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Table of Conten ts

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, 2024
OR

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

Commission file number: 001-34776

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

Delaware |  | 80-0554627
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)
1001 Fannin Street, Suite 1500 |  |
Houston, Texas |  | 77002
(Address of principal executive offices) |  | (Zip Code)

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

Securities Registered Pursuant to Section 12(b) of the Act:

Title of each class |  | Trading Symbol(s) |  | Name of each exchange on which registered
Common Stock, par value $0.01 per share |  | CHRD |  | The Nasdaq Stock Market LLC

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.

Large accelerated filer | ☒ | Accelerated filer | ☐
Non-accelerated filer | ☐ | Smaller reporting company | ☐
|  | Emerging growth company | ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant 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: $10,389,641,105
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 21, 2025: 59,629,556
_______________________________________
Documents Incorporated By Reference:
Portions of the registrant’s definitive proxy statement for its 2025 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2024, are incorporated by reference into Part III of this report for the year ended December 31, 2024.

i

Table of Conten ts
CHORD ENERGY CORPORATION
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2024
TABLE OF CONTENTS

Glossary of Terms | 2
Cautionary Note Regarding Forward-Looking Statements | 5
Risk Factors Summary | 8
| PART I |
Item 1. | Business | 10
Item 1A. | Risk Factors | 35
Item 1B. | Unresolved Staff Comments | 57
Item 1C. | Cybersecurity | 57
Item 2. | Properties | 59
Item 3. | Legal Proceedings | 59
Item 4. | Mine Safety Disclosures | 59
| PART II |
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 60
Item 6. | [Reserved] | 61
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 62
Item 7A. | Quantitative and Qualitative Disclosures about Market Risk | 77
Item 8. | Financial Statements and Supplementary Data | 79
Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 134
Item 9A. | Controls and Procedures | 134
Item 9B. | Other Information | 135
Item 9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 135
| PART III |
Item 10. | Directors, Executive Officers and Corporate Governance | 136
Item 11. | Executive Compensation | 136
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 136
Item 13. | Certain Relationships and Related Transactions, and Director Independence | 136
Item 14. | Principal Accountant Fees and Services | 136
| PART IV |
Item 15. | Exhibits, Financial Statement Schedules | 137
Item 16. | Form 10-K Summary | 141
Signatures | 142

1

Table of Conten ts
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 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 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.
“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 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. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“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”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Annual Report on Form 10-K, regarding our strategic tactics, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this 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. In particular, the factors discussed below and detailed under “Part 1, Item 1A. Risk Factors” could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.
These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Without limiting the generality of the foregoing, certain statements incorporated by reference or included in this Annual Report on Form 10-K constitute forward-looking statements.
Forward-looking statements may include statements about:
•crude oil, NGLs and natural gas realized prices;
•uncertainty regarding the future actions of foreign oil producers and the related impacts such actions have on the balance between the supply of and demand for crude oil, NGLs and natural gas;
•the actions taken by OPEC+ with respect to oil production levels and announcements of potential changes in such levels, including the ability of the OPEC+ countries to agree on and comply with supply limitations;
•war between Russia and Ukraine, military conflicts in the Red Sea Region and war between Hamas and Israel, with the potential for escalation of hostilities across the surrounding countries in the Middle East, and their effect on commodity prices;
•changes in general economic and geopolitical conditions, including in connection with the recent elections in the United States;
•inflation rates and the impact of associated monetary policy responses, including elevated interest rates;
•logistical challenges and supply chain disruptions;
•changes in trade policies and regulations, including the potential for increases or change in duties, current and potentially new tariffs or quotas;
•our business strategy;
•the geographic concentration of our operations;
•estimated future net reserves and present value thereof;
•timing and amount of future production of crude oil, NGLs and natural gas;
•drilling and completion of wells;
•estimated inventory of wells remaining to be drilled and completed;
•costs of exploiting and developing our properties and conducting other operations;
•availability of drilling, completion and production equipment and materials;
•availability of qualified personnel;
•infrastructure for produced and flowback water gathering and disposal;
•gathering, transportation and marketing of crude oil, NGLs and natural gas in the Williston Basin and other regions in the United States;
•the possible shutdown of the Dakota Access Pipeline;
•incurring significant transaction and other costs in connection with the Arrangement (as defined in the “Overview” section of Item 1 below) in excess of those anticipated;
•the ultimate timing, outcome and results of integrating the operations of Chord and Enerplus;
•failure to realize the anticipated benefits or synergies from the Arrangement in the timeframe expected or at all;
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•property acquisitions, including the Arrangement, and divestitures;
•integration and benefits of property acquisitions or the effects of such acquisitions on our cash position and levels of indebtedness, including the Arrangement;
•the amount, nature and timing of capital expenditures;
•availability and terms of capital;
•our financial strategic tactics, budget, projections, execution of business plan and operating results;
•cash flows and liquidity;
•our ability to pursue capital management activities such as share repurchases, paying dividends on our common stock or additional means to return capital to shareholders;
•our ability to utilize net operating loss carryforwards or other tax attributes in future periods;
•our ability to comply with the covenants under our Credit Agreement and other indebtedness;
•operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
•interruptions in service and fluctuations in tariff provisions of third-party connecting pipelines;
•potential effects arising from cybersecurity threats, terrorist attacks and any consequential or other hostilities;
•compliance with, and, changes in environmental, safety and other laws and regulations, including the Inflation Reduction Act of 2022 (the “IRA”);
•execution of our sustainability initiatives;
•effectiveness of risk management activities;
•competition in the oil and gas industry;
•counterparty credit risk;
•incurring environmental liabilities;
•developments in the global economy as well as any public health crisis and resulting demand and supply for crude oil, NGLs and natural gas;
•governmental regulation and the taxation of the oil and gas industry;
•developments in crude oil-producing and natural gas-producing countries;
•technology;
•consumer demand and preferences for, and governmental policies encouraging, fossil fuel alternatives;
•the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;
•uncertainty regarding future operating results;
•our ability to successfully forecast future operating results and manage activity levels with ongoing macroeconomic uncertainty;
•the impact of disruptions in the financial markets, including bank failures and the elevated interest rate environment;
•plans, objectives, expectations and intentions contained in this Annual Report on Form 10-K that are not historical; and
•certain factors discussed elsewhere in this Annual Report on Form 10-K.
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. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report on Form 10-K are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in crude oil, NGL and natural gas prices, climatic and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, inflationary pressures, the proximity to and capacity of transportation facilities
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and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed under “Part I, 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, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
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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 Arrangement
•The synergies attributable to the Arrangement may vary from expectations.
•The market price of our common stock may decline if large amounts of our common stock are sold following the Arrangement.
Risks related to the oil and gas industry and our business
•Global geopolitical tensions may create heightened volatility in 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, NGLs 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 NGLs 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, NGLs 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, NGLs 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 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.
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•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.
•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, NGLs 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, NGLs 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, including the Arrangement, 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.
•We may maintain material balances of cash and cash equivalents for extended periods of time at commercial banks in excess of amounts insured by government agencies such as the FDIC.
•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 exercise of all or any number of outstanding warrants or 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 (together with our consolidated subsidiaries, the “Company,” “Chord,” “we,” “us,” or “our”), a Delaware corporation, 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. Chord, formerly known as Oasis Petroleum Inc. (“Oasis”), was established upon the completion of the merger of equals with Whiting Petroleum Corporation (“Whiting”) on July 1, 2022 (the “Merger”). On May 31, 2024, we completed the arrangement agreement (the “Arrangement Agreement”) with Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”), pursuant to which we acquired Enerplus. Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We are ideally positioned to generate strong free cash flow and enhance return of capital, while being responsible stewards of the communities and environment where we operate.
The results of operations and reserves data presented herein report the results of legacy Oasis prior to the closing of the Merger on July 1, 2022, the results of Chord (including legacy Whiting) from July 1, 2022 through May 30, 2024 and the results of Chord (including legacy Whiting and legacy Enerplus) from May 31, 2024 through December 31, 2024, unless otherwise noted.
In addition, on February 1, 2022, we completed the merger of Oasis Midstream Partners LP (“OMP”) and OMP GP, OMP’s general partner, with and into a subsidiary of Crestwood Equity Partners LP (“Crestwood”) (the “OMP Merger”). The OMP Merger qualified for reporting as a discontinued operation. Accordingly, the results of operations of OMP have been classified as discontinued operations in the Consolidated Statement of Operations for the period from January 1, 2022 to February 1, 2022. Additionally, effective July 1, 2022, we elected to report crude oil, NGLs and natural gas separately on a three-stream basis. Accordingly, our reported production volumes subsequent to July 1, 2022 are reported on a three-stream basis, while periods prior to July 1, 2022 were reported on a two-stream basis with NGLs combined with the natural gas stream. This change impacts comparability with prior periods.
As of December 31, 2024, we had 1,254,860 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, 2024, we had 4,824 gross (3,752.2 net) operated producing wells. Our working interest for producing wells averaged 78% in the wells we operate. During the year ended December 31, 2024, we had average daily production of 232,737 net Boepd. As of December 31, 2024, Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, estimated our net proved reserves to be 883.0 MMBoe, of which 70% were classified as proved developed and 57% 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 our capital allocation, while evaluating our performance and focusing on continuous improvement. We have established a rigorous 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. Since our inaugural dividend in February 2021, we have declared cash dividends to our stockholders of $55.99 per share 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. 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 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 $750 million share repurchase program, which the Board of Directors authorized during the third quarter of 2024.
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As of December 31, 2024, we had $592.6 million remaining under this share repurchase program. We plan to return capital through a mix of base and variable dividend payouts, supplemented by opportunistic share repurchases.
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 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)

The variable dividend will be calculated using the framework noted above to establish the minimum percentage of free cash flow to be returned less share repurchases completed during the quarter and the base dividend.
•Financial strength. Our management team is focused on maintaining a solid risk management process to preserve our 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, 2024, we had $1.1 billion of liquidity available, including $37.0 million of cash and cash equivalents and $1.0 billion 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”). During the first quarter of 2025, we expect to have approximately $1.6 billion of liquidity available after taking into account the increase in the aggregate amount of elected commitments to $2.0 billion.
•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 significant 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 best practices aligned with 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
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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.
From a safety standpoint, our corporate, field and environmental, health and safety teams are enhancing best practices and training to minimize the likelihood and severity of safety incidents among employees and contractors. We owe it to our employees, our service providers and stakeholders to do all we can to create an environment where everyone on a Chord location is safe. We hold ourselves 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 remain focused on reducing Scope 1 GHG emissions, and in particular methane emissions. We are establishing a carbon management program that includes a team focused on gas capture, flare management and replacement or retrofit of gas pneumatics. We continue to work 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, 2024, 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 diverse and experienced energy industry professionals. Our Board of Directors is 82% independent and 45% of our directors are women. As part of our ongoing effort to enhance our ESG practices, the Board of Directors has 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 2025 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, 2024, we had 1,254,860 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin. Approximately all of our 1,254,860 net leasehold acres was held by production, and 60% of our 839.1 MMBoe estimated net proved reserves as of December 31, 2024 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, 2024, 91% of our estimated net proved reserves were attributable to properties that we operate. In 2025, we plan to TIL approximately 130 to 150 gross operated wells with an average working interest of approximately 78%. 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.
•Strong balance sheet. We believe our strong balance sheet will allow 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.
•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 nearly 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,
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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, 2024, 2023 and 2022 are based on reports independently prepared by NSAI, our independent reserve engineers. NSAI evaluated 100% of the reserves and discounted values at December 31, 2024, 2023 and 2022 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 24.—Supplemental Oil and Gas Reserve Information — Unaudited” for additional information about our estimated net proved reserves.
The following table summarizes our estimated net proved reserves based upon the SEC Price:

| At December 31,
| 2024 |  | 2023 |  | 2022
Estimated proved reserves: |  |  |  |  |
Crude oil (MMBbls) | 503.4 |  |  | 368.4 |  |  | 381.3 |
NGLs (MMBbls) | 167.2 |  |  | 138.2 |  |  | 138.5 |
Natural gas (Bcf) | 1,274.7 |  |  | 777.9 |  |  | 814.9 |
Total estimated proved reserves (MMBoe) | 883.0 |  |  | 636.2 |  |  | 655.6 |
Percent crude oil | 57 | % |  | 58 | % |  | 58 | %
Estimated proved developed reserves: |  |  |  |  |
Crude oil (MMBbls) | 317.7 |  |  | 241.4 |  |  | 272.5 |
NGLs (MMBbls) | 125.8 |  |  | 105.7 |  |  | 115.2 |
Natural gas (Bcf) | 1,053.3 |  |  | 640.2 |  |  | 689.7 |
Total estimated proved developed reserves (MMBoe) | 619.1 |  |  | 453.8 |  |  | 502.7 |
Percent proved developed | 70 | % |  | 71 | % |  | 77 | %
Estimated proved undeveloped reserves: |  |  |  |  |
Crude oil (MMBbls) | 185.7 |  |  | 127.0 |  |  | 108.8 |
NGLs (MMBbls) | 41.4 |  |  | 32.5 |  |  | 23.2 |
Natural gas (Bcf) | 221.4 |  |  | 137.8 |  |  | 125.3 |
Total estimated proved undeveloped reserves (MMBoe) | 264.0 |  |  | 182.4 |  |  | 152.9 |
Standardized Measure (GAAP) (in millions)(1) | $ | 8,354.2 |  |  | $ | 6,990.6 |  |  | $ | 11,494.5 |
PV-10 (Non-GAAP) (in millions)(2): |  |  |  |  |
Proved developed PV-10 | $ | 7,519.9 |  |  | $ | 6,572.4 |  |  | $ | 11,460.3 |
Proved undeveloped PV-10 | 2,742.7 |  |  | 1,956.1 |  |  | 2,991.9 |
Total PV-10 (Non-GAAP) | $ | 10,262.6 |  |  | $ | 8,528.5 |  |  | $ | 14,452.2 |

__________________
(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.
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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.
The following table provides a reconciliation of Standardized Measure to PV-10:

| At December 31,
| 2024 |  | 2023 |  | 2022
|  |  | (In millions) |  |
Standardized Measure of discounted future net cash flows | $ | 8,354.2 |  |  | $ | 6,990.6 |  |  | $ | 11,494.5 |
Add: present value of future income taxes discounted at 10% | 1,908.4 |  |  | 1,537.9 |  |  | 2,957.7 |
PV-10 | $ | 10,262.6 |  |  | $ | 8,528.5 |  |  | $ | 14,452.2 |

Independent petroleum engineers
Our estimated net proved reserves and PV-10 at December 31, 2024, 2023 and 2022 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.
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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 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 and geoscience professionals 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 14 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, NGLs and natural gas, which are commodities. The prices that we receive for the crude oil, NGLs 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, NGLs 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.
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The Merger and Arrangement were accounted for as of July 1, 2022 and May 31, 2024, respectively. Accordingly, the results of operations presented herein report the results of legacy Oasis prior to the closing of the Merger on July 1, 2022, the results of Chord (including legacy Whiting) from July 1, 2022 through May 30, 2024 and the results of Chord (including legacy Whiting and legacy Enerplus) from May 31, 2024 through December 31, 2024. 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.”

| Year Ended December 31, |  |  |
| 2024 |  | 2023 |  | 2022 |  |
Net production volumes: |  |  |  |  |  |  |  |
Crude oil (MBbls) | 48,479 |  |  | 36,427 |  |  | 25,457 |  |  |  |
NGLs (MBbls)(1) | 16,338 |  |  | 13,047 |  |  | 7,026 |  |  |  |
Natural gas (MMcf)(1) | 122,193 |  |  | 82,953 |  |  | 67,428 |  |  |  |
Oil equivalents (MBoe) | 85,182 |  |  | 63,300 |  |  | 43,722 |  |  |  |
Average daily production (Boepd) | 232,737 |  |  | 173,425 |  |  | 119,785 |  |  |  |
Average sales prices: |  |  |  |  |  |  |  |
Crude oil, without derivative settlements (per Bbl) | $ | 73.67 |  |  | $ | 77.85 |  |  | $ | 92.98 |  |  |  |
Crude oil, with derivative settlements(2) (per Bbl) | 73.69 |  |  | 70.92 |  |  | 73.50 |  |  |  |
NGL, without derivative settlements(1) (per Bbl) | 9.92 |  |  | 13.62 |  |  | 26.23 |  |  |  |
NGL, with derivative settlements(1)(2) (per Bbl) | 9.92 |  |  | 13.84 |  |  | 26.94 |  |  |  |
Natural gas, without derivative settlements(1) (per Mcf) | 0.84 |  |  | 1.43 |  |  | 6.30 |  |  |  |
Natural gas, with derivative settlements(1)(2) (per Mcf) | 0.84 |  |  | 1.35 |  |  | 5.26 |  |  |  |
Average costs (per Boe): |  |  |  |  |  |  |  |
Lease operating expenses | 9.68 |  |  | 10.41 |  |  | 10.14 |  |  |  |
Gathering, processing and transportation expenses | 3.14 |  |  | 2.85 |  |  | 3.24 |  |  |  |
Production taxes | 3.91 |  |  | 4.11 |  |  | 5.25 |  |  |  |

__________________
(1)For periods prior to July 1, 2022, we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when presenting our production data and average sales prices. As of July 1, 2022, NGLs were reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented.
(2)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, 2024. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

| Gross |  | Net
Developed acres | 2,338,431 |  |  | 1,211,829 |
Undeveloped acres | 163,750 |  |  | 75,809 |
Total acres | 2,502,181 |  |  | 1,287,638 |

Our total net leasehold position shown in the table above includes 1,254,860 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin. At December 31, 2024, our total acreage that is held by production increased to 1,283,462 net acres from 1,025,375 net acres at December 31, 2023.
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The following table sets forth the number of gross and net undeveloped acres as of December 31, 2024 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, |  |  |
2025 | 1,059 |  |  | 583 |
2026 | 1,323 |  |  | 1,086 |
2027 | 477 |  |  | 275 |

We have not assigned any PUD reserves to locations scheduled to be drilled after lease expiration.
Productive wells
As of December 31, 2024, we had 9,011 (4,174.2 net) total gross productive wells, of which 4,824 gross (3,752.2 net) productive wells were operated by us. Substantially all of our productive wells as of December 31, 2024 were horizontal wells.
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,
| 2024 |  | 2023 |  | 2022
| Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net
Development wells: |  |  |  |  |  |  |  |  |  |  |
Oil | 189 |  |  | 103.9 |  |  | 111 |  |  | 66.9 |  |  | 67 |  |  | 41.3 |
Gas | 2 |  |  | 0.1 |  |  | — |  |  | — |  |  | — |  |  | — |
Dry | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Total development wells | 191 |  |  | 104.0 |  |  | 111 |  |  | 66.9 |  |  | 67 |  |  | 41.3 |

