PV-10 of $9.1 billion.
•TIL’d 122 gross (99 net) operated wells for the year ended December 31, 2025.
Shareholder Return Highlights
•Paid $5.20 per share base cash dividends for the year ended December 31, 2025.
•Repurchased $364.5 million of common stock (excluding accrued excise taxes) during the year ended December 31, 2025 with $952.2 million remaining under the new $1.0 billion share repurchase program authorized by the Board of Directors in August 2025.
•On February 25, 2026, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 27, 2026 to stockholders of record as of March 12, 2026.
Net Income
We had net income of $44.5 million for the year ended December 31, 2025, which decreased 95% as compared to $848.6 million for the year ended December 31, 2024, primarily due to decreased realized oil prices and a non-cash goodwill impairment charge during the year ended December 31, 2025. The impacts on net income of our expanded operations from the Arrangement and other increases and decreases in revenues and expenses are further explained below.
Revenues
Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold and/or changes in commodity prices. Additionally, our revenues for the year ended December 31, 2025 were positively impacted due to the Arrangement, which expanded our operations primarily in the Williston Basin. Our purchased oil and gas sales are derived from the sale of crude oil, NGL 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:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands, except price per unit data) | |||||||||||
| Revenues | |||||||||||
| Crude oil revenues | $ | 3,546,890 | $ | 3,571,336 | |||||||
| NGL revenues | 138,277 | 162,052 | |||||||||
| Natural gas revenues | 211,973 | 102,750 | |||||||||
| Purchased oil and gas sales | 979,986 | 1,414,944 | |||||||||
| Total revenues | $ | 4,877,126 | $ | 5,251,082 | |||||||
| Production data | |||||||||||
| Crude oil (MBbls) | 56,500 | 48,479 | |||||||||
| NGL (MBbls) | 19,149 | 16,338 | |||||||||
Natural gas (MMcf)(1) | 151,903 | 122,193 | |||||||||
| Oil equivalents (MBoe) | 100,966 | 85,182 | |||||||||
| Average daily production (Boepd) | 276,620 | 232,737 | |||||||||
| Average daily crude oil production (Bopd) | 154,795 | 132,455 | |||||||||
| Average sales prices | |||||||||||
| Crude oil (per Bbl) | |||||||||||
| Average sales price | $ | 62.78 | $ | 73.67 | |||||||
Effect of derivative settlements(2) | 0.81 | 0.02 | |||||||||
Average realized price after the effect of derivative settlements(2) | $ | 63.59 | $ | 73.69 | |||||||
| NGL (per Bbl) | |||||||||||
| Average sales price | $ | 7.22 | $ | 9.92 | |||||||
Effect of derivative settlements(2) | — | — | |||||||||
Average realized price after the effect of derivative settlements(2) | $ | 7.22 | $ | 9.92 | |||||||
| Natural gas (per Mcf) | |||||||||||
Average sales price(1) | $ | 1.40 | $ | 0.84 | |||||||
Effect of derivative settlements(2) | 0.11 | — | |||||||||
Average realized price after the effect of derivative settlements(1)(2) | $ | 1.51 | $ | 0.84 | |||||||
__________________
(1)For the years ended December 31, 2025 and 2024, natural gas production volume from the Marcellus Shale was 45,151 MMcf and 24,727 MMcf, respectively. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $3.15 per Mcf and $1.78 per Mcf for the years ended December 31, 2025 and 2024, respectively.
(2)The effect of derivative settlements includes the cash received or paid for the cumulative gains or losses on our commodity derivatives settled in the periods presented. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.
Crude oil revenues. Our crude oil revenues decreased $24.4 million to $3,546.9 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. Excluding the increase of $491.4 million due to our expanded operations as a result of the Arrangement, our crude oil revenues decreased $545.6 million due to lower crude oil realized prices year-over-year, partially offset by an increase of $29.8 million due to higher total crude oil production volumes sold. Average crude oil sales prices, without derivative settlements, decreased by $10.89 per barrel year-over-year to an average of $62.78 per barrel for the year ended December 31, 2025 due to decreases in NYMEX WTI and widening in-basin differentials.
NGL revenues. Our NGL revenues decreased $23.8 million to $138.3 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. Excluding the increase of $3.8 million due to our expanded operations as a result of the Arrangement, our NGL revenues decreased $34.5 million due to lower NGL realized prices year-over-year, partially offset by an increase of $6.9 million due to higher total NGL production volumes sold. Average NGL sales prices, without derivative settlements, decreased by $2.70 per barrel period over period to an average of $7.22 per barrel for the year
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ended December 31, 2025 primarily due to wider differentials on incremental production volumes primarily as a result of the Arrangement.
Natural gas revenues. Our natural gas revenues increased $109.2 million to $212.0 million for the year ended December 31, 2025 as compared to the year ended December 31, 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 $41.4 million primarily due to higher average natural gas realized prices. Average natural gas sales prices, without derivative settlements, increased by $0.56 per Mcf period over period to $1.40 per Mcf for the year ended December 31, 2025 primarily due to increases in natural gas index prices period over period.
Purchased oil and gas sales. Purchased oil and gas sales decreased $435.0 million to $980.0 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. This decrease was primarily due to a decrease in the volume of crude oil purchased and subsequently sold as well as lower crude oil prices year-over-year.
Expenses and other income (expense)
Certain operating expenses, including LOE, GPT expenses and DD&A, increased for the year ended December 31, 2025 as compared to the year ended December 31, 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:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands, except per Boe of production) | |||||||||||
| Operating expenses | |||||||||||
| Lease operating expenses | $ | 982,610 | $ | 824,408 | |||||||
| Gathering, processing and transportation expenses | 290,917 | 267,559 | |||||||||
| Purchased oil and gas expenses | 975,128 | 1,412,357 | |||||||||
| Production taxes | 291,880 | 333,397 | |||||||||
| Depreciation, depletion and amortization | 1,470,171 | 1,107,776 | |||||||||
| General and administrative expenses | 126,294 | 205,585 | |||||||||
| Impairment and exploration | 551,412 | 17,021 | |||||||||
| Total operating expenses | 4,688,412 | 4,168,103 | |||||||||
| Gain on sale of assets, net | 8,711 | 17,088 | |||||||||
| Operating income | 197,425 | 1,100,067 | |||||||||
| Other income (expense) | |||||||||||
| Net gain on derivative instruments | 127,618 | 12,563 | |||||||||
| Net gain (loss) from investment in equity securities | (12,957) | 51,284 | |||||||||
| Interest expense, net of capitalized interest | (80,150) | (56,523) | |||||||||
| Loss on extinguishment of debt | (3,494) | — | |||||||||
| Other income, net | 15,042 | 5,047 | |||||||||
| Total other income, net | 46,059 | 12,371 | |||||||||
| Income before income taxes | 243,484 | 1,112,438 | |||||||||
| Income tax expense | (199,025) | (263,811) | |||||||||
| Net income | $ | 44,459 | $ | 848,627 | |||||||
| Costs and expenses (per Boe of production) | |||||||||||
| Lease operating expenses | $ | 9.73 | $ | 9.68 | |||||||
| Gathering, processing and transportation expenses | 2.88 | 3.14 | |||||||||
| Production taxes | 2.89 | 3.91 | |||||||||
Lease operating expenses. LOE increased $158.2 million to $982.6 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. The increase was primarily driven by our expanded operations after the Arrangement, contributing $115.3 million of additional LOE period over period. Additionally, workover costs increased by $30.2 million and
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fixed and variable costs increased by $12.6 million primarily due to 122 gross (99 net) operated new wells brought online during year ended December 31, 2025. LOE per Boe increased $0.05 per Boe period over period to $9.73 per Boe for the year ended December 31, 2025 primarily due to increased workover costs.
Gathering, processing and transportation expenses. GPT expenses increased $23.4 million to $290.9 million for the year ended December 31, 2025 as compared to the year ended December 31, 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 certain derivative transportation contracts in June 2024. GPT expenses decreased $0.26 per Boe period over period to $2.88 per Boe for the year ended December 31, 2025 primarily due to an increase in production volumes, lower transportation rates and fair value losses period over period.
Purchased oil and gas expenses. Purchased oil and gas expenses decreased $437.2 million to $975.1 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024 primarily due to a decrease in the volume of crude oil purchased and subsequently sold as well as lower crude oil prices year-over-year.
Production taxes. Production taxes decreased $41.5 million to $291.9 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. Excluding the $46.0 million increase in production taxes attributable to our expanded operations after the Arrangement, production taxes decreased $66.6 million primarily due to a decrease in crude oil revenues year over year due to lower crude oil realized prices and decreased $20.9 million as a result of a reduction in the production tax rate during the year ended December 31, 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 sales was 7.5% for the year ended December 31, 2025 as compared to 8.7% for the year ended December 31, 2024. This rate decrease year-over-year was primarily due to the non-recurring refund in 2025 coupled with natural gas comprising a larger percentage of total sales relative to the prior period.
Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $362.4 million to $1,470.2 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. The increase was primarily due to $209.6 million of additional depletion expense due to a higher depletion rate year-over-year, coupled with $128.2 million of additional DD&A expense related to an overall increase in production volumes year-over-year, mainly due to our expanded operations after the Arrangement, as well as an increase in accretion expense of $19.8 million. The depletion rate increased $1.82 per Boe year-over-year to $14.12 per Boe for the year ended December 31, 2025 primarily due to the purchase consideration allocated to the fair value of oil and gas properties acquired in the Arrangement and the 2025 Williston Basin Acquisition.
General and administrative expenses. Our general and administrative (“G&A”) expenses decreased $79.3 million to $126.3 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024, primarily due to a $79.5 million decrease in merger and acquisition-related costs year-over-year. Merger and acquisition-related costs for the years ended December 31, 2025 and 2024 were $9.8 million and $89.3 million, respectively, and were primarily comprised of severance, legal, and advisory expenses related to the Arrangement.
Impairment and exploration expenses. Impairment and exploration expenses increased $534.4 million to $551.4 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024, primarily due to the impairment of our goodwill. During the year ended December 31, 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 during that same period.
Gain on sale of assets, net. During the years ended December 31, 2025 and 2024, we recorded a net gain on sale of assets of $8.7 million and $17.1 million, respectively, primarily related to the divestiture of certain oil and gas properties within each period.
Derivative instruments. During the year ended December 31, 2025, we recorded a $127.6 million net gain on derivative instruments, which was primarily comprised of a net gain of $125.4 million associated with our commodity derivative contracts and a net gain of $2.2 million associated with a contract that included contingent consideration. The net gain of $125.4 million on commodity derivative contracts included a realized gain of $63.8 million on settled commodity derivative contracts, coupled with an unrealized gain of $61.6 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. During the year ended December 31, 2024, we recorded a $12.6 million net gain on derivative instruments, which was primarily comprised of a net gain of $7.5 million associated with our commodity derivative contracts and a net gain of $5.1 million associated with a contract that included contingent consideration. The net gain of $7.5 million on commodity derivative contracts included an unrealized gain of $6.6 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, coupled with a realized gain of $0.9 million on settled commodity derivative contracts.
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Investment in equity securities. We recorded a $13.0 million loss related to our investment in Energy Transfer for the year ended December 31, 2025, which included an unrealized loss of $22.5 million as a result of a decrease in the fair value of the investment during the year, partially offset by a realized gain of $9.5 million for cash distributions received. During the year ended December 31, 2024, we recorded a $51.3 million gain related to our investment in Energy Transfer, primarily related to a realized gain of $42.0 million as a result of an increase in the fair value of the investment during the year and a realized gain of $9.3 million for cash distributions received.
Interest expense, net of capitalized interest. Interest expense increased $23.6 million to $80.2 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. The increase is primarily due to $32.0 million of higher interest expense on a greater outstanding balance of senior notes resulting from the issuance of the 2033 Senior Notes (as defined below) and the 2030 Senior Notes (as defined below) during 2025, partially offset by the impact of the repayment of the 2026 Senior Notes in March 2025. This increase in interest expense was partially offset by a decrease in interest expense on the Credit Facility (as defined below) of $9.6 million year-over-year. For the year ended December 31, 2025, the weighted average borrowings outstanding under the Credit Facility were $215.0 million, and the weighted average interest rate incurred on the outstanding borrowings was 6.52%. For the year ended December 31, 2024, the weighted average borrowings outstanding under the Credit Facility were $362.2 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.27%.
Loss on debt extinguishment. On March 13, 2025, we paid an aggregate of $409.1 million to purchase and satisfy and discharge $400.0 million of our 6.375% senior unsecured notes due June 1, 2026 (the “2026 Senior Notes), resulting in a loss on debt extinguishment of $3.5 million for the year ended December 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.
Other income, net. For the year ended December 31, 2025, we recognized $15.0 million of other income, net, which related primarily to proceeds from the disposition of surplus equipment, partially offset by remeasurement of equipment inventory. For the year ended December 31, 2024, we recognized $5.0 million of other income, net, which related primarily to interest income associated with the average cash balance in our money market account.
Income tax expense. Our effective tax rate was recorded at 81.7% and 23.7% of pre-tax income for the years ended December 31, 2025 and December 31, 2024, respectively. Our effective tax rate for the year ended December 31, 2025 was higher than the statutory federal tax rate of 21% primarily as a result of the impact of the goodwill impairment charge recorded during the second quarter of 2025. The effective tax rate for the year ended December 31, 2024 was higher than the statutory federal tax rate of 21% primarily as a result of the impact of state income taxes.
Liquidity and Capital Resources
As of December 31, 2025, we had $2,156.7 million of liquidity available, including $1,967.2 million of aggregate unused borrowing base capacity available under our Credit Facility (as defined below) and $189.5 million in cash and cash equivalents. We had no net borrowings outstanding under our Credit Facility and $32.8 million of outstanding letters of credit. Our primary sources of liquidity were from cash flows from operations, available borrowing capacity under the Credit Facility, proceeds from the issuance of the 2030 Senior Notes and the 2033 Senior Notes and cash on hand. Our primary liquidity requirements were debt repayments under our Credit Facility, capital expenditures for the development of oil and gas properties, acquisitions, debt repayments under the 2026 Senior Notes, share repurchases, dividend payments and working capital requirements.
Capital availability is affected by prevailing conditions in our industry, the global economy, the global banking and financial markets, stakeholder scrutiny of sustainability matters and other factors, many of which are beyond our control. The U.S. Federal Reserve has continued to steadily decrease interest rates, however the potential for such rates to decrease further or to increase or remain elevated for an extended period of time creates 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.
Williston Basin Acquisition. On October 31, 2025, we completed the 2025 Williston Basin Acquisition for total cash consideration of $542.2 million, including the $55.0 million deposit and $487.2 million paid to XTO at closing (including customary preliminary purchase price adjustments).
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 and $102.4 million to settle all outstanding Enerplus equity-based compensation awards, as well as $5.9 million in retention bonuses paid to Enerplus employees.
We also incurred certain costs for advisory, legal and other third-party fees in connection with the Arrangement, which were recorded to G&A expenses on the Consolidated Statements of Operations. During the years ended December 31, 2025 and
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2024, we incurred merger and acquisition-related costs of $9.8 million and $89.3 million, respectively, and were primarily comprised of severance, legal, and advisory expenses related to the Arrangement.
Our cash flows depend on many factors, including the price of crude oil, NGL and natural gas and the success of our development and exploration activities as well as future acquisitions. 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.
Commodity derivative contracts. As of December 31, 2025, our commodity derivative contracts cover 7,216 MBbls of our crude oil production and 44,185 MMBtu of our natural gas production for 2026, as well as 2,501 MBbls of our crude oil production and 13,620 MMBtu of our natural gas production for 2027. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and “Part I, Item 1A. Risk Factors” for additional information.
Subsequent to December 31, 2025, we entered into new commodity derivative contracts to manage risks related to changes in commodity prices. The following table summarizes these commodity derivative contracts:
| Weighted Average Prices | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity | Settlement Period | Derivative Instrument | Volumes | Fixed-Price Swaps | Sub-Floor | Floor | Ceiling | |||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2026 | Three-way collars | 459,000 | Bbls | $ | 45.00 | $ | 55.00 | $ | 67.75 | ||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2026 | Two-way collars | 2,108,000 | Bbls | $ | 60.00 | $ | 66.28 | ||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2027 | Three-way collars | 1,732,000 | Bbls | $ | 48.42 | $ | 58.42 | $ | 72.01 | ||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2027 | Two-way collars | 270,000 | Bbls | $ | 60.00 | $ | 65.22 | ||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2028 | Three-way collars | 364,000 | Bbls | $ | 48.75 | $ | 58.75 | $ | 73.79 | ||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2026 | Fixed-price swaps | 3,220,000 | MMBtu | $ | 4.10 | ||||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2027 | Fixed-price swaps | 905,000 | MMBtu | $ | 4.00 | ||||||||||||||||||||||||||||||||||||||||||||
Material cash requirements
Our material cash requirements from known obligations include repayment of outstanding borrowings and interest payment obligations related to our long-term debt, payment of income taxes, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, obligations associated with our leases, obligations associated with outstanding commodity derivative contracts that settle in a loss position and obligations to pay dividends on equity awards. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to stockholders through base dividend payouts, supplemented by opportunistic share repurchases and variable dividend payouts. There were no borrowings outstanding under the Credit Facility (as defined below) as of December 31, 2025; however, 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.
We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGL, natural gas and water within specified time frames, the majority of which are five years or less. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. The estimable future commitments under these agreements were $467.9 million as of December 31, 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 can purchase sufficient volumes of crude oil, NGL and natural gas from third parties to satisfy our minimum volume commitments.
Long-term debt
Our long-term debt consists of a senior secured revolving line of credit that is generally used to support our working capital requirements, $750.0 million of 6.000% senior unsecured notes and $750.0 million of 6.750% senior unsecured notes.
Senior secured revolving line of credit. As of December 31, 2025, we had a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $2.75 billion and an aggregate amount of elected commitments of $2.0 billion that is due November 3, 2029. We had no net borrowings outstanding and $32.8 million of outstanding letters of credit, resulting in an unused borrowing base capacity of $1,967.2 million as of December 31, 2025. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. In November 2025, we completed the semi-annual borrowing base redetermination, which affirmed the borrowing base of $2.75 billion and the aggregate amount of elected commitments of $2.0 billion and entered into the Seventh Amendment to the Amended and Restated Credit Agreement.
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For the year ended December 31, 2025, the weighted average interest rate incurred on borrowings under the Credit Facility was 6.52%, compared to 7.27% for the year ended December 31, 2024.
We were in compliance with the financial covenants in the Credit Facility at December 31, 2025. See “Item 8. Financial Statements and Supplementary Data—Note 12—Long-Term Debt” for additional information.
Senior unsecured notes. As of December 31, 2025, we had $750.0 million of 6.750% senior unsecured notes (the “2033 Senior Notes”) that mature on March 15, 2033 and $750.0 million of 6.000% senior unsecured notes (the “2030 Senior Notes”) that mature on October 1, 2030. Interest on the 2033 Senior Notes is payable semi-annually on March 15 and September 15 of each year, and interest on the 2030 Senior Notes is payable semi-annually on April 1 and October 1 of each year. We were in compliance with the terms of the indentures for the 2030 Senior Notes and the 2033 Senior Notes at December 31, 2025. See “Item 8. Financial Statements and Supplementary Data—Note 12—Long-Term Debt” for additional information.
Cash flows
The following table summarizes our changes in cash flows for the years presented:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Net cash provided by operating activities | $ | 2,040,657 | $ | 2,097,227 | |||||||
Net cash used in investing activities | (1,805,981) | (1,753,817) | |||||||||
Net cash used in financing activities | (82,095) | (624,458) | |||||||||
| Increase (decrease) in cash and cash equivalents | $ | 152,581 | $ | (281,048) | |||||||
For a discussion on cash flows for the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2024 Annual Report on Form 10-K filed with the SEC on February 27, 2025 under the subheading “Cash flows.”
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 $2,040.7 million for the year ended December 31, 2025. The decrease in net cash provided by operating activities of $56.6 million from the year ended December 31, 2024 was primarily due to lower revenues from crude oil and NGL sales driven by decreased crude oil and NGL realized prices, higher cash interest expenses and changes in our working capital. These decreases were largely offset by our expanded operations from the Arrangement, lower merger and acquisition-related costs and decreased production taxes primarily driven by decreased crude oil sales. Crude oil, NGL and natural gas revenues were positively impacted by an increase in crude oil, NGL, and natural gas production volumes due to our expanded operations from the Arrangement, partially offset by increases in LOE and GPT expenses. See “Results of Operations” above for additional information.
Working capital. Our working capital is primarily impacted due to the factors discussed above, coupled with the timing of cash receipts and disbursements. During the years ended December 31, 2025 and 2024, changes in working capital (as reflected in the Consolidated Statements of Cash Flows) decreased net cash flows from operating activities by $7.2 million and $34.1 million, 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 $1,967.2 million as of December 31, 2025, and excludes current hedge assets, which were $77.3 million as of December 31, 2025. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which there were none as of December 31, 2025.
Cash flows used in investing activities
For the year ended December 31, 2025, net cash used in investing activities of $1,806.0 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $1,347.9 million and net cash paid for acquisitions of $575.7 million paid primarily for the 2025 Williston Basin Acquisition, partially offset by the settlement of derivative contracts of $56.3 million, the receipt of a 2024 contingent consideration earn-out payment of $25.0 million, proceeds from divestitures of certain non-core oil and gas properties of $24.8 million and distributions from our investment in equity securities of $11.6
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million. For the year ended December 31, 2024, net cash used in investing activities of $1,753.8 million was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $1,179.1 million, and net cash paid for acquisitions of $655.0 million. The net cash paid for acquisitions during 2024 primarily related to the Arrangement and included $395.0 million paid to settle Enerplus’ revolving bank credit facility balance, $375.8 million paid to Enerplus shareholders and $102.4 million paid to settle Enerplus’ outstanding equity awards, partially offset by cash acquired in the Arrangement of $239.9 million. Net cash used in investing activities for the year ended December 31, 2024 also included proceeds from divestitures of $60.7 million, the receipt of a 2023 contingent consideration earn-out payment of $25.0 million and distributions from our investment in equity securities of $7.2 million.
Cash flows used in financing activities
For the year ended December 31, 2025, net cash used in financing activities of $82.1 million was primarily attributable to repayments under the Credit Facility of $4,271.0 million, which were offset by borrowings of $3,826.0 million, resulting in net repayments under the Credit Facility of $445.0 million, repayments of the 2026 Senior Notes totaling $401.4 million, payments to repurchase common stock of $364.9 million, dividends paid to shareholders of $317.8 million, payment of debt issuance costs of $29.4 million made in connection with the 2030 Senior Notes, 2033 Senior Notes and the Seventh Amendment to the Amended and Restated Credit Agreement and payments for income tax withholdings on vested equity-based compensation awards of $22.1 million. These uses of cash were partially offset by the issuance of the 2030 Senior Notes and the 2033 Senior Notes of $1,500.0 million. For the year ended December 31, 2024, net cash used in financing activities of $624.5 million was primarily attributable to dividends paid to shareholders of $529.9 million, payments to repurchase common stock of $444.2 million, payments for income tax withholdings on vested equity-based compensation awards of $63.4 million and repayment of the $63.0 million of 3.79% senior unsecured notes assumed from Enerplus. These uses of cash were partially offset by borrowings under the Credit Facility of $3,535.0 million, offset by repayments of $3,090.0 million, resulting in net borrowings under the Credit Facility of $445.0 million, made primarily in connection with the Arrangement and proceeds from the exercise of outstanding warrants of $35.8 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:
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands) | |||||||||||||||||
E&P(1) | $ | 1,337,565 | $ | 1,222,507 | $ | 918,851 | |||||||||||
| Midstream | 18,320 | 6,756 | 1,990 | ||||||||||||||
Other(2) | 1,999 | 2,286 | 1,493 | ||||||||||||||
| Capitalized interest | 4,419 | 4,905 | 4,133 | ||||||||||||||
Total capital expenditures(3) | $ | 1,362,303 | $ | 1,236,454 | $ | 926,467 | |||||||||||
__________________
(1)Total E&P capital expenditures include approximately $19.7 million, $25.2 million and $14.5 million of non-operated capital expenditures related to certain non-operated divested assets that were reimbursable for the years ended December 31, 2025, 2024 and 2023, respectively.
(2)Other capital expenditures include items such as corporate and administrative capital.
(3)Total capital expenditures reflected in the table above differ from the amounts for capital expenditures shown in the statements of cash flows in our consolidated financial statements because amounts reflected in the table above include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis.
For the year ended December 31, 2025, our total capital expenditures increased $125.8 million to $1,362.3 million primarily due to an increase in non-operated drilling and completion activities of $109.6 million, coupled with our expanded operations as a result of the Arrangement.
Acquisition and leasehold costs were $576.5 million, $16.0 million and $361.6 million for the years ended December 31, 2025, 2024 and 2023, respectively. Acquisitions include $542.2 million for the 2025 Williston Basin Acquisition and $361.6 million for the acquisition of net acreage in the Williston Basin for the years ended December 31, 2025 and 2023, respectively, and exclude amounts attributable to the Arrangement, including cash consideration of $375.8 million, for the year ended December 31, 2024.
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Refer to “Item 8. Financial Statements and Supplementary Data—Note 9—Acquisitions” for additional information.
Our planned 2026 capital expenditures are expected to be approximately $1.35 billion to $1.45 billion. We expect to run four to five operated rigs during the majority of 2026 and plan to TIL approximately 135 to 165 gross operated wells with an average working interest of approximately 75%.
The ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Our capital plan may further be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If crude oil prices decline substantially or for an extended period of time, we could defer a significant portion of our planned capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. Furthermore, we actively review acquisition opportunities on an ongoing basis. If we acquire additional acreage, our capital expenditures may be higher than planned. However, our ability to make significant acquisitions for cash may require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.
Dividends
During the year ended December 31, 2025, we declared base cash dividends of $5.20 per share of common stock, or $302.5 million in aggregate. On February 25, 2026, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 27, 2026 to shareholders of record as of March 12, 2026.
During the year ended December 31, 2024, we declared base-plus-variable cash dividends of $10.15 per share of common stock, or $507.6 million in aggregate.
Future dividend payments will depend on our 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
In August 2025, our Board of Directors authorized a new share repurchase program covering up to $1.0 billion of our common stock. At times we have 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 us to repurchase shares at times that may otherwise be prohibited under its insider trading policy. The share repurchase program does not require us to make purchases within a particular time frame.
During the year ended December 31, 2025, we repurchased 3,491,618 shares of common stock at a weighted average price of $104.39 per common share for a total cost of $364.5 million (excluding accrued excise taxes) under our existing and previous share repurchase programs. As of December 31, 2025, there was $952.2 million of capacity remaining under the existing $1.0 billion program.
During the year ended December 31, 2024, we repurchased 3,114,007 shares of common stock at a weighted average price of $142.20 per common share for a total cost of $442.8 million under our previous share repurchase programs.
Critical accounting policies and estimates
Our consolidated financial statements have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. See “Item 8. Financial Statements and Supplementary Data—Note 2—Summary of Significant Accounting Policies” for the significant accounting policies and estimates made by management as well as the expected impact of recent accounting pronouncements on our consolidated financial statements. The following are the accounting policies, estimates and judgments used in preparation of our consolidated financial statements which we consider most critical:
Method of accounting for oil and gas properties
GAAP provides two alternative methods to account for oil and gas properties known as the successful efforts method and the full cost method. These two accounting methods differ in a number of ways, including the treatment of the costs of exploratory dry holes and geological and geophysical costs which are charged against earnings during the period incurred under the successful efforts method and capitalized within a pool of assets under the full cost method. We account for oil and gas
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properties under the successful efforts method of accounting. See “Item 8. Financial Statements and Supplementary Data—Note 2—Summary of Significant Accounting Policies—Property, Plant and Equipment” for additional information.
Estimated quantities of reserves
Our independent reserve engineers prepare our estimates of crude oil, NGL and natural gas reserves. While the SEC rules allow us to disclose proved, probable and possible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. Estimates of reserve quantities and the related estimates of future net cash flows are used as inputs into the calculation of the fair value of oil and gas properties in a business combination, the assessment of whether sufficient future taxable income will be generated to realize deferred tax assets, the calculation of depletion expense, the evaluation of proved oil and gas properties for impairment and the Standardized Measure.
Estimates of reserves are prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the Estimating and Auditing Standards. Crude oil, NGL and natural gas reserves engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, changes to our anticipated five-year development plan, changes to commodity prices, cost changes, timing of settlement of ARO liabilities, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities of crude oil, NGL and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions, and if such revisions are significant, they could significantly affect future depletion expense, the carrying amount of our proved oil and gas properties and the Standardized Measure. See “Item 1. Business—Exploration and Production Operations—Estimated net proved reserves” for additional information on the revisions to our estimated net proved reserves.
Our estimated net proved reserves and PV-10 were determined using the SEC Price. The SEC Price was $65.34 per Bbl for crude oil and $3.39 per MMBtu for natural gas for the year ended December 31, 2025. We cannot reasonably predict future commodity prices; however, assuming all other factors are held constant, a 10% decrease in the SEC Price for crude oil and natural gas would decrease our estimated net proved reserves by 30.4 MMBoe and decrease the PV-10 by $1.8 billion, and a 10% increase in the SEC Price for crude oil and natural gas would increase our estimated net proved reserves by 24.4 MMBoe and increase the PV-10 by $1.8 billion.
Business combinations
We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.
We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair value of the oil and gas properties is calculated using an income approach based on the net discounted future cash flows that utilized inputs requiring significant judgment and assumptions, including future production volumes based upon estimates of reserves prepared by our reserve engineers, future commodity prices (adjusted for basis differentials), future operating and development costs and a market-based weighted average cost of capital discount rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of crude oil, NGL and natural gas properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties. Different techniques may be used to determine fair values, including market prices (where available), comparisons to transactions for similar assets and liabilities and present values of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.
Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill and is subject to ongoing impairment evaluation. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
The purchase price allocation recorded in a business combination may change during the measurement period, which is a period not to exceed one year from the date of acquisition, as additional information about conditions existing at the acquisition date becomes available.
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See Note 9—Acquisitions of the Notes to Consolidated Financial Statements in this Annual Report for additional details regarding our business combinations, including further discussion of the estimated fair value of assets acquired and liabilities assumed in the Merger and the Arrangement as well as any significant changes in these estimates from the date of acquisition.
Impairment of proved oil and gas properties
We review proved oil and gas properties for impairment whenever events and circumstances indicate that their carrying value may not be recoverable. We estimate the expected undiscounted future cash flows by field and compare such undiscounted amounts to the carrying amount to determine if the asset is recoverable. If the carrying amount is not recoverable, we will recognize an impairment by adjusting the carrying amount of the oil and gas properties to fair value. We estimate the fair value of proved oil and gas properties using an income approach that converts future cash flows to a single discounted amount.
The factors used to determine the undiscounted future cash flows and fair value require significant judgment and assumptions, including future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials) and estimates of future operating and development costs. These factors are generally consistent with those used in the planning and budgeting processes. Future production is based upon a combination of inputs and assumptions, including the timing and pace of our development plans, as well as estimates of reserve quantities. When discounting future cash flows to estimate fair value, cash flows realized later in the projection period are less valuable compared to those realized earlier in the projection period due to the time value of money. Future commodity prices are estimated by using a combination of quoted forward market prices adjusted for geographical location and quality differentials based upon assumptions that are developed by reviewing historical realized prices, market supply and demand factors and other relevant factors. Future operating and development costs are generally estimated using inputs including authorizations for expenditures, review of historical data and forecasts developed during the budgeting and planning processes. In addition, estimates of future operating and development costs may be impacted by market supply and demand factors, including inflation expectations and the availability of materials, labor and services. To calculate fair value, future cash flows are discounted using a discount rate that is based on rates utilized by market participants and is commensurate with the risk and current market conditions associated with realizing the expected cash flows projected.
A substantial or extended decline in commodity prices could result in future impairment charges which would negatively impact our future operating results. However, because of the uncertainty inherent in the factors described above, we cannot predict when or if future impairment charges for proved oil and gas properties will be recorded.
Impairment of unproved oil and gas properties
The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage.
We recognize impairment expense for unproved properties at the time when the lease term has expired or sooner based on management’s periodic assessments. We consider the following factors in our assessment of the impairment of unproved properties:
•the remaining amount of unexpired term under our leases;
•our ability to actively manage and prioritize our capital expenditures to drill leases;
•our ability to make rental or extension payments to extend existing leases that may be closer to expiration;
•our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
•our ability to convey partial leasehold ownership in certain leases to other companies in exchange for their drilling of those leases;
•our ability to sell lease positions to other companies; and
•our evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations by us or by other operators in areas adjacent to or near our unproved properties.
Impairment of goodwill
Goodwill represents the excess of consideration paid over the fair value of identified tangible and intangible assets. Goodwill and intangible assets with indefinite lives are not amortized, but are evaluated for impairment annually as of October 1 or whenever events or changes in circumstances indicate that the fair value of the reporting unit may have been reduced below its carrying value.
For the purpose of the goodwill impairment test, we first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers
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of fair value of the reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. This evaluation includes, but is not limited to, assessment of macroeconomic trends, capital accessibility, operating income trends and industry conditions, as well as our share performance. If an initial qualitative assessment identifies that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative evaluation is performed. The quantitative goodwill impairment assessment involves determining the fair value of the reporting unit and comparing it to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, including goodwill, then an impairment charge would be recorded to write down goodwill to its implied fair value. A reporting unit, for the purpose of the impairment test, is at or below the operating segment level, and constitutes a business for which discrete financial information is available and regularly reviewed by segment management. Our single reportable business segment, which is the exploration and production of crude oil, NGL and natural gas, was the reporting unit that carried our goodwill balance as of December 31, 2024. The fair value of the reporting unit was determined using an income approach analysis based on the Company’s net discounted future cash flows. Significant inputs used are subject to management’s judgment and expertise and include, but are not limited to, future oil and gas production from our reserve report, commodity prices based on future pricing assumptions (adjusted for basis differentials), operating and development costs and a discount rate based on our weighted average cost of capital.
Income taxes
Our provision for taxes includes both federal and state income taxes. We record our income taxes in accordance with ASC 740, Income Taxes, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.
We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.
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Item 7A. 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.
Commodity price exposure risk. We are exposed to market risk as the prices of crude oil, NGL and natural gas fluctuate as a result of a variety of factors, including changes in supply and demand and the macroeconomic environment, all of which are typically beyond our control. The markets for crude oil, NGL and natural gas have been volatile, 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, NGL and natural gas. We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on our 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.
The fair value of our unrealized crude oil derivative positions at December 31, 2025 was a net asset of $62.7 million. A 10% increase in crude oil prices would decrease the fair value of this unrealized derivative asset position by approximately $39.1 million, while a 10% decrease in crude oil prices would increase the fair value of this unrealized derivative asset position by approximately $36.8 million. The fair value of our unrealized natural gas derivative positions at December 31, 2025 was a net asset of $13.5 million. A 10% increase in natural gas prices would decrease the fair value of this unrealized derivative asset position by approximately $15.3 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative asset position by approximately $20.2 million. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Market Conditions and Commodity Prices,” for further discussion on the commodity price environment.
See “Item 8. Financial Statements and Supplementary Data—Note 7— Derivative Instruments” and “Note 6—Fair Value Measurements” for additional information regarding our commodity derivative contracts.
Interest rate risk. At December 31, 2025, we had $750.0 million of senior unsecured notes at a fixed interest rate of 6.750% per annum and $750.0 million of senior unsecured notes at a fixed cash interest rate of 6.000% per annum.
At December 31, 2025, we had no borrowings outstanding and $32.8 million of outstanding letters of credit issued under the Credit Facility; therefore, a 100-basis point increase in interest rates would have no impact on our annual interest expense. 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 amended and restated credit agreement). See “Item 8. Financial Statements and Supplementary Data—Note 12—Long-Term Debt” for additional information on the interest incurred on the Credit Facility.
We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the year ended December 31, 2025, our credit losses on joint interest receivables were immaterial. We are also subject to credit risk due to 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.
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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.
Inflation risks. Although inflation rates in the United States have moderated, they have remained persistent in recent years. Costs of certain materials and services have remained elevated, and inflationary pressures could continue or increase in the future. We seek to mitigate these inflationary impacts by reviewing our pricing agreements on a regular basis and entering into agreements with our service providers to manage costs and availability of certain services that are utilized in our operations. It is difficult to predict whether such inflationary pressures will have a materially negative impact to our overall financial and operating results in the future; however, such inflationary pressures are not expected to materially impact our overall liquidity position, cash requirements or financial position, or the ability to conduct our day-to-day drilling, completion and production activities. See “Part I, Item 1A.—Risk Factors—Our profitability may be negatively impacted by inflationary pressures in the cost of labor, materials and services and general economic, business or industry conditions” for additional information.