During the years ended December 31, 2024, 2023 and 2022, there were no exploratory wells completed.
As of December 31, 2024, we had 98 gross (74.5 net) wells in the process of being drilled or completed, which included 86 gross operated wells waiting on completion and 5 gross non-operated wells drilling or completing.
As of December 31, 2024, we had five operated rigs running, and we expect to run four to five operated rigs during the majority of 2025.
Description of properties
As of December 31, 2024, 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 one of the top producers 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. 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, 2024, 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
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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.”
Delivery commitments
As of December 31, 2024, we had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 46.1 MMBbl of crude oil, 7.5 MMBbl of NGLs, 448.8 Bcf of natural gas and 0.1 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, NGLs and natural gas from third parties to satisfy our minimum volume commitments.
Midstream Transactions
On February 1, 2022, we completed the OMP Merger and, in exchange, received $160.0 million in cash and 20,985,668 common units representing limited partner interests of Crestwood. Prior to the completion of the OMP Merger, OMP was a consolidated subsidiary, and we owned approximately 70% of OMP’s issued and outstanding common units. We had provided OMP acreage dedications pursuant to several long-term, fee-based contractual arrangements for midstream services, including (i) natural gas gathering, compression, processing and gas lift supply services, (ii) crude oil gathering, terminal and transportation services, (iii) produced and flowback water gathering and disposal services and (iv) freshwater distribution services. These contracts were assigned to Crestwood upon completion of the OMP Merger. On November 3, 2023, Energy Transfer LP (“Energy Transfer”) completed a merger with Crestwood and, as a result, Energy Transfer now owns and operates the legacy Crestwood assets.
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 oil, NGLs 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 oil, NGLs 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, NGLs 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
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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.”
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 federal, tribal, regional, state and local laws and regulations. In particular, crude oil and natural gas production is, or has been, subject to price controls, taxes and numerous laws and regulations. All of the jurisdictions in which we own or operate properties for crude oil and natural gas production have statutory provisions regulating the exploration for and production of crude oil and natural gas or the gathering, transportation and processing of those commodities, including provisions related to permits for the drilling of wells or processing of natural gas, bonding requirements to drill or operate producing or injection wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled or processing plants are constructed, sourcing and disposal of water used in the drilling and completion process and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, the siting of processing plants, disposal wells and gathering or transportation lines, and the unitization or pooling of crude oil and natural gas wells, as well as regulations that generally discourage the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the 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. Additionally, environmental incidents such as spills or other releases may occur or past non-compliance with environmental laws or regulations may be discovered, any of which may require us to install new or modified controls on equipment or processes, incur longer permitting timelines and incur increased capital or operating expenditures, the costs of which may be material. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”), the U.S. Environmental Protection Agency (“EPA”), other federal agencies and the courts. We cannot predict when or whether any such proposals may be finalized and become effective.
Regulation of transportation and sales of crude oil
Sales of crude oil and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of crude oil by common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate crude oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for crude oil pipelines that allows a pipeline to increase its rates annually up to prescribed ceiling levels that are tied to changes in the Producer Price Index (“PPI”), without making a cost of service filing. Many existing pipelines utilize the FERC crude oil index to change transportation rates annually every July 1. Every five years, FERC reviews the
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appropriateness of the index level in relation to changes in industry costs. On December 17, 2020, FERC established a new price index for the five-year period commencing July 1, 2021 and ending June 30, 2026, in which common carriers charging indexed rates were permitted to adjust their indexed ceiling annually by PPI plus 0.78% (“December 2020 Order”). The Commission received requests for rehearing of the December 2020 Order and on January 20, 2022, in Docket No. RM20-14, granted rehearing and modified the oil index (“January 2022 Order”). Specifically, for the five-year period commencing July 1, 2021 and ending June 30, 2026, common carriers charging indexed rates were permitted to adjust their indexed ceilings annually by PPI minus 0.21%. FERC directed oil pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022 based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022.
On February 22, 2022, several shippers filed for a Request for Clarification, or in the alternative, Rehearing of the January 2022 Order, which was denied by FERC on May 6, 2022 (“May 2022 Order”).
N umerous parties filed petitions for review of the January 2022 Order and May 2022 Order in the D.C. Circuit and the 5 th Circuit. These petitions were ultimately resolved on July 26, 2024 in Liquid Energy Pipeline Ass’n v. FERC, 109 F.4 th 543 (D.C. Cir. 2024) (“LEPA v. FERC”). LEPA v. FERC vacated the January 2022 Order on the basis that FERC had failed to comply with notice-and-comment rulemaking requirements before issuing the January 2022 Order and dismissed other petitions for review as moot. On September 17, 2024, FERC issued an order reinstating the index level of PPI plus 0.78% previously established in the December 2020 Order, directing pipelines to make an informational filing showing the recomputed ceiling levels, and allowing pipelines to file prospective rate increases based on the recomputed ceiling levels. Shippers have submitted multiple pleadings in response to FERC’s September 17, 2024 order, which include requests that FERC: establish a new proceeding to remedy the procedural defects identified in LEPA v. FERC and re-institute the PPI minus 0.21% index level; direct oil pipelines not to issue invoices reflecting the PPI plus 0.78% indexed ceilings for periods prior to September 17, 2024; and clarify that rates calculated using the PPI plus 0.78% index level remain subject to refund, all of which remain pending before FERC.
Intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of crude oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Further, interstate and intrastate common carrier crude oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When crude oil pipelines operate at full capacity, access is generally governed by proration provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to crude oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
We sell a significant amount of our crude oil production through gathering systems connected to rail facilities. Due to several crude oil train derailments in the past 15 years, transportation safety regulators in the United States and Canada have examined the adequacy of transporting crude oil by rail, with an emphasis on the safe transport of Bakken crude oil by rail, following findings by the U.S. Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that Bakken crude oil tends to be more volatile and flammable than certain other crude oils, and thus poses an increased risk for a significant accident.
Since 2011, all new railroad tank cars built to transport crude oil or other petroleum type fluids, including ethanol, have been built to more stringent safety standards. In 2015, PHMSA adopted a final rule that includes, among other things, additional requirements to enhance tank car standards for certain trains carrying crude oil and ethanol, a classification and testing program for crude oil, new operational protocols for trains transporting large volumes of flammable liquids and a requirement that older DOT-111 tank cars be phased out beginning in late 2017 if they are not already retrofitted to comply with new tank car design standards. In 2016, PHMSA released a final rule mandating a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids, including crude oil and ethanol, between 2018 and 2029, and in early 2019, PHMSA published a final rule requiring railroads to develop and submit comprehensive oil spill response plans for specific route segments traveled by a single train carrying 20 or more loaded tanks of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train. Additionally, the 2019 final rule requires railroads to establish geographic response zones along various rail routes, ensure that both personnel and equipment are staged and prepared to respond in the event of an accident, and share information about high-hazard flammable train operations with state and tribal emergency response commissions. In 2024, PHMSA issued a final rule requiring railroads to collect and provide to first responders, emergency response officials, and law enforcement real-time information regarding the transportation of hazardous materials on a train beginning in 2025 and 2026.
In addition, a number of states proposed or enacted laws in recent years that encourage safer rail operations, urge the federal government to strengthen requirements for these operations or otherwise seek to impose more stringent standards on rail transport of crude oil. For example, in the absence of a current federal standard on the vapor pressure of crude oil transported by
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rail, the State of Washington passed a law that became effective in July 2019, prohibiting the loading or unloading of crude oil from a rail car in the state unless the crude oil vapor pressure is lower than 9 pounds per square inch. In response, the States of North Dakota and Montana filed a preemption application with PHMSA in July 2019 and in May 2020, PHMSA published a Notice of Administrative Determination of Preemption, finding that the federal Hazardous Material Transportation Law preempts Washington State’s vapor pressure limit.
One or more of these federal or state safety improvements or updates relating to rail tank cars and rail crude oil-related operational practices imposed by PHMSA since 2015 could drive up the cost of transportation and lead to shortages in availability of tank cars. We do not currently own or operate rail transportation facilities or rail cars. However, we cannot assure that costs incurred by the railroad industry to comply with these enhanced standards resulting from PHMSA’s final rules or that restrictions on rail transport of crude oil due to state crude oil volatility standards, if not preempted by PHMSA, will not increase our costs of doing business or limit our ability to transport and sell our crude oil at favorable prices, the consequences of which could be material to our business, financial condition or results of operations. However, we believe that any such consequences would not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
More stringent regulatory initiatives have likewise been pursued in Canada to assess and address risks from the transport of crude oil by rail. For example, since 2014, Transport Canada has issued requirements prohibiting crude oil shippers from using certain DOT-111 tank cars and imposed a phase out schedule for other tank cars that do not meet specified safety requirements, imposed a 50 mile per hour speed limit on trains carrying hazardous materials and required all crude oil shipments in Canada to have an emergency response plan. Also, at or near the same time that PHMSA released its 2015 rule, Canada’s Minister of Transport announced Canada’s new tank car standards, which largely align with the requirements in the PHMSA rule. Likewise, Transport Canada’s rail car retrofitting and phase out timeline largely aligned with the requirements in the PHMSA rule and issued retrofitting and phase out timelines similar to those introduced by PHMSA. Transport Canada also introduced new requirements that railways carry minimum levels of insurance depending on the quantity of crude oil or dangerous goods that they transport as well as a final report recommending additional practices for the transportation of dangerous goods.
Historically, our hazardous materials transportation compliance costs have not had a material adverse effect on our results of operations; however, any new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement regarding hazardous material transportation may occur in the future, which could directly and indirectly increase our operation, compliance and transportation costs and lead to shortages in availability of tank cars. We cannot assure that costs incurred to comply with PHMSA and Transport Canada standards and regulations emerging from these existing and any future rulemakings will not be material to our business, financial condition or results of operations. In addition, any derailment of crude oil from the Williston Basin involving crude oil that we have sold or are shipping may result in claims being brought against us that may involve significant liabilities. Although we believe that we are adequately insured against such events, we cannot assure you that our insurance policies will cover the entirety of any damages that may arise from such an event. Nonetheless, we believe that any such consequences would not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Regulation of transportation and sales of natural gas
Historically, the transportation and sale for resale of natural gas in interstate commerce has been 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. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.
FERC regulates interstate natural gas 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. Since 1985, FERC has endeavored through a series of orders to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. We cannot provide any assurance that the less stringent regulatory approach established by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, 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”). Please see below the discussion of “Other federal laws and regulations affecting our industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities. Please see below the discussion of “Other federal laws and regulations affecting our industry—FERC market transparency rules.”
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Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters. 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.
Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, 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.
Regulation of production
The production of crude oil, NGLs and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local 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 or to have reductions in well spacing. Moreover, both states impose a production or severance tax with respect to the production and sale of crude oil, NGLs and natural gas within their jurisdictions.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Other federal laws and regulations affecting our industry
Energy Policy Act of 2005
The Energy Policy Act of 2005 (“EPAct 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,584,648 per day, adjusted annually for inflation, for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,584,648 per violation per day, adjusted annually for inflation. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. FERC’s regulations implementing EPAct 2005 make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) engage in any act, practice or course of business that operates as a fraud or deceit upon any person. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704, as described below. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
FERC market transparency rules
Under FERC’s regulations, Order No. 704 and related subsequent orders, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.
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Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the FTC issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale from: (a) knowingly engaging in any act, practice or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person; or (b) intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1,584,648 per day per violation, adjusted annually for inflation, in addition to any applicable penalty under the Federal Trade Commission Act.
North Dakota Industrial Commission crude oil and natural gas rules
The North Dakota Industrial Commission (“NDIC”) regulates the drilling and production of crude oil and natural gas in North Dakota. Beginning in 2012 and continuing thereafter, the NDIC has adopted more stringent rules relating to production activities, including with respect to financial assurance for wells and underground gathering pipelines, waste discharges and storage, hydraulic fracturing and associated public disclosure on the FracFocus chemical disclosure registry, site construction, underground gathering pipelines and spill containment, which new requirements are now in effect. These requirements could increase or may increase the well costs incurred by us and similarly situated crude oil and natural gas E&P operators, and we expect to continue to incur these increased costs as well as any added costs arising from new NDIC legal requirements laws and regulations applicable to the drilling and production of crude oil and natural gas that may be issued in the future.
Furthermore, the NDIC regulates natural gas flaring and over the past decade has issued orders limiting flaring emissions. These requirements were further revised in 2020. Please see below the discussion of “Environmental protection and natural gas flaring initiatives” for more information on the natural gas flaring program. In addition, the NDIC has adopted rules that improve the safety of transporting Bakken crude oil by establishing operating standards for conditioning equipment to properly separate production fluids, limits to the vapor pressure of produced crude oil, and parameters for temperatures and pressures associated with the production equipment.
Pipeline safety regulation
Certain of our pipelines are subject to regulation by PHMSA under the Hazardous Liquids Pipeline Safety Act (“HLPSA”) with respect to crude oil and condensates and the Natural Gas Pipeline Safety Act (“NGPSA”) with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction, operation, replacement and management of hazardous liquid and gas pipeline facilities. These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation pipeline operators to develop and implement integrity management programs to comprehensively evaluate certain relatively higher risk areas, known as high consequence areas (“HCA”) and moderate consequence areas (“MCA”) along pipelines and take additional safety measures to protect people and property in these areas. The HCAs for natural gas pipelines are predicated on high-population areas (which, for natural gas transmission pipelines, may include Class 3 and Class 4 areas) whereas HCAs for crude oil, NGL and condensate pipelines are based on high-population areas, certain drinking water sources and unusually sensitive ecological areas. An MCA is attributable to natural gas pipelines and is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet the definition of a natural gas pipeline HCA. In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines, which regulations may impose more stringent requirements than found under federal law. Historically, our pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse effect on our business and operating results. New pipeline safety laws or regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational restrictions, delays or cancellations.
Legislation since 2010 has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline safety requirements on pipeline operators. In particular, the HLPSA and NGPSA were amended by the Pipeline, Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety (“PIPES”) Act of 2016 and, most recently, the PIPES Act of 2020. Each of these laws imposed increased pipeline safety obligations on pipeline operators. The 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. The PIPES Act of 2020 reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory initiatives, including obligating operators of nonrural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations.
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Following the adoption of the 2011 Pipeline Safety Act, the PIPES Act of 2016 and the PIPES Act of 2020, PHMSA issued a series of significant rulemakings imposing more stringent regulations on certain types of pipelines. In October 2019, PHMSA published a final rule imposing numerous requirements on onshore gas transmission pipelines relating to maximum allowable operating pressure reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage found in MCAs and non-HCA Class 3 and Class 4 areas by 2033, and the consideration of seismicity as a risk factor in integrity management. PHMSA published a second final rule in October 2019 for hazardous liquid transmission and gathering pipelines that significantly extends and expands the reach of certain of its integrity management requirements, requires accommodation of in-line inspection tools by 2039 unless the pipeline cannot be modified to permit such accommodation, increased annual, accident and safety-related conditional reporting requirements, and expanded the use of leak detection systems beyond HCAs. PHMSA also published final rules during February and July 2020 that amended the minimum safety issues related to natural gas storage facilities, including wells, wellbore tubing and casing, as well as added applicable reporting requirements. In November 2021, PHMSA issued a final rule that imposed safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, imposed criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and applied a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. In August 2022, PHMSA issued a final rule that established more stringent standards for management of change, integrity management, corrosion control, and inspection criteria to help identify and mitigate potential failures and worst-case scenarios, although certain portions of this rule were vacated by the D.C. Circuit in August 2024. Separately, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities. PHMSA, together with state regulators, inspected these plans throughout 2022. In 2023, PHMSA published a notice of proposed rulemaking for regulations that would enhance leak detection and repair requirements for gas distribution, transmission and gathering lines. PHMSA issued the final rule in early January 2025, but it has not been published in the Federal Register and has not taken effect, pending review by the new Trump Administration. PHMSA is also developing new requirements for inspection and maintenance obligations when idled pipelines are returned to service and for pipeline class location changes.
These regulatory actions or any future regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs or other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. In the absence of PHMSA pursuing any legal requirements, state agencies, to the extent authorized, may pursue state standards, including standards for rural gathering lines.
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. These laws and regulations may, among other things, require the acquisition of permits to conduct drilling; govern the amounts and types of substances that may be released into the environment; limit or prohibit construction or drilling activities in environmentally-sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered species; require investigatory and remedial actions to mitigate pollution conditions; impose obligations to reclaim and abandon well sites and pits; and impose specific criteria addressing worker protection. Certain environmental laws impose strict, joint and several liability for costs required to remediate and restore sites where hydrocarbons, materials or wastes have been stored or released. 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 also 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 consequently affects profitability.
The trend in environmental regulation is to place more restrictions and limitations on, and enhanced disclosures of, activities that may affect the environment, and thus, 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 environmental 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
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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 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. Under CERCLA, these “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. 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 neighboring landowners and other 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. RCRA imposes 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, 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 for numerous years 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 (including wastes disposed of or released by prior owners or operators), 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 from many sources 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 certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in 2015, the EPA under the Obama Administration issued a final rule under the CAA, making the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone more stringent. Since that time, the EPA has issued area designations with respect to ground-level ozone, and, on December 31, 2020, published a notice of final action to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups have filed litigation over this December 2020 decision, and in October 2021 the EPA announced plans to reconsider the December 2020 decision. In August 2023, the EPA announced a new review of ozone NAAQS which will incorporate the ongoing reconsideration of the December 2020 decision. If the EPA were to adopt more stringent NAAQS for ground-level ozone as a result of its new review and ongoing reconsideration of the December 2020 decision, state implementation of the
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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 one or more developments could adversely impact our business.
Environmental protection and natural gas flaring initiatives
We attempt to conduct our operations in a manner that protects the health, safety and welfare of the public, our employees and the environment. 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.
We believe that one of the leading causes of natural gas flaring from the Bakken and Three Forks formations is a historical lack of sufficient natural gas gathering infrastructure in the Williston Basin, which translates into the inability of operators to promptly connect their wells to natural gas processing and gathering infrastructure. External factors impacting such inability that are out of the control of the operator include, for example, the granting of right-of-way access by land owners, investment from third parties in the development of gas gathering systems and processing facilities, and the development and adoption of regulations. We have allocated significant resources to connect our wells to natural gas infrastructure. The substantial majority of our operated wells are connected to gas gathering systems, which reduces our flared volumes of natural gas.
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, 2024, 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, 2024, 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 from certain sources. Moreover, the previous Biden Administration highlighted addressing climate change as a priority, issued several Executive Orders related to climate change, recommitted the United States to long-term international goals to reduce emissions and required the incorporation of climate change considerations into executive agency decision-making. As a result, 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 new 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 new 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.
In recent years the U.S. Congress has considered legislation to reduce emissions of GHGs, including methane. While it presently appears unlikely that comprehensive climate change legislation will be passed by Congress in the near future, energy legislation and other regulatory initiatives have been and continue to be proposed that are relevant to GHG emissions issues. For example, the IRA, which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on methane emissions from certain facilities, was signed into law in August 2022. 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. The provision applies to methane leaks from certain oil and gas facilities and begins at $900 per metric ton of leaked methane in 2024 and rises to $1,200 per metric ton in 2025 and $1,500 per metric ton in 2026. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry. Additionally, in September 2023, the previous Biden Administration directed federal agencies to consider the Social Cost of GHGs (“SC-GHGs”) (formerly known as the Social Cost of Carbon (“SCC”)) metric in budgeting, procurement and other agency decisions, including in environmental reviews, where appropriate. However, the new Trump Administration has rescinded many executive orders issued under the Biden Administration concerning climate change initiatives. Several states, though none in the areas where we
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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. The EPA also works together with the Department of Transportation (“DOT”) to implement GHG emissions limits on vehicles manufactured for operation in the United States.
In recent years, there has been considerable focus on the regulation of methane emissions from the oil and gas sector. During 2020, the first Trump Administration finalized two sets of amendments to the 2016 Subpart OOOO performance standards for methane, volatile organic compound (“VOC”) and sulfur dioxide emissions to lessen the impact of those standards and remove the transmission and storage segments from the source category for certain regulations. The first, known as the “2020 Technical Rule,” reduced the 2016 rule’s fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes. The second, known as the “2020 Policy Rule,” rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments. However, shortly after taking office in 2021, President Biden issued an executive order calling on the EPA to revisit federal regulations regarding methane and establish new or more stringent standards for existing or new sources in the oil and gas sector, including the transmission and storage segments. The U.S. Congress also passed, and President Biden signed into law, a resolution under the Congressional Review Act (“CRA”) that revoked the 2020 Policy Rule. The CRA resolution did not address the 2020 Technical Rule. In response to President Biden’s executive order, the EPA proposed and finalized more stringent methane rules for new, modified and reconstructed upstream and midstream facilities under New Source Performance Standards (“NSPS”) Subpart OOOOb, as well as, for the first time ever, standards for existing sources under NSPS Subpart OOOOc in December 2023. The final rules expand the scope of regulated oil and gas sources beyond those currently regulated under the existing NSPS Subpart OOOOa. Under the final rules, states have two years to prepare and submit plans to impose methane and VOC emissions controls for existing sources. The presumptive standards established under the final rules are generally the same 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 parts of OOOOb that became effective during 2024 and parts of the rule that phase in over time. 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 finalized and proposed regulatory requirements, any such requirements have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows. We also note that the regulatory activities discussed above are subject to ongoing political debate and could be subject to major modification, especially given the new administration as a result of the outcome of the 2024 election cycle.
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. President Biden recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. Various U.S. states and local governments have also publicly committed to furthering the goals of the Paris Agreement. Additionally, at the UN Climate Change Conference of Parties (“COP26”), held in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. COP26 concluded with the finalization of the Glasgow Climate Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. These goals were reaffirmed at the November 2022 Conference of Parties (“COP27”), at which the U.S. also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. In December 2023, the United Arab Emirates hosted the 28th session of the Conference of the Parties (“COP28”) where parties signed onto an agreement to transition “away from fossil fuels in energy systems in a just, orderly and equitable manner” and increase renewable energy capacity so as to achieve net zero emissions by 2050, although no timeline for doing so was set. The full impact of these actions, and any legislation or regulation promulgated to fulfill the United States’ commitments thereunder, is uncertain at this time, given President Trump’s recent decision to again withdraw the
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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.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States. President Biden has issued several executive orders focused on addressing climate change, including items that may impact costs to produce, or demand for, oil and gas. Additionally, in November 2021, the previous Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency, decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels, eliminating subsidies provided to the fossil fuel industry, reducing non-carbon dioxide GHG emissions and increasing the emphasis on climate-related risks across government agencies and economic sectors. The former Biden Administration also called for revisions and restrictions to the leasing and permitting programs for oil and gas development on federal lands and, for a time, suspended federal oil and gas leasing activities. The Department of Interior’s comprehensive review of the federal leasing program resulted in a reduction in the volume of onshore land held for lease, increased minimum bid requirements, and an increased royalty rate. Any of these actions or 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 new Trump Administration 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 fossil fuel sector. In January 2023, the Federal Reserve published instructions for its pilot climate scenario analysis exercise, which the six largest U.S. banks were required to complete by July 31, 2023. The SEC has 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 that are currently proceeding before the U.S. Court of Appeals for the Eighth Circuit. Enhanced climate disclosure requirements could result in additional legal and accounting costs and accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors. States may also pass laws imposing more expansive disclosure requirements for climate-related risks. For example, the State of California has enacted legislation that will require large U.S. companies doing business in California to make broad-based climate-related disclosures, and other states are also considering similar measures. Separately, the SEC released its final rule on climate-change related disclosures in public filings on March 6, 2024, 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 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 effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events, as well as chronic shifts in temperature and precipitation patterns. These climatic developments have the potential to
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cause physical damage to our assets or disrupt our supply chains and thus could have an adverse effect on our exploration and production operations through, for example, water use curtailments in response to extended drought conditions. Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or its production. While our consideration of changing climatic conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
Water discharges
The Federal Water Pollution Control Act (the “CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The scope of regulated waters has been subject to substantial controversy. In 2015 and 2020, respectively, the former Obama and Trump Administrations each published final rules attempting to define the federal jurisdictional reach over waters of the United States (“WOTUS”). However, both of these rulemakings were subject to legal challenge. In January 2023, the EPA and the U.S. Army Corps of Engineers (the “Corps”) published a final rule based on the pre-2015 definition of WOTUS, with updates to incorporate existing Supreme Court decisions and regulatory guidance. However, the January 2023 rule was challenged and is currently enjoined in 27 states. In May 2023, the U.S. Supreme Court released its opinion in Sackett v. EPA, which involved issues relating to the legal tests used to determine whether wetlands qualify as WOTUS. The Sackett decision invalidated certain parts of the January 2023 rule and significantly narrowed its scope, resulting in a revised rule being issued in September 2023. However, due to the injunction on the January 2023 rule, the implementation of the September 2023 rule currently varies by state. In the 27 states subject to the injunction, the agencies are interpreting the definition of WOTUS consistent with the pre-2015 regulatory regime and the changes made by the Sackett decision, which utilizes the “continuous surface connection” test to determine if wetlands qualify as WOTUS. In the remaining 23 states, the agencies are implementing the September 2023 rule, which did not define the term “continuous surface connection.” Therefore, some uncertainty remains as to how broadly the September 2023 rule and the Sackett decision will be interpreted by the agencies. To the extent the implementation of the final rule, results of the litigation or any action further expands the scope of the CWA’s jurisdiction in areas where we operate, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. In addition, in an April 2020 decision, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. The Court rejected the EPA’s and Corps’ assertion that groundwater should be totally excluded from the CWA. To the extent any new rule or judicial determination expands the scope of the CWA’s jurisdiction in areas where we conduct operations, such developments could delay, restrict or halt permitting or development of projects, result in longer permitting timelines, or increase compliance expenditures or mitigation costs for our operations, which may reduce our rate of production of crude oil or natural gas.
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.
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In response to seismic events near underground injection wells used for the disposal of produced water from crude oil and natural gas activities, federal and some state agencies have investigated, and continue to investigate, whether such wells have caused increased seismic activity. In 2016, the United States Geological Survey identified six states, though not North Dakota or Montana, with areas of increased rates of induced seismicity that could be attributed to fluid injection or crude oil and natural gas extraction. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. 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 process involves the injection of water, sand or other proppants and chemical additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs.
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. While hydraulic fracturing is generally exempt from regulation under the SDWA’s UIC program, the EPA has published permitting guidance for certain hydraulic fracturing activities involving the use of diesel fuel and issued a final regulation under the CWA prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas extraction facilities. In late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. These reports or any future studies could spur initiatives to further regulate hydraulic fracturing and ultimately make it more difficult or costly for us to perform fracturing activities. Moreover, in 2016, the BLM under the former Obama Administration published a final rule imposing more stringent standards on hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, wellbore integrity and handling of flowback water. However, in late 2018, the BLM under the first Trump Administration published a final rule rescinding the 2016 final rule. Since that time, litigation challenging the BLM’s 2016 final rule and the 2018 final rule has resulted in rescission in federal courts of both the 2016 and 2018 rules. Appeals to those decisions are on-going, but with little activity in the last several years.
From time to time Congress has considered, but has not adopted, legislation to provide for federal regulation of hydraulic fracturing. The former Biden Administration has issued executive orders, and future administrations could issue additional executive orders and could pursue other legislative and regulatory initiatives that restrict hydraulic fracturing activities on federal lands.
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. States could elect to adopt certain prohibitions on hydraulic fracturing, following the approach already taken by several states. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Nevertheless, 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 perhaps 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 the hydraulic fracturing process could 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 the pursuit of 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 and prohibits the taking of endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”) and
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to bald and golden eagles under the Bald and Golden Eagle Protection Act. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed or endangered species or modify their critical habitats. 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 determinations on the listing 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 more fulsome protections for non-protected or lesser-protected species pursuant to specific timelines. 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. For example, these regulations require the plugging and abandonment of wells and removal of production facilities by current and former operators, including corporate successors of former operators. These requirements 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.
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. For example, in January 2021, President Biden issued an executive order that instructed the Secretary of the DOI to pause new oil and natural gas leases on public lands, but not existing operations under valid leases or on tribal lands which the federal government merely holds in trust, pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices. This pause was initially enjoined by a federal court order in 13 states and then lifted following negotiations pursuant to the passage of the IRA. Meanwhile, the DOI released a report on the federal oil and natural gas leasing program in November 2021 which included several recommendations for how to reform the program. Some of the report’s 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. While most of the former Biden Administration’s changes to federal lands regulations have focused on new leases, future regulatory efforts could shift focus to existing lease operations. For example, the BLM issued a proposed rule in November 2022 to reduce natural gas waste from venting, flaring, and leaks associated with exploration and production activities on federal and tribal lands. The outcome of litigation surrounding the former Biden Administration’s SC-GHGs metric may also impact future regulatory decision-making. While the Fifth Circuit dismissed initial challenges to the Biden Administration’s interim calculations of (then named) SCC values on standing grounds in February 2023, future litigation opposing federal agency applications of the current SC-GHGs metric appears likely. In September 2023, the former Biden Administration announced it would be directing federal agencies to incorporate SC-GHGs values in budgeting, procurement and other agency decisions, including in environmental reviews, where appropriate. The ultimate impacts of these recent policy directives and ongoing and future litigation concerning BLM leases and the use of the SC-GHGs metric cannot be predicted at this time, but such could affect the character of new regulations on certain federal oil and gas leases or oil and gas infrastructure on federal lands, which in turn could impact our future operations.
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. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. On July 16, 2020, the Council on Environmental Quality (the “CEQ”) under the first Trump Administration published a final rule modifying NEPA. The 2020 rule established a time limit of two years for preparation of environmental impact statements and one year for the preparation of environmental assessments. The 2020 rule also limited the scope of review to the direct effects of a proposed project on the environment. However, in April 2022 the CEQ under the former Biden Administration introduced a new ‘Final Rule’ that reversed several parts of the 2020 rule, including the scope limitations. The 2022 Final Rule requires NEPA reviews to incorporate consideration of indirect and cumulative impacts of the proposed project, including effects on climate change and GHGs, consistent with pre-2020 requirements. The new rule also allows
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agencies to create stricter NEPA rules as they see fit but left in place the 2020 rule two-year time limit to complete environmental impact statements. More recently, in January 2023, the CEQ released updated guidance for agency consideration of GHG emissions and climate change impacts in environmental reviews, which includes, among other recommendations, best practices for analyzing and communicating climate change effects. Additionally, in May 2024, the CEQ finalized revisions to NEPA which include requirements to analyze the cumulative effects of a proposed project on climate change and consider any disproportionate impact on communities with environmental justice concerns as well enhancements to certain obligations for implementing environmental mitigation measures; however, the rule is currently being litigated and is subject to executive orders issued by the new Trump Administration critical of the 2024 rule.
Operations on federal lands also face litigation risks. From time to time, legal challenges have been filed relating to federal leasing decisions, such as for failure to adequately assess the impact of any increase in GHG emissions resulting from increased 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 or performance of midstream services. 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. However, we believe that the vast majority of our future drilling locations would not be affected by any subsequent need to obtain a federal permit.
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, as a company and as individuals, seek to foster a culture of innovation and continuous improvement, 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 talented and diverse 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 14, 2025, we employed 762 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-ann ual safety summits, exec utive-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.
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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 feel valued, 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, flexible work schedules, financial wellness tools and resources and emotional well-being services, such as an Employee Assistance Program.
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 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. We are also proud to sponsor training and scholarships to support growth in our communities, such as: serving as corporate sponsor to the Bakken Area Skills Center, which provides high school students hands on training in various technical trades; sponsoring engineering college scholarships in North Dakota and Montana; volunteering at Habitat for Humanity to build homes for families in need of safe and affordable housing; and supporting and promoting OneGoal and Junior Achievement in Houston, which provide access to college scholarships and classroom mentorship opportunities for students across our community. In addition, Chord launched the Waves of Hope campaign to provide education and resources for those struggling with mental health.
Finally, we have in place a robust approach to succession planning for key personnel by assessing the competencies, experience, leadership capabilities and development opportunities of identified succession candidates. We will continue to build a pipeline of talent for the future through our graduate and intern hiring programs, which aims to bring fresh perspectives and new ideas to the organization to help us continually challenge the status quo.
Diversity, equity and inclusion
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 diverse workforce enriches the Company with unique perspectives, experiences and ideas, and helps to ensure every employee is valued and heard. We actively seek to support diversity of our workforce through a merit-based talent identification process, and we embrace an approach to talent attraction and promotion that enables each and every individual to be evaluated based on merit.
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, diversity, equity and inclusion and other employment practices. As of February 14, 2025, approximately 47% of our employees are either women or members of a minority group. 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. As of February 14, 2025, 45% of our directors are women.
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, gender expression, sex (including pregnancy, sexual orientation and gender identity), 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.
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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, as well as training programs on equal employment opportunity.
Offices
Our principal corporate office is located in Houston, Texas at 1001 Fannin Street. We also have corporate offices in Calgary, Alberta at 333 7th Avenue S.W. and in Denver, Colorado at 950 17th 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.
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 Arrangement
The synergies attributable to the Arrangement may vary from expectations.
The combined company may fail to realize the anticipated benefits and synergies expected from the Arrangement, which could adversely affect the combined company’s business, financial condition and operating results. The success of the Arrangement will depend, in significant part, on the combined company’s ability to successfully integrate the acquired business, grow the revenue of the combined company and realize the anticipated strategic benefits and synergies from the combination. Chord believes that the combination of the companies will provide operational and financial scale, increasing free cash flow, and will enhance the combined company’s corporate rate of return. However, achieving these goals requires, among other things, realization of the targeted cost synergies expected from the Arrangement. This growth and the anticipated benefits of the transaction may not be realized fully or at all, or may take longer to realize than expected. Actual operating, technological, strategic and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. If the combined company is not able to achieve these objectives and realize the anticipated benefits and synergies expected from the Arrangement within the anticipated timing or at all, the combined company’s business, financial condition and operating results may be adversely affected.
The market price of our common stock may decline if large amounts of our common stock are sold following the Arrangement and may be affected by factors different from those that historically have affected or currently affect the market price of our common stock.
The market price of our common stock may fluctuate significantly following completion of the Arrangement and holders of our common stock could lose some or all of the value of their investment. Upon closing of the Arrangement, we issued shares of our common stock to former Enerplus shareholders. The Arrangement Agreement contains no restrictions on the ability of former Enerplus shareholders to sell or otherwise dispose of such shares. Former Enerplus shareholders may decide not to hold the shares of our common stock that they received in the Arrangement, and our historic stockholders may decide to reduce their investment in Chord as a result of the changes to our investment profile as a result of the Arrangement. These sales of our common stock (or the perception that these sales may occur) could have the effect of depressing the market price for our common stock. Furthermore, the stock market has experienced significant price and volume fluctuations in recent times which, if they continue to occur, could have a material adverse effect on the market for, or liquidity of, our common stock, regardless of our actual operating performance.
Risks related to the oil and gas industry and our business
Global geopolitical tensions may create heightened volatility in oil, NGL and natural gas prices and could adversely affect our business, financial condition and results of operations.
On February 24, 2022, Russian military forces commenced a military operation in Ukraine, and the sustained conflict and disruption in the region that has occurred since this date is expected to continue. Additionally, on October 7, 2023, Hamas, a U.S.-designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto Israel. On October 8, 2023, Israel formally declared war on Hamas. The parties entered into truces to pause the conflict and have periodically resumed hostilities; accordingly, the state of the conflict remains fluid and unpredictable. Additionally, Iranian-backed Houthi rebels have conducted several attacks against commercial shipping in the Red Sea and conflict has occurred and continues to occur in Lebanon, Syria and Yemen. Hostilities could continue to escalate in Lebanon and Syria and spread across the Middle East. Although the length, impact and outcome of the military conflicts between Russia and Ukraine and between Hamas and Israel 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.
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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. For example, in 2023, the failures, closure and receivership of Silicon Valley Bank, Silvergate Bank, Signature Bank and First Republic Bank impacted financial markets. Although we did not have any funds deposited with these banks, we regularly maintain domestic cash deposits in FDIC-insured banks, which exceed the FDIC insurance limits. 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. 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 following the September 2024 rate reduction, as well as the potential for a U.S. government shutdown (such as the near shutdown in December 2024 related to debt ceiling legislation), 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, NGLs 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, NGLs and natural gas, heavily influence our revenue, profitability, cash flow from operations, access to capital and future rate of growth. Crude oil, NGLs 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, NGLs and natural gas have been volatile, and 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, NGLs 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;
•the price and quantity of imports of foreign crude oil, NGLs 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, such as the ongoing conflicts between Russia and Ukraine and between Hamas and Israel and global health epidemics and concerns such as the COVID-19 pandemic;
•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 oil, natural gas, and NGLs;
•weather conditions and natural disasters;
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•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, NGLs and natural gas and related infrastructure;
•price and availability of competitors’ supplies of crude oil, NGLs 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, NGLs 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 oil, which could adversely affect our business, financial condition, results of operations and cash flows.
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;
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•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, NGLs 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 generate the highest possible 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 horizontal 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.
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 24—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, 2024, 2023 and 2022.
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.
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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, NGLs 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.
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 and goodwill.
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. These circumstances could also indicate that the carrying amount of our goodwill may exceed the fair value, which could result in a future goodwill impairment.
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, NGLs 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, NGLs 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, NGLs 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.
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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 now back on remand before the D.C. Federal District Court and other subsequent related motions and claims have been made, the outcome of each of which 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 NGLs to market may adversely affect our earnings, cash flows and results of operations.
Our delivery of oil, NGLs 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 oil, NGLs 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, NGLs 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, NGLs 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. Our failure to obtain these services on acceptable terms could materially harm our business.
Legal and regulatory challenges to transportation may impact our ability to move volume.
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
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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. A final EIS and formal decision by the Corps is expected by the end of 2025; 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.
A portion of our crude oil and NGL production is transported to market centers by rail. Potential crude oil or NGL train derailments or crashes as well as state or federal restrictions on the vapor pressure of crude oil transported by, or loaded on or unloaded from, railcars could also impact our ability to market and deliver our products and cause significant fluctuations in our realized prices due to tighter safety regulations imposed on crude-by-rail transportation and interruptions in service. See “Item 1. Business—Regulation—Regulation of transportation and sales of crude oil” for more information about the regulations relating to the transport of crude oil by rail.
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, 2024, 2023 and 2022.
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 30% of our estimated net proved reserves were classified as PUD as of December 31, 2024. 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.
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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, c rude 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;
•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, NGLs 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, NGLs or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of crude oil, NGLs 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
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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, NGLs 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.
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, 2024, 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, 2024, we had an aggregate of 568 net acres expiring in 2025, 1,086 net acres expiring in 2026 and 186 net acres expiring in 2027 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, 2024, 2023 and 2022.
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 of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. Our non-operated activity is expected to increase in 2025 and beyond relative to prior years. 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;
•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
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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.
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, the new Trump Administration has proposed to significantly increase tariffs on foreign imports into the United States and any new tariffs have been and continue to be rapidly and actively evolving. The state, duration and scope of any tariffs enacted are 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, NGLs 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, NGLs 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, NGLs 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, 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.
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Stakeholder and market attention to matters related to corporate responsibility may impact our business and ability to secure financing.
Businesses across all industries are facing scrutiny from 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 do not adapt to or comply with evolving investor or stakeholder expectations and 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.
As part of our ongoing effort to enhance our ESG practices related to corporate responsibility, our Board of Directors has established the Safety and Sustainability Committee, which is charged with overseeing our ESG policies related to corporate responsibility. Committee members are expected to review the implementation and effectiveness of our ESG programs and policies. Additionally, to help strengthen our ESG performance, we have implemented compensation practices focused on value creation and aligned with stockholders’ interests. Additionally, while 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, including the purchase of various environmental credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. However, even in those cases we cannot guarantee that the environmental credits or offsets we do purchase will not subsequently be determined to have failed to result in GHG emission reductions for reasons out of our control. 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. Unfavorable ESG ratings and recent 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 and to the diversion of investment to other industries, which could have a negative impact on us and our access to and costs of capital. Furthermore, 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.
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.
The SEC’s Final Rules on The Enhancement and Standardization of Climate-Related Disclosures could result in increased compliance risks and costs.
The SEC released its final rule on climate-related disclosures on March 6, 2024, requiring the disclosure of certain climate-related risks, management and governance practices, and financial impacts, as well as greenhouse gas emissions, but these rules
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have currently been staved. If the rules come into effect, large accelerated filers would be required to incorporate the applicable climate-related disclosures into their filings beginning in fiscal year 2025 (which is likely to be delayed), with additional requirements relating to the disclosure of Scope 1 and 2 greenhouse gas emissions, if material, and attestation reports for certain large accelerated filers subsequently phasing in. While we are still assessing our obligations under the rule, complying with such obligations may result in increased costs and SEC or investor scrutiny of our disclosures. As noted above, the SEC has stayed the final rule pending the resolution of consolidated legal challenges that are currently proceeding before the U.S. Court of Appeals for the Eighth Circuit. The outcome of this litigation may reduce or expand our obligations under the final rule. Additionally, given the new administration as a result of the outcome of the 2024 election cycle, it is uncertain what approach the new SEC leadership will take with respect to this regulation moving forward and how such approach may affect our compliance risks and costs.
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 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 that are outside of our control and could significantly disrupt our operations and adversely affect our business and financial condition. For example, the global outbreak of COVID-19 during 2020 negatively impacted demand for crude oil and natural gas because of reduced global and national economic activity levels. In response to any future public health crisis (like COVID-19), 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.
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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, NGLs 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 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, NGLs 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.
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Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil, NGLs 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, NGLs 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.
Further, the COVID-19 pandemic that began in early 2020 provides an illustrative example of how a pandemic or epidemic can also impact our operations and business by affecting the health of these qualified or trained personnel and rendering them unable to work or travel. 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—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, including the Arrangement, 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
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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, including the Arrangement, 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, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;
•difficulty associated with coordinating geographically separate organizations;
•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, including those obtained in the Arrangement, 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, including the Arrangement, our results of operations and stock price may be adversely affected.
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. For example, in 2019, the Supreme Court of North Dakota issued an opinion indicating a change in its interpretation of how certain gas royalty payments are calculated under North Dakota law with respect to certain state leases, which may require us to make additional royalty payments and reduce our revenues. 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.
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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;
•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
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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, NGLs 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 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 $3.4 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.
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, NGLs and natural gas we are able to produce from existing wells and new projected wells;
•the prices at which our crude oil, NGLs 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
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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.
We may maintain material balances of cash and cash equivalents for extended periods of time at commercial banks in excess of amounts insured by government agencies such as the FDIC.
We may maintain material balances of cash and cash equivalents for extended periods of time at commercial banks in excess of amounts insured by government agencies such as the FDIC. A failure of our commercial banks could result in us losing any funds we have deposited in excess of amounts insured by the FDIC. Any losses we sustain on our cash deposits could materially adversely affect our financial position.
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 20—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, 2024, changes in our estimate of expected credit losses was 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, 2024, we had commodity derivatives in place with 15 counterparties and a total net commodity derivative asset of $16.5 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 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.
The IRA includes, among other things, a corporate alternative minimum tax (the “CAMT”). Under the CAMT, a 15% minimum tax will be imposed on certain financial statement income of “applicable corporations.” The CAMT generally treats a corporation as an applicable corporation in any taxable year in which the “average annual adjusted financial statement income” of the corporation and certain of its subsidiaries and affiliates for a three-taxable-year period ending prior to such taxable year exceeds $1 billion.
Based on our current interpretation of the IRA and the CAMT and a number of operational, economic, accounting and regulatory assumptions, we do not anticipate the CAMT materially increasing our U.S. federal income tax liability in the near term. If our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash flows in that year, but
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provide an offsetting credit against our regular U.S. federal income tax liability in future tax years. The foregoing analysis is based upon our current interpretation of the provisions contained in the IRA and the CAMT. The Internal Revenue Service has provided interim interpretive guidance and the U.S. Department of Treasury has issued proposed regulations relating to the CAMT. The details of the computation will be subject to the final regulations and interpretive guidance to be issued, and any significant variance from our current interpretation could result in a change in the expected application of the CAMT to us and 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 with Whiting. 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 (including as a result of the issuance of our stock in connection with our acquisition of Enerplus), 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 enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price changes, interest rate and other risks associated with our business.
In 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has proposed new regulations to set position limits for certain futures, options and swap contracts in designated physical commodities, including, among others, crude oil, NGLs and natural gas. The Dodd-Frank Act and CFTC rules have also designated certain types of swaps (thus far, only certain interest rate swaps and credit default swaps) for mandatory clearing and exchange trading and may designate other types of swaps for mandatory clearing and exchange trading in the future. To the extent that we engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply with the clearing and exchange trading requirements or to take steps to qualify for an exemption to such requirements. In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the non-financial end-user exception from margin requirements for swaps to other market participants, such as swap dealers, these rules may change the cost and availability of the swaps we use for hedging. If any of our swaps do not qualify for the non-financial end-user exception, we could be required to post initial or variation margin, which would impact liquidity and reduce our cash. This would in turn reduce our ability to execute hedges to reduce risk and protect cash flows. Other regulations to be promulgated under the Dodd-Frank Act also remain to be finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Further, to the extent our revenues are unhedged, they could be adversely
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affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations.
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, 2024, we had $445.0 million of net outstanding borrowings and $30.8 million of outstanding letters of credit under our revolving credit facility and $400.0 million of 6.375% 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.
A negative shift in investor sentiment regarding the oil and gas industry could adversely affect our ability to raise debt and equity capital.
Certain segments of the investor community have developed negative sentiment towards investing in the oil and gas industry. Historic equity returns in this sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have adopted policies to divest holdings in the oil and gas sector based on social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects.
Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential acquisitions or development projects, impacting our future financial results.
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 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
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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 exercise of all or any number of outstanding warrants or the issuance of stock-based awards may dilute your holding of shares of our common stock.
As of December 31, 2024, we had 888,742 outstanding warrants to purchase shares of our common stock and 594,520 outstanding stock–based awards. In addition, as of December 31, 2024, a total of 2,801,654 shares of common stock were available for future issuance under our equity incentive plans, including 1,613,057 shares of common stock reserved for future issuance under the Chord Energy Corporation Long Term Incentive Plan (the “2020 LTIP”) and 1,188,597 shares of common stock reserved for future issuance under the Whiting 2020 Equity Incentive Plan (the “Whiting Equity Incentive Plan”), which we assumed in connection with the Merger. 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 change from period to period, and such changes could be material.
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 slightly, 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
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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 2025; 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 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 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, 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;
•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 regulatory fines or penalties; 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 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, ransomware attacks, employee error, malfeasance, system error, faulty password management or other irregularities.
Moreover, as the sophistication 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
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through the use of artificial intelligence, and we may face difficulties in 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 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 recently 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 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. 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.
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These risks may include, among other things, operational risks, 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 and applications. 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. Regular assessments of our cybersecurity safeguards are conducted both internally and by independent third-party cybersecurity vendors. Additionally, our internal audit department conducts regular audits to identify, assess and manage material 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 to help promptly identify cybersecurity incidents. While processes are in place to minimize the chance of a successful cyberattack, we have established incident response procedures 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 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 to continuously 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 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: We 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 to identify 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 regularly tests our controls through penetration tests, vulnerability scans and attack simulations.
•Encryption and Data Protection: We have encryption methods in place to protect certain sensitive data. This includes the encryption of customer data, financial information and other confidential data. We also have multiple programs in place to monitor our retained data and take actions to secure the data.
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, before engaging with any third-party service provider, we conduct due diligence to evaluate the third-party provider’s cybersecurity capabilities. For new cloud-based third-party providers, we aim to review their cybersecurity practices 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.
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.
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As of the date of this report, we are not aware of any previous cybersecurity threats that have materially affected or are reasonably likely to materially affect us. However, we acknowledge that cybersecurity threats are continually evolving and the possibility of future cybersecurity incidents remains. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our IT systems could have significant consequences for the business. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. No security measure is infallible. See “Item 1A. Risk Factors” for additional information about the risks to our business associated with a breach or compromise to our IT systems.
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, provides updates to the Audit and Reserves Committee on data protection and cybersecurity matters on at least a semi-annual basis, or as requested or deemed necessary. The topics covered in such reports may include an overview of our current cybersecurity risk assessment, key risk areas, any significant cyber incidents that have occurred or are reasonably likely to occur, as well as recent updates on cybersecurity trends and emerging threats. Additionally, on an annual basis, the Vice President, Information Technology, reviews with the Audit and Reserves Committee the results from tests of key cybersecurity risks and the subsequent steps taken to mitigate such risks.
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 17 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 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.
We have developed a Cybersecurity Council that reports directly to our Chief Strategy Officer & Chief Commercial Officer. The Cybersecurity Council is led by the Vice President, Information Technology, and is comprised of select members of the IT team with an average of nearly 20 years of cybersecurity experience. The Cybersecurity Council meets monthly to review current cybersecurity threats as well as our potential exposure. The Cybersecurity Council also engages periodically with external and internal auditors, as well as the Cybersecurity and Infrastructure Security Agency, the American Exploration and Production Council and the Federal Bureau of Investigation to stay informed on cybersecurity risk management.
Item 2. Properties
The information required by Item 2. is contained in Item 1. Business.
Item 3. Legal Proceedings
See “Part II, Item 8. Financial Statements and Supplementary Data—Note 21—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 2024, we paid an aggregate amount of cash dividends of $10.15 per share of common stock, including base dividends of $5.00 per share of common stock and variable dividends of $5.15 per share of common stock. On February 25, 2025, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 26, 2025 to stockholders of record as of March 11, 2025.
In October 2024, the Board of Directors authorized a new $750 million share repurchase program, which replaced the $750 million share repurchase program the Board of Directors had previously authorized in October 2023. 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 14, 2025, the number of record holders of our common stock was 299. Based on inquiry, management believes that the number of beneficial owners of our common stock as of February 14, 2025 was approximately 162,227.
On February 14, 2025, the last sale price of our common stock, as reported on the Nasdaq, was $110.93 per share.
Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2024.
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 2025 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, 2024:

Period |  | Total Number of Shares Exchanged(1)(2) |  | Average Price Paid per Share |  | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2)(3) |  | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs(2)
October 1 – October 31, 2024 |  | 366,961 |  |  | $ | 129.90 |  |  | 366,961 |  |  | $ | 397,561,163 |
November 1 – November 30, 2024 |  | 811,848 |  |  | 129.81 |  |  | 810,456 |  |  | 644,792,257 |
December 1 – December 31, 2024 |  | 472,518 |  |  | 121.45 |  |  | 426,594 |  |  | 592,635,902 |

___________________
(1)During the fourth quarter of 2024, we withheld 47,316 shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.
(2)During the fourth quarter of 2024, we repurchased 1,604,011 shares of common stock at a weighted average price of $127.82 per common share for a total cost of $205.0 million, under our publicly announced share repurchase program.
(3)In October 2023, our Board of Directors had previously authorized a share repurchase program of up to $750 million of our common stock. In October 2024, our Board of Directors authorized a new share repurchase program covering up to $750 million of common stock, which replaced the existing $750 million share repurchase program. The amount presented for the period ending October 31, 2024 was calculated using the remaining authorization under the previously authorized share repurchase program, and the amounts presented for the periods ending November 30, 2024 and December 31, 2024 were calculated using the authorization under the new 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 November 20, 2020 (the date we emerged from bankruptcy and our common stock commenced trading) through December 31, 2024. 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 November 20, 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, 2023 compared to the year ended December 31, 2022, 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, 2023, filed with the SEC on February 26, 2024.
Overview
Chord Energy 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, natural gas liquids (“NGL”) and natural gas primarily in the Williston Basin. Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We are ideally positioned to enhance return of capital and generate strong free cash flow, while being responsible stewards of the communities and environment where we operate.
Recent Developments
Enerplus Arrangement
On February 21, 2024, we 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, we 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 Arrangement was completed on May 31, 2024.
Upon completion of the Arrangement on May 31, 2024, we issued 20,680,097 shares of common stock and paid $375.8 million in cash to Enerplus shareholders. Under the terms of the Arrangement Agreement, Enerplus shareholders received 0.10125 shares of Chord common stock, par value $0.01 per share, and $1.84 per share in cash in exchange for each share of Enerplus they owned at closing.
Divestitures
On October 25, 2024, we completed the sale of certain of our non-core properties located in the DJ Basin in Colorado that were classified as assets held for sale as of September 30, 2024, for total net cash proceeds (including preliminary purchase price adjustments) of $36.4 million, resulting in a $0.6 million gain on asset divestment.
In addition, during the year ended December 31, 2024, we completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds (subject to purchase price adjustments) of $25.0 million.
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, NGLs and natural gas have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future due to a combination of macro-economic factors that impact the supply and demand for crude oil, NGLs and natural gas. Commodity prices remained low throughout 2024 due to a combination of factors, including slowing demand growth as a result of decreased global economic activity levels and higher levels of production from domestic oil and gas producers in the United States and other non-OPEC+ countries.
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. 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, NGLs and natural gas (see “Item 7A. —Quantitative and Qualitative Disclosures about Market Risk—Inflation risks” for additional information). The uncertainties
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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 wars between Russia and Ukraine and Hamas and Israel, 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 or goodwill 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 and goodwill as a result of a future material or extended decline in the price of crude oil, NGLs or natural gas or a material increase in the costs of labor, materials or services. 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 and goodwill” for additional information.
In an effort to improve price realizations from the sale of our crude oil, NGLs and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGLs and natural gas to a broader array of potential purchasers. We enter into crude oil, NGL and natural gas sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single customer would have a material adverse effect on our results of operations or cash flows. 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:

| 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) | %

| 2023 |  | Year Ended December 31, 2023
| Q1 |  | Q2 |  | Q3 |  | Q4 |
Average realized crude oil prices ($/Bbl)(1) | $ | 76.04 |  |  | $ | 73.89 |  |  | $ | 83.22 |  |  | $ | 77.88 |  |  | $ | 77.85 |
Average price differential ($/Bbl)(2) | $ | — |  |  | $ | 0.14 |  |  | $ | 0.69 |  |  | $ | (0.52) |  |  | $ | 0.07 |
Average price differential percentage(2) | — | % |  | 0.2 | % |  | 0.8 | % |  | (0.7) | % |  | 0.1 | %

__________________
(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, 2024, 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 rail markets in order to optimize price realizations. Expansions of both rail and pipeline 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, 2024 and 2023. 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 and the 2023 acquisition of acreage in the Williston Basin, while the results reported for the year ended December 31, 2023 reflect the consolidated results of Chord, including the 2023 acquisition of acreage in the Williston Basin beginning on June 30, 2023, and excluding the impact from the business combination with Enerplus, unless otherwise noted.
For a discussion of the changes related to the financial condition and results of operations for the year ended December 31, 2023 compared to the year ended December 31, 2022, 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, 2023, filed with the SEC on February 26, 2024.
Operational and Financial Highlights
•Production volumes averaged 232,737 Boepd (57% oil) for the year ended December 31, 2024.
•Lease operating expenses (“LOE”) were $9.68 per Boe for the year ended December 31, 2024.
•E&P and other capital expenditures were $1.2 billion for the year ended December 31, 2024.
•Net cash provided by operating activities was $2.1 billion and net income was $848.6 million for the year ended December 31, 2024.
•Estimated net proved reserves were 883.0 MMBoe as of December 31, 2024, with a Standardized Measure of $8.4 billion and PV-10 of $10.3 billion.
•TIL’d 142 gross (93 net) operated wells for the year ended December 31, 2024.
Shareholder Return Highlights
•Paid $10.15 per share base-plus-variable cash dividend for the year ended December 31, 2024.
•Repurchased $442.8 million of common stock during the year ended December 31, 2024 with $592.6 million remaining under the new $750 million share repurchase program authorized by the Board of Directors in October 2024.
•On February 25, 2025, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 26, 2025 to stockholders of record as of March 11, 2025.
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Revenues
Our crude oil, NGL and natural gas revenues are derived from the sale of crude oil, NGL and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold and/or changes in commodity prices. Our revenues for the year ended December 31, 2024 increased 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, NGLs and natural gas purchased through our marketing activities primarily to optimize transportation costs, for blending to meet pipeline specifications or to cover production shortfalls. Revenues and expenses from crude oil, NGL and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the counterparty. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis.
The following table summarizes our revenues, production and average realized prices for the periods presented:

| Year Ended December 31, |  |  |
| 2024 |  | 2023 |  |  |  |  |
| (In thousands, except price per unit data) |  |  |  |  |
Revenues |  |  |  |  |  |  |  |
Crude oil revenues | $ | 3,571,336 |  |  | $ | 2,835,962 |  |  |  |  |  |
NGL revenues | 162,052 |  |  | 177,715 |  |  |  |  |  |
Natural gas revenues | 102,750 |  |  | 118,734 |  |  |  |  |  |
Purchased oil and gas sales | 1,414,944 |  |  | 764,230 |  |  |  |  |  |
Total revenues | $ | 5,251,082 |  |  | $ | 3,896,641 |  |  |  |  |  |
Production data |  |  |  |  |  |  |  |
Crude oil (MBbls) | 48,479 |  |  | 36,427 |  |  |  |  |  |
NGLs (MBbls) | 16,338 |  |  | 13,047 |  |  |  |  |  |
Natural gas (MMcf)(1) | 122,193 |  |  | 82,953 |  |  |  |  |  |
Oil equivalents (MBoe) | 85,182 |  |  | 63,300 |  |  |  |  |  |
Average daily production (Boepd) | 232,737 |  |  | 173,425 |  |  |  |  |  |
Average daily crude oil production (Bopd) | 132,455 |  |  | 99,801 |  |  |  |  |  |
Average sales prices |  |  |  |  |  |  |  |
Crude oil (per Bbl) |  |  |  |  |  |  |  |
Average sales price | $ | 73.67 |  |  | $ | 77.85 |  |  |  |  |  |
Effect of derivative settlements(2) | 0.02 |  |  | (6.93) |  |  |  |  |  |
Average realized price after the effect of derivative settlements(2) | $ | 73.69 |  |  | $ | 70.92 |  |  |  |  |  |
NGLs (per Bbl) |  |  |  |  |  |  |  |
Average sales price | $ | 9.92 |  |  | $ | 13.62 |  |  |  |  |  |
Effect of derivative settlements(2) | — |  |  | 0.22 |  |  |  |  |  |
Average realized price after the effect of derivative settlements(2) | $ | 9.92 |  |  | $ | 13.84 |  |  |  |  |  |
Natural gas (per Mcf) |  |  |  |  |  |  |  |
Average sales price(1) | $ | 0.84 |  |  | $ | 1.43 |  |  |  |  |  |
Effect of derivative settlements(2) | — |  |  | (0.08) |  |  |  |  |  |
Average realized price after the effect of derivative settlements(1)(2) | $ | 0.84 |  |  | $ | 1.35 |  |  |  |  |  |