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Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Reports of Independent Registered Public Accounting Firm (PCAOB ID | 71 | ||||
Consolidated Balance Sheets at December 31, 2025 and 2024 | 73 | ||||
Consolidated Statements of Operations for the Years Ended December 31, 2025, 2024 and 2023 | 75 | ||||
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2025, 2024 and 2023 | 76 | ||||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023 | 77 | ||||
Notes to Consolidated Financial Statements | |||||
1. Organization and Operations of the Company | 79 | ||||
2. Summary of Significant Accounting Policies | 79 | ||||
3. Revenue Recognition | 88 | ||||
4. Inventory | 89 | ||||
5. Additional Balance Sheet Information | 89 | ||||
6. Fair Value Measurements | 90 | ||||
7. Derivative Instruments | 92 | ||||
8. Property, Plant and Equipment | 94 | ||||
9. Acquisitions | 95 | ||||
10. Divestitures | 99 | ||||
11. Investment in Equity Securities | 99 | ||||
12. Long-Term Debt | 99 | ||||
13. Asset Retirement Obligations | 102 | ||||
14. Income Taxes | 103 | ||||
15. Equity-Based Compensation | 106 | ||||
16. Stockholders' Equity | 108 | ||||
17. Earnings Per Share | 110 | ||||
18. Leases | 111 | ||||
19. Significant Concentrations | 113 | ||||
20. Commitments and Contingencies | 113 | ||||
21. Subsequent Events | 115 | ||||
22. Supplemental Oil and Gas Disclosures — Unaudited | 115 | ||||
23. Supplemental Oil and Gas Reserve Information — Unaudited | 116 | ||||
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Chord Energy Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Chord Energy Corporation and its subsidiaries (the "Company") as of December 31, 2025 and 2024, and the related consolidated statements of operations, of changes in stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s report on internal control over financial reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Developed Oil and Natural Gas Reserves on Proved Oil and Gas Properties, Net
As described in Notes 2 and 8 to the consolidated financial statements, the Company’s consolidated proved oil and gas properties, net balance was $10.6 billion as of December 31, 2025. Depreciation, depletion, and amortization (DD&A) expense for the year ended December 31, 2025 was $1.5 billion. Crude oil, natural gas liquids (NGL) and natural gas exploration and development activities are accounted for using the successful efforts method. All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGL and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. As disclosed by management, periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, changes to the Company’s anticipated five-year development plan, changes to commodity prices, cost changes, technological advances, new geological or geophysical data or other economic factors. The Company’s internal staff of petroleum engineers work with the independent reserve engineers (“management’s specialists”) related to the estimates of crude oil, NGL and natural gas reserves.
The principal considerations for our determination that performing procedures relating to the impact of proved developed oil and natural gas reserves on proved oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved developed oil and natural gas reserves, which are derived using historical production volumes, and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, specifically historical production volumes, methods, and assumptions used by management and its specialists in developing the estimates of proved developed oil and natural gas reserves.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved developed oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved developed oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the methods and assumptions used by the specialists, (ii) testing the completeness and accuracy of the underlying data used by management’s specialists related to historical production volumes; and (iii) evaluating the specialists’ findings related to future production volumes by comparing future production volumes to relevant historical and current period production volumes, as applicable.
/s/ PricewaterhouseCoopers LLP
February 26, 2026
We have served as the Company’s auditor since 2007.
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Chord Energy Corporation
Consolidated Balance Sheets
| December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands, except share data) | |||||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | $ | |||||||||
| Accounts receivable, net | |||||||||||
| Inventory | |||||||||||
| Prepaid expenses | |||||||||||
| Derivative instruments | |||||||||||
| Other current assets | |||||||||||
| Total current assets | |||||||||||
| Property, plant and equipment | |||||||||||
| Oil and gas properties (successful efforts method) | |||||||||||
| Other property and equipment | |||||||||||
| Less: accumulated depreciation, depletion and amortization | ( | ( | |||||||||
| Total property, plant and equipment, net | |||||||||||
| Derivative instruments | |||||||||||
| Investment in equity securities | |||||||||||
| Long-term inventory | |||||||||||
| Operating right-of-use assets | |||||||||||
| Goodwill | |||||||||||
| Other assets | |||||||||||
| Total assets | $ | $ | |||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Accounts payable | $ | $ | |||||||||
| Revenues and production taxes payable | |||||||||||
| Accrued liabilities | |||||||||||
| Accrued interest payable | |||||||||||
| Derivative instruments | |||||||||||
| Current operating lease liabilities | |||||||||||
| Other current liabilities | |||||||||||
| Total current liabilities | |||||||||||
| Long-term debt | |||||||||||
| Deferred tax liabilities | |||||||||||
| Asset retirement obligations | |||||||||||
| Derivative instruments | |||||||||||
| Operating lease liabilities | |||||||||||
| Other liabilities | |||||||||||
| Total liabilities | |||||||||||
Commitments and contingencies (Note 20) | |||||||||||
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| December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands, except share data) | |||||||||||
| Stockholders’ equity | |||||||||||
Common stock, $ | |||||||||||
Treasury stock, at cost: | ( | ( | |||||||||
| Additional paid-in capital | |||||||||||
| Retained earnings | |||||||||||
| Total stockholders’ equity | |||||||||||
| Total liabilities and stockholders’ equity | $ | $ | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Chord Energy Corporation
Consolidated Statements of Operations
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands, except share data) | |||||||||||||||||
| Revenues | |||||||||||||||||
| Oil, NGL and gas revenues | $ | $ | $ | ||||||||||||||
| Purchased oil and gas sales | |||||||||||||||||
| Total revenues | |||||||||||||||||
| Operating expenses | |||||||||||||||||
| Lease operating expenses | |||||||||||||||||
| Gathering, processing and transportation expenses | |||||||||||||||||
| Purchased oil and gas expenses | |||||||||||||||||
| Production taxes | |||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||
| General and administrative expenses | |||||||||||||||||
| Impairment and exploration | |||||||||||||||||
| Total operating expenses | |||||||||||||||||
| Gain (loss) on sale of assets, net | ( | ||||||||||||||||
| Operating income | |||||||||||||||||
| Other income (expense) | |||||||||||||||||
| Net gain on derivative instruments | |||||||||||||||||
| Net gain (loss) from investment in equity securities | ( | ||||||||||||||||
| Interest expense, net of capitalized interest | ( | ( | ( | ||||||||||||||
| Loss on debt extinguishment | ( | ||||||||||||||||
| Other income, net | |||||||||||||||||
| Total other income, net | |||||||||||||||||
| Income before income taxes | |||||||||||||||||
| Income tax expense | ( | ( | ( | ||||||||||||||
| Net income | $ | $ | $ | ||||||||||||||
Earnings per share (Note 17): | |||||||||||||||||
Basic | $ | $ | $ | ||||||||||||||
Diluted | $ | $ | $ | ||||||||||||||
| Weighted average shares outstanding: | |||||||||||||||||
Basic | |||||||||||||||||
Diluted | |||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Chord Energy Corporation
Consolidated Statements of Changes in Stockholders’ Equity
The accompanying notes are an integral part of these consolidated financial statements.
| Common Stock | Treasury Stock | Additional Paid-in-Capital | Retained Earnings | Total Stockholders’ Equity | |||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2022 | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||||||||||
| Equity-based compensation and vestings | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Tax withholding on settlement of equity-based awards | ( | ( | — | — | ( | — | ( | ||||||||||||||||||||||||||||||||||
| Dividends | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||
| Share repurchases | ( | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||
| Warrants exercised | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2023 | ( | ||||||||||||||||||||||||||||||||||||||||
| Shares issued in Arrangement | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Equity-based compensation and vestings | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Tax withholdings on settlement of equity-based awards | ( | ( | — | — | ( | — | ( | ||||||||||||||||||||||||||||||||||
| Dividends | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||
| Share repurchases | ( | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||
| Warrants exercised | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2024 | ( | ||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation and vestings | — | — | — | ||||||||||||||||||||||||||||||||||||||
| Tax withholdings on settlement of equity-based awards | ( | ( | — | — | ( | — | ( | ||||||||||||||||||||||||||||||||||
| Dividends | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||
| Share repurchases | ( | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||
| Warrants exercised | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2025 | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Chord Energy Corporation
Consolidated Statements of Cash Flows
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||
| Net income | $ | $ | $ | ||||||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||
| Loss on debt extinguishment | |||||||||||||||||
| (Gain) loss on sale of assets | ( | ( | |||||||||||||||
| Impairment | |||||||||||||||||
| Deferred income taxes | |||||||||||||||||
| Net (gain) loss from investment in equity securities | ( | ( | |||||||||||||||
| Net gain on derivative instruments | ( | ( | ( | ||||||||||||||
| Equity-based compensation expenses | |||||||||||||||||
| Deferred financing costs amortization and other | ( | ||||||||||||||||
| Working capital and other changes: | |||||||||||||||||
| Change in accounts receivable, net | ( | ( | |||||||||||||||
| Change in inventory | ( | ( | ( | ||||||||||||||
| Change in prepaid expenses | ( | ( | |||||||||||||||
| Change in accounts payable, interest payable and accrued liabilities | ( | ||||||||||||||||
| Change in other assets and liabilities, net | ( | ( | ( | ||||||||||||||
| Net cash provided by operating activities | |||||||||||||||||
| Cash flows from investing activities: | |||||||||||||||||
| Capital expenditures | ( | ( | ( | ||||||||||||||
| Acquisitions, net of cash acquired | ( | ( | ( | ||||||||||||||
| Proceeds from divestitures, net of cash divested | |||||||||||||||||
| Derivative settlements | ( | ( | |||||||||||||||
| Proceeds from sale of investment in equity securities | |||||||||||||||||
| Contingent consideration received | |||||||||||||||||
| Distributions from investment in equity securities | |||||||||||||||||
| Net cash used in investing activities | ( | ( | ( | ||||||||||||||
| Cash flows from financing activities: | |||||||||||||||||
| Proceeds from revolving credit facility | |||||||||||||||||
| Principal payments on revolving credit facility | ( | ( | ( | ||||||||||||||
| Repurchase of senior unsecured notes | ( | ( | |||||||||||||||
| Issuance of senior notes | |||||||||||||||||
| Deferred financing costs | ( | ( | |||||||||||||||
| Repurchases of common stock | ( | ( | ( | ||||||||||||||
| Tax withholding on vesting of equity-based awards | ( | ( | ( | ||||||||||||||
| Dividends paid | ( | ( | ( | ||||||||||||||
| Payments on finance lease liabilities | ( | ( | ( | ||||||||||||||
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| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Proceeds from warrants exercised | |||||||||||||||||
| Net cash used in financing activities | ( | ( | ( | ||||||||||||||
| Increase (decrease) in cash and cash equivalents | ( | ( | |||||||||||||||
| Cash and cash equivalents: | |||||||||||||||||
| Beginning of period | |||||||||||||||||
| End of period | $ | $ | $ | ||||||||||||||
| Supplemental cash flow information: | |||||||||||||||||
| Cash paid for interest, net of capitalized interest | $ | $ | $ | ||||||||||||||
| Supplemental non-cash transactions: | |||||||||||||||||
| Change in accrued capital expenditures | $ | $ | $ | ||||||||||||||
| Change in asset retirement obligations | |||||||||||||||||
| Non-cash consideration exchanged in business combinations | |||||||||||||||||
| Dividends payable | |||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Chord Energy Corporation
Notes to Consolidated Financial Statements
1. Organization and Operations of the Company
Chord Energy Corporation, a Delaware corporation (together with its consolidated subsidiaries, the “Company” or “Chord”), is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, NGL and natural gas primarily in the Williston Basin with limited non-operated interests in the Marcellus Shale.
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.
In connection with the Arrangement, the Board of Directors of Chord unanimously (i) determined the issuance of the shares of common stock, par value $0.01 per share, of Chord (the “Chord Stock Issuance”), and the amendment of Chord’s restated certificate of incorporation to increase the number of authorized shares of common stock from 120,000,000 to 240,000,000 shares of common stock (the “Chord Charter Amendment”) are fair to, and in the best interests of, Chord and the holders of common stock, (ii) approved and declared advisable the Chord Stock Issuance and Chord Charter Amendment and (iii) recommended that the holders of common stock approve the Chord Stock Issuance and Chord Charter Amendment.
Under the terms of the Arrangement Agreement, Enerplus shareholders received 0.10125 shares of Chord common stock (the “Share Consideration”) and $1.84 per share in cash (the “Cash Consideration” and together with the Share Consideration, the “Arrangement Consideration”) in exchange for each share of Enerplus they owned at closing.
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. See Note 9—Acquisitions for additional information.
2. Summary of Significant Accounting Policies
Basis of Presentation
Certain prior period amounts have been reclassified to conform to current period presentation. The reclassification had no effect on the reported results of operations.
Segment Information
The Company has evaluated how it is organized and managed and has identified only one
The operating results of the Company’s single reportable segment are evaluated by the Company’s President & Chief Executive Officer, who has been determined to be the Company’s Chief Operating Decision Maker (“CODM”), to make key operating decisions, such as the allocation of resources and the evaluation of operating segment performance.
The primary measure of profit and loss evaluated by the Company’s CODM for its single reportable segment is consolidated net income. Consolidated net income, total assets, and all significant segment expense items are presented in the Company’s consolidated financial statements and notes to the consolidated financial statements.
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Use of Estimates
Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to (i) proved crude oil, NGL and natural gas reserves and related cash flow estimates, (ii) assignment of fair value and allocation of purchase price in connection with business combinations, including the determination of any resulting goodwill or bargain purchase, (iii) impairment tests of long-lived assets, (iv) estimates of future development, dismantlement and abandonment costs, (v) estimates relating to certain crude oil, NGL and natural gas revenues and expenses, (vi) income taxes, (vii) valuation of derivative instruments and (viii) estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.
Estimates of crude oil, NGL and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGL and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future DD&A expense, dismantlement and abandonment costs and impairment expense.
Risks and Uncertainties
As a producer of crude oil, NGL and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGL and natural gas, which are dependent upon numerous factors beyond its control such as economic, geopolitical, political and regulatory developments and competition from other energy sources. During 2025, the energy markets were marked by heightened volatility that led to frequent and unpredictable changes in crude oil prices. Throughout the year, prices fluctuated considerably, with periods of both decline and recovery. The average NYMEX WTI declined 14% during the year ended December 31, 2025, compared to the prior year, and overall conditions remain unstable. Market conditions during the year were adversely influenced by elevated production levels from 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, NGL 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.
Cash and Cash Equivalents
The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such highly liquid investments with original maturity dates less than 90 days as cash equivalents. While the Company may maintain balances of cash and cash equivalents in excess of amounts that are federally insured by the Federal Deposit Insurance Corporation, the Company invests with financial institutions that it believes are creditworthy and has not experienced any material losses in such accounts.
Accounts Receivable
Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities. The Company’s accounts receivable consist mainly of receivables from crude oil, NGL and natural gas purchasers and joint interest owners on properties the Company operates.
The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability and if an allowance for credit losses is warranted. The Company estimates credit losses and accrues a reserve on a receivable based on (i) historic loss experience for pools of receivable balances with similar characteristics, (ii) the length of time balances have been outstanding and (iii) the economic status of each counterparty. These loss estimates are then adjusted for current and expected future economic conditions, which may include an assessment of the probability of non-payment, financial distress or expected future commodity prices and the impact that any current or future conditions could have on a counterparty’s credit quality and liquidity. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s crude oil, NGL and natural gas receivables are collected within two months.
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Inventory
The Company’s inventory includes equipment and materials and crude oil inventory. Equipment and materials consist primarily of well equipment, tanks and tubular goods to be used in the Company’s exploration and production activities. Crude oil inventory includes crude oil in tanks and linefill. Linefill represents the minimum volume of product in a pipeline system that enables the system to operate and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil and NGL linefill in third-party pipelines that is not expected to be withdrawn within one year is included in long-term inventory on the Company’s Consolidated Balance Sheets (see Note 4—Inventory).
Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value.
Property, Plant and Equipment
Proved Oil and Gas Properties
Crude oil, NGL and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and gas properties are capitalized at their estimated net present value.
The provision for depletion of oil and gas properties is calculated using the unit-of-production method. All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude oil.
Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized.
The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows 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 and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, the Company’s estimated undiscounted future cash flows, the timing and pace of development and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges for proved oil and gas properties will be recorded.
Unproved Oil and Gas Properties
Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
The Company assesses its unproved properties periodically for impairment on a prospect-by-prospect basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties:
•the remaining amount of unexpired term under its leases;
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•its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;
•its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
•its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and
•its evaluation of the continuing successful results from the development of properties by the Company or by other operators in areas adjacent to or near the Company’s unproved properties.
For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Capitalized Interest
The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. The Company capitalized interest costs of $4.4 million, $4.9 million and $4.1 million for the years ended December 31, 2025, 2024 and 2023, respectively. Capitalized interest costs are amortized over the life of the related assets.
Other Property and Equipment
Other property and equipment consists primarily of field office buildings, oilfield equipment, furniture, software, and leasehold improvements, and is recorded at cost and depreciated using the straight-line method based on expected lives of the individual assets (ranging from two years to 30 years) and net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations.
Exploration Expenses
Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred.
Costs from drilling exploratory wells are initially capitalized but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought.
The Company had no capitalized exploratory well costs as of December 31, 2025, 2024, or 2023.
Goodwill
Goodwill represents the excess of consideration paid over the fair value of identified tangible and intangible assets. Goodwill and intangible assets with indefinite lives are not amortized, but are evaluated for impairment annually as of October 1 or more frequently if events or changes in circumstances indicate that the carrying amount might be impaired.
For the purpose of the goodwill impairment test, the Company first assesses qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, the Company determines the drivers of fair value of the reporting unit and evaluates whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. This evaluation includes, but is not limited to, assessment of macroeconomic trends, capital accessibility, operating income trends and industry conditions, as well as the Company’s share performance. If an initial qualitative assessment identifies that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative evaluation is performed. The quantitative goodwill impairment assessment involves determining the fair value of the reporting unit and comparing it to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, including goodwill, then an impairment charge would be recorded to write down goodwill to its implied fair value. A reporting unit, for the purpose of the impairment test, is at or below the operating segment level, and constitutes a business for which discrete financial information is available and regularly reviewed by segment management. The Company’s single reportable business segment, which is the E&P of crude oil, NGL and natural gas, is the reporting unit that carried the Company’s goodwill balance as of December 31, 2024. The fair value of the reporting unit is estimated using an income approach. Significant inputs used are subject to the
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judgment and expertise of the Company’s management and include, but are not limited to, future production volumes based upon estimates of reserves prepared by the Company’s reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital discount rate.
Business Combinations
The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed measured at the estimated acquisition date fair value. Transaction and integration costs associated with business combinations are expensed as incurred.
The Company makes various assumptions in estimating the fair value of the assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair value of proved and unproved oil and gas properties. The fair value of the oil and gas properties was calculated by a third party valuation expert using an income approach based on the net discounted future cash flows that utilized inputs requiring significant judgment and assumptions, including future production volumes based upon estimates of reserves prepared by the Company’s reserve engineers, future commodity prices (adjusted for basis differentials), future operating and development costs and a market-based weighted average cost of capital discount rate. In addition, when appropriate, the Company reviews comparable transactions between market participants for the purchase and sale of oil and gas properties within the same region to measure fair value, which illustrates the amount a willing buyer and seller would enter into in exchange for such properties.
The Company records goodwill for any amount of the consideration transferred in excess of the estimated fair value of the net assets acquired and a bargain purchase gain for any amount of the estimated fair value of net assets acquired in excess of the consideration transferred. Deferred taxes are recorded for any difference between the acquisition date fair value and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. The Company may adjust the provisional amounts recorded in a business combination during the measurement period which extends for up to one year after the acquisition date.
Investment in Equity Securities
Deferred Financing Costs
The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. Deferred financing costs related to the Credit Facility (defined in Note 12—Long-Term Debt) are included in other assets on the Company’s Consolidated Balance Sheets, while deferred financing costs related to the Company’s senior unsecured notes are included as a reduction of long-term debt on the Company’s Consolidated Balance Sheets. See Note 12—Long-Term Debt for additional information.
Asset Retirement Obligations
In accordance with the FASB’s authoritative guidance on ARO, the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties and
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produced water disposal wells, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable laws and regulations. The liability is accreted to its present value each period, and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of DD&A in the Company’s Consolidated Statements of Operations.
The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. 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, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 6—Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Revenue Recognition
The Company recognizes revenue in accordance with FASB ASC 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Disclosures in accordance with ASC 606 have been provided in Note 3—Revenue Recognition.
The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or a bundle of goods or services) at a point in time or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.
The Company’s revenues are predominantly derived from contracts for the sale of crude oil, NGL and natural gas. Generally, for the crude oil, NGL and natural gas contracts: (i) each unit of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue at a point in time, which is typically when production is delivered and title or risk of loss transfers to the customer. The sales prices for crude oil, NGL and natural gas are market-based and are adjusted for transportation and other related fees and deductions. Fees included in the contract that are incurred after the transfer of control to the customer are included as a reduction of the transaction price, while fees that are incurred prior to the transfer of control to the customer are classified as gathering, processing and transportation expenses in the Company’s Consolidated Statements of Operations. The sales of crude oil, NGL and natural gas as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling crude oil, NGL and natural gas on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis.
Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and the Company’s NGL production is generally sold to purchasers under long-term (more than 12-month) contracts at market-based prices. The Company sells the majority of its production soon after it is produced at various locations, and, as a result, the Company maintains a minimum amount of product inventory in storage. For sales of commodities, the Company records revenue in the month that 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 volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Differences between estimated and actual revenues have historically not been significant. Revenue recognized related to performance obligations satisfied in prior reporting periods was not material for the periods presented.
The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are recorded on a gross basis when the Company acts as a
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principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with FASB ASC 845, Nonmonetary Transactions.
Leases
The Company accounts for leases in accordance with FASB ASC 842, Leases (“ASC 842”). In accordance with ASC 842, the Company determines whether an arrangement is a lease at its inception. The Company’s long-term operating and finance leases consist primarily of office space, vehicles and other property and equipment used in its operations. The operating lease right-of-use (“ROU”) asset also includes any lease incentives received in the recognition of the present value of future lease payments. The Company considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Company is reasonably certain to exercise the renewal or termination. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Company determines the incremental borrowing rate based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases.
The Company’s share of operating, variable and short-term lease costs are either capitalized and included in property, plant and equipment on the Company’s Consolidated Balance Sheets or are recognized in the Company’s Consolidated Statements of Operations in lease operating expenses and general and administrative expenses, as applicable. The finance lease costs for the amortization of ROU assets are included in depreciation, depletion and amortization and the interest on lease liabilities is included in interest expense, net of capitalized interest, on the Company’s Consolidated Statements of Operations.
Fair Value Measurements
As defined in FASB ASC 820, Fair Value Measurement (“ASC 820”), fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.
ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:
Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 — Pricing inputs are generally unobservable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.
Concentrations of Market and Credit Risk
The future results of the Company’s operations will be affected by the market prices of crude oil, NGL and natural gas. The availability of a ready market for crude oil, NGL and natural gas products in the future will depend on numerous factors beyond the Company’s control, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and
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natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, NGL and natural gas, the regulatory environment, the economic environment and other regional and political events, none of which can be predicted with certainty. Commodity prices have been volatile in recent years and could be volatile in the future. A substantial or extended decline in the price of crude oil could have a material adverse effect on the Company’s financial position, cash flows and results of operations.
The Company’s receivables include amounts due from purchasers of its crude oil, NGL and natural gas production and amounts due from joint interest owners for their respective portions of operating expenses and development costs. While certain of these customers and joint interest owners are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long term.
The Company manages market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments, which potentially subject the Company to credit risk, consist principally of cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally-insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.
Risk Management
The Company utilizes derivative financial instruments to manage risks related to changes in crude oil, NGL and natural gas prices. The Company uses fixed-price swaps and two-way and three-way collars to reduce the volatility of crude oil, NGL and natural gas prices on future expected production. See Note 7—Derivative Instruments for additional information.
The Company records all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all existing counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statements of Operations and as operating activities in the Company’s Consolidated Statement of Cash Flows. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows.
Derivative financial instruments that hedge the price of crude oil, NGL and natural gas are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. At December 31, 2025, the Company had derivatives in place with 15 counterparties, all of which are secured parties under the Credit Facility (defined in Note 12—Long-Term Debt), which eliminates the need to post or receive collateral associated with its derivative positions. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from the counterparties to its commodity derivative contracts. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.
Contingencies
Certain conditions may exist as of the date the Company’s consolidated financial statements are issued that may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company’s management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against the Company or unasserted claims that may result in proceedings, the Company’s management, with input from legal counsel, evaluates the perceived
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merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be estimated, then the estimated undiscounted liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments.
Environmental Costs
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable, and the costs can be reasonably estimated.
Equity-Based Compensation
The Company has the Chord Energy Corporation Long Term Incentive Plan (the “2020 LTIP”), which provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents, other stock-based awards, cash awards, performance awards or any combination of the foregoing. In connection with the merger of equals with Whiting Petroleum Corporation (“Whiting”) on July 1, 2022 (the “Merger”), the Company assumed the Whiting Petroleum Corporation 2020 Equity Incentive Plan (the “Whiting Equity Incentive Plan”), which provides for the grant of incentive stock options, nonstatutory stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and annual incentive awards or any combination of the foregoing.
The Company determines the compensation expense for share-settled awards based on the grant date fair value, and such expense is recognized ratably over the requisite service period, which is generally the vesting period. The Company recognizes compensation expense using the straight-line attribution method for service-based awards with a graded vesting feature. Compensation expense for cash-settled awards is recognized over the requisite service period and is remeasured at the fair value of such awards at the end of each reporting period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. Equity awards that settle in shares of common stock are generally net settled by withholding shares of common stock to satisfy income tax withholding obligations due upon vesting.
The fair values of awards are determined based on the type of award and may utilize market prices on the date of grant (for service-based equity awards) or at the end of the reporting period (for liability-classified awards), Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of award. A Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. See Note 15—Equity-Based Compensation for additional information.
Any excess tax benefit arising from the Company’s equity-based compensation plans is recognized as a credit to income tax expense or benefit in the Company’s Consolidated Statements of Operations.
Treasury Stock
Treasury stock purchases are recorded at cost and represent shares of common stock repurchased under the Company’s share repurchase program.
Income Taxes
The Company’s provision for taxes includes U.S. federal and state income taxes as well as Canadian federal and provincial income taxes. The Company records its income taxes in accordance with FASB ASC 740, Income Taxes, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is
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uncertain. The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows.
The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. All deferred tax assets and liabilities, along with any related valuation allowance, are classified as non-current on the Company’s Consolidated Balance Sheets.
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 adopted this ASU effective for its annual disclosures beginning after January 1, 2025, and applied the amendments prospectively effective January 2025. See Note 14—Income Taxes for additional information.
In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”). This standard requires that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating this ASU to determine its impact on the Company’s annual financial statement disclosures.
In July 2025, the FASB issued ASU 2025-05, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets (“ASU 2025-05”). This standard amends the guidance for measuring expected credit losses on accounts receivable and contract assets. The amendments are intended to clarify the application of the current expected credit loss model to short-term receivables and contract assets, and to provide additional guidance on the use of historical loss information and forecasts in estimating expected credit losses. ASU 2025-05 is effective for annual and interim reporting periods beginning after December 15, 2025, with early adoption permitted. The Company is currently evaluating this ASU to determine its impact on the Company’s consolidated financial statements.
In December 2025, the FASB issued ASU 2025-10, Government Grants (Topic 832): Accounting for Government Grants Received by Business Entities (“ASU 2025-10”). This standard establishes guidance for how a business entity accounts for government grants, distinguishing between grants related to assets and grants related to income. The standard also requires enhanced disclosures regarding the nature, terms, and amounts of government grants recognized in the financial statements. ASU 2025-10 is effective for annual and interim reporting periods beginning after December 15, 2026, with early adoption permitted. The Company is currently evaluating this ASU to determine its impact on the Company’s consolidated financial statements.
3. Revenue Recognition
Revenues associated with contracts with customers were as follows for the periods presented:
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Crude oil revenues | $ | $ | $ | ||||||||||||||
| Purchased crude oil sales | |||||||||||||||||
| NGL and natural gas revenues | |||||||||||||||||
| Purchased NGL and natural gas sales | |||||||||||||||||
| Total revenues | $ | $ | $ | ||||||||||||||
The Company has elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a
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distinct service that forms part of a series of distinct services and (ii) contracts with an original expected duration of one year or less.
4. Inventory
The following table sets forth the Company’s inventory balances for the periods presented:
| December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Inventory | |||||||||||
| Equipment and materials | $ | $ | |||||||||
| Crude oil inventory | |||||||||||
| Total inventory | $ | $ | |||||||||
| Long-term inventory | |||||||||||
| Linefill in third-party pipelines | $ | $ | |||||||||
| Total long-term inventory | $ | $ | |||||||||
| Total | $ | $ | |||||||||
5. Additional Balance Sheet Information
The following table sets forth certain balance sheet amounts comprised of the following:
| December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Accounts receivable, net | |||||||||||
| Trade and other accounts | $ | $ | |||||||||
| Joint interest accounts | |||||||||||
| Total accounts receivable | |||||||||||
| Less: allowance for credit losses | ( | ( | |||||||||
| Total accounts receivable, net | $ | $ | |||||||||
| Revenues and production taxes payable | |||||||||||
| Royalties payable and revenue suspense | $ | $ | |||||||||
| Production taxes payable | |||||||||||
| Total revenues and production taxes payable | $ | $ | |||||||||
| Accrued liabilities | |||||||||||
| Accrued oil and gas marketing | $ | $ | |||||||||
| Accrued capital costs | |||||||||||
| Accrued lease operating expenses | |||||||||||
| Accrued general and administrative expenses | |||||||||||
| Current portion of asset retirement obligations | |||||||||||
| Accrued dividends | |||||||||||
| Other accrued liabilities | |||||||||||
| Total accrued liabilities | $ | $ | |||||||||
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6. Fair Value Measurements
In accordance with the FASB’s authoritative guidance on fair value measurements, certain of the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 13—Asset Retirement Obligations) and properties acquired in a business combination (see Note 9—Acquisitions) or upon impairment (see Note 8—Property, Plant and Equipment), at fair value on a non-recurring basis.
Financial Assets and Liabilities
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 December 31, 2025 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
Commodity derivative contracts (see Note 7) | $ | $ | $ | $ | |||||||||||||||||||
Investment in equity securities (see Note 11) | |||||||||||||||||||||||
| Total assets | $ | $ | $ | $ | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||
Commodity derivative contracts (see Note 7) | $ | $ | $ | $ | |||||||||||||||||||
| Total liabilities | $ | $ | $ | $ | |||||||||||||||||||
| Fair value at December 31, 2024 | |||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||
Commodity derivative contracts (see Note 7) | $ | $ | $ | $ | |||||||||||||||||||
Contingent consideration (see Note 7) | |||||||||||||||||||||||
Investment in equity securities (see Note 11) | |||||||||||||||||||||||
| Total assets | $ | $ | $ | $ | |||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||
Commodity derivative contracts (see Note 7) | $ | $ | $ | $ | |||||||||||||||||||
| Total liabilities | $ | $ | $ | $ | |||||||||||||||||||
Commodity derivative contracts. The Company enters into commodity derivative contracts to manage risks related to changes in crude oil and natural gas prices. The Company’s swaps and two-way and three-way 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 compares the valuation performed by the third-party preparer to counterparty valuation statements to assess the reasonableness of its valuation. The determination of the fair value also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the market credit spread of the Company or similarly rated public issuers. The credit risk adjustments to the fair value of the Company’s net derivative assets and liabilities were not material for the periods presented. See Note 7—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 was entitled to receive up to three earn-out payments of $25.0 60 per barrel for such year (the “Contingent Consideration”). The fair value of the Contingent Consideration was determined by a third-party preparer using a Monte Carlo simulation model and Ornstein-Uhlenbeck pricing process. The significant inputs included 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 were substantially observable in active markets or can be derived from observable data. In each of January 2024, 2025 and 2026, the Company received $25.0
Investment in equity securities. The Company owns common units in 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 December 31, 2025 and 2024, respectively. See Note 11—Investment in Equity Securities for additional information.
Non-Financial Assets and Liabilities
The fair value of the Company’s non-financial assets and liabilities measured on a non-recurring basis are determined using valuation techniques that include Level 3 inputs.
Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, environmental and regulatory environments.
Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials), estimates of future operating and development costs and a risk-adjusted discount rate.
Business Combinations. The Company records the fair value of the oil and gas properties acquired was calculated 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 future 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 these acquisitions 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 combinations:
•2025 Williston Basin Acquisition. On October 31, 2025, the Company completed the 2025 Williston Basin Acquisition (defined in Note 9—Acquisitions). The assets acquired and liabilities assumed were recorded at fair value as of October 31, 2025.
•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 annual impairment evaluation as described in Note 2—Summary of Significant Accounting Policies—Goodwill.
•2023 Williston Basin Acquisition. On June 30, 2023, the Company completed the 2023 Williston Basin Acquisition (defined in Note 9—Acquisitions). The assets acquired and liabilities assumed were recorded at fair value as of June 30, 2023.
See Note 9—Acquisitions for additional information.
Goodwill Impairment. The Company tested goodwill for impairment annually on October 1 or whenever events or changes in circumstances indicated 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 of 2025, which was impacted by a decline in crude oil and
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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 were based on management’s expectations for the future and unobservable inputs and assumptions, which included estimates of future oil and gas production from the Company’s reserve report, commodity prices based on future pricing assumptions (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 to reduce the carrying value of goodwill to zero as of June 30, 2025. The non-cash impairment charge is included within impairment and exploration expenses on the Consolidated Statements of Operations for the year ended December 31, 2025.
7. 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 December 31, 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 | 2026 | Three-way collars | Bbls | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2026 | Two-way collars | Bbls | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2026 | Fixed-price swaps | Bbls | $ | |||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2027 | Three-way collars | Bbls | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2027 | Two-way collars | Bbls | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2026 | Two-way collar | MMBtu | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2026 | Fixed price swaps | MMBtu | $ | |||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2027 | Two-way collar | MMBtu | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2027 | Fixed price swaps | MMBtu | $ | |||||||||||||||||||||||||||||||||||||||||||
Subsequent to December 31, 2025, the Company entered into the following commodity derivative contracts:
| Weighted Average Prices | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity | Settlement Period | Derivative Instrument | Volumes | Fixed-Price Swaps | Sub-Floor | Floor | Ceiling | |||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2026 | Three-way collars | Bbls | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2026 | Two-way collars | Bbls | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2027 | Three-way collars | Bbls | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2027 | Two-way collars | Bbls | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2028 | Three-way collars | Bbls | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2026 | Fixed-price swaps | MMBtu | $ | ||||||||||||||||||||||||||||||||||||||||||||||
| Natural gas | 2027 | Fixed-price swaps | MMBtu | $ | ||||||||||||||||||||||||||||||||||||||||||||||
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Transportation derivative contracts. The Company had contracts that provided for the transportation of crude oil through a buy/sell structure from North Dakota to either Cushing, Oklahoma or Guernsey, Wyoming. The contracts had required the purchase and sale of fixed volumes of crude oil through July 2024 as specified in the agreements. The Company determined that these contracts qualified as derivatives and did not elect the “normal purchase normal sale” exclusion. The Company recorded the changes in fair value of these contracts within GPT expenses on the Company’s Consolidated Statement of Operations. Settlements on these contracts are reflected as operating activities on the Company’s Consolidated Statements of Cash Flows and represent cash payments to the counterparties for transportation of crude oil or the net settlement of contract liabilities if the transportation was not utilized, as applicable. See Note 6—Fair Value Measurements for additional information.