__________________
(1)For the year ended December 31, 2024, natural gas production volume from the Marcellus Shale was 24,727 MMcf. The realized natural gas price related to this production, prior to the effect of derivative settlements, was $1.78 per Mcf.
(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.
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Crude oil revenues. Our crude oil revenues increased $735.4 million to $3.6 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023. Our crude oil revenues increased $837.3 million due to higher total crude oil production volumes sold, primarily due to our expanded operations as a result of the Arrangement. Excluding the increase from the Arrangement, crude oil revenues decreased $124.9 million due to lower crude oil realized prices, partially offset by an increase of $23.0 million due to higher crude oil production volumes sold year-over-year. Average crude oil sales prices, without derivative settlements, decreased by $4.18 per barrel year-over-year to an average of $73.67 per barrel for the year ended December 31, 2024 due to decreases in NYMEX WTI and widening in-basin differentials.
NGL revenues. Our NGL revenues decreased $15.7 million to $162.1 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The decrease was primarily due to lower NGL realized prices year-over-year resulting in a $48.3 million decrease, partially offset by an increase of $32.6 million due to higher NGL production volumes primarily as a result of the Arrangement. Average NGL sales prices, without derivative settlements, decreased by $3.70 per barrel period over period to an average of $9.92 per barrel for the year ended December 31, 2024 primarily due to wider differentials on incremental production volumes primarily as a result of the Arrangement.
Natural gas revenues. Our natural gas revenues decreased $16.0 million to $102.8 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The decrease was primarily due to lower natural gas realized prices year-over-year resulting in a $49.0 million decrease, offset by an increase in total natural gas production volumes sold of $33.0 million, primarily due to our expanded operations as a result of the Arrangement. Average natural gas sales prices, without derivative settlements decreased by $0.59 per Mcf period over period to $0.84 per Mcf for the year ended December 31, 2024 primarily due to a decrease in natural gas index prices, coupled with the impact of incurring fixed fees and related fee escalations for the majority of our natural gas marketing contracts beginning in the second quarter of 2023.
Purchased oil and gas sales. Purchased oil and gas sales increased $650.7 million to $1.4 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023. This increase was primarily due to an increase in the volume of crude oil purchased and subsequently sold, partially offset by lower crude oil and gas prices year-over-year.
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Expenses and other income (expense)
The following table summarizes our operating expenses and other income (expense) for the periods presented:

| Year Ended December 31,
| 2024 |  | 2023
| (In thousands, except per Boe of production)
Operating expenses |  |  |
Lease operating expenses | $ | 824,408 |  |  | $ | 658,938 |
Gathering, processing and transportation expenses | 267,559 |  |  | 180,219 |
Purchased oil and gas expenses | 1,412,357 |  |  | 761,325 |
Production taxes | 333,397 |  |  | 260,002 |
Depreciation, depletion and amortization | 1,107,776 |  |  | 598,562 |
General and administrative expenses | 205,585 |  |  | 126,319 |
Exploration and impairment | 17,021 |  |  | 35,330 |
Total operating expenses | 4,168,103 |  |  | 2,620,695 |
Gain (loss) on sale of assets, net | 17,088 |  |  | (2,764) |
Operating income | 1,100,067 |  |  | 1,273,182 |
Other income (expense) |  |  |
Net gain on derivative instruments | 12,563 |  |  | 63,182 |
Net gain from investment in unconsolidated affiliate | 51,284 |  |  | 21,330 |
Interest expense, net of capitalized interest | (56,523) |  |  | (28,630) |
Other income, net | 5,047 |  |  | 9,964 |
Total other income, net | 12,371 |  |  | 65,846 |
Income before income taxes | 1,112,438 |  |  | 1,339,028 |
Income tax expense | (263,811) |  |  | (315,249) |
Net income | $ | 848,627 |  |  | $ | 1,023,779 |
Costs and expenses (per Boe of production) |  |  |
Lease operating expenses | $ | 9.68 |  |  | $ | 10.41 |
Gathering, processing and transportation expenses | 3.14 |  |  | 2.85 |
Production taxes | 3.91 |  |  | 4.11 |

Lease operating expenses. LOE increased $165.5 million to $824.4 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily driven by our expanded operations after the Arrangement contributing $181.3 million of additional LOE period over period. Excluding the increase from the Arrangement, LOE decreased $31.7 million due to lower workover costs, offset by an increase of $17.0 million due to higher variable costs period over period. LOE per Boe decreased $0.73 per Boe period over period to $9.68 per Boe for the year ended December 31, 2024 primarily due to higher production volumes and lower workover costs.
Gathering, processing and transportation expenses. Gathering, processing and transportation (“GPT”) expenses increased $87.3 million to $267.6 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily due to our expanded operations after the Arrangement contributing $79.5 million of additional GPT period over period and lower fair value gains of $26.4 million attributable to the completion of certain derivative transportation contracts at the end of 2023 and during the first half of 2024. These increases were partially offset by a decrease of $19.5 million due to lower transportation rates, primarily due to several contracts expiring during the year ended December 31, 2024. These net increases resulted in an increase in GPT expenses of $0.29 per Boe period over period to $3.14 per Boe for the year ended December 31, 2024.
Purchased oil and gas expenses. Purchased oil and gas expenses increased $651.0 million to $1.4 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023 primarily due to an increase in the volume of crude oil purchased and subsequently sold, partially offset by lower crude oil and gas prices year-over-year.
Production taxes. Production taxes increased $73.4 million to $333.4 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily driven by our expanded operations after the Arrangement contributing $77.4 million of additional production tax, or $3.59 per Boe, for the year ended December 31, 2024.
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The production tax rate as a percentage of crude oil, NGL and natural gas sales was 8.7% for the year ended December 31, 2024 as compared to 8.3% for the year ended December 31, 2023. This rate increase year-over-year was primarily due to an increase in new wells with a higher associated oil production tax rate, coupled with decreased natural gas and NGL revenues as a result of lower realized prices.
Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $509.2 million to $1.1 billion for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily due to our expanded operations after the Arrangement contributing $281.1 million of additional DD&A expense period over period, an increase of $225.0 million due to a higher depletion rate period over period and an increase of $4.5 million due to higher production volumes year-over-year. The depletion rate increased $3.50 per Boe year-over-year to $12.70 per Boe for the year ended December 31, 2024 primarily due to the purchase consideration allocated to the fair value of oil and gas properties acquired in the Arrangement.
General and administrative expenses. Our general and administrative (“G&A”) expenses increased $79.3 million to $205.6 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023, primarily due to increased merger-related costs of $79.6 million incurred in connection with the Arrangement and an increase in costs associated with a larger organization after the Arrangement of $26.7 million. These increases were partially offset by a decrease in stock-based compensation costs of $23.1 million due to the vesting of certain equity-based compensation awards year-over-year.
Exploration and impairment expenses. Exploration and impairment expenses decreased $18.3 million to $17.0 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. During the year ended December 31, 2024, we recorded an impairment expense of $9.8 million, which primarily included a $7.4 million lower of cost or net realizable value write-down of oil-in-tank inventory and a $2.5 million impairment expense related to the Denver office lease and related fixed assets acquired in connection with the Arrangement. During the year ended December 31, 2023, exploration and impairment expenses totaled $35.3 million, which was primarily due to impairment expenses of $29.0 million, including $17.5 million associated with the write-down of our Denver office lease acquired in 2022, $5.8 million associated with a lower of cost or net realizable value write-down of oil-in-tank inventory and $5.6 million to adjust the carrying value of certain non-core properties held for sale to their estimated fair value less costs to sell.
Gain (loss) on sale of assets, net. During the year ended December 31, 2024, we recorded a net gain on sale of assets of $17.1 million, primarily related to certain non-operated wellbore divestitures in the Williston Basin. During the year ended December 31, 2023, we recorded a net loss on sale of assets of $2.8 million, primarily related to divestitures of certain of our non-core properties located outside of the Williston Basin.
Derivative instruments. 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 includes 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. During the year ended December 31, 2023, we recorded a $63.2 million net gain on derivative instruments, which was primarily comprised of a net gain of $56.4 million associated with our commodity derivative contracts and a net gain of $6.8 million associated with a contract that includes contingent consideration. The net gain of $56.4 million on commodity derivative contracts included an unrealized gain of $313.1 million related to the change in fair value of our commodity derivative contracts primarily driven by a downward shift in the futures curve for forecasted commodity prices, partially offset by a realized loss of $256.7 million on settled commodity derivative contracts.
Investment in unconsolidated affiliate. We recorded a $51.3 million gain related to our investment in Energy Transfer for the year ended December 31, 2024, which included an unrealized 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. During the year ended December 31, 2023, we recorded a $21.3 million gain related to our investment in Energy Transfer, primarily related to a realized gain of $10.8 million for cash distributions received and an unrealized gain of $8.4 million as a result of an increase in the fair value of the investment during the year.
Interest expense, net of capitalized interest. Interest expense increased $27.9 million to $56.5 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. The increase is primarily due to higher borrowings outstanding on our Credit Facility (defined below) during the year. 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 7.3%. For the year ended December 31, 2023, the weighted average borrowings outstanding under the Credit Facility were $4.9 million, and the weighted average interest rate incurred on the outstanding borrowings was 7.1%. Interest capitalized during the year ended December 31, 2024 and December 31, 2023 was $4.9 million and $4.1 million, respectively.
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Other income, net. For the year ended December 31, 2024, we recognized $5.0 million of other income, net as compared to $10.0 million for the year ended December 31, 2023. The $5.0 million decrease was primarily due to a decrease in interest income year-over-year associated with lower balances in our money market accounts.
Income tax expense. Our effective tax rate for the year ended December 31, 2024 was materially unchanged from our effective tax rate for the year ended December 31, 2023. Our income tax expense was recorded at 23.7% and 23.5% of pre-tax income for the year ended December 31, 2024 and December 31, 2023, respectively.
Liquidity and Capital Resources
As of December 31, 2024, we had $1.1 billion of liquidity available, including $37.0 million in cash and cash equivalents and $1.0 billion of aggregate unused borrowing base capacity available under our Credit Facility (defined below). During the first quarter of 2025, we expect to have approximately $1.6 billion of liquidity available after taking into account the increase in the aggregate amount of elected commitments to $2.0 billion. Our primary sources of liquidity were from cash on hand, cash flows from operations and available borrowing base capacity under our Credit Facility. Our primary liquidity requirements were capital expenditures for the development of oil and gas properties, dividend payments, debt repayments under our Credit Facility, share repurchases, cash consideration and transaction costs associated with the Arrangement, 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 recently decreased 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.
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 year ended December 31, 2024, we incurred merger-related costs of $89.3 million, primarily related to legal and advisory services and severance costs.
Our cash flows depend on many factors, including the price of crude oil, NGLs and natural gas and the success of our development and exploration activities as well as future acquisitions. 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, 2024, our commodity derivative contracts cover 9,301 MBbls of our crude oil production and 8,902 MMBtu of our natural gas production for 2025, as well as 4,000 MBbls of our crude oil production and 10,475 MMBtu of our natural gas production for 2026. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and “Part I, Item 1A. Risk Factors” for additional information.
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Subsequent to December 31, 2024, we entered into new commodity derivative contracts to manage risks related to changes in commodity prices. The following table summarizes these commodity derivative contracts:

|  |  |  |  |  | Volumes |  | Weighted Average Prices
Commodity |  | Settlement Period |  | Derivative Instrument |  | Total |  |  | Units |  | Fixed-price swaps |  | Sub-floor |  | Floor |  | Ceiling
Crude oil |  | 2025 |  | Fixed-price swaps |  | 2,015,000 |  |  |  | Bbls |  | $ | 70.45 |  |  |  |  |  |  |
Crude oil |  | 2025 |  | Two-way collars |  | 91,000 |  |  |  | Bbls |  |  |  |  |  | $ | 65.00 |  |  | $ | 77.35 |
Crude oil |  | 2026 |  | Three-way collars |  | 730,000 |  |  |  | Bbls |  |  |  | $ | 50.00 |  |  | $ | 65.00 |  |  | $ | 73.93 |
Crude oil |  | 2026 |  | Fixed-price swaps |  | 180,000 |  |  |  | Bbls |  | $ | 68.67 |  |  |  |  |  |  |
Crude oil |  | 2027 |  | Three-way collars |  | 182,000 |  |  |  | Bbls |  |  |  | $ | 50.00 |  |  | $ | 65.00 |  |  | $ | 74.15 |
Natural gas |  | 2025 |  | Fixed-price swaps |  | 15,640,000 |  |  |  | MMBtu |  | $ | 4.12 |  |  |  |  |  |  |
Natural gas |  | 2026 |  | Fixed-price swaps |  | 8,220,000 |  |  |  | MMBtu |  | $ | 3.94 |  |  |  |  |  |  |
Natural gas |  | 2026 |  | Two-way collars |  | 5,430,000 |  |  |  | MMBtu |  |  |  |  |  | $ | 3.83 |  |  | $ | 4.26 |

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, obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, payment of income taxes, obligations associated with outstanding commodity derivative contracts that settle in a loss position, obligations to pay dividends on vested equity awards that include dividend equivalent rights and obligations associated with our leases. In addition, we have announced a return of capital plan pursuant to which we intend to return capital to stockholders through a mix of base and variable dividend payouts, supplemented by opportunistic share repurchases. On a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.
We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, NGLs, natural gas and water within specified time frames, the majority of which are five years or less. Under the terms of these contracts, if we fail to deliver, transport or purchase the committed volumes we will be required to pay a deficiency payment for the volumes not tendered over the duration of the contract. The estimable future commitments under these agreements were $579.2 million as of December 31, 2024. 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, NGLs 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 and $400.0 million of 6.375% senior unsecured notes as of December 31, 2024.
Senior secured revolving line of credit. As of December 31, 2024, we had a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $3.0 billion and an aggregate amount of elected commitments of $1.5 billion that is due July 1, 2027. We had $445.0 million in net borrowings outstanding, primarily made in connection with the Arrangement, and $30.8 million of outstanding letters of credit, resulting in an unused borrowing base capacity of $1.0 billion as of December 31, 2024. Additionally, we are permitted to incur term loans in addition to the revolving loans provided under the Credit Facility. On November 4, 2024, we completed the semi-annual borrowing base redetermination, which affirmed the borrowing base of $3.0 billion and the aggregate amount of elected commitments of $1.5 billion and entered into the Sixth Amendment to the Amended and Restated Credit Agreement. In February 2025, we completed our semi-annual borrowing base redetermination, setting the borrowing base at $2.75 billion and increasing the aggregate amount of elected commitments to $2.0 billion.
For the year ended December 31, 2024, the weighted average interest rate incurred on borrowings under the Credit Facility was 7.27%, compared to 7.13% for the year ended December 31, 2023.
We were in compliance with the financial covenants in the Credit Facility at December 31, 2024. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information.
Senior unsecured notes. As of December 31, 2024, we had $400.0 million of 6.375% senior unsecured notes (the “Senior Notes”) that mature on June 1, 2026. Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information.
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Cash flows
The following table summarizes our changes in cash flows for the years presented:

| Year Ended December 31, |  |  |  |  |
| 2024 |  | 2023 |  |  |
| (In thousands) |  |  |  |  |
Net cash provided by operating activities | $ | 2,097,227 |  |  | $ | 1,819,851 |  |  |  |  |  |
Net cash used in investing activities | (1,753,817) |  |  | (1,430,306) |  |  |  |  |  |
Net cash used in financing activities | (624,458) |  |  | (664,698) |  |  |  |  |  |
Decrease in cash and cash equivalents | $ | (281,048) |  |  | $ | (275,153) |  |  |  |  |  |

For a discussion on cash flows for the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2023 Annual Report on Form 10-K filed with the SEC on February 26, 2024 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 $2.1 billion for the year ended December 31, 2024. The increase in net cash provided by operating activities of $277.4 million from the year ended December 31, 2023 was primarily due to an increase in oil revenues, offset by increases in LOE, merger-related costs, GPT costs and production taxes, as well as lower NGL and natural gas revenues and changes in our working capital. 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, 2024 and 2023, changes in working capital (as reflected in the Consolidated Statements of Cash Flows) decreased net cash flows from operating activities by $34.1 million and $91.9 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 $1.0 billion as of December 31, 2024, and excludes current hedge assets, which were $35.9 million as of December 31, 2024. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $1.2 million as of December 31, 2024.
Cash flows used in investing activities
For the year ended December 31, 2024, net cash used in investing activities of $1.8 billion was primarily attributable to capital expenditures incurred to develop our oil and gas properties of $1.2 billion and net cash paid for acquisitions of $655.0 million. The net cash paid for acquisitions 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 during the year ended December 31, 2024 also included proceeds from divestitures of $60.7 million and the receipt of a 2023 contingent consideration earn-out payment of $25.0 million in connection with a 2021 divestiture of certain oil and gas properties. Net cash used in investing activities for the year ended December 31, 2023 of $1.4 billion was primarily attributable to $905.7 million of capital expenditures, $361.6 million paid for the 2023 acquisition of acreage in the Williston Basin and $268.9 million associated with the settlement of derivative contracts, partially offset by $54.4 million of proceeds from divestitures and $40.6 million of proceeds from the sale of Energy Transfer units.
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Cash flows used in financing activities
For the year ended December 31, 2024, net cash used in financing activities of $624.5 million was primarily attributable to dividends paid to stockholders of $529.9 million, payments made to repurchase common stock of $444.2 million, payments for income tax withholdings on vested equity-based compensation awards of $63.4 million and repayments on the Enerplus Senior Notes of $63.0 million. These uses of cash were partially offset by borrowings under the Credit Facility of $3.5 billion, offset by repayments of $3.1 billion, resulting in net borrowings under the Credit Facility of $445.0 million, primarily made in connection with the Arrangement, and proceeds from the exercise of outstanding warrants of $35.8 million. Net cash used in financing activities for the year ended December 31, 2023 of $664.7 million was primarily attributable to dividends paid to shareholders of $500.3 million, payments to repurchase our common stock of $239.3 million and payments for income tax withholdings on vested equity-based compensation awards of $14.6 million, partially offset by proceeds from the exercise of outstanding warrants of $91.3 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, |  |  |
| 2024 |  | 2023 |  | 2022 |  |
| (In thousands) |  |  |
E&P(1) | $ | 1,229,263 |  |  | $ | 920,841 |  |  | $ | 495,947 |  |  |  |
Other capital expenditures(2) | 7,191 |  |  | 5,626 |  |  | 11,771 |  |  |  |
Total E&P and other capital expenditures(3) | 1,236,454 |  |  | 926,467 |  |  | 507,718 |  |  |  |
Acquisitions(4) | 15,951 |  |  | 361,609 |  |  | (2,275) |  |  |  |
Total capital expenditures from continuing operations(3)(6) | 1,252,405 |  |  | 1,288,076 |  |  | 505,443 |  |  |  |
Discontinued operations(5) | — |  |  | — |  |  | 3,396 |  |  |  |
Total capital expenditures(6) | $ | 1,252,405 |  |  | $ | 1,288,076 |  |  | $ | 508,839 |  |  |  |

__________________
(1)For the year ended December 31, 2024, capital expenditures related to the Marcellus Shale were $8.9 million.
(2)Other capital expenditures include items such as infrastructure capital, administrative capital and capitalized interest. Capitalized interest totaled $4.9 million, $4.1 million and $4.6 million for the years ended December 31, 2024, 2023 and 2022, respectively.
(3)Total capital expenditures for the year ended December 31, 2024 include approximately $25.2 million related to certain non-operated divested assets that are expected to be reimbursed.
(4)Excludes amounts attributable to the Arrangement, including cash consideration of $375.8 million, for the year ended December 31, 2024, and to the merger with Whiting Petroleum Corporation on July 1, 2022 (the “Merger”), including cash consideration of $245.4 million, for the year ended December 31, 2022.
(5)Represents capital expenditures attributable to our midstream assets that were classified as discontinued operations related to the merger of Oasis Midstream Partners LP (“OMP”) and OMP GP, OMP’s general partner, with and into a subsidiary of Crestwood Equity Partners LP (the “OMP Merger”).
(6)Total capital expenditures (including acquisitions) reflected in the table above differ from the amounts for capital expenditures and acquisitions 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, 2024, our total E&P and other capital expenditures increased $310.0 million to $1.2 billion primarily due to our expanded operations as a result of the Arrangement. We completed 93 net operated wells in 2024, compared to 69 net operated wells in 2023. Non-operated drilling and completion activities accounted for $135.9 million of our total E&P and other capital expenditures for the year ended December 31, 2024.
Additionally, on June 30, 2023, we completed the Williston Basin Acquisition for total cash consideration of $361.6 million. Refer to “Item 8. Financial Statements and Supplementary Data—Note 9—Acquisitions” for additional information.
Our planned 2025 E&P capital expenditures are expected to be approximately $1.3 billion to $1.5 billion. We expect to run four to five operated rigs during the majority of 2025 and plan to TIL approximately 130 to 150 gross operated wells with an average working interest of approximately 78%.
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.
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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, 2024, we declared base-plus-variable cash dividends of $10.15 per share of common stock, or $507.6 million in aggregate. On February 25, 2025, we declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 26, 2025 to shareholders of record as of March 11, 2025. At December 31, 2024, we had dividends payable of $16.7 million related to dividend equivalent rights accrued on equity-based compensation awards, including $16.1 million that was recorded under accrued liabilities and $0.6 million that was recorded under other liabilities on the Consolidated Balance Sheet.
During the year ended December 31, 2023, we declared base-plus-variable cash dividends of $11.88 per share of common stock, or $508.6 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 October 2024, our Board of Directors authorized a new share repurchase program covering up to $750 million of our common stock, which replaced the existing $750 million share repurchase program that was authorized in October 2023. We 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, 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 both the October 2024 and October 2023 share repurchase programs. As of December 31, 2024, there was $592.6 million of capacity remaining under the existing $750 million program.
During the year ended December 31, 2023, the Company repurchased 1,533,791 shares of common stock at a weighted average price of $157.08 per common share for a total cost of $240.9 million, excluding accrued excise taxes of $0.4 million under both the October 2023 and August 2022 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 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.
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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, 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 $75.48 per Bbl for crude oil and $2.13 per MMBtu for natural gas for the year ended December 31, 2024. 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 26.7 MMBoe and decrease the PV-10 by $2.0 billion, and a 10% increase in the SEC Price for crude oil and natural gas would increase our estimated net proved reserves by 21.4 MMBoe and increase the PV-10 by $2.0 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 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 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 more frequently if events or changes in circumstances indicate that the carrying amount might be impaired.
For the purpose of the goodwill impairment test, we first assesses qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value of the reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant
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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, NGLs and natural gas, is the reporting unit that carries our 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 management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of reserves prepared by our reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital rate.
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, NGLs and natural gas fluctuate as a result of a variety of factors, including changes in supply and demand and the macroeconomic environment, all of which are typically beyond our control. The markets for crude oil, NGLs and natural gas have been volatile, especially over the last several years and these prices will likely continue to be volatile in the future. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a portion of our future production. In addition, entering into derivative instruments could limit the benefit we would receive from increases in the prices for crude oil, NGLs and natural gas. We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on our 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, 2024 was a net asset of $16.2 million. A 10% increase in crude oil prices would decrease the fair value of this unrealized derivative asset position by approximately $55.9 million, while a 10% decrease in crude oil prices would increase the fair value of this unrealized derivative asset position by approximately $54.3 million. The fair value of our unrealized natural gas derivative positions at December 31, 2024 was a net liability of $1.6 million. A 10% increase in natural gas prices would decrease the fair value of this unrealized derivative liability position by approximately $6.3 million, while a 10% decrease in natural gas prices would increase the fair value of this unrealized derivative liability position by approximately $6.3 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.
In addition, in connection with the 2021 divestiture of certain oil and gas properties, we are entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI crude oil exceeds $60 per barrel for such year. As of December 31, 2024, the fair value of this contingent consideration was $22.8 million. We received $25.0 million related to the 2023 and 2024 earn-out payments in January 2024 and 2025, respectively.
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 and other derivatives.
Interest rate risk. At December 31, 2024, we had $400.0 million of senior unsecured notes at a fixed cash interest rate of 6.375% per annum.
At December 31, 2024, we had $445.0 million net borrowings outstanding and $30.8 million of outstanding letters of credit issued under the Credit Facility. Borrowings under the Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the amended and restated credit agreement). As of December 31, 2024, if interest rates were to increase by 100 basis points on the Credit Facility, the impact on our annual interest expense would not be material. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information on the interest incurred on the Credit Facility.
We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
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Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the year ended December 31, 2024, 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.
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. Similar to other companies in our industry, we experienced an increase in the costs of labor, materials and services beginning in 2022 due to a combination of factors, including: (i) global supply chain disruptions, (ii) increased demand for materials and services after COVID-19 and (iii) labor shortages. The combination of these factors increased our operating costs and capital expenditures. Costs of certain materials and services remained elevated in 2023 and 2024, and inflationary pressures could continue or increase in 2025. 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 2025; 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 238) | 80
Consolidated Balance Sheets at December 31, 2024 and December 31, 2023 | 83
Consolidated Statements of Operations for the Year Ended December 31, 2024, the Year Ended December 31, 2023 and the Year Ended December 31, 2022 | 85
Consolidated Statements of Changes in Stockholders’ Equity for the Year Ended December 31, 2024, the Year Ended December 31, 2023 and the Year Ended December 31, 2022 | 86
Consolidated Statements of Cash Flows for the Year Ended December 31, 2024, the Year Ended December 31, 2023 and the Year Ended December 31, 2022 | 87
Notes to Consolidated Financial Statements |
1. Organization and Operations of the Company | 89
2. Summary of Significant Accounting Policies | 89
3. Revenue Recognition | 99
4. Inventory | 99
5. Additional Balance Sheet Information | 100
6. Fair Value Measurements | 100
7. Derivative Instruments | 102
8. Property, Plant and Equipment | 105
9. Acquisitions | 106
10. Divestitures | 111
11. Discontinued Operations | 113
12. Investment in Unconsolidated Affiliate | 114
13. Long-Term Debt | 114
14. Asset Retirement Obligations | 116
15. Income Taxes | 116
16. Equity-Based Compensation | 118
17. Stockholders' Equity | 121
18. Earnings Per Share | 123
19. Leases | 124
20. Significant Concentrations | 126
21. Commitments and Contingencies | 126
22. Subsequent Events | 128
23. Supplemental Oil and Gas Disclosures — Unaudited | 128
24. Supplemental Oil and Gas Reserve Information — Unaudited | 129