Contingent consideration. The Company bifurcated the Contingent Consideration from the host contract and accounted for it separately at fair value. The Contingent Consideration was marked-to-market each reporting period, with changes in fair value recorded in the other income (expense) section of the Company’s Consolidated Statements of Operations as a net gain or loss on derivative instruments. As of December 31, 2025, the remaining contingency for the 2025 year was met, which resulted in a current receivable of $25.0 million recorded within accounts receivable, net on the Consolidated Balance Sheet. See Note 6—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 Consolidated Statements of Operations for the periods presented:
| Year Ended December 31, | ||||||||||||||||||||||||||
| Derivative Instrument | Statement of Operations Location | 2025 | 2024 | 2023 | ||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
| Commodity derivatives | Net gain on derivative instruments | $ | $ | $ | ||||||||||||||||||||||
| Commodity derivatives (buy/sell transportation contracts) | Gathering, processing and transportation expenses(1) | ( | ||||||||||||||||||||||||
| Contingent consideration | ||||||||||||||||||||||||||
__________________
(1) The change in the fair value of the transportation derivative contracts was recorded as a loss in GPT expenses for the year ended December 31, 2024 and as a gain in GPT expenses for the year ended December 31, 2023.
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 Consolidated Balance Sheets.
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The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheets:
| December 31, 2025 | ||||||||||||||||||||||||||
| Derivative Instrument | Balance Sheet Location | Gross Amount | Gross Amount Offset | Net Amount | ||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
| Derivatives assets: | ||||||||||||||||||||||||||
| Commodity derivatives | Derivative instruments — current assets | $ | $ | ( | $ | |||||||||||||||||||||
| Commodity derivatives | Derivative instruments — non-current assets | ( | ||||||||||||||||||||||||
| Total derivatives assets | $ | $ | ( | $ | ||||||||||||||||||||||
| Derivatives liabilities: | ||||||||||||||||||||||||||
| Commodity derivatives | Derivative instruments — current liabilities | $ | $ | ( | $ | |||||||||||||||||||||
| Commodity derivatives | Derivative instruments — non-current liabilities | ( | ||||||||||||||||||||||||
| Total derivatives liabilities | $ | $ | ( | $ | ||||||||||||||||||||||
| December 31, 2024 | ||||||||||||||||||||||||||
| Derivative Instrument | Balance Sheet Location | Gross Amount | Gross Offset Amount | Net Amount | ||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
| Derivatives assets: | ||||||||||||||||||||||||||
| Commodity derivatives | Derivative instruments — current assets | $ | $ | ( | $ | |||||||||||||||||||||
| Contingent consideration | Derivative instruments — current assets | |||||||||||||||||||||||||
| Commodity derivatives | Derivative instruments — non-current assets | ( | ||||||||||||||||||||||||
| Total derivatives assets | $ | $ | ( | $ | ||||||||||||||||||||||
| Derivatives liabilities: | ||||||||||||||||||||||||||
| Commodity derivatives | Derivative instruments — current liabilities | $ | $ | ( | $ | |||||||||||||||||||||
| Commodity derivatives | Derivative instruments — non-current liabilities | ( | ||||||||||||||||||||||||
| Total derivatives liabilities | $ | $ | ( | $ | ||||||||||||||||||||||
8. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment:
| December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Proved oil and gas properties | $ | $ | |||||||||
| Less: Accumulated depletion | ( | ( | |||||||||
| Proved oil and gas properties, net | |||||||||||
| Unproved oil and gas properties | |||||||||||
| Other property and equipment | |||||||||||
| Less: Accumulated depreciation and impairment | ( | ( | |||||||||
| Other property and equipment, net | |||||||||||
| Total property, plant and equipment, net | $ | $ | |||||||||
Impairment
The Company reviews its property, plant and equipment for impairment by asset group whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. If events occur that indicate an asset group may not be recoverable, the asset group is tested for recoverability.
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Unproved oil and gas properties. The Company did not
Other property and equipment. The Company reviews its other property and equipment for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. For the years ended December 31, 2025, 2024 and 2023, the Company did not
9. Acquisitions
2025 Acquisition
On September 15, 2025, a wholly-owned subsidiary of the Company entered into a definitive agreement to acquire certain developed and undeveloped oil and gas assets located in the Williston Basin from XTO Energy Inc. and affiliates (collectively, “XTO”), subsidiaries of Exxon Mobil Corporation, for total cash consideration of $550.0 million, subject to customary purchase price adjustments (the “2025 Williston Basin Acquisition”). The effective date of the 2025 Williston Basin Acquisition was September 1, 2025.
On October 31, 2025, the Company completed the 2025 Williston Basin Acquisition for total cash consideration of $542.2 million, including a cash deposit of $55.0 million to XTO upon execution of the purchase and sale agreement and $487.2 million paid to XTO at closing (including customary preliminary purchase price adjustments). The Company funded the 2025 Williston Basin Acquisition with proceeds from the issuance of the 2030 Senior Notes (defined in Note 12—Long-Term Debt) and cash on hand. The 2025 Williston Basin Acquisition was accounted for as a business combination and was recorded under the acquisition method of accounting in accordance with ASC 805. The post-acquisition operating results and pro forma revenue and earnings for the 2025 Williston Basin Acquisition were not material to the Company’s consolidated financial statements and have therefore not been presented.
Preliminary purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the 2025 Williston Basin Acquisition at their estimated fair value on October 31, 2025 of $542.2 million. The allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no
The tables below present the total consideration transferred and its allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on October 31, 2025. Certain estimated values for the acquisition, including oil and natural gas properties, are not yet finalized.
| Purchase Price Consideration | ||||||||
| (In thousands) | ||||||||
| Cash consideration transferred | $ | |||||||
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| Preliminary Purchase Price Allocation | ||||||||
| (In thousands) | ||||||||
| Assets acquired: | ||||||||
| Oil and gas properties (successful efforts method) | $ | |||||||
| Other property and equipment | ||||||||
| Inventory | ||||||||
| Total assets acquired | $ | |||||||
| Liabilities assumed: | ||||||||
| Asset retirement obligations | $ | |||||||
| Revenue and production taxes payable | ||||||||
| Total liabilities assumed | $ | |||||||
| Net assets acquired | $ | |||||||
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 was deductible for income tax purposes, and was 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 judgment and certain assumptions to be made. See Note 6—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, and a corresponding decrease to goodwill, totaling $0.5 million.
| Purchase Price Consideration | ||||||||
| (In thousands) | ||||||||
Common stock issued to Enerplus shareholders(1) | $ | |||||||
Cash paid to Enerplus shareholders(1) | ||||||||
Cash paid to settle Enerplus equity-based compensation awards(2) | ||||||||
Cash paid to settle Enerplus credit facility(3) | ||||||||
Cash paid for retention bonus to Enerplus employees(4) | ||||||||
| Total consideration transferred | $ | |||||||
__________________
1) The Company issued 20,680,097 shares of common stock and paid $375.8 million of cash to Enerplus shareholders as Arrangement Consideration. 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 16—Stockholders’ Equity 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 16—Stockholders’ Equity for additional information.
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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 12—Long-Term Debt 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.
| Final Purchase Price Allocation | ||||||||
| (In thousands) | ||||||||
| Assets acquired: | ||||||||
| Cash and cash equivalents | $ | |||||||
| Accounts receivable, net | ||||||||
| Inventory | ||||||||
| Prepaid expenses | ||||||||
| Oil and gas properties (successful efforts method) | ||||||||
| Other property and equipment | ||||||||
| Long-term inventory | ||||||||
| Operating right-of-use assets | ||||||||
| Other assets | ||||||||
| Total assets acquired | $ | |||||||
| Liabilities assumed: | ||||||||
| Accounts payable | $ | |||||||
| Revenues and production taxes payable | ||||||||
| Accrued liabilities | ||||||||
| Current portion of long-term debt | ||||||||
| Current operating lease liabilities | ||||||||
| Deferred tax liabilities | ||||||||
| Asset retirement obligations | ||||||||
| Operating lease liabilities | ||||||||
| Total liabilities assumed | $ | |||||||
| Net assets acquired | $ | |||||||
| Goodwill | ||||||||
| Purchase price consideration | $ | |||||||
Post-arrangement operating results. The results of operations of Enerplus have been included in the Company’s consolidated financial statements since the closing of the Arrangement on May 31, 2024. The following table summarizes the total revenues and income before income taxes attributable to Enerplus that were recorded in the Company’s Consolidated Statement of Operations for the period presented.
| Year Ended December 31, 2024 | ||||||||
| (In thousands) | ||||||||
| Revenues | $ | |||||||
| Income before income taxes | ||||||||
Unaudited pro forma financial information. Summarized below are the consolidated results of operations for the periods 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 $89.3 million for the year ended December 31, 2024, which were
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recorded to general and administrative expenses on the 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.
| Year Ended December 31, | ||||||||||||||
| 2024 | 2023 | |||||||||||||
| (In thousands, except per share data) | ||||||||||||||
| Revenues | $ | $ | ||||||||||||
| Net income | ||||||||||||||
2023 Acquisition
On May 22, 2023, the Company announced that a wholly-owned subsidiary of the Company had entered into a definitive agreement to acquire approximately 62,000 net acres in the Williston Basin from XTO, for total cash consideration of $375.0 million, subject to customary purchase price adjustments (the “2023 Williston Basin Acquisition”). The effective date of the 2023 Williston Basin Acquisition was April 1, 2023.
On June 30, 2023, the Company completed the 2023 Williston Basin Acquisition for total cash consideration of $361.6 million, including a deposit of $37.5 million paid to XTO upon execution of the purchase and sale agreement and $324.1 million paid to XTO at closing (including customary purchase price adjustments). The Company funded the 2023 Williston Basin Acquisition with cash on hand. The 2023 Williston Basin Acquisition was accounted for as a business combination and was recorded under the acquisition method of accounting in accordance with ASC 805. The post-acquisition operating results and pro forma revenue and earnings for the 2023 Williston Basin Acquisition were not material to the Company’s consolidated financial statements and have therefore not been presented.
Purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the 2023 Williston Basin Acquisition at their estimated fair value on June 30, 2023 of $361.6 million. The allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no
The tables below present the total consideration transferred and its allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on June 30, 2023. As of December 31, 2023, the purchase price was finalized with an immaterial adjustment to the preliminary purchase price allocation.
| Purchase Price Consideration | ||||||||
| (In thousands) | ||||||||
| Cash consideration transferred | $ | |||||||
| Purchase Price Allocation | ||||||||
| (In thousands) | ||||||||
| Assets acquired: | ||||||||
| Oil and gas properties (successful efforts method) | $ | |||||||
| Inventory | ||||||||
| Total assets acquired | $ | |||||||
| Liabilities assumed: | ||||||||
| Asset retirement obligations | $ | |||||||
| Revenue and production taxes payable | ||||||||
| Total liabilities assumed | $ | |||||||
| Net assets acquired | $ | |||||||
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10. Divestitures
During the years ended December 31, 2025, 2024 and 2023, the Company completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds of $24.8 million (subject to purchase price adjustments), $25.0 million and $12.1 million, respectively.
Divestitures of non-core properties. During the year ended December 31, 2024, the Company completed the sale of certain of its non-core properties located in the DJ Basin in Colorado and received net cash proceeds (including preliminary purchase price adjustments) of $36.4 million, resulting in a $0.6 million gain on asset divestment.
11. Investment in Equity Securities
The Company owns less than 5 % of Energy Transfer’s issued and outstanding common units in connection with the terms of a merger and has elected to account for its investment using the fair value option. As of December 31, 2025 and 2024, the fair value of the Company’s investment was $119.7 million and $142.2 million, respectively. The carrying amount of the Company’s investment in Energy Transfer is recorded to investment in equity securities on the Consolidated Balance Sheet.
During the year ended December 31, 2025, the Company recorded a net loss of $13.0 million on its investment, comprised of an unrealized loss for the change in fair value of the investment of $22.5 million and a realized gain for cash distributions received of $9.5 million. During the year ended December 31, 2024, the Company recorded a net gain of $51.3 million on its investment, comprised of an unrealized gain for the change in fair value of the investment of $42.0 million and a realized gain for cash distributions received of $9.3 million.
12. Long-Term Debt
The Company’s long-term debt consists of the following:
| December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Senior secured revolving line of credit | $ | $ | |||||||||
| 2030 Senior Notes | |||||||||||
| 2033 Senior Notes | |||||||||||
| 2026 Senior Notes | |||||||||||
| Less: unamortized deferred financing costs | ( | ( | |||||||||
| Total long-term debt, net | $ | $ | |||||||||
Senior secured revolving line of credit. The Company has a senior secured revolving credit facility (the “Credit Facility”) that matures on November 3, 2029. In November 2025, the Company completed its semi-annual borrowing base redetermination, which reaffirmed the borrowing base at $2.75 billion and the aggregate amount of elected commitments to $2.0 billion. At December 31, 2025, the Company had no borrowings outstanding and $32.8 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing base capacity of $1,967.2 million. At December 31, 2024, the Company had $445.0 million net borrowings outstanding and $30.8 million of outstanding letters of credit issued under the Credit Facility. For the years ended December 31, 2025 and 2024, the weighted average interest rate incurred on borrowings under the Credit Facility was 6.52 % and 7.27 %, respectively.
In November 2025, the Company entered into a seventh amended and restated credit agreement (the “Seventh Amended Credit Facility”). Pursuant to the Seventh Amended Credit Facility, the Credit Facility maturity date was extended from July 1, 2027 to November 3, 2029 and the Term SOFR Loans are no longer subject to the 0.1 % credit spread adjustment. Additionally, certain baskets were increased and certain provisions were updated to reflect current market practice.
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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 Term SOFR Loans, ABR Loans or Swingline Loans at their respective interest rate plus the margin shown in the table below. In addition, the unused borrowing base is subject to a commitment fee as shown in the table below:
| Total Revolving Commitment Utilization Percentage | ABR Loans or Swingline Loans | Term SOFR Loans | Commitment Fee | |||||||||||||||||
Less than | % | % | % | |||||||||||||||||
Greater than or equal to | % | % | % | |||||||||||||||||
Greater than or equal to | % | % | % | |||||||||||||||||
Greater than or equal to | % | % | % | |||||||||||||||||
Greater than or equal to | % | % | % | |||||||||||||||||
The Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on or about April 1 and October 1 of each year, with one interim redetermination available to each of the Company and the administrative agent between scheduled redeterminations during any 12-month period. The next scheduled redetermination is expected to occur on or about April 1, 2026.
A portion of the Credit Facility, in an aggregate amount not to exceed $100.0 million, may be used for the issuance of letters of credit. Additionally, the Credit Facility provides the ability for the Company to request swingline loans subject to a swingline loans sublimit of $50.0 million.
Borrowings under the Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the assets of Chord, as parent, Oasis Petroleum North America LLC (“OPNA”), as borrower, and certain of the Company’s subsidiaries, as guarantors, including mortgage liens on oil and gas properties having at least 85 % of the reserve value as determined by reserve reports.
A loan may be repaid at any time before the scheduled maturity of the Credit Facility upon the Company providing advance notification to the lenders.
The Credit Facility contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, investments, asset dispositions, fundamental changes, restricted payments, transactions with affiliates, and other customary covenants.
The financial covenants in the Credit Facility include:
•a requirement that the Company maintain a ratio of Total Net Debt to EBITDAX (as defined in the Credit Facility, the “Leverage Ratio”) of less than 3.50 to 1.00 as of the last day of any fiscal quarter; and
•a requirement that the Company 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.
The Credit Facility contains customary events of default, as well as cross-default provisions with other indebtedness of OPNA and the restricted subsidiaries under the Credit Facility. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable. The Company was in compliance with the financial covenants under the Credit Facility at December 31, 2025.
2030 Senior Notes. On September 30, 2025, the Company issued in a private placement $750.0 million of 6.000 % senior unsecured notes due October 1, 2030 (the “2030 Senior Notes”). The 2030 Senior Notes were issued at par and resulted in proceeds of $739.6 million, after deducting underwriters’ discounts, commissions and other expenses. The proceeds were used (i) to fund the 2025 Williston Basin Acquisition and to pay related costs and expenses, (ii) to pay fees and expenses associated with the offering of the 2030 Senior Notes and (iii) for general corporate purposes, including repayment of a portion of the borrowings outstanding under the Credit Facility. Interest on the 2030 Senior Notes is payable semi-annually on April 1 and October 1 of each year, beginning April 1, 2026. In connection with the issuance of the 2030 Senior Notes, the Company recorded deferred financing costs of $10.4 million, which are amortized to interest expense on the Company’s Consolidated Statement of Operations over the term of the 2030 Senior Notes. As of December 31, 2025, the fair value of the 2030 Senior Notes, which are traded among qualified institutional investors and represent a Level 1 fair value measurement, was $759.2 million.
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
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$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. Interest on the 2033 Senior Notes is payable semi-annually on March 15 and September 15 of each year. 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. As of December 31, 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 $775.6 million.
The 2030 Senior Notes and the 2033 Senior Notes are guaranteed on a senior unsecured basis by certain subsidiaries of the Company (the “Chord Guarantors”). These guarantees are full and unconditional and joint and several among the Chord Guarantors, subject to certain customary release provisions. The indentures governing the 2030 Senior Notes and the 2033 Senior Notes contain customary events of default as well as cross-default provisions with other indebtedness of Chord and its restricted subsidiaries.
The indentures governing the 2030 Senior Notes and the 2033 Senior Notes restrict the Company’s ability and the ability of certain subsidiaries to, among other things: (i) make investments, (ii) incur additional indebtedness or issue preferred stock, (iii) create liens, (iv) sell assets, (v) enter into agreements that restrict dividends or other payments by restricted subsidiaries, (vi) consolidate, merge or transfer all or substantially all of the Company’s assets with another company, (vii) enter into transactions with affiliates, (viii) pay dividends or make other distributions on capital stock or prepay subordinated indebtedness and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Senior Notes are rated investment grade by two out of the three rating agencies and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Company will cease to be subject to such covenants. The Company was in compliance with the terms of the indentures for the 2030 Senior Notes and the 2033 Senior Notes as of December 31, 2025.
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.
Enerplus credit facility. Upon consummation of the Arrangement on May 31, 2024, the Enerplus credit facility was terminated, and the Company paid the remaining outstanding amount of $395.0 million to fully satisfy all such outstanding obligations that were owed under the Enerplus credit facility.
Enerplus senior unsecured notes. Upon consummation of the Arrangement on May 31, 2024, the Company assumed $63.0 million of 3.79 % senior unsecured notes from Enerplus (the “Enerplus Senior Notes”). The Enerplus Senior Notes were recorded on the Consolidated Balance Sheet at their fair value acquired of $60.1 million as of the acquisition date. The fair value of the Enerplus Senior Notes, which represented a Level 2 fair value measurement, was estimated based on the amount that the Company would have to pay a third party to assume the debt, including the credit spread for the difference between the issue rate and the May 31, 2024 market rate. The May 31, 2024 market rate was estimated by comparing the debt to new issuances (secured or unsecured) and secondary trades of similar size and credit statistics for both public and private debt. On July 2, 2024, the Company repaid all of the remaining outstanding Enerplus Senior Notes of $63.0 million and the remaining accrued interest on such notes of $0.8 million.
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13. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Asset retirement obligation — beginning of period | $ | $ | |||||||||
| Liabilities incurred during period | |||||||||||
Liabilities incurred through acquisitions | |||||||||||
| Liabilities settled during period | ( | ( | |||||||||
| Liabilities settled through divestitures | ( | ( | |||||||||
| Accretion expense during period | |||||||||||
| Revisions to estimates | |||||||||||
| Asset retirement obligation — end of period | $ | $ | |||||||||
The Company’s ARO includes plugging and abandonment liabilities for its oil and gas properties in the United States and Canada. The revisions to estimates included in the table above increased the ARO liability by $147.1 million, which was primarily comprised of $98.7 million related to updates in the plugging and abandonment cost estimates of the Company’s wells in North Dakota and $48.4 million related to lower estimated well lives as a result of decreased oil and gas prices. Accretion expense is included in depreciation, depletion and amortization on the Company’s Consolidated Statements of Operations. At December 31, 2025 and 2024, the current portion of the total ARO balance was $49.1 million and $26.1 million, respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets.
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14. Income Taxes
The Company adopted ASU 2023-09 on a prospective basis in this Annual Report on Form 10-K for the year ended December 31, 2025, in accordance with the transition provisions.
A summary of the Company’s income before income taxes, income tax expense and income taxes paid for the year ended December 31, 2025 is set forth below:
| Year Ended December 31, 2025 | |||||
| (In thousands) | |||||
| Income before income taxes: | |||||
| United States | $ | ||||
| Foreign | ( | ||||
| Total income before income taxes | $ | ||||
| Income tax expense: | |||||
| U.S. Federal | $ | ||||
| Foreign | |||||
| U.S. State and Local | |||||
| Total income tax expense | $ | ||||
Income taxes paid(1): | |||||
| U.S. Federal | $ | ||||
| Foreign | |||||
| U.S. State and Local | |||||
| Total income taxes paid | $ | ||||
__________________
(1) Income taxes paid for the years ended December 31, 2024 and 2023 were $53.7 million and $17.2 million, respectively.
The Company’s income tax expense for the years ended December 31, 2024 and 2023 consists of the following:
| Year Ended December 31, | ||||||||||||||
| 2024 | 2023 | |||||||||||||
| (In thousands) | ||||||||||||||
| Current: | ||||||||||||||
| Federal | $ | $ | ||||||||||||
| U.S. State and local | ( | |||||||||||||
| Total current tax expense | ||||||||||||||
| Deferred: | ||||||||||||||
| Federal | ||||||||||||||
| U.S. State and local | ||||||||||||||
| Total deferred tax expense | ||||||||||||||
| Total income tax expense | $ | $ | ||||||||||||
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The reconciliation of income taxes calculated at the U.S. federal statutory tax rate to the Company’s effective tax rate for the year ended December 31, 2025 is set forth below:
_________________
| Year Ended December 31, 2025 | |||||||||||
| % | (In thousands) | ||||||||||
| Total income before income taxes | $ | ||||||||||
| U.S. federal statutory tax rate | % | $ | |||||||||
State and local income taxes, net of federal tax benefit(1) | % | ||||||||||
| Effects of changes in tax laws or rates | % | ||||||||||
| Deferred tax on unremitted earnings | % | ||||||||||
| Research and development tax credit | ( | % | ( | ||||||||
| Impact of return to provision and tax basis balance sheet | % | ||||||||||
| Non-taxable or nondeductible items | |||||||||||
| Nondeductible executive compensation | % | ||||||||||
| Goodwill impairment | % | ||||||||||
| Other | % | ||||||||||
| Total income tax expense | % | $ | |||||||||
(1)State taxes in North Dakota make up the majority (greater than 50%) of the tax effect in this category.
The reconciliation of income taxes calculated at the U.S. federal statutory tax rate to the Company’s effective tax rate for the years ended December 31, 2024 and 2023 is set forth below:
| Year Ended December 31, | ||||||||||||||||||||||||||
| 2024 | 2023 | |||||||||||||||||||||||||
| (%) | (In thousands) | (%) | (In thousands) | |||||||||||||||||||||||
| U.S. federal statutory tax rate | % | $ | % | $ | ||||||||||||||||||||||
| State income taxes, net of federal income tax benefit | % | % | ||||||||||||||||||||||||
| Change in valuation allowance | % | % | ||||||||||||||||||||||||
| Other | % | ( | % | ( | ||||||||||||||||||||||
| Annual effective tax expense | % | $ | % | $ | ||||||||||||||||||||||
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Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2025 and 2024 were as follows:
| December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Deferred tax assets | |||||||||||
| Net operating loss carryforward | $ | $ | |||||||||
| Bonus and equity-based compensation | |||||||||||
| Other deferred tax assets | |||||||||||
| Total deferred tax assets | |||||||||||
| Less: Valuation allowance | ( | ( | |||||||||
| Total deferred tax assets, net | $ | $ | |||||||||
| Deferred tax liabilities | |||||||||||
| Oil and natural gas properties | $ | $ | |||||||||
| Investment in partnerships | |||||||||||
| Tax on unremitted earnings | |||||||||||
| Other deferred tax liabilities | |||||||||||
| Total deferred tax liabilities | $ | $ | |||||||||
| Total deferred tax liabilities, net | $ | ( | $ | ( | |||||||
The Company’s effective tax rate for the year ended December 31, 2025 was 81.7 % of pre-tax income, as compared to an effective tax rate of 23.7 % of pre-tax income for the year ended December 31, 2024. The effective tax rate for the year ended December 31, 2025 was higher than the federal statutory tax rate of 21% primarily as a result of the impact of non-deductible goodwill impairment. The effective tax rate for the year ended December 31, 2024 was higher than the federal statutory tax rate of 21% primarily as a result of state income taxes.
As of December 31, 2025, the Company had gross U.S. federal net operating loss (“NOL”) carryforwards of $1,013.0 million, of which approximately $928.7 million will not expire and $84.2 million will expire from 2032 to 2037. In addition, the Company had gross state NOL carryforwards of $2,001.3 million as of December 31, 2025, which expire between 2025 and 2042. The Company and Whiting both experienced an “ownership change” as defined by the Internal Revenue Code of 1986, as amended (the “Code”), in the past, including as a result of the Merger. Accordingly, under Section 382 of the Code, the Company’s NOL carryforwards and other tax attributes (collectively, “Tax Benefits”) are subject to various limitations going forward. However, the limitations applicable under Section 382 of the Code resulting from the Merger are not expected to have a material impact on the realizability of the Company’s deferred tax assets.
Tax Benefits are recorded as an asset to the extent that management assesses the utilization of such Tax Benefits to be more likely than not, and when the future utilization of some portion of the Tax Benefits is determined not to be more likely than not, then a valuation allowance is provided to reduce the Tax Benefits from such assets.
The Company’s estimated valuation allowance as of December 31, 2025 was $7.9 million, which relates to state NOL carryforwards and is approximately consistent with the valuation allowance as of December 31, 2024.
On May 31, 2024, the Company completed the Arrangement, and as a result recognized a net deferred tax liability of $1,179.2 million in its purchase price allocation as of the acquisition date primarily to reflect the difference between the tax basis and the fair value of Enerplus’ assets acquired and liabilities assumed. The Company did not record a Canadian deferred tax asset due to the lack of continued operations in Canada going forward.
Unrecognized Tax Benefits. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution. As part of the Arrangement, an uncertain tax position was recorded for $15.5 million, which is included in deferred tax liabilities on the Company’s Consolidated Balance Sheet as of December 31, 2025, all of which would affect the effective tax rate if recognized.
With respect to income taxes, the Company’s policy is to account for interest charges as interest expense and any penalties as tax expense in its Consolidated Statements of Operations. The Company files U.S. federal income tax returns, Canadian federal tax returns and income tax returns in the various states and provinces where it operates.
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As the Company has NOL carryforwards from previous tax years, which are utilized in open years, the Internal Revenue Service may examine the Company’s loss years back to the 2012 tax year. The Canadian federal tax returns are open from 2019 and forward.
On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law. The legislation, among other things, makes permanent, extends, or modifies certain provisions under the Inflation Reduction Act and Tax Cuts and Jobs Act. Significant provisions impacting the Company include (i) the permanent reinstatement of 100% bonus depreciation on qualified property, and (ii) the allowance for immediate and full expensing of domestic research and experimentation expenditures. The enactment of the OBBBA did not have a material impact on the Company’s effective tax rate for the year ended December 31, 2025.
15. Equity-Based Compensation
The Company has granted equity-based compensation awards under the 2020 LTIP. In accordance with the FASB’s authoritative guidance for share-based payments, the Company accounts for awards that settle in shares of common stock as equity-classified awards and awards that settle in cash as liability-classified awards.
Equity-based compensation expense is recognized in general and administrative expenses on the Company’s Consolidated Statements of Operations. The Company recognized $25.7 million, $23.0 million and $46.1 million in equity-based compensation expenses related to equity-classified awards during the years ended December 31, 2025, 2024 and 2023, respectively. Equity-based compensation expenses related to liability-classified awards were $1.0 million, $1.0 million and $3.4 million during the years ended December 31, 2025, 2024 and 2023, respectively.
Restricted stock units. The Company has granted restricted stock units (“RSUs”) to employees and non-employee directors. RSUs are contingent shares with a service-based vesting condition. The RSUs granted to employees vest following a graded vesting schedule and vest ratably each year over a three-year or four-year period. The RSUs granted to non-employee directors vest over a one-year period. The fair value is based on the closing price of the Company’s common stock on the date of grant or, if applicable, the date of modification. The Company recognizes compensation expense under the straight-line method over the requisite service period.
The following table summarizes information related to RSUs held by employees and non-employee directors of the Company:
| Shares | Weighted Average Grant Date Fair Value per Share | ||||||||||
Non-vested shares outstanding December 31, 2024 | $ | ||||||||||
| Granted | |||||||||||
| Vested | ( | ||||||||||
| Forfeited | ( | ||||||||||
Non-vested shares outstanding December 31, 2025 | $ | ||||||||||
The fair value of awards vested was $14.9 million and $23.2 million for the years ended December 31, 2025 and 2024, respectively. The weighted average grant date fair value of RSUs was $118.16 per share and $161.23 per share for the years ended December 31, 2025 and 2024, respectively. Unrecognized expense as of December 31, 2025 for all outstanding RSUs was $23.8 million and will be recognized over a weighted average period of approximately 1.6 years.
Performance share units. During the years ended December 31, 2025 and 2024, the Company granted performance share units to certain employees that include (i) total stockholder return (“TSR”) performance share units (“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, 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.
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The PSUs are bifurcated and classified as equity-based and liability-based awards based on the probability of achieving various target performance thresholds.
The following table summarizes information related to the Absolute TSR PSUs held by employees of the Company:
| Shares | Weighted Average Grant Date Fair Value per Share | ||||||||||
Non-vested shares outstanding December 31, 2024 | $ | ||||||||||
| Granted | |||||||||||
| Vested | |||||||||||
| Forfeited | ( | ||||||||||
Non-vested shares outstanding December 31, 2025 | $ | ||||||||||
There were no vested awards during the year ended December 31, 2025. The fair value of awards vested was $0.1 million for the year ended December 31, 2024. Unrecognized expense as of December 31, 2025 for all outstanding Absolute TSR PSUs was $2.3 million and will be recognized over a weighted average period of 1.8 years.
The following table summarizes information related to the Relative TSR PSUs held by employees of the Company:
| Shares | Weighted Average Grant Date Fair Value per Share | ||||||||||
Non-vested shares outstanding December 31, 2024 | $ | ||||||||||
| Granted | |||||||||||
| Vested | |||||||||||
| Forfeited | ( | ||||||||||
Non-vested shares outstanding December 31, 2025 | $ | ||||||||||
There were no vested awards during the year ended December 31, 2025. The fair value of awards vested was $0.2 million for the year ended December 31, 2024. Unrecognized expense as of December 31, 2025 for all outstanding Relative TSR PSUs was $7.4 million and will be recognized over a weighted average period of 1.7 years.
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. The key valuation inputs were: (i) the forecast period, (ii) risk-free interest rate, (iii) implied equity volatility and (iv) stock price on the date of grant. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to each 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.
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 by grant date:
| Absolute and Relative TSR PSUs | |||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | ||||||||||||||||
| Forecast period (years) | |||||||||||||||||
| Risk-free interest rates | — | ||||||||||||||||
| Implied equity volatility | |||||||||||||||||
| Range of stock price on date of grant | $ | $ | — | $ | |||||||||||||
Phantom unit awards. The Company granted phantom unit awards to certain employees. Phantom unit awards represent the right to receive, upon vesting of the award, a cash payment equal to the fair market value of one share of common stock. The phantom unit awards are subject to a service-based vesting condition and generally vest in equal installments each year over a three-year period from the date of grant. Compensation expense is recognized over the requisite service period.
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The following table summarizes information related to phantom unit awards held by employees of the Company:
| Phantom Unit Awards | Weighted Average Grant Date Fair Value per Share | ||||||||||
Non-vested phantom unit awards outstanding December 31, 2024 | $ | ||||||||||
| Granted | |||||||||||
| Vested | ( | ( | |||||||||
| Forfeited | ( | ( | |||||||||
Non-vested phantom unit awards outstanding December 31, 2025 | $ | ||||||||||
The fair value of vested phantom unit awards was $0.8 million and $0.6 million for the years ended December 31, 2025 and 2024, respectively. Unrecognized expense as of December 31, 2025 for all outstanding phantom unit awards was $1.1 million and will be recognized over a weighted average period of approximately 1.7 years.
Legacy awards. The Company previously granted performance share units (“Legacy PSUs”) and leveraged stock units (“LSUs”) to certain employees. These awards were contingent shares that could be earned over a three-year or four-year performance period subject to market-based and service-based vesting conditions. The completion of the Merger represented a “change in control” such that such awards earned by award recipients were subject to a service-based vesting condition.
As of December 31, 2024, these Legacy PSUs were fully vested and the fair value of the awards vested was $9.0 million for the year ended December 31, 2024.
16. 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.
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Dividends
The following table summarizes the Company’s fixed and variable dividends declared by quarter for the years ended December 31, 2025, 2024 and 2023:
| Rate per Share | |||||||||||||||||||||||||||||
| Base | Variable | Total | Total Dividends Declared | ||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Q4 2025 | $ | $ | $ | $ | |||||||||||||||||||||||||
| Q3 2025 | |||||||||||||||||||||||||||||
| Q2 2025 | |||||||||||||||||||||||||||||
| Q1 2025 | |||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | |||||||||||||||||||||||||
| Q4 2024 | $ | $ | $ | $ | |||||||||||||||||||||||||
| Q3 2024 | |||||||||||||||||||||||||||||
| Q2 2024 | |||||||||||||||||||||||||||||
| Q1 2024 | |||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | |||||||||||||||||||||||||
| Q4 2023 | $ | $ | $ | $ | |||||||||||||||||||||||||
| Q3 2023 | |||||||||||||||||||||||||||||
| Q2 2023 | |||||||||||||||||||||||||||||
| Q1 2023 | |||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | |||||||||||||||||||||||||
Total dividends declared in the table above includes $2.6 million, $7.0 million and $14.4 million associated with dividend equivalent rights on unvested equity-based compensation awards for the years ended December 31, 2025, 2024 and 2023, respectively.
As of December 31, 2025, the Company had dividends payable of $1.4 million related to dividend equivalent rights accrued on equity-based compensation awards, including $0.9 million that was recorded under accrued liabilities and $0.5 million that was recorded under other liabilities on the Consolidated Balance Sheet.
On February 25, 2026, the Company declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 27, 2026 to shareholders of record as of March 12, 2026.
Share Repurchase Program
The Company’s Board of Directors authorized a share repurchase program in August 2025 of up to $1.0 billion of the Company’s common stock. This program replaces previous share repurchase programs.
During the year ended December 31, 2025, the Company repurchased 3,491,618 shares of common stock at a weighted average price of $104.39 per common share for a total cost of $364.5 million (excluding accrued excise taxes) under both the August 2025 and October 2024 share repurchase programs. As of December 31, 2025, there was $952.2 million of capacity remaining under the Company’s August 2025 program.
During the years ended December 31, 2024 and 2023, the Company repurchased 3,114,007 and 1,533,791 shares of common stock at weighted average prices of $142.20 and $157.08 per share for total costs of $442.8 million and $240.9 million, respectively, under previous share repurchase programs.
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Warrants
Legacy Oasis warrants. On November 19, 2020, the Company entered into a Warrant Agreement with Computershare Inc. and Computershare Trust Company N.A., as warrant agent. The warrants, which were indexed to the Company’s common stock and were classified as equity, were exercisable until November 19, 2024, at which time all unexercised warrants expired and the rights of the holders of such warrants to purchase common stock terminated. The Company had 124,495 legacy Oasis warrants expire on November 19, 2024. As of December 31, 2025, there were no remaining legacy Oasis warrants outstanding, as all such warrants had expired prior to that date.
Assumed Whiting warrants. Pursuant to the terms of the Merger, all of Whiting’s outstanding warrants immediately prior to the effective time of the Merger were assumed by the Company at the closing of the Merger. Each Whiting warrant was exercisable for 0.5774 shares of the Company’s common stock. Therefore, as a result of the completion of the Merger on July 1, 2022, the Company assumed (i) 4,833,455 legacy Whiting Series A Warrants which were exercisable for an aggregate amount of 2,790,837 shares of the Company’s common stock at an exercise price of $116.37 per share and (ii) 2,418,832 legacy Whiting Series B Warrants which were exercisable for an aggregate amount of 1,396,634 shares of the Company’s common stock at an exercise price of $133.70 per share.
In the event that a holder of Whiting warrants elected to exercise their option to acquire shares of the Company’s common stock, the Company issued a net number of exercised shares of common stock. The net number of exercised shares was calculated as (i) the number of Whiting warrants exercised multiplied by (ii) the difference between the 30 day daily volume weighted average price of the common stock leading up to the exercise date and the relevant exercise price, calculated as a percentage of the current market price on the exercise date.