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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, 2024 and 2023, 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, 2024, 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, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 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, 2024, 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.
As described in Management’s report on internal control over financial reporting, management has excluded Enerplus from its assessment and conclusion on the effectiveness of internal control over financial reporting as of December 31, 2024 as it was acquired by the Company in a purchase business combination on May 31, 2024. We have also excluded Enerplus from our audit of internal control over financial reporting. Enerplus is a wholly-owned subsidiary whose total assets and total revenues, excluded from management's assessment and our audit of internal control over financial reporting, represent approximately 46% and 16%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2024.
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
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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.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
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 $9.8 billion as of December 31, 2024. Depreciation, depletion and amortization (DD&A) expense for the year ended December 31, 2024 was $1.1 billion. Crude oil, 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. Reserve engineers prepare 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 and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, 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 data used by the specialists, and (iii) evaluating the specialists’ findings.
Arrangement with Enerplus Corporation (“Enerplus”) – Valuation of Oil and Gas Properties Acquired
As described in Notes 1 and 9 to the consolidated financial statements, on May 31, 2024, the Company completed the arrangement with Enerplus, which has been accounted for under the acquisition method of accounting. Under the acquisition method of accounting, the assets and liabilities of Enerplus have been recorded at their respective fair values as of the arrangement date. The Company recorded the assets acquired and liabilities assumed at their estimated fair values on May 31, 2024 of which $5.3 billion related to oil and gas properties. As disclosed by management, the fair value of the oil and gas properties was calculated using an income approach based on the net discounted cash flows that utilized inputs requiring significant judgment and assumptions, including future production volumes based upon estimates of reserves prepared by 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 principal considerations for our determination that performing procedures relating to the valuation of oil and gas properties acquired in the arrangement with Enerplus is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of future production volumes used in the discounted cash
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flow model, (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future production volumes, future commodity prices (adjusted for basis differentials), future operating and development costs, and the market-based weighted average cost of capital rate, and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
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 acquisition accounting, including controls over management’s valuation of oil and gas properties acquired. These procedures also included, among others, (i) reading the arrangement agreement, (ii) testing management’s process for developing the fair value estimate of oil and gas properties acquired, (iii) evaluating the appropriateness of the discounted cash flow model, (iv) testing the completeness and accuracy of underlying data used in the discounted cash flow model, and (v) evaluating the reasonableness of the significant assumptions used by management related to future production volumes, future commodity prices (adjusted for basis differentials), future operating and development costs, and the market-based weighted average cost of capital rate. Evaluating the reasonableness of management’s significant assumptions related to future commodity prices (adjusted for basis differentials) and future operating and development costs involved evaluating whether the assumptions used by management were reasonable considering (i) the past performance of Enerplus, (ii) the consistency with observable market data, and (iii) whether the assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the discounted cash flow model and (ii) the reasonableness of the market-based weighted average cost of capital rate significant assumption. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of future production volumes used in the discounted cash flow model. 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 data used by the specialists, and (iii) evaluating the specialists’ findings.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 27, 2025
We have served as the Company’s auditor since 2007.
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Table of Conten ts
Chord Energy Corporation
Consolidated Balance Sheets

| December 31,
| 2024 |  | 2023
| (In thousands, except share data)
ASSETS |  |  |
Current assets |  |  |
Cash and cash equivalents | $ | 36,950 |  |  | $ | 317,998 |
Accounts receivable, net | 1,298,973 |  |  | 943,114 |
Inventory | 94,299 |  |  | 72,565 |
Prepaid expenses | 30,875 |  |  | 42,450 |
Derivative instruments | 35,944 |  |  | 37,369 |
Other current assets | 82,077 |  |  | 11,055 |
Total current assets | 1,579,118 |  |  | 1,424,551 |
Property, plant and equipment |  |  |
Oil and gas properties (successful efforts method) | 12,770,786 |  |  | 6,320,243 |
Other property and equipment | 58,158 |  |  | 49,051 |
Less: accumulated depreciation, depletion and amortization | (2,142,775) |  |  | (1,054,616) |
Total property, plant and equipment, net | 10,686,169 |  |  | 5,314,678 |
Derivative instruments | 5,629 |  |  | 22,526 |
Investment in unconsolidated affiliate | 142,201 |  |  | 100,172 |
Long-term inventory | 25,973 |  |  | 22,936 |
Operating right-of-use assets | 38,004 |  |  | 21,343 |
Goodwill | 530,616 |  |  | — |
Other assets | 24,297 |  |  | 19,944 |
Total assets | $ | 13,032,007 |  |  | $ | 6,926,150 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |
Current liabilities |  |  |
Accounts payable | $ | 68,751 |  |  | $ | 34,453 |
Revenues and production taxes payable | 752,742 |  |  | 604,704 |
Accrued liabilities | 732,296 |  |  | 493,381 |
Accrued interest payable | 4,693 |  |  | 2,157 |
Derivative instruments | 1,230 |  |  | 14,209 |
Advances from joint interest partners | 2,434 |  |  | 2,381 |
Current operating lease liabilities | 37,629 |  |  | 13,258 |
Other current liabilities | 84,203 |  |  | 916 |
Total current liabilities | 1,683,978 |  |  | 1,165,459 |
Long-term debt | 842,600 |  |  | 395,902 |
Deferred tax liabilities | 1,496,442 |  |  | 95,322 |
Asset retirement obligations | 282,369 |  |  | 155,040 |
Derivative instruments | 1,016 |  |  | 717 |
Operating lease liabilities | 15,190 |  |  | 18,667 |
Other liabilities | 8,150 |  |  | 18,419 |
Total liabilities | 4,329,745 |  |  | 1,849,526 |

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Table of Conten ts

| December 31,
| 2024 |  | 2023
| (In thousands, except share data)
Commitments and contingencies (Note 21) |  |  |
Stockholders’ equity |  |  |
Common stock, $0.01 par value: 240,000,000 shares authorized, 66,967,779 shares issued and 60,070,893 shares outstanding at December 31, 2024; and 120,000,000 shares authorized, 45,032,537 shares issued and 41,249,658 shares outstanding at December 31, 2023 | 673 |  |  | 456 |
Treasury stock, at cost: 6,896,886 shares at December 31, 2024 and 3,782,879 shares at December 31, 2023 | (936,157) |  |  | (493,289) |
Additional paid-in capital | 7,336,091 |  |  | 3,608,819 |
Retained earnings | 2,301,655 |  |  | 1,960,638 |
Total stockholders’ equity | 8,702,262 |  |  | 5,076,624 |
Total liabilities and stockholders’ equity | $ | 13,032,007 |  |  | $ | 6,926,150 |

The accompanying notes are an integral part of these consolidated financial statements.
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Table of Conten ts
Chord Energy Corporation
Consolidated Statements of Operations

| Year Ended December 31, |  |  |  |  |
| 2024 |  | 2023 |  | 2022 |  |  |  |
| (In thousands, except share data) |  |  |
Revenues |  |  |  |  |  |  |  |  |  |
Oil, NGL and gas revenues | $ | 3,836,138 |  |  | $ | 3,132,411 |  |  | $ | 2,976,296 |  |  |  |  |  |
Purchased oil and gas sales | 1,414,944 |  |  | 764,230 |  |  | 670,174 |  |  |  |  |  |
Other services revenues | — |  |  | — |  |  | 324 |  |  |  |  |  |
Total revenues | 5,251,082 |  |  | 3,896,641 |  |  | 3,646,794 |  |  |  |  |  |
Operating expenses |  |  |  |  |  |  |  |  |  |
Lease operating expenses | 824,408 |  |  | 658,938 |  |  | 443,560 |  |  |  |  |  |
Gathering, processing and transportation expenses | 267,559 |  |  | 180,219 |  |  | 141,644 |  |  |  |  |  |
Purchased oil and gas expenses | 1,412,357 |  |  | 761,325 |  |  | 671,935 |  |  |  |  |  |
Production taxes | 333,397 |  |  | 260,002 |  |  | 229,571 |  |  |  |  |  |
Depreciation, depletion and amortization | 1,107,776 |  |  | 598,562 |  |  | 369,659 |  |  |  |  |  |
General and administrative expenses | 205,585 |  |  | 126,319 |  |  | 209,299 |  |  |  |  |  |
Exploration and impairment | 17,021 |  |  | 35,330 |  |  | 2,204 |  |  |  |  |  |
Total operating expenses | 4,168,103 |  |  | 2,620,695 |  |  | 2,067,872 |  |  |  |  |  |
Gain (loss) on sale of assets, net | 17,088 |  |  | (2,764) |  |  | 4,867 |  |  |  |  |  |
Operating income | 1,100,067 |  |  | 1,273,182 |  |  | 1,583,789 |  |  |  |  |  |
Other income (expense) |  |  |  |  |  |  |  |  |  |
Net gain (loss) on derivative instruments | 12,563 |  |  | 63,182 |  |  | (208,128) |  |  |  |  |  |
Net gain from investment in unconsolidated affiliate | 51,284 |  |  | 21,330 |  |  | 34,366 |  |  |  |  |  |
Interest expense, net of capitalized interest | (56,523) |  |  | (28,630) |  |  | (29,349) |  |  |  |  |  |
Other income, net | 5,047 |  |  | 9,964 |  |  | 2,901 |  |  |  |  |  |
Total other income (expense), net | 12,371 |  |  | 65,846 |  |  | (200,210) |  |  |  |  |  |
Income from continuing operations before income taxes | 1,112,438 |  |  | 1,339,028 |  |  | 1,383,579 |  |  |  |  |  |
Income tax (expense) benefit | (263,811) |  |  | (315,249) |  |  | 46,884 |  |  |  |  |  |
Net income from continuing operations | 848,627 |  |  | 1,023,779 |  |  | 1,430,463 |  |  |  |  |  |
Income from discontinued operations attributable to Chord, net of income tax | — |  |  | — |  |  | 425,696 |  |  |  |  |  |
Net income attributable to Chord | $ | 848,627 |  |  | $ | 1,023,779 |  |  | $ | 1,856,159 |  |  |  |  |  |
Earnings attributable to Chord per share: |  |  |  |  |  |  |  |  |  |
Basic from continuing operations (Note 18) | $ | 16.32 |  |  | $ | 24.59 |  |  | $ | 46.90 |  |  |  |  |  |
Basic from discontinued operations (Note 18) | — |  |  | — |  |  | 13.96 |  |  |  |  |  |
Basic total | $ | 16.32 |  |  | $ | 24.59 |  |  | $ | 60.86 |  |  |  |  |  |
Diluted from continuing operations (Note 18) | $ | 16.02 |  |  | $ | 23.51 |  |  | $ | 44.35 |  |  |  |  |  |
Diluted from discontinued operations (Note 18) | — |  |  | — |  |  | 13.20 |  |  |  |  |  |
Diluted total | $ | 16.02 |  |  | $ | 23.51 |  |  | $ | 57.55 |  |  |  |  |  |
Weighted average shares outstanding: |  |  |  |  |  |  |  |  |  |
Basic (Note 18) | 51,796 |  |  | 41,490 |  |  | 30,497 |  |  |  |  |  |
Diluted (Note 18) | 52,748 |  |  | 43,398 |  |  | 32,251 |  |  |  |  |  |

The accompanying notes are an integral part of these consolidated financial statements.
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Table of Conten ts
Chord Energy Corporation
Consolidated Statements of Changes in Stockholders’ Equity

| Attributable to Chord |  |  |  | Total Stockholders’ Equity
| Common Stock |  | Treasury Stock |  | Additional Paid-in-Capital |  | Retained Earnings |  | Non-controlling Interests |
| Shares |  | Amount |  | Shares |  | Amount |  |  |  |
| (In thousands)
Balance as of December 31, 2021 | 19,276 |  |  | $ | 200 |  |  | 871 |  |  | $ | (100,000) |  |  | $ | 863,010 |  |  | $ | 269,690 |  |  | $ | 188,673 |  |  | $ | 1,221,573 |
Equity-based compensation and vestings | 835 |  |  | 4 |  |  | — |  |  | — |  |  | 61,217 |  |  | — |  |  | 48 |  |  | 61,269 |
Tax withholding on vesting of equity-based awards | (345) |  |  | — |  |  | 35 |  |  | (4,789) |  |  | (36,963) |  |  | — |  |  | — |  |  | (41,752) |
Modification of equity-based awards | — |  |  | — |  |  | — |  |  | — |  |  | (226) |  |  | — |  |  | — |  |  | (226) |
Dividends | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (680,358) |  |  | — |  |  | (680,358) |
Transfer of equity plan shares from treasury | — |  |  | — |  |  | (35) |  |  | 4,789 |  |  | (4,789) |  |  | — |  |  | — |  |  | — |
Shares issued in Merger | 22,672 |  |  | 227 |  |  | — |  |  | — |  |  | 2,477,809 |  |  | — |  |  | — |  |  | 2,478,036 |
Replacement equity awards issued in Merger | — |  |  | — |  |  | — |  |  | — |  |  | 27,402 |  |  | — |  |  | — |  |  | 27,402 |
Replacement warrants issued in Merger | — |  |  | — |  |  | — |  |  | — |  |  | 79,774 |  |  | — |  |  | — |  |  | 79,774 |
Share repurchases | (1,378) |  |  | — |  |  | 1,378 |  |  | (151,950) |  |  | — |  |  | — |  |  | — |  |  | (151,950) |
Warrants exercised | 417 |  |  | 7 |  |  | — |  |  | — |  |  | 18,585 |  |  | — |  |  | — |  |  | 18,592 |
OMP Merger | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (191,032) |  |  | (191,032) |
Net income | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 1,856,159 |  |  | 2,311 |  |  | 1,858,470 |
Balance as of December 31, 2022 | 41,477 |  |  | 438 |  |  | 2,249 |  |  | (251,950) |  |  | 3,485,819 |  |  | 1,445,491 |  |  | — |  |  | 4,679,798 |
Equity-based compensation and vestings | 305 |  |  | 6 |  |  | — |  |  | — |  |  | 46,104 |  |  | — |  |  | — |  |  | 46,110 |
Tax withholding on settlement of equity-based awards | (105) |  |  | (1) |  |  | — |  |  | — |  |  | (14,603) |  |  | — |  |  | — |  |  | (14,604) |
Dividends | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (508,632) |  |  | — |  |  | (508,632) |
Share repurchases | (1,534) |  |  | — |  |  | 1,534 |  |  | (241,339) |  |  | — |  |  | — |  |  | — |  |  | (241,339) |
Warrants exercised | 1,107 |  |  | 13 |  |  | — |  |  | — |  |  | 91,499 |  |  | — |  |  | — |  |  | 91,512 |
Net income | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 1,023,779 |  |  | — |  |  | 1,023,779 |
Balance as of December 31, 2023 | 41,250 |  |  | 456 |  |  | 3,783 |  |  | (493,289) |  |  | 3,608,819 |  |  | 1,960,638 |  |  | — |  |  | 5,076,624 |
Shares issued in Arrangement | 20,680 |  |  | 207 |  |  | — |  |  | — |  |  | 3,731,930 |  |  | — |  |  | — |  |  | 3,732,137 |
Equity-based compensation and vestings | 834 |  |  | 6 |  |  | — |  |  | — |  |  | 22,990 |  |  | — |  |  | — |  |  | 22,996 |
Tax withholdings on settlement of equity-based awards | (391) |  |  | (3) |  |  | — |  |  | — |  |  | (63,383) |  |  | — |  |  | — |  |  | (63,386) |
Dividends | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (507,610) |  |  | — |  |  | (507,610) |
Share repurchases | (3,114) |  |  | — |  |  | 3,114 |  |  | (442,868) |  |  | — |  |  | — |  |  | — |  |  | (442,868) |
Warrants exercised | 812 |  |  | 7 |  |  | — |  |  | — |  |  | 35,735 |  |  | — |  |  | — |  |  | 35,742 |
Net income | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 848,627 |  |  | — |  |  | 848,627 |
Balance as of December 31, 2024 | 60,071 |  |  | $ | 673 |  |  | 6,897 |  |  | $ | (936,157) |  |  | $ | 7,336,091 |  |  | $ | 2,301,655 |  |  | $ | — |  |  | $ | 8,702,262 |

The accompanying notes are an integral part of these consolidated financial statements.
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Table of Conten ts
Chord Energy Corporation
Consolidated Statements of Cash Flows

| Year Ended December 31, |  |  |
| 2024 |  | 2023 |  | 2022 |  |
| (In thousands) |
Cash flows from operating activities: |  |  |  |  |  |  |  |
Net income including non-controlling interests | $ | 848,627 |  |  | $ | 1,023,779 |  |  | $ | 1,858,470 |  |  |  |
Adjustments to reconcile net income including non-controlling interests to net cash provided by operating activities: |  |  |  |  |  |  |  |
Depreciation, depletion and amortization | 1,107,776 |  |  | 598,562 |  |  | 369,659 |  |  |  |
(Gain) loss on sale of assets | (17,088) |  |  | 2,764 |  |  | (523,767) |  |  |  |
Impairment | 9,839 |  |  | 28,963 |  |  | (344) |  |  |  |
Deferred income taxes | 221,921 |  |  | 295,548 |  |  | 28,341 |  |  |  |
Net gain from investment in unconsolidated affiliate | (51,284) |  |  | (21,330) |  |  | (34,366) |  |  |  |
Net (gain) loss on derivative instruments | (12,563) |  |  | (63,182) |  |  | 208,128 |  |  |  |
Equity-based compensation expenses | 22,996 |  |  | 46,108 |  |  | 61,269 |  |  |  |
Deferred financing costs amortization and other | 1,056 |  |  | 505 |  |  | 3,194 |  |  |  |
Working capital and other changes: |  |  |  |  |  |  |  |
Change in accounts receivable, net | (7,746) |  |  | (147,870) |  |  | 84,041 |  |  |  |
Change in inventory | (14,307) |  |  | (12,659) |  |  | 8,756 |  |  |  |
Change in prepaid expenses | 10,850 |  |  | (1,199) |  |  | 3,423 |  |  |  |
Change in accounts payable, interest payable and accrued liabilities | 30,047 |  |  | 78,267 |  |  | (131,687) |  |  |  |
Change in other assets and liabilities, net | (52,897) |  |  | (8,405) |  |  | (11,091) |  |  |  |
Net cash provided by operating activities | 2,097,227 |  |  | 1,819,851 |  |  | 1,924,026 |  |  |  |
Cash flows from investing activities: |  |  |  |  |  |  |  |
Capital expenditures | (1,179,075) |  |  | (905,673) |  |  | (531,327) |  |  |  |
Acquisitions, net of cash acquired | (655,023) |  |  | (361,609) |  |  | (148,144) |  |  |  |
Proceeds from divestitures, net of cash divested | 60,748 |  |  | 54,445 |  |  | 169,198 |  |  |  |
Costs related to divestitures | — |  |  | — |  |  | (11,368) |  |  |  |
Derivative settlements | (12,672) |  |  | (268,887) |  |  | (633,025) |  |  |  |
Proceeds from sale of investment in unconsolidated affiliate | — |  |  | 40,612 |  |  | 428,231 |  |  |  |
Contingent consideration received | 25,000 |  |  | — |  |  | — |  |  |  |
Distributions from investment in unconsolidated affiliate | 7,205 |  |  | 10,806 |  |  | 43,873 |  |  |  |
Net cash used in investing activities | (1,753,817) |  |  | (1,430,306) |  |  | (682,562) |  |  |  |
Cash flows from financing activities: |  |  |  |  |  |  |  |
Proceeds from revolving credit facility | 3,535,000 |  |  | 260,000 |  |  | 1,035,000 |  |  |  |
Principal payments on revolving credit facility | (3,090,000) |  |  | (260,000) |  |  | (1,020,000) |  |  |  |
Cash paid to settle Enerplus senior notes | (63,000) |  |  | — |  |  | — |  |  |  |
Cash paid to settle Whiting debt | — |  |  | — |  |  | (2,154) |  |  |  |
Deferred financing costs | (3,313) |  |  | — |  |  | (5,997) |  |  |  |
Repurchases of common stock | (444,235) |  |  | (239,339) |  |  | (151,950) |  |  |  |
Tax withholding on vesting of equity-based awards | (63,386) |  |  | (14,604) |  |  | (41,752) |  |  |  |
Dividends paid | (529,910) |  |  | (500,304) |  |  | (654,728) |  |  |  |
Payments on finance lease liabilities | (1,458) |  |  | (1,702) |  |  | (1,299) |  |  |  |

87

Table of Conten ts

| Year Ended December 31, |  |  |
| 2024 |  | 2023 |  | 2022 |  |  |
| (In thousands) |
Proceeds from warrants exercised | 35,844 |  |  | 91,251 |  |  | 19,784 |  |  |  |
Net cash used in financing activities | (624,458) |  |  | (664,698) |  |  | (823,096) |  |  |  |
Increase (decrease) in cash and cash equivalents | (281,048) |  |  | (275,153) |  |  | 418,368 |  |  |  |
Cash and cash equivalents: |  |  |  |  |  |  |  |
Beginning of period | 317,998 |  |  | 593,151 |  |  | 174,783 |  |  |  |
End of period | $ | 36,950 |  |  | $ | 317,998 |  |  | $ | 593,151 |  |  |  |
Supplemental cash flow information: |  |  |  |  |  |  |  |
Cash paid for interest, net of capitalized interest | $ | 49,509 |  |  | $ | 26,371 |  |  | $ | 24,266 |  |  |  |
Cash paid for income taxes | 53,721 |  |  | 17,195 |  |  | 10,000 |  |  |  |
Supplemental non-cash transactions: |  |  |  |  |  |  |  |
Change in accrued capital expenditures | $ | 43,235 |  |  | $ | 45,513 |  |  | $ | (21,668) |  |  |  |
Change in asset retirement obligations | 6,220 |  |  | 1,238 |  |  | 852 |  |  |  |
Non-cash consideration exchanged in business combinations | 3,732,137 |  |  | — |  |  | 2,585,211 |  |  |  |
Investment in unconsolidated affiliate | — |  |  | — |  |  | 568,312 |  |  |  |
Dividends payable | 16,658 |  |  | 37,553 |  |  | 30,630 |  |  |  |

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 (together with its consolidated subsidiaries, the “Company” or “Chord”) is an independent exploration and production (“E&P”) company with quality and sustainable long-lived assets primarily located in the Williston Basin. The Company, formerly known as Oasis Petroleum Inc. (“Oasis”), was established upon completion of the merger with Whiting Petroleum Corporation (“Whiting”) on July 1, 2022 (the “Merger”). Whiting was an independent oil and gas company engaged in E&P activities primarily in the Rocky Mountains region of the United States.
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. As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after May 31, 2024. See Note 9—Acquisitions for additional information.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
Segment Information
The Company has evaluated how it is organized and managed and has identified only one reportable business segment, which is the E&P of crude oil, NGLs and natural gas. All of the Company’s operations and assets are primarily located in the United States, and substantially all of its revenues are attributable to United States customers.
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.
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
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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, NGLs and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGLs and natural gas, which are dependent upon numerous factors beyond its control such as economic, geopolitical, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile, and there can be no assurance that the prices for crude oil, NGLs or natural gas will not be subject to wide fluctuations in the future. A substantial or extended decline in prices for crude oil and, to a lesser extent, NGLs and natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows, the quantities of crude oil, NGLs 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 $4.9 million, $4.1 million and $4.6 million for the years ended December 31, 2024, 2023 and 2022, 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.
Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented:

| Year Ended December 31, |  |  |
| 2024 |  | 2023 |  | 2022 |  |
| (In thousands) |  |  |
Beginning of period | $ | — |  |  | $ | — |  |  | $ | 1 |  |  |  |
Exploratory well cost additions (pending determination of proved reserves) | — |  |  | — |  |  | 21 |  |  |  |
Exploratory well cost reclassifications (successful determination of proved reserves) | — |  |  | — |  |  | (2) |  |  |  |
Exploratory well dry hole costs (unsuccessful in adding proved reserves) | — |  |  | — |  |  | — |  |  |  |
Exploratory well cost reclassifications (canceled wells written off to predrill write-off) | — |  |  | — |  |  | (20) |  |  |  |
End of period | $ | — |  |  | $ | — |  |  | $ | — |  |  |  |

As of December 31, 2024, the Company had no exploratory well costs that were capitalized for a period of greater than one year after the completion of drilling.
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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, NGLs and natural gas, is the reporting unit that carries 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 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.
As of October 1, 2024, the Company performed a quantitative assessment as part of its annual goodwill impairment test, and determined that the fair value of the reporting unit substantially exceeded its carrying value. As a result, the Company determined that no adjustment to the carrying value of goodwill was necessary.
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.
Discontinued Operations
The OMP Merger (defined in Note 10—Divestitures) represented a strategic shift for the Company and qualified for reporting as a discontinued operation on February 1, 2022, in accordance with FASB ASC 205-20, Presentation of financial statements – Discontinued Operations (“ASC 205-20”). Accordingly, the results of operations of OMP (defined in Note 10—Divestitures) were classified as discontinued operations in the Consolidated Statements of Operations for the year ended December 31, 2022. There were no discontinued operations for the years ended December 31, 2024 or 2023. The Consolidated Statements of Cash Flows were not required to be reclassified for discontinued operations for any period. See Note 11—Discontinued Operations for additional information.
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Investment in Unconsolidated Affiliate
On February 1, 2022, the Company completed the OMP Merger (defined in Note 10—Divestitures) and received common units representing limited partner interests of Crestwood Equity Partners LP, a Delaware limited partnership (“Crestwood”). The Company elected to account for its investment in Crestwood using the fair value option under FASB ASC 825-10, Financial Instruments. Under the fair value option, the Company measures the carrying amount of its investment in Crestwood at fair value each reporting period, with changes in fair value recorded to net gain from investment in unconsolidated affiliate on the Consolidated Statement of Operations. Cash distributions from Crestwood are recorded to net gain from investment in unconsolidated affiliate on the Consolidated Statement of Operations and distributions from investment in unconsolidated affiliate on the Consolidated Statement of Cash Flows. In August 2023, Crestwood and Energy Transfer LP (“Energy Transfer”) entered into a definitive merger agreement to which Energy Transfer would acquire Crestwood. On November 3, 2023, Energy Transfer completed their acquisition of Crestwood, and holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood unit held. See Note 6—Fair Value Measurements, Note 10—Divestitures and Note 12—Investment in Unconsolidated Affiliate for additional information.
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 13—Long-Term Debt) are included in other assets on the Company’s Consolidated Balance Sheets, while deferred financing costs related to the Senior Notes (defined in Note 13—Long-Term Debt) are included as a reduction of long-term debt on the Company’s Consolidated Balance Sheets.
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 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, NGLs 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
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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, NGLs 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 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.
The Company has elected practical expedients under ASC 842, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs; the use-of-hindsight practical expedient; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-lease components for all asset classes. In addition, the Company elected not to apply the recognition requirements of ASC 842 to leases with terms of one year or less, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight-line basis. See Note 19—Leases for additional information.
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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, NGLs 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 natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, NGLs 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 partners for their respective portions of operating expenses and development costs. While certain of these customers and joint interest partners 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. As of December 31, 2024, the Company utilized fixed-price swaps and 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
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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, 2024, the Company had derivatives in place with 15 counterparties, all of which are secured parties under the Credit Facility (defined in Note 13—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.
The Company’s derivative contracts are documented with industry-standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross-collateralization with the properties securing the Credit Facility (defined in Note 13—Long-Term Debt). As of December 31, 2024, the Company was in compliance with these requirements.
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 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.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 21—Commitments and Contingencies for additional information regarding the Company’s contingencies.
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, 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
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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 16—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 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 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 November 2023, the FASB issued ASU No. 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures” (“ASU 2023-07”). This standard clarifies that single reportable segment entities are subject to the disclosure requirements under Topic 280 in its entirety. This ASU is effective for fiscal years beginning after December 15, 2023 and interim periods within those fiscal years beginning after December 15, 2024. The Company adopted this ASU effective December 31, 2024, and applied the amendments retrospectively to all prior periods presented in its consolidated financial statements (see Basis of Presentation above).
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 expects to adopt this ASU effective January 1, 2025, and the adoption is not expected to affect the Company’s financial position or results of operations, but will result in additional disclosures.
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In November 2024, the FASB issued ASU No. 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses” (“ASU 2024-03”). This standard requires that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating this ASU to determine its impact on the Company’s annual financial statement disclosures.
3. Revenue Recognition
Revenues associated with contracts with customers were as follows for the periods presented:

| Year Ended December 31, |  |  |
| 2024 |  | 2023 |  | 2022 |  |
| (In thousands)
Crude oil revenues | $ | 3,571,336 |  |  | $ | 2,835,962 |  |  | $ | 2,366,995 |  |  |  |
Purchased crude oil sales | 1,376,860 |  |  | 709,817 |  |  | 511,020 |  |  |  |
NGL and natural gas revenues | 264,802 |  |  | 296,449 |  |  | 609,301 |  |  |  |
Purchased NGL and natural gas sales | 38,084 |  |  | 54,413 |  |  | 159,154 |  |  |  |
Other services revenues | — |  |  | — |  |  | 324 |  |  |  |
Total revenues | $ | 5,251,082 |  |  | $ | 3,896,641 |  |  | $ | 3,646,794 |  |  |  |