17. Earnings Per Share
The Company calculates earnings per share under the two-class method. The two-class method is an earnings allocation formula that 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 (loss) (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.
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The following table summarizes the basic and diluted earnings per share for the periods presented:
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands, except per share data) | |||||||||||||||||
| Net income | $ | $ | $ | ||||||||||||||
| Distributed and undistributed earnings allocated to participating securities | ( | ( | ( | ||||||||||||||
| Net income attributable to common stockholders (basic) | |||||||||||||||||
| Reallocation of distributed and undistributed earnings allocated to participating securities | |||||||||||||||||
| Net income attributable to common stockholders (diluted) | $ | $ | $ | ||||||||||||||
| Weighted average common shares outstanding: | |||||||||||||||||
| Basic weighted average common shares outstanding | |||||||||||||||||
Dilutive effect of share-based awards | |||||||||||||||||
| Dilutive effect of warrants | |||||||||||||||||
| Diluted weighted average common shares outstanding | |||||||||||||||||
| Basic earnings per share | $ | $ | $ | ||||||||||||||
| Diluted earnings per share | $ | $ | $ | ||||||||||||||
| Anti-dilutive weighted average common shares: | |||||||||||||||||
| Potential common shares | |||||||||||||||||
For the years ended December 31, 2025, 2024 and 2023, the diluted earnings per share calculation excludes the impact of unvested share-based awards and outstanding warrants that were anti-dilutive.
18. Leases
The Company’s long-term leases consist primarily of office space, vehicles and other property and equipment used in its operations. The components of lease costs before joint-interest recoveries were as follows for the periods presented:
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Operating lease costs | $ | $ | $ | ||||||||||||||
Variable lease costs(1) | |||||||||||||||||
| Short-term lease costs | |||||||||||||||||
| Sublease income | ( | ( | ( | ||||||||||||||
| Finance lease costs: | |||||||||||||||||
| Amortization of ROU assets | |||||||||||||||||
| Interest on lease liabilities | |||||||||||||||||
| Total lease costs | $ | $ | $ | ||||||||||||||
___________________
(1)Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate.
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As of December 31, 2025, maturities of the Company’s lease liabilities were as follows:
| Operating Leases | Finance Leases | ||||||||||
| (In thousands) | |||||||||||
| 2026 | $ | $ | |||||||||
| 2027 | |||||||||||
| 2028 | |||||||||||
| 2029 | |||||||||||
| 2030 | |||||||||||
| Thereafter | |||||||||||
| Total future lease payments | |||||||||||
| Less: Imputed interest | |||||||||||
| Present value of future lease payments | $ | $ | |||||||||
Supplemental balance sheet information related to the Company’s leases were as follows:
| December 31, | ||||||||||||||||||||
| Balance Sheet Location | 2025 | 2024 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Assets | ||||||||||||||||||||
Operating lease assets(1) | Operating right-of-use assets | $ | $ | |||||||||||||||||
| Other assets | ||||||||||||||||||||
| Total lease assets | $ | $ | ||||||||||||||||||
| Liabilities | ||||||||||||||||||||
| Current | ||||||||||||||||||||
Operating lease liabilities(1) | Current operating lease liabilities | $ | $ | |||||||||||||||||
| Other current liabilities | ||||||||||||||||||||
| Long-term | ||||||||||||||||||||
Operating lease liabilities(1) | Operating lease liabilities | |||||||||||||||||||
| Other liabilities | ||||||||||||||||||||
| Total lease liabilities | $ | $ | ||||||||||||||||||
___________________
(1)The year ended December 31, 2024 includes $43.0 million of operating leases for certain operating equipment and office buildings acquired in connection with the Arrangement.
(2)Finance lease ROU assets are recorded net of accumulated amortization of $4.2 million and $2.4 million as of December 31, 2025 and 2024, respectively.
During the years ended December 31, 2024 and 2023, the Company recorded impairment charges related to the Denver offices and its related fixed assets acquired in the Arrangement and Merger of $2.5 million and $17.5 million, respectively, as a result of overall market conditions. The ROU asset impairment charges are recorded within impairment and exploration on the Consolidated Statements of Operations.
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Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows:
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities | |||||||||||||||||
| Operating cash flows from operating leases | $ | $ | $ | ||||||||||||||
| Operating cash flows from finance leases | |||||||||||||||||
| Financing cash flows from finance leases | |||||||||||||||||
| ROU assets obtained in exchange for lease obligations | |||||||||||||||||
Operating leases(1) | $ | $ | $ | ||||||||||||||
| Finance leases | |||||||||||||||||
___________________
Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows:
| December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Operating leases | |||||||||||
| Weighted average remaining lease term | |||||||||||
| Weighted average discount rate | % | % | |||||||||
| Finance leases | |||||||||||
| Weighted average remaining lease term | |||||||||||
| Weighted average discount rate | % | % | |||||||||
19. Significant Concentrations
Major customers. For the year ended December 31, 2025, sales to Phillips 66 Company and Marathon Petroleum Supply & Trading LLC accounted for approximately 21 % and 12 %, respectively, of the Company’s total product sales. For the year ended December 31, 2024, sales to Phillips 66 Company accounted for approximately 19 % of the Company’s total product sales. For the year ended December 31, 2023, sales to Phillips 66 Company and Gunvor USA LLC accounted for approximately 20 % and 14 %, respectively, of the Company’s total product sales. No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2025, 2024 or 2023.
Substantially all of the Company’s accounts receivable result from sales of crude oil, NGL and natural gas as well as joint interest billings to third-party companies who have working interest payment obligations in projects completed by the Company. This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative crude oil, NGL and natural gas purchasers in the Company’s producing regions.
20. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of December 31, 2025. The commitments under these arrangements are not recorded in the accompanying Consolidated Balance Sheets. The amounts disclosed represent undiscounted cash flows on a gross basis and no inflation elements have been applied. As of December 31, 2025, the Company’s material off-balance sheet arrangements and transactions include $32.8 million in outstanding letters of credit issued under the Credit Facility and $113.4 million in net surety bond exposure issued as financial assurance on certain agreements.
Volume commitment agreements. As of December 31, 2025, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 40.6 MMBbl of crude oil, 10.6 MMBbl of NGL, 335.6 Bcf of natural gas and 12.0 MMBbl of water within specified timeframes, the majority of which have a remaining term of five years or less.
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The estimable future commitments under these volume commitment agreements as of December 31, 2025 are as follows:
| (In thousands) | |||||
| 2026 | $ | ||||
| 2027 | |||||
| 2028 | |||||
| 2029 | |||||
| 2030 | |||||
| Thereafter | |||||
| $ | |||||
The future commitments under certain agreements cannot be estimated and are therefore excluded from the table above as they are based on fixed differentials relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for the production month.
The Company enters into long-term contracts to provide production flow assurance in oversupplied areas with limited infrastructure, which provides for optimization of transportation and processing costs. As properties are undergoing development activities, the Company may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. The Company recognizes any monthly deficiency payments in the period in which the under delivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred.
Mandan, Hidatsa and Arikara Nation (“MHA Nation”) Title Dispute. This matter relates to certain leases acquired by the Company from QEP Energy Company (“QEP”) in October 2021. In June 2018, the MHA Nation notified QEP of its position that QEP has no valid lease covering certain minerals underlying the Missouri and Little Missouri River riverbeds on the Fort Berthold Reservation in North Dakota. The MHA Nation also passed a resolution purporting to rescind those portions of QEP's Indian Mineral Development Act of 1982 lease covering the disputed minerals underlying the Missouri River. QEP responded in September 2018 stating that the minerals underlying the Missouri River are properly leased. In May 2020, the Office of the Solicitor of the United States Department of the Interior (the “Department of the Interior”) issued an opinion (the “Missouri River Opinion”) finding that the State of North Dakota, not the MHA Nation, is the legal owner of the minerals underlying the Missouri River. The MHA Nation filed actions in two federal courts seeking to overturn the May 2020 decision, and in March 2021, the Department of the Interior withdrew the Missouri River Opinion and on February 4, 2022, the Department of the Interior issued a new opinion on the matter stating that the minerals beneath the Missouri River riverbed located on the Fort Berthold Indian Reservation belong to the MHA Nation and not the State of North Dakota. Based on the new opinion from the Department of Interior, on June 21, 2022, the D.C. Federal District Court issued an order dismissing the MHA Nation’s claims relating to title of the riverbed as moot and denied the State of North Dakota’s motion to intervene on remaining counts. The D.C. Federal District Court did not address the substantive question of ownership at that time. On June 29, 2022, the State of North Dakota appealed this order to the D.C. Circuit Court of Appeals. On April 21, 2023, the D.C. Circuit Court of Appeals issued an opinion reversing the D.C. Federal District Court’s denial of the State of North Dakota’s motion to intervene on the remaining counts.
The case is currently on remand before the D.C. Federal District Court. In 2025, the parties filed dispositive motions, including motions for summary judgment, but on January 6, 2026, the Court denied these dispositive motions and ruled that factual determinations would need to be made, and would require a trial and full evidentiary record, in order to rule on the riverbed ownership and related issues. The parties are currently required to file a joint status report, informing the Court of the time required for expert testimony and exhibit production, beyond the documentation already filed with the prior motions. On January 30, 2026, the federal defendants filed a motion to extend the timeline for the joint status report by 90 days to allow sufficient time for an internal review. However, the Court denied that motion. The parties are now required to submit a joint status report by February 17, 2026.
Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed. As of December 31, 2024, the Company had accrued a settlement obligation and offsetting insurance receivable in the Company’s Consolidated Balance Sheet. Such obligation and insurance claims were settled during the year ended December 31, 2025.
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21. Subsequent Events
The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than those matters previously disclosed herein.
22. Supplemental Oil and Gas Disclosures — Unaudited
The supplemental data presented below reflects information for all of the Company’s oil and gas producing activities.
Capitalized Costs
The following table sets forth the capitalized costs related to the Company’s oil and gas producing activities:
| December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Proved oil and gas properties | $ | $ | |||||||||
| Less: Accumulated depletion and impairment | ( | ( | |||||||||
| Proved oil and gas properties, net | |||||||||||
| Unproved oil and gas properties | |||||||||||
| Total oil and gas properties, net | $ | $ | |||||||||
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
The following table sets forth costs incurred related to the Company’s oil and gas activities for the periods presented:
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Acquisition costs: | |||||||||||||||||
Proved oil and gas properties(1) | $ | $ | $ | ||||||||||||||
| Unproved oil and gas properties | |||||||||||||||||
| Exploration costs | |||||||||||||||||
Development costs(2) | |||||||||||||||||
| Total costs incurred | $ | $ | $ | ||||||||||||||
___________________
(1)Acquisition costs include non-cash upward adjustments to oil and gas properties of $16.6 million, $66.9 million and $6.8 million, which relate to estimated future plugging and abandonment costs of the oil and gas wells acquired in the 2025 Williston Basin Acquisition, the Arrangement and the 2023 Williston Basin Acquisition for the years ended December 31, 2025, 2024 and 2023, respectively.
(2)Development costs include non-cash upward adjustments to oil and gas properties of $152.1 million, $6.1 million and $18.5 million for the years ended December 31, 2025, 2024 and 2023, respectively, which relate to estimated future plugging and abandonment costs of the Company’s oil and gas wells.
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Results of Operations for Oil and Gas Producing Activities
The following table sets forth the results of operations for oil and gas producing activities, which exclude goodwill impairment, general and administrative expenses and interest expense, for the periods presented:
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Revenues | $ | $ | $ | ||||||||||||||
| Production costs | |||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||
| Impairment and exploration | |||||||||||||||||
| Income tax expense | |||||||||||||||||
| Results of operations for oil and gas producing activities | $ | $ | $ | ||||||||||||||
23. Supplemental Oil and Gas Reserve Information — Unaudited
The reserve estimates presented below at December 31, 2025, 2024 and 2023 are based on reports prepared by Netherland, Sewell & Associates, Inc., the Company’s independent reserve engineers. All of the Company’s oil and gas reserves are attributable to properties within the United States.
Proved oil and gas reserves are the estimated quantities of crude oil, NGL and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
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Estimated Quantities of Proved Reserves
The following table summarizes changes in quantities of the Company’s estimated net proved reserves by product for the periods presented:
| Crude Oil (MBbl) | NGL (MBbl) | Natural Gas (MMcf) | MBoe | ||||||||||||||||||||
2023 | |||||||||||||||||||||||
| Proved reserves | |||||||||||||||||||||||
| Beginning balance | |||||||||||||||||||||||
| Revisions of previous estimates | ( | ( | ( | ( | |||||||||||||||||||
| Extensions, discoveries and other additions | |||||||||||||||||||||||
| Sales of reserves in place | ( | ( | ( | ( | |||||||||||||||||||
| Purchases of reserves in place | |||||||||||||||||||||||
| Production | ( | ( | ( | ( | |||||||||||||||||||
Net proved reserves at December 31, 2023 | |||||||||||||||||||||||
Proved developed reserves, December 31, 2023 | |||||||||||||||||||||||
Proved undeveloped reserves, December 31, 2023 | |||||||||||||||||||||||
2024 | |||||||||||||||||||||||
| Proved reserves | |||||||||||||||||||||||
| Beginning balance | |||||||||||||||||||||||
| Revisions of previous estimates | ( | ( | ( | ( | |||||||||||||||||||
| Extensions, discoveries and other additions | |||||||||||||||||||||||
| Sales of reserves in place | ( | ( | ( | ( | |||||||||||||||||||
| Purchases of reserves in place | |||||||||||||||||||||||
| Production | ( | ( | ( | ( | |||||||||||||||||||
Net proved reserves at December 31, 2024 | |||||||||||||||||||||||
Proved developed reserves, December 31, 2024 | |||||||||||||||||||||||
Proved undeveloped reserves, December 31, 2024 | |||||||||||||||||||||||
2025 | |||||||||||||||||||||||
| Proved reserves | |||||||||||||||||||||||
| Beginning balance | |||||||||||||||||||||||
| Revisions of previous estimates | ( | ( | |||||||||||||||||||||
| Extensions, discoveries and other additions | |||||||||||||||||||||||
| Purchases of reserves in place | |||||||||||||||||||||||
| Production | ( | ( | ( | ( | |||||||||||||||||||
Net proved reserves at December 31, 2025 | |||||||||||||||||||||||
Proved developed reserves, December 31, 2025 | |||||||||||||||||||||||
Proved undeveloped reserves, December 31, 2025 | |||||||||||||||||||||||
2025
Proved reserves increased by 34.5 MMBoe during the year ended December 31, 2025 due to the following:
Purchases of reserves in place. The Company added 38.0 MMBoe of proved reserves from the purchase of reserves in place as a result of the 2025 Williston Basin Acquisition.
Production. Production decreased proved reserves by 101.0 MMBoe.
Revisions of previous estimates. The Company had net negative revisions of 6.4 MMBoe attributable to the following:
Decreases:
•31.9 MMBoe primarily associated with timing changes to the Company’s development plan following the 2025 Williston Basin Acquisition
•10.7 MMBoe primarily associated with lower crude oil and NGL prices and weaker differentials
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Increases:
•24.5 MMBoe primarily associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets
•11.7 MMBoe primarily associated with the reduction in operating expenses and capital expenses primarily associated with deflation
Extensions, discoveries and other additions. The Company added 103.8 MMBoe of proved reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin. Proved reserves increased due to new wells drilled in this area, as well as proved undeveloped (“PUD”) locations added as a result of offset drilling.
Sales of reserves in place. There were no sales of reserves in place in 2025.
2024
Proved reserves increased by 246.8 MMBoe during the year ended December 31, 2024 due to the following:
Purchases of reserves in place. The Company added 315.3 MMBoe of proved reserves from the purchase of reserves in place as a result of the Arrangement.
Production. Production decreased proved reserves by 85.2 MMBoe.
Revisions of previous estimates. The Company had net negative revisions of 45.4 MMBoe attributable to the following:
Decreases:
•14.5 MMBoe associated with lower crude oil, NGL and natural gas prices and weaker differentials
•23.8 MMBoe primarily associated with timing changes to the Company’s development plan following the Arrangement
•11.0 MMBoe primarily associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets
Increases:
•3.9 MMBoe associated with the reduction in operating expenses and capital expenses primarily associated with deflation
Extensions, discoveries and other additions. The Company added 63.7 MMBoe of proved reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin. New wells drilled in this area, as well as PUD locations added as a result of offset drilling, increased proved reserves.
Sales of reserves in place. Proved reserves decreased 1.6 MMBoe primarily as a result of the divestiture of certain non-core properties located in the DJ Basin of Colorado.
2023
Proved reserves decreased by 19.4 MMBoe during the year ended December 31, 2023 due to the following:
Production. Production decreased proved reserves by 63.3 MMBoe.
Revisions of previous estimates. The Company had net negative revisions of 48.9 MMBoe attributable to the following:
Decreases:
•41.2 MMBoe associated with lower crude oil, NGL and natural gas prices and tighter differentials
•19.6 MMBoe associated with increases in operating expenses and capital expenses primarily associated with inflation
•9.9 MMBoe primarily associated with updated expectations on undeveloped well reserves and changes to development timing
Increases:
•14.4 MMBoe associated with stronger NGL yields
•7.4 MMBoe primarily associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets
Extensions, discoveries and other additions. The Company added 78.6 MMBoe of proved reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin. New wells drilled in this area, as well as PUD locations added as a result of offset drilling, increased proved reserves.
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Purchases of reserves in place. The Company added 18.8 MMBoe of proved reserves from the purchase of reserves in place as a result of the 2023 Williston Basin Acquisition.
Sales of reserves in place. Proved reserves decreased 4.6 MMBoe primarily as a result of the Non-core Asset Sales.
Changes in Proved Undeveloped Reserves
The following table summarizes the changes in the Company’s estimates of PUD reserves during 2025:
| Year Ended December 31, 2025 | |||||
| (MBoe) | |||||
| Proved undeveloped reserves, beginning of period | |||||
| Purchases of minerals in place | |||||
| Extensions, discoveries and other additions | |||||
| Revisions of previous estimates | ( | ||||
| Conversion to proved developed reserves | ( | ||||
| Proved undeveloped reserves, end of period | |||||
Proved undeveloped reserves increased by 24.0 MMBoe during the year ended December 31, 2025 due to the following:
Purchases of minerals in place. The Company added 20.0 MMBoe of PUD reserves from the purchase of minerals in place as a result of the 2025 Williston Basin Acquisition.