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 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,
| 2024 |  | 2023
| (In thousands)
Inventory |  |  |
Equipment and materials | $ | 47,121 |  |  | $ | 30,201 |
Crude oil inventory | 47,178 |  |  | 42,364 |
Total inventory | $ | 94,299 |  |  | $ | 72,565 |
Long-term inventory |  |  |
Linefill in third-party pipelines | $ | 25,973 |  |  | $ | 22,936 |
Total long-term inventory | $ | 25,973 |  |  | $ | 22,936 |
Total | $ | 120,272 |  |  | $ | 95,501 |

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5. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:

| December 31,
| 2024 |  | 2023
| (In thousands)
Accounts receivable, net |  |  |
Trade and other accounts | $ | 1,029,343 |  |  | $ | 749,356 |
Joint interest accounts | 283,696 |  |  | 207,571 |
Total accounts receivable | 1,313,039 |  |  | 956,927 |
Less: allowance for credit losses | (14,066) |  |  | (13,813) |
Total accounts receivable, net | $ | 1,298,973 |  |  | $ | 943,114 |
Revenues and production taxes payable |  |  |
Royalties payable and revenue suspense | $ | 706,674 |  |  | $ | 564,235 |
Production taxes payable | 46,068 |  |  | 40,469 |
Total revenue and production taxes payable | $ | 752,742 |  |  | $ | 604,704 |
Accrued liabilities |  |  |
Accrued oil and gas marketing | $ | 203,899 |  |  | $ | 165,141 |
Accrued capital costs | 252,827 |  |  | 122,260 |
Accrued lease operating expenses | 148,837 |  |  | 107,606 |
Accrued general and administrative expenses | 61,319 |  |  | 37,882 |
Current portion of asset retirement obligations | 26,065 |  |  | 10,507 |
Accrued dividends | 16,062 |  |  | 25,167 |
Other accrued liabilities | 23,287 |  |  | 24,818 |
Total accrued liabilities | $ | 732,296 |  |  | $ | 493,381 |

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 14—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
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
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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, 2024
| Level 1 |  | Level 2 |  | Level 3 |  | Total
| (In thousands)
Assets: |  |  |  |  |  |  |
Commodity derivative contracts (see Note 7) | $ | — |  |  | $ | 18,793 |  |  | $ | — |  |  | $ | 18,793 |
Contingent consideration (see Note 7) | — |  |  | 22,780 |  |  | — |  |  | 22,780 |
Investment in unconsolidated affiliate (see Note 12) | 142,201 |  |  | — |  |  | — |  |  | 142,201 |
Total assets | $ | 142,201 |  |  | $ | 41,573 |  |  | $ | — |  |  | $ | 183,774 |
Liabilities: |  |  |  |  |  |  |
Commodity derivative contracts (see Note 7) | $ | — |  |  | $ | 2,246 |  |  | $ | — |  |  | $ | 2,246 |
Total liabilities | $ | — |  |  | $ | 2,246 |  |  | $ | — |  |  | $ | 2,246 |

| Fair value at December 31, 2023
| Level 1 |  | Level 2 |  | Level 3 |  | Total
| (In thousands)
Assets: |  |  |  |  |  |  |
Commodity derivative contracts (see Note 7) | $ | — |  |  | $ | 11,312 |  |  | $ | 5,877 |  |  | $ | 17,189 |
Contingent consideration (see Note 7) | — |  |  | 42,706 |  |  | — |  |  | 42,706 |
Investment in unconsolidated affiliate (see Note 12) | 100,172 |  |  | — |  |  | — |  |  | 100,172 |
Total assets | $ | 100,172 |  |  | $ | 54,018 |  |  | $ | 5,877 |  |  | $ | 160,067 |
Liabilities: |  |  |  |  |  |  |
Commodity derivative contracts (see Note 7) | $ | — |  |  | $ | 14,926 |  |  | $ | — |  |  | $ | 14,926 |
Total liabilities | $ | — |  |  | $ | 14,926 |  |  | $ | — |  |  | $ | 14,926 |

Commodity derivative contracts. The Company enters into commodity derivative contracts to manage risks related to changes in crude oil, NGL and natural gas prices. The Company’s swaps and collars are valued by a third-party preparer based on an income approach. The significant inputs used are commodity prices, discount rate and the contract terms of the derivative instruments. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the fair value hierarchy. The Company 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 Company recorded a credit risk adjustment to reduce the fair value of its net derivative asset for these contracts by $1.0 million at December 31, 2024 and by $0.5 million at December 31, 2023. See Note 7—Derivative Instruments for additional information.
Transportation derivative contracts. The Company had a buy/sell transportation contract as of December 31, 2023 that was a derivative contract for which the Company had not elected the “normal purchase normal sale” exclusion under FASB ASC 815, Derivatives and Hedging. This transportation derivative contract was valued by a third-party preparer based on an income approach. The significant inputs used were quoted forward prices for commodities, market differentials for crude oil and either the Company’s or the counterparty’s nonperformance risk, as appropriate. The assumptions used in the valuation of this contract included certain market differential metrics that were unobservable during the term of the contract. Such unobservable inputs were significant to the contract valuation methodology, and the contract’s fair value was therefore designated as Level 3 within the fair value hierarchy as of December 31, 2023. As of June 30, 2024, the term of this contract had expired. See Note 7—Derivative Instruments for additional information.
Contingent consideration. In connection with the 2021 divestiture of certain oil and gas properties, the Company is entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX WTI exceeds $60 per barrel for such year (the “Contingent Consideration”). The fair value of the Contingent
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Consideration is determined by a third-party preparer using a Monte Carlo simulation model and Ornstein-Uhlenbeck pricing process. The significant inputs include NYMEX WTI forward price curve, volatility, mean reversion rate and counterparty credit risk adjustment. The Company determined these were Level 2 fair value inputs that are substantially observable in active markets or can be derived from observable data. In each of January 2024 and 2025, the Company received $25.0 million related to the 2023 and 2024 earn-out payments, respectively. See Note 7—Derivative Instruments for additional information.
Investment in unconsolidated affiliate. In connection with the OMP Merger (defined in Note 10—Divestitures), the Company received common units in Crestwood, which are accounted for using the fair value option under FASB ASC 825-10, Financial Instruments. On November 3, 2023, Energy Transfer completed their acquisition of Crestwood. For the years ended December 31, 2024 and 2023, 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, 2024 and December 31, 2023, respectively. See Note 12—Investment in Unconsolidated Affiliate for additional information.
Non-Financial Assets and Liabilities
The fair value of the Company’s non-financial assets and liabilities measured on a non-recurring basis are determined using valuation techniques that include Level 3 inputs.
Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, environmental and regulatory environments.
Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials), estimates of future operating and development costs and a risk-adjusted discount rate.
Business Combinations. For the following acquisitions, 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 forward strip price curves (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.
•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.
•Williston Basin Acquisition. On June 30, 2023, the Company completed the Williston Basin Acquisition (defined in Note 9—Acquisitions). The assets acquired and liabilities assumed were recorded at fair value as of June 30, 2023.
•Whiting Merger. On July 1, 2022, the Company completed the Merger with Whiting. The assets acquired and liabilities assumed were recorded at fair value as of July 1, 2022.
See Note 9—Acquisitions for additional information.
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
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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 call 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, 2024, the Company had the following outstanding commodity derivative contracts:

Commodity |  | Settlement Period |  | Derivative Instrument |  |  |  | Volumes |  | Weighted Average Prices
|  |  |  |  | Fixed-Price Swaps |  |  |  | Sub-Floor |  | Floor |  | Ceiling
Crude oil |  | 2025 |  | Two-way collars |  |  |  | 5,838,000 |  | Bbls |  |  |  |  |  |  |  | $ | 64.22 |  |  | $ | 77.75 |
Crude oil |  | 2025 |  | Three-way collars |  |  |  | 2,371,000 |  | Bbls |  |  |  |  |  | $ | 52.69 |  |  | $ | 67.69 |  |  | $ | 82.14 |
Crude oil |  | 2025 |  | Fixed-price swaps |  |  |  | 1,092,000 |  | Bbls |  | $ | 70.90 |  |  |  |  |  |  |  |  |
Crude oil |  | 2026 |  | Three-way collars |  |  |  | 3,270,000 |  | Bbls |  |  |  |  |  | $ | 51.38 |  |  | $ | 66.38 |  |  | $ | 78.72 |
Crude oil |  | 2026 |  | Two-way collars |  |  |  | 730,000 |  | Bbls |  |  |  |  |  |  |  | $ | 65.00 |  |  | $ | 71.83 |
Natural gas |  | 2025 |  | Two-way collars |  |  |  | 1,380,000 |  | MMBtu |  |  |  |  |  |  |  | $ | 3.00 |  |  | $ | 4.18 |
Natural gas |  | 2025 |  | Fixed price swaps |  |  |  | 7,521,600 |  | MMBtu |  | $ | 3.65 |  |  |  |  |  |  |  |  |
Natural gas |  | 2026 |  | Two-way collars |  |  |  | 2,262,500 |  | MMBtu |  |  |  |  |  |  |  | $ | 3.00 |  |  | $ | 4.73 |
Natural gas |  | 2026 |  | Fixed-price swaps |  |  |  | 8,212,500 |  | MMBtu |  | $ | 3.74 |  |  |  |  |  |  |  |  |

Subsequent to December 31, 2024, 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 |  | 2025 |  | Fixed-price swaps |  | 2,015,000 |  |  | Bbls |  | $ | 70.45 |  |  |  |  |  |  |
Crude oil |  | 2025 |  | Two-way collars |  | 91,000 |  |  | Bbls |  |  |  |  |  | $ | 65.00 |  |  | $ | 77.35 |
Crude oil |  | 2026 |  | Three-way collars |  | 730,000 |  |  | Bbls |  |  |  | $ | 50.00 |  |  | $ | 65.00 |  |  | $ | 73.93 |
Crude oil |  | 2026 |  | Fixed-price swaps |  | 180,000 |  |  | Bbls |  | $ | 68.67 |  |  |  |  |  |  |
Crude oil |  | 2027 |  | Three-way collars |  | 182,000 |  |  | Bbls |  |  |  | $ | 50.00 |  |  | $ | 65.00 |  |  | $ | 74.15 |
Natural gas |  | 2025 |  | Fixed-price swaps |  | 15,640,000 |  |  | MMBtu |  | $ | 4.12 |  |  |  |  |  |  |
Natural gas |  | 2026 |  | Fixed-price swaps |  | 8,220,000 |  |  | MMBtu |  | $ | 3.94 |  |  |  |  |  |  |
Natural gas |  | 2026 |  | Two-way collars |  | 5,430,000 |  |  | MMBtu |  |  |  |  |  | $ | 3.83 |  |  | $ | 4.26 |

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. As of December 31, 2023, the estimated fair value of the remaining contract was a $5.9 million asset, which was classified as a current derivative asset on the Company’s Consolidated Balance Sheet. 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 is 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, 2024, the estimated fair value of the Contingent Consideration was classified as a current derivative asset of $22.8 million on the Consolidated Balance Sheet. See Note 6—Fair Value Measurements for additional information.
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Table of Conten ts
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 |  | 2024 |  | 2023 |  | 2022
|  |  |  | (In thousands)
Commodity derivatives |  | Net gain (loss) on derivative instruments |  | $ | 7,489 |  |  | $ | 56,396 |  |  | $ | (224,238) |
Commodity derivatives (buy/sell transportation contracts) |  | Gathering, processing and transportation expenses(1) |  | (5,877) |  |  | 20,570 |  |  | 7,331 |
Contingent consideration |  | Net gain on derivative instruments |  | 5,074 |  |  | 6,786 |  |  | 16,110 |

__________________
(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 years ended December 31, 2023 and 2022.
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.
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, 2024
Derivative Instrument |  | Balance Sheet Location |  | Gross Amount |  | Gross Amount Offset |  | Net Amount
|  |  |  | (In thousands)
Derivatives assets: |  |  |  |  |  |  |  |
Commodity derivatives |  | Derivative instruments — current assets |  | $ | 33,579 |  |  | $ | (20,415) |  |  | $ | 13,164 |
Contingent consideration |  | Derivative instruments — current assets |  | 22,780 |  |  | — |  |  | 22,780 |
Commodity derivatives |  | Derivative instruments — non-current assets |  | 31,676 |  |  | (26,047) |  |  | 5,629 |
Total derivatives assets |  |  |  | $ | 88,035 |  |  | $ | (46,462) |  |  | $ | 41,573 |
Derivatives liabilities: |  |  |  |  |  |  |  |
Commodity derivatives |  | Derivative instruments — current liabilities |  | $ | 21,645 |  |  | $ | (20,415) |  |  | $ | 1,230 |
Commodity derivatives |  | Derivative instruments — non-current liabilities |  | 27,063 |  |  | (26,047) |  |  | 1,016 |
Total derivatives liabilities |  | $ | 48,708 |  |  | $ | (46,462) |  |  | $ | 2,246 |

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Table of Conten ts

|  |  |  | December 31, 2023
Derivative Instrument |  | Balance Sheet Location |  | Gross Amount |  | Gross Offset Amount |  | Net Amount
|  |  |  | (In thousands)
Derivatives assets: |  |  |  |  |  |  |  |
Commodity derivatives |  | Derivative instruments — current assets |  | $ | 20,647 |  |  | $ | (11,769) |  |  | $ | 8,878 |
Contingent consideration |  | Derivative instruments — current assets |  | 22,614 |  |  | — |  |  | 22,614 |
Commodity derivatives (buy/sell transportation contracts) |  | Derivative instruments — current assets |  | 5,877 |  |  | — |  |  | 5,877 |
Commodity derivatives |  | Derivative instruments — non-current assets |  | 16,760 |  |  | (14,326) |  |  | 2,434 |
Contingent consideration |  | Derivative instruments — non-current assets |  | 20,092 |  |  | — |  |  | 20,092 |
Total derivatives assets |  |  |  | $ | 85,990 |  |  | $ | (26,095) |  |  | $ | 59,895 |
Derivatives liabilities: |  |  |  |  |  |  |  |
Commodity derivatives |  | Derivative instruments — current liabilities |  | $ | 25,978 |  |  | $ | (11,769) |  |  | $ | 14,209 |
Commodity derivatives |  | Derivative instruments — non-current liabilities |  | 15,043 |  |  | (14,326) |  |  | 717 |
Total derivatives liabilities |  | $ | 41,021 |  |  | $ | (26,095) |  |  | $ | 14,926 |

8. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment:

| December 31,
| 2024 |  | 2023
| (In thousands)
Proved oil and gas properties | $ | 11,923,792 |  |  | $ | 6,220,766 |
Less: Accumulated depletion | (2,115,428) |  |  | (1,035,393) |
Proved oil and gas properties, net | 9,808,364 |  |  | 5,185,373 |
Unproved oil and gas properties | 846,994 |  |  | 99,477 |
Other property and equipment | 58,158 |  |  | 49,051 |
Less: Accumulated depreciation and impairment | (27,347) |  |  | (19,223) |
Other property and equipment, net | 30,811 |  |  | 29,828 |
Total property, plant and equipment, net | $ | 10,686,169 |  |  | $ | 5,314,678 |

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.
Proved oil and gas properties. The Company estimates the expected undiscounted future cash flows of its proved oil and gas properties by field and then compares such amount to the carrying amount of the proved oil and gas properties in the applicable field to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company adjusts the carrying amount of the proved 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, recent sales prices of comparable properties, the present value of future cash flows net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production volume estimates, the timing and pace of development, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows. These assumptions represent Level 3 inputs, as further discussed under Note 6—Fair Value Measurements. During the year ended December 31, 2023 the Company recorded impairment charges of $5.6 million, primarily related to the Non-core Asset Sales (defined in Note 10—Divestitures). For the years ended December 31, 2024 and 2022, the Company did not record impairment of proved oil and gas properties.
Unproved oil and gas properties. For the years ended December 31, 2024, 2023 and 2022, the Company did not record impairment of unproved oil and gas properties.
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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, 2024, 2023 and 2022, the Company did not record impairment of other property and equipment.
9. Acquisitions
2024 Acquisition
On May 31, 2024, the Company completed the Arrangement with Enerplus and issued 20,680,097 shares of common stock and paid $375.8 million of cash to Enerplus shareholders. Also on May 31, 2024, and pursuant to the Arrangement Agreement, the Company (i) paid cash to settle Enerplus equity-based compensation awards, (ii) paid cash to satisfy and discharge in full the Enerplus credit facility and (iii) paid a cash retention bonus to Enerplus employees.
Preliminary purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the Arrangement at their estimated fair value on May 31, 2024 of $4.1 billion. Goodwill was recognized as a result of the Arrangement, none of which is deductible for income tax purposes. Goodwill is primarily attributable to additional operational and financial synergies expected to be realized from the combined operations. Determining the fair value of the assets and liabilities of Enerplus requires judgement 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 preliminary 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. As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after May 31, 2024, which may result in a different allocation than that presented in the tables below. Since the acquisition date, the Company has recorded an adjustment to the purchase price allocation, and a corresponding decrease to goodwill, totaling $9.2 million. Certain estimated values for the acquisition, including oil and natural gas properties, are not yet finalized and are subject to revision as additional information becomes available and more detailed analyses are completed.

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

__________________
1) The Company issued 20,680,097 shares of common stock 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 17—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 17—Stockholders’ Equity for additional information.
3) On May 31, 2024, the Company fully satisfied all obligations under the Enerplus credit facility, and the Enerplus credit facility was concurrently terminated. See Note 13— Long-Term Debt for additional information.
4) In connection with the Arrangement, employees of Enerplus were paid a retention bonus upon the closing of the Arrangement totaling $5.9 million.
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Table of Conten ts

|  | Preliminary Purchase Price Allocation
|  | (In thousands)
Assets acquired: |  |
Cash and cash equivalents |  | $ | 239,921 |
Accounts receivable, net |  | 281,492 |
Inventory |  | 14,878 |
Prepaid expenses |  | 16,323 |
Oil and gas properties (successful efforts method) |  | 5,253,860 |
Other property and equipment |  | 6,812 |
Long-term inventory |  | 8,636 |
Operating right-of-use assets |  | 42,954 |
Other assets |  | 1,049 |
Total assets acquired |  | $ | 5,865,925 |
Liabilities assumed: |  |
Accounts payable |  | $ | 1,965 |
Revenues and production taxes payable |  | 199,706 |
Accrued liabilities |  | 186,334 |
Current portion of long-term debt |  | 60,063 |
Current operating lease liabilities |  | 27,420 |
Deferred tax liabilities |  | 1,179,200 |
Asset retirement obligations |  | 115,056 |
Operating lease liabilities |  | 15,534 |
Total liabilities assumed |  | $ | 1,785,278 |
Net assets acquired |  | $ | 4,080,647 |
Goodwill |  | 530,616 |
Purchase price consideration |  | $ | 4,611,263 |

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 |  |  |  | $ | 866,382 |
Income before income taxes |  |  |  | 81,698 |

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 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.
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Table of Conten ts

|  |  |  | Year Ended December 31,
|  |  |  | 2024 |  | 2023
|  |  |  | (In thousands, except per share data)
Revenues |  |  |  | $ | 5,852,567 |  |  | $ | 5,442,727 |
Net income |  |  |  | 1,030,629 |  |  | 1,305,443 |
Net income per share: |  |  |  |  |  |
Basic |  |  |  | $ | 17.06 |  |  | $ | 21.00 |
Diluted |  |  |  | 16.80 |  |  | 20.37 |

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 Energy Inc. and affiliates, each a subsidiary of Exxon Mobil Corporation (collectively “XTO”), for total cash consideration of $375.0 million, subject to customary purchase price adjustments (the “Williston Basin Acquisition”). The effective date of the Williston Basin Acquisition was April 1, 2023.
On June 30, 2023, the Company completed the 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 Williston Basin Acquisition with cash on hand. The 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 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 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 goodwill or bargain purchase gain being recognized. Determining the fair value of the assets and liabilities of the Williston Basin Acquisition required judgement 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 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 |  | $ | 361,609 |

|  | Preliminary Purchase Price Allocation
|  | (In thousands)
Assets acquired: |  |
Oil and gas properties (successful efforts method) |  | $ | 367,672 |
Inventory |  | 1,844 |
Total assets acquired |  | $ | 369,516 |
Liabilities assumed: |  |
Asset retirement obligations |  | $ | 6,771 |
Revenue and production taxes payable |  | 1,136 |
Total liabilities assumed |  | $ | 7,907 |
Net assets acquired |  | $ | 361,609 |

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Table of Conten ts
2022 Acquisitions
On March 7, 2022, Oasis and Whiting entered into an Agreement and Plan of Merger (the “Merger Agreement”), which provided for, among other things, the combination of Oasis and Whiting in a merger of equals transaction. On July 1, 2022, the Company completed the Merger with Whiting and issued 22,671,871 shares of common stock and paid $245.4 million of cash to Whiting stockholders. Also on July 1, 2022 and pursuant to the Merger Agreement, the Company (i) assumed the outstanding Whiting Series A Warrants and Whiting Series B Warrants, (ii) assumed the outstanding Whiting equity-based compensation awards and (iii) paid cash to satisfy and discharge in full the Whiting credit facility.
Purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the Merger at their estimated fair value on July 1, 2022 of $2.8 billion. The allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no goodwill or bargain purchase gain being recognized. Determining the fair value of the assets and liabilities of Whiting required judgement 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 identifiable assets acquired and liabilities assumed as of the acquisition date on July 1, 2022. As of December 31, 2023, the purchase price was finalized with no adjustment to the preliminary purchase price allocation.

|  | Purchase Price Consideration
|  | (In thousands)
Common stock issued to Whiting stockholders(1) |  | $ | 2,478,036 |
Cash paid to Whiting stockholders(1) |  | 245,436 |
Replacement of Whiting Series A Warrants and Whiting Series B Warrants(2) |  | 79,774 |
Replacement of Whiting equity-based compensation awards(3) |  | 27,402 |
Cash paid to settle Whiting credit facility(4) |  | 2,154 |
Total consideration transferred |  | $ | 2,832,802 |

__________________
(1) The Company issued 22,671,871 shares of common stock and paid $245.4 million of cash to Whiting stockholders as Merger consideration. Each holder of Whiting common stock received 0.5774 shares of common stock as share consideration and $6.25 of cash as cash consideration. The fair value of the common stock issued was based on the closing price of the Company’s common stock on July 1, 2022 of $109.30.
(2) The Company assumed (i) 4,833,455 Whiting Series A Warrants and (ii) 2,418,832 Whiting Series B Warrants. The replacement of Whiting Series A and B Warrants was based on the closing price of the warrants on July 1, 2022 of $11.25 and $10.50, respectively. See Note 17—Stockholders’ Equity for additional information.
(3) The Whiting equity awards were replaced with awards issued by Chord with similar terms and conditions as the original awards. The fair value of the replacement equity awards attributable to pre-Merger service was recorded as consideration transferred. See Note 16— Equity-Based Compensation for additional information.
(4) On July 1, 2022, the Company fully satisfied all obligations under the Whiting credit facility and the Whiting credit facility was concurrently terminated. See Note 13—Long-Term Debt for additional information.
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Table of Conten ts

|  | Purchase Price Allocation
|  | (In thousands)
Assets acquired: |  |
Cash and cash equivalents |  | $ | 94,641 |
Accounts receivable, net |  | 491,514 |
Inventory |  | 35,256 |
Prepaid expenses |  | 14,851 |
Other current assets |  | 5,719 |
Current assets held for sale |  | 16,074 |
Oil and gas properties (successful efforts method) |  | 3,211,043 |
Other property and equipment |  | 31,244 |
Long-term inventory |  | 3,138 |
Operating right-of-use assets |  | 15,752 |
Deferred tax assets |  | 228,574 |
Other assets |  | 3,346 |
Total assets acquired |  | $ | 4,151,152 |
Liabilities assumed: |  |
Accounts payable |  | $ | 116,769 |
Revenues and production taxes payable |  | 411,553 |
Accrued liabilities |  | 215,218 |
Derivatives instruments (current liability) |  | 471,693 |
Current operating lease liabilities |  | 2,629 |
Other current liabilities |  | 2,902 |
Current liabilities held for sale |  | 9,410 |
Asset retirement obligations |  | 57,197 |
Derivative instruments (long-term liability) |  | 15,128 |
Operating lease liabilities |  | 13,123 |
Other liabilities |  | 2,728 |
Total liabilities assumed |  | $ | 1,318,350 |
Net assets acquired |  | $ | 2,832,802 |

Post-merger operating results. The results of operations of Whiting have been included in the Company’s consolidated financial statements since the closing of the Merger on July 1, 2022. The following table summarizes the total revenues and income from continuing operations before income taxes attributable to Whiting that were recorded in the Company’s Consolidated Statement of Operations for the period presented.

|  | Year Ended December 31, 2022
|  | (In thousands)
Revenues |  | $ | 1,044,079 |
Income from continuing operations before income taxes |  | 553,686 |

Other information. The Company recorded an assumed liability of $18.0 million in accrued liabilities on the Consolidated Balance Sheet as of July 1, 2022 related to success-based transaction costs that were incurred by Whiting prior to the consummation of the Merger. These amounts were paid during the year ended December 31, 2022.
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In addition, the Company recorded an assumed liability of $55.0 million in accrued liabilities on the Consolidated Balance Sheet as of July 1, 2022 related to a loss contingency from a legal proceeding with Arguello Inc. and Freeport-McMoRan Oil & Gas LLC that the Company determined was both probable and reasonably estimable under FASB ASC 450-20, Loss Contingencies as of the consummation of the Merger. See Note 21—Commitments and Contingencies for additional information.
Unaudited pro forma financial information. Summarized below are the consolidated results of operations for the period presented, on an unaudited pro forma basis, as if the Merger had occurred on January 1, 2021 (the beginning of the comparable prior reporting period). 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 Merger, including transaction costs incurred by the Company and Whiting. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Merger 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 Merger or any estimated costs that have not yet been incurred by the Company to integrate the Whiting assets.

|  | Year Ended December 31, 2022
|  | (In thousands, except per share data)
Revenues |  | $ | 4,759,706 |  |  |  |  |
Net income attributable to Chord |  | 2,093,776 |  |  |  |  |
Net income attributable to Chord per share: |  |  |  |  |  |
Basic |  | $ | 50.00 |  |  |  |  |
Diluted |  | 47.88 |  |  |  |  |

10. Divestitures
2024 Divestitures
Non-core properties. On October 25, 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.
Other divestitures. During the year ended December 31, 2024, the Company completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds (subject to purchase price adjustments) of $25.0 million.
2023 Divestitures
Non-core properties. During the year ended December 31, 2023, the Company entered into separate agreements with multiple buyers to sell a vast majority of its non-core properties located outside of the Williston Basin (the “Non-core Asset Sales”). As of December 31, 2023, the Company completed these Non-core Asset Sales and received total net cash proceeds (including purchase price adjustments) of $39.1 million, subject to customary post-closing adjustments. During the year ended December 31, 2023, the Company recorded a pre-tax net loss on sale of assets of $8.4 million for the Non-core Asset Sales.
During the year ended December 31, 2023, the Company recorded an impairment loss of $5.6 million to adjust the carrying value of the assets held for sale to their estimated fair value less costs to sell. The impairment loss was recorded within exploration and impairment expenses on the Consolidated Statements of Operations.
Other divestitures. In addition, during the year ended December 31, 2023, the Company completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds of $12.1 million.
2022 Divestitures
OMP Merger. On February 1, 2022, the Company completed the merger of Oasis Midstream Partners LP (“OMP”), a master limited partnership formed by the Company to own, develop, operate and acquire midstream assets in North America, and OMP GP, the general partner of OMP, with Crestwood and Crestwood Equity GP LLC, a Delaware limited liability company, and Crestwood GP, the general partner of Crestwood. The Company merged OMP into a subsidiary of Crestwood and exchanged all of its OMP common units and all of the limited liability company interests of OMP GP for $160.0 million in cash and 20,985,668 common units of Crestwood (the “OMP Merger”). The OMP Merger represented a strategic shift for the Company
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Table of Conten ts
and qualified for reporting as discontinued operations under ASC 205-20. See Note 11—Discontinued Operations for additional information.
Immediately prior to the completion of the OMP Merger, the Company owned approximately 70% of OMP’s issued and outstanding common units. The Company recorded a pre-tax gain on sale of assets of $518.9 million, which included (i) the cash consideration of $160.0 million, (ii) the fair value of the Company’s retained investment in Crestwood of $568.3 million; less (iii) the book value of the Company’s investment in OMP of $198.0 million and (iv) transaction costs of $11.4 million. The gain on sale of assets was reported within income from discontinued operations attributable to Chord, net of income tax on the Company’s Consolidated Statement of Operations for the year ended December 31, 2022.
Prior to the OMP Merger, OMP’s long-term debt consisted of $203.0 million of borrowings outstanding and $5.5 million of outstanding letters of credit issued under the OMP Credit Facility and $450.0 million of 8.00% senior unsecured notes due April 1, 2029 (the “OMP Senior Notes”). Upon consummation of the OMP Merger on February 1, 2022, Crestwood assumed the obligations pursuant to the OMP Senior Notes and paid in full all amounts due under the OMP Credit Facility.
The Company had previously entered into several long-term, fee-based contractual arrangements with OMP for midstream services, including (i) natural gas gathering, compression, processing and gas lift supply services; (ii) crude oil gathering, terminal and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater distribution services. In connection with the closing of the OMP Merger, these contracts were assigned to Crestwood, which was acquired by Energy Transfer in November 2023. The Company has continuing cash outflows to Energy Transfer for these midstream services. See Note 12—Investment in Unconsolidated Affiliate for additional information.
Rio Blanco County Divestiture. On July 14, 2022, the Company completed the divestiture of its interests in various assets, including producing wells and an equity interest in a pipeline in Rio Blanco County, Colorado, for an aggregate sales price of $8.0 million (the “Rio Blanco County Divestiture”). No gain or loss was recognized for this sale. The net assets from the Rio Blanco County Divestiture were measured at fair value and classified as held-for-sale upon consummation of the Merger on July 1, 2022.
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11. Discontinued Operations
The OMP Merger qualified for reporting as discontinued operations on February 1, 2022, in accordance with ASC 205-20. There were no discontinued operations for the year ended December 31, 2024 or 2023.
Consolidated Statements of Operations
The results of operations reported as discontinued operations in connection with the OMP Merger were as follows for the periods presented:

|  | Year Ended December 31, 2022 |  |  |  |  |
|  | (In thousands) |  |  |  |  |
Revenues |  |  |  |  |  |  |  |  |
Purchased oil and gas sales(1) |  | $ | (13,364) |  |  |  |  |  |  |  |
Midstream revenues |  | 23,271 |  |  |  |  |  |  |  |
Total revenues |  | 9,907 |  |  |  |  |  |  |  |
Operating expenses |  |  |  |  |  |  |  |  |
Lease operating expenses(1) |  | (4,535) |  |  |  |  |  |  |  |
Midstream expenses |  | 13,224 |  |  |  |  |  |  |  |
Gathering, processing and transportation expenses (1) |  | (3,555) |  |  |  |  |  |  |  |
Purchased oil and gas expenses(1) |  | (12,506) |  |  |  |  |  |  |  |
General and administrative expenses(1) |  | 3,314 |  |  |  |  |  |  |  |
Total operating expenses |  | (4,058) |  |  |  |  |  |  |  |
Gain on sale of assets |  | 518,900 |  |  |  |  |  |  |  |
Operating income |  | 532,865 |  |  |  |  |  |  |  |
Other expense |  |  |  |  |  |  |  |  |
Interest expense, net of capitalized interest |  | (3,685) |  |  |  |  |  |  |  |
Other expense |  | (93) |  |  |  |  |  |  |  |
Total other expense, net |  | (3,778) |  |  |  |  |  |  |  |
Income from discontinued operations before income taxes |  | 529,087 |  |  |  |  |  |  |  |
Income tax expense(2) |  | (101,080) |  |  |  |  |  |  |  |
Income from discontinued operations, net of income tax |  | 428,007 |  |  |  |  |  |  |  |
Net income attributable to non-controlling interests |  | 2,311 |  |  |  |  |  |  |  |
Income from discontinued operations attributable to Chord, net of income tax |  | $ | 425,696 |  |  |  |  |  |  |  |

__________________
(1)Includes discontinued intercompany eliminations.
(2)The Company applied the intraperiod tax allocation rules in accordance with FASB ASC 740-20, Intraperiod Tax Allocation (“ASC 740-20”) to determine the allocation of tax expense between continuing operations and discontinued operations. ASC 740-20 generally requires the allocation of tax expense to be based on a comparative calculation of tax expense with and without income from discontinued operations. During the year ended December 31, 2022, the Company released a portion of its valuation allowance (see Note 15—Income Taxes for additional information) and allocated the majority of the income tax benefit associated with this valuation allowance release to continuing operations. The total tax expense associated with the OMP Merger was partially offset by the release of the Company’s valuation allowance allocated to discontinued operations, resulting in a tax expense of $101.1 million attributable to discontinued operations during the year ended December 31, 2022.
Consolidated Statements of Cash Flows
There was no DD&A from discontinued operations included in “Cash flows from operating activities” for the year ended December 31, 2022. Capital expenditures attributable to discounted operations included in “Cash flows used in investing activities” were $6.1 million for the year ended December 31, 2022. There were no significant non-cash activities from discontinued operations for the period presented.
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12. Investment in Unconsolidated Affiliate
On February 1, 2022, the Company completed the OMP Merger and received 20,985,668 Crestwood common units. On November 3, 2023, Energy Transfer acquired Crestwood, and holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood unit held. The Company has continued to record its investment in Energy Transfer using the fair value option. Additionally, no gain or loss was recorded in the Consolidated Statements of Operations as a result of the Crestwood and Energy Transfer merger. As of December 31, 2024 and 2023, the fair value of the Company’s investment was $142.2 million and $100.2 million, respectively. As of December 31, 2024, the Company owned less than 5% of Energy Transfer’s issued and outstanding common units. The carrying amount of the Company’s investment in Energy Transfer is recorded to investment in unconsolidated affiliate on the Consolidated Balance Sheet.
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. During the year ended December 31, 2023, the Company recorded a net gain of $21.3 million on its investment, primarily comprised of a realized gain for cash distributions received of $10.8 million and an unrealized gain for the change in fair value of the investment of $8.4 million.
13. Long-Term Debt
The Company’s long-term debt consists of the following:

| December 31,
| 2024 |  | 2023
| (In thousands)
Senior secured revolving line of credit | $ | 445,000 |  |  | $ | — |
Senior unsecured notes | 400,000 |  |  | 400,000 |
Less: unamortized deferred financing costs | (2,400) |  |  | (4,098) |
Total long-term debt, net | $ | 842,600 |  |  | $ | 395,902 |

Senior secured revolving line of credit. As of December 31, 2024, the Company had a senior secured revolving credit facility (the “Credit Facility”) with a $3.0 billion borrowing base and $1.5 billion of elected commitments that matures on July 1, 2027. In February 2025, the Company completed its semi-annual borrowing base redetermination, setting the borrowing base at $2.75 billion, and increasing the aggregate amount of elected commitments to $2.0 billion. 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, resulting in an unused borrowing base capacity of $1.0 billion. At December 31, 2023, the Company had no borrowings outstanding and $8.9 million of outstanding letters of credit issued under the Credit Facility. For the years ended December 31, 2024 and 2023, the weighted average interest rate incurred on borrowings under the Credit Facility was 7.3% and 7.1%, respectively. The Company was in compliance with the financial covenants under the Credit Facility at December 31, 2024.
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 or an ABR Loan (each as defined in the Credit Facility). The Company incurs interest on outstanding Term SOFR Loans or ABR Loans at their respective interest rate plus the margin shown in the table below plus a 0.1% credit spread adjustment applicable to Term SOFR Loans. 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 |  | SOFR Loans |  | Commitment Fee
Less than 25% |  | 0.75 | % |  | 1.75 | % |  | 0.375 | %
Greater than or equal to 25% but less than 50% |  | 1.00 | % |  | 2.00 | % |  | 0.375 | %
Greater than or equal to 50% but less than 75% |  | 1.25 | % |  | 2.25 | % |  | 0.500 | %
Greater than or equal to 75% but less than 90% |  | 1.50 | % |  | 2.50 | % |  | 0.500 | %
Greater than or equal to 90% |  | 1.75 | % |  | 2.75 | % |  | 0.500 | %

The Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on 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.
In connection with the consummation of the Merger on July 1, 2022, the Company entered into the Amended and Restated Credit Agreement. The Company completed two amendments to the Amended and Restated Credit Agreement during 2024, as
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follows: (i) on May 31, 2024, the Company entered into the Fifth Amendment to Amended and Restated Credit Agreement to increase the borrowing base to $3.0 billion and increase the aggregate amount of elected commitments to $1.5 billion, (ii) on November 4, 2024, the Company completed its semi-annual borrowing base redetermination, which affirmed the current borrowing base of $3.0 billion and the aggregate elected commitment amounts of $1.5 billion and entered into the Sixth Amendment to Amended and Restated Credit Agreement. The foregoing description of the Fifth Amendment and Sixth Amendment does not purport to be complete and is qualified in its entirety by reference to the text of the Fifth Amendment and Sixth Amendment, copies of which are filed as Exhibit 10.38 and Exhibit 10.39, respectively, to this Annual Report on Form 10-K. The next scheduled redetermination is expected to occur in or around October 2025.
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.
Senior unsecured notes. At December 31, 2024, the Company had $400.0 million of 6.375% senior unsecured notes outstanding due June 1, 2026 (the “Senior Notes”). The Senior Notes were issued in a private placement on June 9, 2021 at par and resulted in net proceeds of $391.6 million, after deducting the underwriters’ discounts, commissions and other expenses. The Company recorded deferred financing costs of $8.4 million, which are being amortized over the term of the Senior Notes. The proceeds were used to fund a portion of an acquisition of certain oil and gas properties located in the Williston Basin in 2021. See Note 9—Acquisitions for additional information.
Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. The Senior Notes are guaranteed on a senior unsecured basis by the Company, along with its wholly-owned subsidiaries (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions.
The indentures governing the Senior Notes contain customary events of default. In addition, the indenture governing the Senior Notes contains cross-default provisions with other indebtedness of the Company and its restricted subsidiaries.
The indentures governing the Senior Notes restrict the Company’s ability and the ability of certain of its 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 Senior Notes as of December 31, 2024.
The fair value of the Senior Notes, which are publicly traded and represent a Level 1 fair value measurement, was $399.9 million and $400.0 million at December 31, 2024 and December 31, 2023, respectively.
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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 in 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.
Whiting credit facility. Whiting had a reserves-based credit facility with a syndicate of banks. Upon consummation of the Merger on July 1, 2022, the Whiting credit facility was terminated, and the Company paid the remaining outstanding accrued interest and other fees of $2.2 million to satisfy and discharge in full all such outstanding obligations that were owed under the Whiting credit facility.
14. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO:

| Year Ended December 31,
| 2024 |  | 2023
| (In thousands)
Asset retirement obligation — beginning of period | $ | 165,546 |  |  | $ | 165,405 |
Liabilities incurred during period | 2,975 |  |  | 1,238 |
Liabilities incurred through acquisitions | 138,489 |  |  | 6,771 |
Liabilities settled during period | (16,014) |  |  | (4,389) |
Liabilities settled through divestitures | (1,870) |  |  | (31,844) |
Accretion expense during period | 16,215 |  |  | 11,183 |
Revisions to estimates | 3,093 |  |  | 17,182 |
Asset retirement obligation — end of period | $ | 308,434 |  |  | $ | 165,546 |

The Company’s ARO includes plugging and abandonment liabilities for its oil and gas properties in the United States and Canada. Accretion expense is included in depreciation, depletion and amortization on the Company’s Consolidated Statements of Operations. At December 31, 2024 and 2023, the current portion of the total ARO balance was approximately $26.1 million and $10.5 million, respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets.
15. Income Taxes
The Company’s income tax expense (benefit) from continuing operations consists of the following:

| Year Ended December 31, |  |  |
| 2024 |  | 2023 |  | 2022 |  |
| (In thousands) |  |  |
Current: |  |  |  |  |  |  |  |
Federal | $ | 42,422 |  |  | $ | 15,877 |  |  | $ | 7,127 |  |  |  |
State | (532) |  |  | 3,824 |  |  | 883 |  |  |  |
Total current tax expense | 41,890 |  |  | 19,701 |  |  | 8,010 |  |  |  |
Deferred: |  |  |  |  |  |  |  |
Federal | 203,752 |  |  | 264,154 |  |  | (46,767) |  |  |  |
State | 18,169 |  |  | 31,394 |  |  | (8,127) |  |  |  |
Total deferred tax expense (benefit) | 221,921 |  |  | 295,548 |  |  | (54,894) |  |  |  |
Total income tax expense (benefit) | $ | 263,811 |  |  | $ | 315,249 |  |  | $ | (46,884) |  |  |  |

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The reconciliation of income taxes from continuing operations calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate is set forth below:

| Year Ended December 31, |  |  |
| 2024 |  | 2023 |  | 2022 |  |
| (%) |  | (In thousands) |  | (%) |  | (In thousands) |  | (%) |  | (In thousands) |  |  |  |  |
U.S. federal tax statutory rate | 21.0 | % |  | $ | 233,612 |  |  | 21.0 | % |  | $ | 281,196 |  |  | 21.0 | % |  | $ | 291,068 |  |  |  |  |  |
State income taxes, net of federal income tax benefit | 2.5 | % |  | 27,779 |  |  | 2.6 | % |  | 35,219 |  |  | 2.6 | % |  | 36,156 |  |  |  |  |  |
Change in valuation allowance | 0.1 | % |  | 1,118 |  |  | — | % |  | — |  |  | (27.2) | % |  | (377,233) |  |  |  |  |  |
Other | 0.1 | % |  | 1,302 |  |  | (0.1) | % |  | (1,166) |  |  | 0.2 | % |  | 3,125 |  |  |  |  |  |
Annual effective tax expense (benefit) | 23.7 | % |  | $ | 263,811 |  |  | 23.5 | % |  | $ | 315,249 |  |  | (3.4) | % |  | $ | (46,884) |  |  |  |  |  |

Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2024 and 2023 were as follows:

| December 31,
| 2024 |  | 2023
| (In thousands)
Deferred tax assets |  |  |
Net operating loss carryforward | $ | 292,978 |  |  | $ | 318,145 |
Bonus and equity-based compensation | 1,693 |  |  | 14,324 |
Other deferred tax assets | 19,593 |  |  | 17,469 |
Total deferred tax assets | 314,264 |  |  | 349,938 |
Less: Valuation allowance | (10,384) |  |  | (9,266) |
Total deferred tax assets, net | $ | 303,880 |  |  | $ | 340,672 |
Deferred tax liabilities |  |  |
Oil and natural gas properties | $ | 1,521,016 |  |  | $ | 367,046 |
Investment in partnerships | 60,093 |  |  | 54,452 |
Tax on unremitted earnings | 194,469 |  |  | — |
Other deferred tax liabilities | 24,744 |  |  | 14,496 |
Total deferred tax liabilities | $ | 1,800,322 |  |  | $ | 435,994 |
Total deferred tax liabilities, net | $ | (1,496,442) |  |  | $ | (95,322) |

The Company’s effective tax rate for the year ended December 31, 2024 was 23.7% of pre-tax income from continuing operations, as compared to an effective tax rate of 23.5% of pre-tax income from continuing operations for the year ended December 31, 2023. The effective tax rates from continuing operations for the years ended December 31, 2024 and December 31, 2023 were higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes.
As of December 31, 2024, the Company had gross U.S. federal net operating loss (“NOL”) carryforwards of $929.9 million, of which approximately $838.7 million will not expire and $91.2 million will expire from 2032 to 2037. In addition, the Company had gross state NOL carryforwards of $2.2 billion as of December 31, 2024, which expire between 2024 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, 2024 was $10.4 million which relates to state NOL carryforwards, and is approximately consistent with the valuation allowance as of December 31, 2023.
On May 31, 2024, the Company completed the Arrangement, and as a result recognized a net deferred tax liability of $1.2 billion 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.
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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, 2024, 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.
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 2010 tax year. The Canadian federal tax returns are open from 2019 and forward.
16. 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 from continuing operations is recognized in general and administrative expenses on the Company’s Consolidated Statements of Operations, and equity-based compensation expense from discontinued operations is recognized in discontinued operations, net of income tax on the Company’s Consolidated Statements of Operations. The Company recognized $23.0 million, $46.1 million and $61.2 million in equity-based compensation expenses related to equity-classified awards that were attributable to continued operations during the years ended December 31, 2024, 2023 and 2022, respectively. Equity-based compensation expenses related to liability-classified awards that were attributable to continued operations were $1.0 million, $3.4 million and $4.9 million during the years ended December 31, 2024, 2023 and 2022, respectively. Stock-based compensation expense related to equity-classified awards that was attributable to discontinued operations was immaterial during the year ended December 31, 2022.
Legacy Whiting equity-based compensation. Pursuant to the Merger Agreement, at the effective time of the Merger, the Company assumed the Whiting Equity Incentive Plan and the outstanding restricted stock units (“RSUs”) and performance share units (“PSUs”) granted under the Whiting Equity Incentive Plan. Accordingly, (i) all shares remaining available for issuance under the Whiting Equity Incentive Plan as of the Merger were automatically converted into shares of the Company’s common stock, available for issuance under the Whiting Equity Incentive Plan and (ii) all Whiting RSUs and PSUs were automatically converted into RSUs and PSUs of the Company, respectively, that, to the extent earned, will be settled in shares of the Company’s common stock, subject to appropriate adjustments to the number of shares subject to each award, resulting in the following as of July 1, 2022: (x) 1,611,725 shares of the Company’s common stock remaining available for issuance to eligible participants under the Whiting Equity Incentive Plan, (y) 335,386 shares of the Company’s common stock subject to RSUs assumed under the Whiting Equity Incentive Plan and (z) 275,310 shares of the Company’s common stock subject to PSUs assumed under the Whiting Equity Incentive Plan. The number of PSUs assumed by the Company was determined based upon the change-in-control provisions contained in the original award agreement at the greater of (i) the target number of PSUs subject to such award and (ii) the actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of the Merger. Following completion of the Merger, the Whiting RSUs and PSUs are subject to time-based vesting criteria. The fair value of the RSU and PSU awards assumed by the Company was $73.3 million, including $27.4 million that was attributable to pre-Merger services and recorded as a part of the consideration transferred and $45.9 million that is attributable to post-Merger services that will be recognized as equity-based compensation expense in the post-combination period. The Company previously granted restricted stock awards (“RSAs”) to non-employee directors. RSAs are legally issued shares which were scheduled to vest over a three-year period subject to a service condition. The Company measured the awards at fair value on the date of grant, which was based on the closing price of the Company’s common stock. Pursuant to the award agreements governing the RSAs, each outstanding RSA became fully vested upon completion of the Merger due to a “change in control” (as defined in the award agreement). As a result, 64,920 outstanding RSAs became fully vested on July 1, 2022 and the Company recognized the remaining unrecognized compensation expense immediately.
Restricted stock units. The Company has granted 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
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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, 2023 | 263,059 |  |  | $ | 98.94 |
Granted | 169,949 |  |  | 161.23 |
Vested | (139,555) |  |  | 93.23 |
Forfeited | (9,231) |  |  | 153.10 |
Non-vested shares outstanding December 31, 2024 | 284,222 |  |  | $ | 137.23 |

The fair value of awards vested was $23.2 million and $42.4 million for the years ended December 31, 2024 and 2023, respectively. The weighted average grant date fair value of RSUs was $161.23 per share and $137.43 per share for the years ended December 31, 2024 and 2023, respectively. Unrecognized expense as of December 31, 2024 for all outstanding RSUs was $24.2 million and will be recognized over a weighted average period of approximately 1.8 years.
Legacy Oasis performance share units. The Company granted PSUs to certain employees. These PSUs were contingent shares that may be earned over three-year and four-year performance periods subject to market-based and service-based vesting conditions. The number of PSUs to be earned was initially subject to a market condition that was based on a comparison of the total stockholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the applicable performance periods, with 50% of the PSU awards eligible to be earned based on performance relative to a certain group of the Company’s oil and gas peers and 50% of the PSU awards eligible to be earned based on performance relative to the broad-based Russell 2000 index. Depending on the Company’s TSR performance relative to the defined peer group, award recipients could earn between 0% and 150% of target. Pursuant to the PSU award agreements, the number of PSUs earned was certified at the greater of (i) target performance and (ii) actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of a “change in control.” The completion of the Merger on July 1, 2022 represented a “change in control” such that 250,016 PSUs were earned by legacy Oasis award recipients subject to a service-based vesting condition, including 183,915 PSUs that were outstanding at December 31, 2021 and an incremental 66,101 PSUs that were earned based upon the achievement of the performance criteria described above.
The following table summarizes information related to PSUs held by employees of the Company:

| Shares |  | Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding December 31, 2023 | 78,943 |  |  | $ | 69.67 |
Granted | — |  |  | — |
Vested | (78,943) |  |  | 69.67 |
Forfeited | — |  |  | — |
Non-vested shares outstanding December 31, 2024 | — |  |  | $ | — |

The fair value of awards vested was $9.0 million and $46.3 million for the years ended December 31, 2024 and 2023, respectively. No PSUs under this award agreement were granted during the years ended December 31, 2024 and 2023.
2024 Performance share units. During the year ended December 31, 2024, the Company granted PSUs that include (i) total stockholder return (“TSR”) PSUs (“Absolute TSR PSUs”) and (ii) relative TSR PSUs (“Relative TSR PSUs” and collectively with the Absolute TSR PSUs, the “2024 PSUs”), which are eligible to vest and become earned at the end of the applicable performance period on December 31, 2026, 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.
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Any earned 2024 PSUs will be settled in shares of the Company’s common stock for up to 100% of the target number of PSUs subject to each applicable award, with any remaining earned PSUs that exceed the target number of PSUs subject to the award being settled in cash based on the fair market value of a share of the Company’s common stock on the applicable payment date. The 2024 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, 2023 | — |  |  | $ | — |
Granted | 15,808 |  |  | 233.01 |
Vested | (364) |  |  | 233.35 |
Forfeited | — |  |  | — |
Non-vested shares outstanding December 31, 2024 | 15,444 |  |  | $ | 233.00 |