Extensions, discoveries and other additions. The Company added 82.9 MMBoe of PUD reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin.
Revisions of previous estimates. The Company had net negative revisions of 16.4 MMBoe primarily attributable to the following:
Decreases:
•31.9 MMBoe primarily associated with timing changes to the Company’s development plan following the 2025 Williston Basin Acquisition and the Arrangement
•2.1 MMBoe associated with lower crude oil and NGL prices and weaker differentials
Increases:
•17.6 MMBoe primarily associated with well performance across the Company’s Williston Basin assets and improved economics from increased lateral lengths
Conversions to proved developed reserves. The Company incurred $520.3 million in capital expenditures to convert 62.5 MMBoe of PUD reserves to proved developed reserves during 2025. The PUD conversions represented 24 % of the Company’s PUD reserves balance at the beginning of 2025.
As of December 31, 2025, the Company expects to develop all of its PUD reserves, including all wells drilled but not yet completed within five years after the initial year booked. Substantially all PUD locations are located on properties where the leases are held by existing production or continuous drilling operations. Approximately 15 % of the Company’s PUD reserves at December 31, 2025 are attributable to wells that have been drilled but not yet completed, and all of the Company’s PUD reserves are within its core acreage in the Williston Basin.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10 % per annum to reflect timing of future cash flows. Production costs do not include DD&A of capitalized acquisition, exploration and development costs.
The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $65.34 per Bbl for crude oil and $3.39 per MMBtu for natural gas, $75.48 per Bbl for crude oil and $2.13 per MMBtu for natural gas and $78.22 per Bbl for crude oil and $2.64 per MMBtu for natural gas for the years ended December 31, 2025, 2024 and 2023, respectively. These prices were adjusted by lease for quality, energy content, transportation fees and marketing differentials. Future operating costs, production taxes and capital costs were based on current costs as of each year end.
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The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2025, 2024 and 2023:
| At December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Future cash inflows | $ | $ | $ | ||||||||||||||
| Future production costs | ( | ( | ( | ||||||||||||||
| Future development costs | ( | ( | ( | ||||||||||||||
| Future income tax expense | ( | ( | ( | ||||||||||||||
| Future net cash flows | |||||||||||||||||
| 10% annual discount for estimated timing of cash flows | ( | ( | ( | ||||||||||||||
| Standardized measure of discounted future net cash flows | $ | $ | $ | ||||||||||||||
The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented:
| 2025 | 2024 | 2023 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| January 1 | $ | $ | $ | ||||||||||||||
| Net changes in prices and production costs | ( | ( | ( | ||||||||||||||
| Net changes in future development costs | ( | ||||||||||||||||
| Sales of crude oil and natural gas, net | ( | ( | ( | ||||||||||||||
| Extensions | |||||||||||||||||
| Purchases of reserves in place | |||||||||||||||||
| Sales of reserves in place | ( | ( | |||||||||||||||
| Revisions of previous quantity estimates | ( | ( | ( | ||||||||||||||
| Previously estimated development costs incurred | |||||||||||||||||
| Accretion of discount | |||||||||||||||||
| Net change in income taxes | ( | ||||||||||||||||
| Changes in timing and other | ( | ||||||||||||||||
| December 31 | $ | $ | $ | ||||||||||||||
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. 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 December 31, 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 December 31, 2025.
Management’s report on internal control over financial reporting
Management, including our CEO and CFO, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As of December 31, 2025, management assessed the effectiveness of our internal control over financial reporting. In making this assessment, management, including our CEO and CFO, used the criteria set forth by the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2025.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this annual report on Form 10-K, has also audited the effectiveness of our internal control over financial reporting as of December 31, 2025 and has issued an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2025. Please see their “Report of Independent Registered Public Accounting Firm” included in “Item 8. Financial Statements and Supplementary Data.”
Changes in internal control over financial reporting
There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
Rule 10b5-1 trading arrangements
During the fiscal quarter ended December 31, 2025, none of our directors or officers (as defined in Rule 16a-1 under the Exchange Act) adopted terminated
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
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PART III
Item 10. Directors, Executive Officers and Corporate Governance
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2026 Annual Meeting of Stockholders.
We have adopted a Code of Business Conduct and Ethics Policy that applies to all of our directors, officers and employees, including our principal executive, principal financial and principal accounting officers, or persons performing similar functions. Our Code of Business Conduct and Ethics Policy can be found on our website located at http://www.chordenergy.com, under “Investors — Corporate Governance.” Any stockholder may request a printed copy of the Code of Business Conduct and Ethics Policy by submitting a written request to our Corporate Secretary.
We intend to disclose future amendments to certain provisions of the Code of Business Conduct and Ethics Policy, and waivers of the Code of Business Conduct and Ethics Policy granted to executive officers and directors, on our website within four business days following the date of the amendment or waiver. The waiver information will remain on our website for at least 12 months after the initial disclosure of such waiver. We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K relating to amendments to or waivers from any provision of the Code of Business Conduct and Ethics Policy applicable to such persons by posting such information on our website.
Item 11. Executive Compensation
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2026 Annual Meeting of Stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2026 Annual Meeting of Stockholders.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2026 Annual Meeting of Stockholders.
Item 14. Principal Accountant Fees and Services
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2026 Annual Meeting of Stockholders.
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PART IV
Item 15. Exhibits, Financial Statement Schedules
a. The following documents are filed as a part of this Annual Report on Form 10-K or incorporated herein by reference:
(1)Financial Statements:
See Item 8. Financial Statements and Supplementary Data.
(2)Financial Statement Schedules:
None.
(3)Exhibits:
The following documents are included as exhibits to this report:
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 | Conformed version of Amended and Restated Certificate of Incorporation of Chord Energy Corporation, as amended by amendments on July 1, 2022 and May 31, 2024 (filed as Exhibit 3.1 to the Company’s Annual Report on Form 10-K on February 27, 2025, and incorporated herein by reference). | |||||||
3.2 | Amended and Restated Certificate of Incorporation of the Company (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference). | |||||||
3.3 | Certificate of First Amendment to the Amended and Restated Certificate of Incorporation of the Company (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K on July 7, 2022 and incorporated by reference herein). | |||||||
3.4 | Certificate of Second Amendment to the Amended and Restated Certificate of Incorporation of Chord Energy Corporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on June 6, 2024, and incorporated herein by reference). | |||||||
3.5 | 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). | |||||||
4.1 | Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A on May 19, 2010, and incorporated herein by reference). | |||||||
4.2 | Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Exchange Act of 1934 (filed as Exhibit 4.1 to the Company’s Report on Form 10-Q on May 4, 2023, and incorporated herein by reference). | |||||||
4.3 | Indenture dated March 13, 2025 by and among Chord Energy Corporation, the Guarantors and Regions Bank, as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K on March 14, 2025, and incorporated herein by reference). | |||||||
4.4 | Indenture dated September 30, 2025 by and among Chord Energy Corporation, the Guarantors and U.S. Bank Trust Company, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Form 8-K on September 30, 2025, and incorporated herein by reference). | |||||||
10.1** | Form of Indemnification Agreement between Chord Energy Corporation (f/k/a Oasis Petroleum Inc.) and each of the directors and executive officers thereof (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference). | |||||||
10.2** | Amended and Restated 2010 Annual Incentive Compensation Plan of Oasis Petroleum Inc. (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q on August 6, 2014, and incorporated herein by reference). | |||||||
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Exhibit No. | Description of Exhibit | |||||||
10.3** | Form of Indemnification Agreement, by and between Oasis Petroleum Inc. and its officers and directors (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference). | |||||||
10.4** | Oasis Petroleum Inc. 2020 Long Term Incentive Plan (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference). | |||||||
10.5** | First Amendment to the Chord Energy Corporation Long Term Incentive Plan (filed as Exhibit 4.3 to the Company's Registration Statement on Form S-8 on September 13, 2024, and incorporated herein by reference). | |||||||
10.6** | Employment Agreement, dated January 18, 2021, by and between Oasis Petroleum Inc. and Michael H. Lou (filed as Exhibit 99.3 to the Company’s Current Report on Form 8-K on January 21, 2021, and incorporated herein by reference). | |||||||
10.7** | Employment Agreement, dated April 13, 2021, by and between Oasis Petroleum Inc. and Daniel E. Brown (filed as Exhibit 99.2 to the Company’s Current Report on Form 8-K on April 19, 2021, and incorporated herein by reference). | |||||||
10.8** | Form of Notice of Grant for Restricted Stock Units (with form of associated Restricted Stock Unit Agreement attached thereto) (filed as Exhibit 99.5 to the Company’s Current Report on Form 8-K on January 21, 2021, and incorporated herein by reference). | |||||||
10.9** | Form of Notice of Grant for Relative Total Shareholder Return Performance Share Units (with form of associated Phantom Share Unit Agreement attached thereto) (filed as Exhibit 99.6 to the Company’s Current Report on Form 8-K/A on February 5, 2021, and incorporated herein by reference). | |||||||
10.10** | Form of Notice of Grant for Absolute Total Shareholder Return Performance Share Units (with form of associated Phantom Share Unit Agreement attached thereto) (filed as Exhibit 99.7 to the Company’s Current Report on Form 8-K/A on February 5, 2021, and incorporated herein by reference). | |||||||
10.11 | Commitment Letter, dated as of May 3, 2021, by and among the Company and JPMorgan Chase Bank, N.A. and Wells Fargo Bank, National Association (filed as Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q on May 6, 2021, and incorporated herein by reference). | |||||||
10.12** | Whiting Petroleum Corporation 2020 Equity Incentive Plan (filed as Exhibit 99.1 to the Company’s Registration Statement on Form S-8 on July 14, 2022, and incorporated herein by reference). | |||||||
10.13** | Oasis Petroleum Inc. 2021 Executive Change in Control and Severance Benefit Plan (filed as Exhibit 10.42 to the Company’s Annual Report on Form 10-K on February 28, 2023, and incorporated herein by reference). | |||||||
10.14** | Chord Energy Corporation Restricted Stock Unit Award Agreement (Non-Employee Director Form) (filed as Exhibit 10.43 to the Company’s Annual Report on Form 10-K on February 28, 2023, and incorporated herein by reference). | |||||||
10.15** | Chord Energy Corporation Restricted Stock Unit Award Agreement (Time Vesting Form) (filed as Exhibit 10.44 to the Company’s Annual Report on Form 10-K on February 28, 2023, and incorporated herein by reference). | |||||||
10.16** | Chord Energy Corporation Executive Severance Plan (filed as Exhibit 10.25 to the Company’s Annual Report on Form 10-K on February 26, 2024, and incorporated herein by reference). | |||||||
10.17** | Form of Notice of Grant for Relative Total Shareholder Return Performance Share Units (with form of associated Performance Share Unit Agreement attached thereto) (filed as Exhibit 10.26 to the Company’s Annual Report on Form 10-K on February 26, 2024, and incorporated herein by reference). | |||||||
10.18** | Form of Notice of Grant for Absolute Total Shareholder Return Performance Share Units (with form of associated Performance Share Unit Agreement attached thereto) (filed as Exhibit 10.27 to the Company’s Annual Report on Form 10-K on February 26, 2024, and incorporated herein by reference). | |||||||
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Exhibit No. | Description of Exhibit | |||||||
10.19** | Letter Agreement, dated as of February 21, 2024, between Chord Energy Corporation and Ian C. Dundas (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on February 26, 2024, and incorporated herein by reference). | |||||||
10.20 | Amended and Restated Credit Agreement, dated as of July 1, 2022, by and among Oasis Petroleum Inc., Oasis Petroleum LLC, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties party thereto. (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on July 7, 2022, and incorporated herein by reference). | |||||||
10.21 | First Amendment to Amended and Restated Credit Agreement, dated as of August 8, 2022, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties thereto (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on August 12, 2022, and incorporated herein by reference). | |||||||
10.22 | Second Amendment to Amended and Restated Credit Agreement, dated October 31, 2022, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties thereto (filed as Exhibit 10.7 to the Company’s Report on Form 10-Q on November 11, 2022, and incorporated herein by reference). | |||||||
10.23 | Third Amendment to Amended and Restated Credit Agreement, dated May 2, 2023, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties thereto (filed as Exhibit 10.1 to the Company’s Report on Form 10-Q on May 4, 2023, and incorporated herein by reference). | |||||||
10.24 | Fourth Amendment to Amended and Restated Credit Agreement, dated October 31, 2023, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties thereto (filed as Exhibit 10.1 to the Company’s Report on Form 10-Q on November 2, 2023, and incorporated herein by reference). | |||||||
10.25 | Fifth Amendment to the Amended and Restated Credit Agreement, dated as of May 31, 2024, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 6, 2024, and incorporated herein by reference). | |||||||
10.26 | Sixth Amendment to the Amended and Restated Credit Agreement, dated as of November 4, 2024, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties party thereto (filed as Exhibit 10.2 to the Company’s Report on Form 10-Q on November 7, 2024, and incorporated herein by reference). | |||||||
10.27 | 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). | |||||||
10.28 | 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). | |||||||
10.29 | Seventh Amendment to the Amended and Restated Credit Agreement, dated as of November 3, 2025, by and among Chord Energy Corporation, Oasis Petroleum North America LLC, Wells Fargo Bank, N.A., and the other parties party thereto (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q on November 6, 2025, and incorporated herein by reference). | |||||||
19.1(a) | ||||||||
21.1(a) | List of Subsidiaries of Chord Energy Corporation. | |||||||
23.1(a) | Consent of PricewaterhouseCoopers LLP. | |||||||
23.2(a) | Consent of Netherland, Sewell & Associates, Inc. | |||||||
31.1(a) | Sarbanes-Oxley Section 302 certification of Principal Executive Officer. | |||||||
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Exhibit No. | Description of Exhibit | |||||||
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. | |||||||
97.1 | Chord Energy Corporation Policy Relating to Recovery of Erroneously Awarded Compensation (filed as Exhibit 97.1 to the Company’s Annual Report on Form 10-K on February 26, 2024, and incorporated herein by reference). | |||||||
99.1(a) | Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers relating to Total Proved Reserves, dated February 10, 2026. | |||||||
| 101(a) | The following financial information from Chord’s Annual Report on Form 10-K for the year ended December 31, 2025, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements. | |||||||
| 104(a) | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | |||||||
__________________
(a)Filed herewith.
(b)Furnished herewith.
**Management contract or compensatory plan or arrangement.
† Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K and will be provided to the SEC upon request.
Item 16. Form 10-K Summary
None.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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: | February 26, 2026 | By: | /s/ Daniel E. Brown | |||||||||||
| Daniel E. Brown President & Chief Executive Officer | ||||||||||||||
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:
| Signature | Title | Date | ||||||||||||
| /s/ Daniel E. Brown | President & Chief Executive Officer and Director (Principal Executive Officer) | February 26, 2026 | ||||||||||||
| Daniel E. Brown | ||||||||||||||
| /s/ Richard N. Robuck | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | February 26, 2026 | ||||||||||||
| Richard N. Robuck | ||||||||||||||
| /s/ Lara J. Kroll | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 26, 2026 | ||||||||||||
| Lara J. Kroll | ||||||||||||||
| /s/ Susan M. Cunningham | Board Chair | February 26, 2026 | ||||||||||||
| Susan M. Cunningham | ||||||||||||||
| /s/ Douglas E. Brooks | Director | February 26, 2026 | ||||||||||||
| Douglas E. Brooks | ||||||||||||||
| /s/ Ian Dundas | Director | February 26, 2026 | ||||||||||||
| Ian Dundas | ||||||||||||||
| /s/ Hilary Foulkes | Director | February 26, 2026 | ||||||||||||
| Hilary Foulkes | ||||||||||||||
| /s/ Kevin S. McCarthy | Director | February 26, 2026 | ||||||||||||
| Kevin S. McCarthy | ||||||||||||||
| /s/ Samantha F. McKinney | Director | February 26, 2026 | ||||||||||||
| Samantha F. McKinney | ||||||||||||||
| /s/ Ward Polzin | Director | February 26, 2026 | ||||||||||||
| Ward Polzin | ||||||||||||||
| /s/ Jeffrey Sheets | Director | February 26, 2026 | ||||||||||||
| Jeffrey Sheets | ||||||||||||||
| /s/ Anne Taylor | Director | February 26, 2026 | ||||||||||||
| Anne Taylor | ||||||||||||||
| /s/ Marguerite N. Woung-Chapman | Director | February 26, 2026 | ||||||||||||
| Marguerite N. Woung-Chapman | ||||||||||||||
128
FAQ
What is Chord Energy (CHRD) focusing on in its core business?
Chord Energy focuses on acquiring, exploring, developing and producing crude oil, NGL and natural gas, primarily in the Williston Basin. It targets the Middle Bakken and Three Forks formations and operates most of its acreage, which supports control over development pace, costs and capital allocation.
How large are Chord Energy’s proved reserves and production as of 2025?
Chord Energy reported 917.5 MMBoe of estimated net proved reserves at December 31, 2025, 69% proved developed and 56% crude oil. Average 2025 daily production was 276,620 net Boepd, reflecting its large operated footprint and the integration of legacy Enerplus volumes after the May 2024 acquisition.
What return of capital strategy does Chord Energy (CHRD) outline?
Chord Energy has a return of capital framework targeting a percentage of adjusted free cash flow based on leverage. It pays a base dividend of $1.30 per share per quarter and operates a $1 billion share repurchase program, with $952.2 million remaining at year-end 2025.
How strong is Chord Energy’s liquidity and balance sheet position?
As of December 31, 2025, Chord Energy reported total liquidity of $2,156.7 million, including $189.5 million of cash and cash equivalents and $1,967.2 million of unused borrowing base capacity under its credit facility. Management emphasizes conservative leverage, risk management and the ability to navigate commodity cycles.
What were Chord Energy’s key 2025 production and cost metrics?
In 2025, Chord Energy produced 100,966 MBoe, including 56,500 MBbl of oil, 19,149 MBbl of NGL and 151,903 MMcf of natural gas. Average lease operating expenses were $9.73 per Boe, gathering, processing and transportation $2.88 per Boe, and production taxes $2.89 per Boe.
What ESG and emissions initiatives does Chord Energy highlight?
Chord Energy emphasizes safety, emissions reduction and community engagement, noting substantial capture of produced natural gas in North Dakota. A cross-functional team uses a Marginal Abatement Cost Curve to prioritize emissions projects, and board-level oversight comes through a Safety and Sustainability Committee established in 2024.
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