The fair value of awards vested was $0.1 million for the year ended December 31, 2024. Unrecognized expense as of December 31, 2024 for all outstanding Absolute TSR PSUs was $1.1 million and will be recognized over a weighted average period of 2.0 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, 2023 | — |  |  | $ | — |
Granted | 47,428 |  |  | 197.10 |
Vested | (1,091) |  |  | 200.54 |
Forfeited | — |  |  | — |
Non-vested shares outstanding December 31, 2024 | 46,337 |  |  | $ | 197.02 |

The fair value of awards vested was $0.2 million for the year ended December 31, 2024. Unrecognized expense as of December 31, 2024 for all outstanding Relative TSR PSUs was $4.5 million and will be recognized over a weighted average period of 2.0 years.
Legacy Oasis leveraged stock units. The Company granted leveraged stock units (“LSUs”) to certain employees. LSUs are contingent shares that may be earned over a three-year or four-year performance period subject to market-based and service-based vesting conditions. The number of LSUs to be earned was initially subject to a market condition that was based on the TSR performance of the Company’s common stock measured against specific premium return objectives. Depending on the Company’s TSR performance, award recipients could earn between 0% and 300% of target; however, the number of shares delivered in respect to these awards during the grant cycle could not exceed ten times the fair value of the award on the grant date. Pursuant to LSU award agreements, the number of LSUs earned was certified at the greater of (i) target performance and (ii) actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of a “change in control.” The completion of the Merger on July 1, 2022 represented a “change in control” such that 787,218 LSUs were earned by award recipients subject to a service-based vesting condition.
The following table summarizes information related to LSUs held by employees of the Company:

| Shares |  | Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding December 31, 2023 | 497,037 |  |  | $ | 84.59 |
Granted | — |  |  | — |
Vested | (248,520) |  |  | 84.59 |
Forfeited | — |  |  | — |
Non-vested shares outstanding December 31, 2024 | 248,517 |  |  | $ | 84.59 |

The fair value of awards vested was $42.3 million for the year ended December 31, 2024. No awards vested for the year ended December 31, 2023. No LSUs were granted during the years ended December 31, 2024 and 2023. Unrecognized expense as of December 31, 2024 for all outstanding LSUs was $0.3 million and will be recognized over a weighted average period of approximately 0.3 years.
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Fair value assumptions. The aggregate grant date fair value of the 2024 PSUs, legacy Oasis PSUs, and LSUs 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:

| 2021 PSUs and LSUs |  | 2024 Absolute and Relative TSR PSUs
| Year Ended December 31, 2021 |  | Year Ended December 31, 2024
Forecast period (years) | 3 | — | 4 |  | 3
Risk-free interest rates | 0.2% | — | 0.6% |  | 3.8% | — |  |  | 4.7%
Implied equity volatility | 45% | — | 60% |  | 35%
Range of stock price on date of grant | $44.41 | — | $68.07 |  | $141.41 | — |  |  | $169.66

Phantom unit awards. The Company has 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.
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, 2023 | 10,043 |  |  | $ | 165.87 |
Granted | 12,613 |  |  | 158.68 |
Vested | (3,557) |  |  | 136.67 |
Forfeited | (1,012) |  |  | 151.09 |
Non-vested phantom unit awards outstanding December 31, 2024 | 18,087 |  |  | $ | 151.71 |

The fair value of vested phantom unit awards was $0.6 million and $1.1 million for the years ended December 31, 2024 and 2023, respectively. Unrecognized expense as of December 31, 2024 for all outstanding phantom unit awards was $1.4 million and will be recognized over a weighted average period of approximately 1.9 years.
17. 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, 2024, 2023 and 2022:

|  | Rate per Share |  |
|  | Base |  | Variable |  | Special |  | Total |  | Total Dividends Declared
|  |  |  |  |  |  |  |  |  | (In thousands)
Q4 2024 |  | $ | 1.250 |  |  | $ | 0.190 |  |  | $ | — |  |  | $ | 1.440 |  |  | $ | 88,271 |
Q3 2024 |  | 1.250 |  |  | 1.270 |  |  | — |  |  | 2.520 |  |  | 157,090 |
Q2 2024 |  | 1.250 |  |  | 1.690 |  |  | — |  |  | 2.940 |  |  | 124,708 |
Q1 2024 |  | 1.250 |  |  | 2.000 |  |  | — |  |  | 3.250 |  |  | 137,541 |
Total |  | $ | 5.000 |  |  | $ | 5.150 |  |  | $ | — |  |  | $ | 10.150 |  |  | $ | 507,610 |
Q4 2023 |  | $ | 1.250 |  |  | $ | 1.250 |  |  | $ | — |  |  | $ | 2.500 |  |  | $ | 107,867 |
Q3 2023 |  | 1.250 |  |  | 0.110 |  |  | — |  |  | 1.360 |  |  | 58,374 |
Q2 2023 |  | 1.250 |  |  | 1.970 |  |  | — |  |  | 3.220 |  |  | 137,507 |
Q1 2023 |  | 1.250 |  |  | 3.550 |  |  | — |  |  | 4.800 |  |  | 204,884 |
Total |  | $ | 5.000 |  |  | $ | 6.880 |  |  | $ | — |  |  | $ | 11.880 |  |  | $ | 508,632 |
Q4 2022 |  | $ | 1.250 |  |  | $ | 2.420 |  |  | $ | — |  |  | $ | 3.670 |  |  | $ | 157,673 |
Q3 2022 |  | 1.250 |  |  | — |  |  | — |  |  | 1.250 |  |  | 70,242 |
Q2 2022 |  | 0.585 |  |  | 2.940 |  |  | 15.000 |  |  | 18.525 |  |  | 379,369 |
Q1 2022 |  | 0.585 |  |  | 3.000 |  |  | — |  |  | 3.585 |  |  | 73,074 |
Total |  | $ | 3.670 |  |  | $ | 8.360 |  |  | $ | 15.000 |  |  | $ | 27.030 |  |  | $ | 680,358 |

Total dividends declared in the table above includes (i) $7.0 million, $14.4 million and $41.6 million associated with dividend equivalent rights on unvested equity-based compensation awards for the year ended December 31, 2024, 2023 and 2022 respectively, and (ii) a special dividend of $15.00 per share of common stock declared in connection with the Merger, or $307.4 million in aggregate, that was paid on July 8, 2022 to stockholders of record as of June 29, 2022.
As of December 31, 2024, the Company had dividends payable of $16.7 million related to dividend equivalent rights accrued on equity-based compensation awards, including $16.1 million that was recorded under accrued liabilities and $0.6 million that was recorded under other liabilities on the Consolidated Balance Sheet.
On February 25, 2025, the Company declared a base cash dividend of $1.30 per share of common stock. The dividend will be payable on March 26, 2025 to shareholders of record as of March 11, 2025.
Share Repurchase Program
The Company’s Board of Directors authorized a share repurchase program in October 2024 of up to $750 million of the Company’s common stock. This program replaces previous share repurchase programs of up to (i) $750 million of the Company’s common stock authorized in October 2023, (ii) $300 million of the Company’s common stock authorized in August 2022, and (iii) $150 million of the Company’s common stock authorized in February 2022.
During the year ended December 31, 2024, the Company 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 both of the October 2023 and October 2024 share repurchase programs. As of December 31, 2024, there was $592.6 million of capacity remaining under the Company’s October 2024 program. Subsequent to December 31, 2024, the Company repurchased 558,285 shares of common stock at a weighted average price of $116.41 per common share for a total cost of $65.0 million.
During the year ended December 31, 2023, the Company repurchased 1,533,791 shares of common stock at a weighted average price of $157.08 per common share for a total cost of $240.9 million, excluding accrued excise taxes of $0.4 million under both of the August 2022 and October 2023 share repurchase programs.
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During the year ended December 31, 2022, the Company repurchased 1,378,070 shares of common stock at a weighted average price of $110.24 per common share for a total cost of $151.9 million under both of the February and August 2022 share repurchase programs.
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.
Assumed Whiting warrants. Pursuant to the Merger Agreement, 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. Prior to the Merger, each legacy Whiting warrant was exercisable for one share of Whiting common stock. Following the completion of the Merger and the Company’s assumption of the legacy Whiting warrants, each such warrant was exercisable for 0.5774 shares of the Company’s common stock, which reflects an adjustment in accordance with the exchange ratio under the Merger Agreement. Also, in accordance with the Merger Agreement, the exercise price of each such legacy Whiting warrant per share of the Company’s common stock was adjusted to equal the quotient of (x) the exercise price of such warrant per share of Whiting common stock immediately prior to the effective time of the Merger less $6.25 divided by (y) the exchange ratio of 0.5774.
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 elects to exercise their option to acquire shares of the Company’s common stock, the Company shall issue a net number of exercised shares of common stock. The net number of exercised shares is 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.
The Company had 395,809 legacy Whiting Series A Warrants expire on September 1, 2024. The legacy Whiting Series B Warrants are exercisable until September 1, 2025, at which respective times all unexercised Whiting warrants will expire and the rights of the holders of such Whiting warrants to acquire common stock will terminate. Pursuant to the Whiting warrant agreements, no holder of a Whiting warrant, by virtue of holding or having a beneficial interest in a Whiting warrant, will have the right to vote, receive dividends, receive notice as stockholders with respect to any meeting of stockholders for the election of directors or any other matter, or exercise any rights whatsoever as a stockholder of Chord unless, until and only to the extent such holders become holders of record of shares of Chord common stock issued upon settlement of the Whiting warrants.
The number of shares of Chord common stock for which a Whiting warrant is exercisable and the exercise prices are subject to adjustment from time to time upon the occurrence of certain events, including stock splits, reverse stock splits or stock dividends to holders of common stock or a reclassification in respect of common stock.
As of December 31, 2024, the Company had 888,742 legacy Whiting Series B Warrants outstanding, with an exercise price of $133.70 per share that expire on September 1, 2025.
During the years ended December 31, 2024 and 2023, there were 1,823,608 and 1,746,859 warrants exercised, respectively.
18. 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, |  |  |
|  |  |  |  | 2024 |  | 2023 |  | 2022 |  |
|  |  |  |  | (In thousands, except per share data)
Net income from continuing operations |  |  |  |  | $ | 848,627 |  |  | $ | 1,023,779 |  |  | $ | 1,430,463 |  |  |  |
Distributed and undistributed earnings from continuing operations allocated to participating securities |  |  |  |  | (3,437) |  |  | (3,370) |  |  | (182) |  |  |  |
Net income from continuing operations attributable to common stockholders (basic) |  |  |  |  | 845,190 |  |  | 1,020,409 |  |  | 1,430,281 |  |  |  |
Reallocation of distributed and undistributed earnings from continuing operations allocated to participating securities |  |  |  |  | 24 |  |  | 76 |  |  | 6 |  |  |  |
Net income from continuing operations attributable to common stockholders (diluted) |  |  |  |  | $ | 845,214 |  |  | $ | 1,020,485 |  |  | $ | 1,430,287 |  |  |  |
Weighted average common shares outstanding: |  |  |  |  |  |  |  |  |  |  |  |
Basic weighted average common shares outstanding |  |  |  |  | 51,796 |  |  | 41,490 |  |  | 30,497 |  |  |  |
Dilutive effect of share-based awards |  |  |  |  | 402 |  |  | 944 |  |  | 1,134 |  |  |  |
Dilutive effect of warrants |  |  |  |  | 550 |  |  | 964 |  |  | 620 |  |  |  |
Diluted weighted average common shares outstanding |  |  |  |  | 52,748 |  |  | 43,398 |  |  | 32,251 |  |  |  |
Basic earnings per share from continuing operations |  |  |  |  | $ | 16.32 |  |  | $ | 24.59 |  |  | $ | 46.90 |  |  |  |
Diluted earnings per share from continuing operations |  |  |  |  | $ | 16.02 |  |  | $ | 23.51 |  |  | $ | 44.35 |  |  |  |
Anti-dilutive weighted average common shares: |  |  |  |  |  |  |  |  |  |  |  |
Potential common shares |  |  |  |  | 1,646 |  |  | 3,709 |  |  | 2,901 |  |  |  |

For the years ended December 31, 2024, 2023 and 2022, the diluted earnings per share calculation excludes the impact of unvested share-based awards and outstanding warrants that were anti-dilutive.
Basic earnings per share from discontinued operations was $13.96 for the year ended December 31, 2022. Diluted earnings per share from discontinued operations was $13.20 for the year ended December 31, 2022.
19. 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 attributable to continuing operations were as follows for the periods presented:

| Year Ended December 31, |  |  |
| 2024 |  | 2023 |  | 2022 |  |
| (In thousands)
Operating lease costs | $ | 31,830 |  |  | $ | 9,853 |  |  | $ | 11,292 |  |  |  |
Variable lease costs(1) | 11,137 |  |  | 13,391 |  |  | 8,562 |  |  |  |
Short-term lease costs | 59,429 |  |  | 56,100 |  |  | 25,716 |  |  |  |
Sublease income | (1,570) |  |  | (199) |  |  | — |  |  |  |
Finance lease costs: |  |  |  |  |  |  |  |
Amortization of ROU assets | 1,569 |  |  | 1,367 |  |  | 1,342 |  |  |  |
Interest on lease liabilities | 299 |  |  | 126 |  |  | 65 |  |  |  |
Total lease costs | $ | 102,694 |  |  | $ | 80,638 |  |  | $ | 46,977 |  |  |  |

___________________
(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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The amounts disclosed herein are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners.
Total lease costs attributable to discontinued operations were recorded in income from discontinued operations, net of income tax on the Consolidated Statements of Operations. Total lease costs attributable to discontinued operations were immaterial for the periods reported.
As of December 31, 2024, maturities of the Company’s lease liabilities were as follows:

|  | Operating Leases |  | Finance Leases
|  | (In thousands)
2025 |  | $ | 33,863 |  |  | $ | 1,953 |
2026 |  | 11,587 |  |  | 1,771 |
2027 |  | 4,417 |  |  | 1,434 |
2028 |  | 2,918 |  |  | 585 |
2029 |  | 2,748 |  |  | 80 |
Thereafter |  | 1,379 |  |  | — |
Total future lease payments |  | 56,912 |  |  | 5,823 |
Less: Imputed interest |  | 4,060 |  |  | 578 |
Present value of future lease payments |  | $ | 52,852 |  |  | $ | 5,245 |

Supplemental balance sheet information related to the Company’s leases were as follows:

|  |  |  | December 31, |  |
|  | Balance Sheet Location |  | 2024 |  | 2023 |  |
|  |  |  | (In thousands) |  |
Assets |  |  |  |  |  |  |  |
Operating lease assets(1) |  | Operating right-of-use assets |  | $ | 38,004 |  |  | $ | 21,343 |  |  |
Finance lease assets(2) |  | Other assets |  | 5,220 |  |  | 2,748 |  |  |
Total lease assets |  |  |  | $ | 43,224 |  |  | $ | 24,091 |  |  |
Liabilities |  |  |  |  |  |  |  |
Current |  |  |  |  |  |  |  |
Operating lease liabilities(1) |  | Current operating lease liabilities |  | $ | 37,629 |  |  | $ | 13,258 |  |  |
Finance lease liabilities |  | Other current liabilities |  | 1,665 |  |  | 916 |  |  |
Long-term |  |  |  |  |  |  |  |
Operating lease liabilities(1) |  | Operating lease liabilities |  | 15,190 |  |  | 18,667 |  |  |
Finance lease liabilities |  | Other liabilities |  | 3,613 |  |  | 1,881 |  |  |
Total lease liabilities |  |  |  | $ | 58,097 |  |  | $ | 34,722 |  |  |

___________________
(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 $2.4 million and $1.2 million as of December 31, 2024 and 2023, 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 exploration and impairment 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, |  |  |
| 2024 |  | 2023 |  | 2022 |  |
| (In thousands) |  |  |
Cash paid for amounts included in the measurement of lease liabilities |  |  |  |  |  |  |  |
Operating cash flows from operating leases | $ | 30,222 |  |  | $ | 15,627 |  |  | $ | 15,843 |  |  |  |
Operating cash flows from finance leases | 297 |  |  | 160 |  |  | 57 |  |  |  |
Financing cash flows from finance leases | 1,458 |  |  | 1,702 |  |  | 1,299 |  |  |  |
ROU assets obtained in exchange for lease obligations |  |  |  |  |  |  |  |
Operating leases(1) | $ | 49,278 |  |  | $ | 22,201 |  |  | $ | 20,164 |  |  |  |
Finance leases(2) | 4,094 |  |  | 2,307 |  |  | 2,659 |  |  |  |

___________________
(1)The year ended December 31, 2024 includes $43.0 million related to operating leases acquired in the Arrangement. The year ended December 31, 2022 includes $15.8 million related to operating leases acquired in the Merger.
(2)The year ended December 31, 2022 includes $2.1 million related to finance leases acquired in the Merger.
Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows:

| December 31,
| 2024 |  | 2023
Operating leases |  |  |
Weighted average remaining lease term | 2.4 years |  | 3.6 years
Weighted average discount rate | 6.8 | % |  | 6.3 | %
Finance leases |  |  |
Weighted average remaining lease term | 3.2 years |  | 3.2 years
Weighted average discount rate | 6.7 | % |  | 5.7 | %

20. Significant Concentrations
Major customers. 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. For the year ended December 31, 2022, sales to Phillips 66 Company and Shell Trading (US) Company accounted for approximately 17% and 11%, 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, 2024, 2023 or 2022.
Substantially all of the Company’s accounts receivable result from sales of crude oil, NGLs 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.
21. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of December 31, 2024. 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, 2024, the Company’s material off-balance sheet arrangements and transactions include $30.8 million in outstanding letters of credit issued under the Credit Facility and $78.6 million in net surety bond exposure issued as financial assurance on certain agreements.
Volume commitment agreements. As of December 31, 2024, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 46.1 MMBbl of crude oil, 7.5 MMBbl of NGLs, 448.8 Bcf of natural gas and 0.1 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, 2024 are as follows:

| (In thousands)
2025 | $ | 150,637 |
2026 | 138,242 |
2027 | 109,331 |
2028 | 66,788 |
2029 | 36,962 |
Thereafter | 77,286 |
| $ | 579,246 |

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.
Whiting Chapter 11 bankruptcy claims. On April 1, 2020, Whiting and certain of its subsidiaries (the “Debtors”) commenced voluntary cases (the “Whiting Chapter 11 Cases”) under chapter 11 of the United States Bankruptcy Code. On June 30, 2020, the Debtors filed their proposed Joint Chapter 11 Plan of Reorganization of Whiting and its Debtor affiliates (as amended, modified and supplemented, the “Whiting Plan”). On August 14, 2020, the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) confirmed the Whiting Plan and on September 1, 2020, the Debtors satisfied all conditions required for plan effectiveness and emerged from the Whiting Chapter 11 Cases.
The filing of the Whiting Chapter 11 Cases allowed Whiting to, upon approval of the Bankruptcy Court, assume, assign or reject certain contractual commitments, including certain executory contracts. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such contract and subject to certain exceptions, relieves Whiting from performing future obligations under such contract but entitles the counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. To the extent that the Bankruptcy Court allows any unsecured claims against the Company, such claims may have been satisfied through an issuance of the Company’s common stock or other remedy or agreement under and pursuant to the Whiting Plan. In connection with the closing of the Merger on July 1, 2022, the Company assumed Whiting’s obligations with respect to the Whiting Plan and, accordingly, reserved 1,224,840 shares of common stock for potential future distribution to certain general unsecured claimants whose claim values are pending resolution in the Bankruptcy Court. As of October 19, 2023, all claims were resolved and the Company released the previously reserved shares of common stock.
Arguello Inc. and Freeport-McMoRan Oil & Gas LLC. Whiting Oil and Gas Corporation (“WOG”), a wholly-owned subsidiary of the Company, had interests in federal oil and gas leases in the Point Arguello Unit located offshore in California. While those interests have expired, pursuant to certain related agreements (the “Point Arguello Agreements”), WOG was subject to certain abandonment and decommissioning obligations prior to WOG and Whiting rejecting the related contracts pursuant to the Whiting Plan. On October 1, 2020, Arguello Inc. and Freeport-McMoRan Oil & Gas LLC, individually and in its capacity as the designated Point Arguello Unit operator (collectively, the “FMOG Entities”) filed with the Bankruptcy Court an application for allowance of certain administrative claims arguing the FMOG Entities were entitled to recover Whiting’s proportionate share of decommissioning obligations owed to the U.S. government through subrogation to the U.S. government’s economic rights. The U.S. Government may also be able to bring claims against WOG directly for decommissioning costs. On February 18, 2021, WOG entered into a stipulation and agreed order with the United States Department of the Interior, Bureau of Safety & Environmental Enforcement (the “BSEE”) pursuant to which the BSEE withdrew its proofs of claims against Whiting and WOG and acknowledged their respective rights and obligations pursuant to the Whiting Plan. On October 20, 2022, the Company filed stipulations and proposed orders with the Bankruptcy Court to resolve all outstanding claims asserted by the FMOG Entities. Those stipulations and proposed orders were signed by the Bankruptcy Court on October 27, 2022. On November l, 2022, the Company paid $55.0 million in cash as full and final satisfaction, discharge and release of all such claims.
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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 now back on remand before the D.C. Federal District Court. The Department of the Interior’s motion for leave to amend its answer and assert a crossclaim to quiet title to the ownership of the Missouri River riverbed against the State of North Dakota was granted by the Court in July 2024. The MHA Nation was also granted the opportunity to intervene in the Department of Interior’s crossclaim against the State of North Dakota. In October 2024, the MHA Nation filed a Motion for Judgment on the Pleadings as to the crossclaim – contending (1) that the undisputed material facts demonstrate that the United States owns the riverbed in trust for the MHA Nation and (2) the State of North Dakota is precluded from asserting otherwise. Briefing on the MHA Nation’s Motion for Judgment on the Pleadings was completed in December 2024 and is being considered by the Court. On January 17, 2025, the Department of Interior filed a Motion for Summary Judgment on the State of North Dakota’s crossclaims.
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. Subsequent to December 31, 2024, the Company reached a settlement in principle on certain claims with the settlement amount to be paid by the Company’s insurance carriers. The accrued settlement obligation and offsetting insurance receivable are included in the Company’s Consolidated Balance Sheet at December 31, 2024 with no impact on the Company’s Consolidated Statement of Operations for the year ended December 31, 2024.
22. 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.
23. Supplemental Oil and Gas Disclosures — Unaudited
The supplemental data presented below reflects information for all of the Company’s oil and gas producing activities. Prior periods have not been recast for discontinued operations.
Capitalized Costs
The following table sets forth the capitalized costs related to the Company’s oil and gas producing activities:

| December 31,
| 2024 |  | 2023
| (In thousands)
Proved oil and gas properties | $ | 11,923,792 |  |  | $ | 6,220,766 |
Less: Accumulated depletion and impairment | (2,115,428) |  |  | (1,035,393) |
Proved oil and gas properties, net | 9,808,364 |  |  | 5,185,373 |
Unproved oil and gas properties | 846,994 |  |  | 99,477 |
Total oil and gas properties, net | $ | 10,655,358 |  |  | $ | 5,284,850 |

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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, |  |  |
| 2024 |  | 2023 |  | 2022 |  |
| (In thousands)
Acquisition costs: |  |  |  |  |  |  |  |
Proved oil and gas properties | $ | 4,346,811 |  |  | $ | 178,629 |  |  | $ | 3,164,665 |  |  |  |
Unproved oil and gas properties | 928,789 |  |  | 185,392 |  |  | 43,084 |  |  |  |
Exploration costs | 8,285 |  |  | 6,366 |  |  | 859 |  |  |  |
Development costs(1) | 1,236,794 |  |  | 940,967 |  |  | 529,126 |  |  |  |
Total costs incurred | $ | 6,520,679 |  |  | $ | 1,311,354 |  |  | $ | 3,737,734 |  |  |  |

___________________
(1)Development costs include non-cash upward adjustments to oil and gas properties of $6.1 million, $18.5 million and $21.2 million for the years ended December 31, 2024, 2023 and 2022, respectively, which relate to estimated future plugging and abandonment costs of the Company’s oil and gas wells.
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 general and administrative expenses and interest expense, for the periods presented:

| Year Ended December 31, |  |  |
| 2024 |  | 2023 |  | 2022 |  |
| (In thousands)
Revenues | $ | 3,836,138 |  |  | $ | 3,132,411 |  |  | $ | 2,976,296 |  |  |  |
Production costs | 1,425,364 |  |  | 1,099,159 |  |  | 814,588 |  |  |  |
Depreciation, depletion and amortization | 1,081,575 |  |  | 582,127 |  |  | 354,050 |  |  |  |
Exploration and impairment | 14,570 |  |  | 17,830 |  |  | 2,204 |  |  |  |
Income tax expense | 309,069 |  |  | 335,534 |  |  | 426,087 |  |  |  |
Results of operations for oil and gas producing activities | $ | 1,005,560 |  |  | $ | 1,097,761 |  |  | $ | 1,379,367 |  |  |  |

24. Supplemental Oil and Gas Reserve Information — Unaudited
The reserve estimates presented below at December 31, 2024, 2023 and 2022 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, NGLs 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) |  | NGLs(1) (MBbl) |  | Natural Gas (MMcf) |  | MBoe(2)
2022 |  |  |  |  |  |  |
Proved reserves |  |  |  |  |  |  |
Beginning balance | 174,317 |  |  | — |  |  | 459,262 |  |  | 250,860 |
Revisions of previous estimates | (8,032) |  |  | 64,557 |  |  | (56,500) |  |  | 47,110 |
Extensions, discoveries and other additions | 38,144 |  |  | 7,452 |  |  | 35,689 |  |  | 51,544 |
Sales of reserves in place | — |  |  | — |  |  | — |  |  | — |
Purchases of reserves in place | 202,316 |  |  | 73,468 |  |  | 443,903 |  |  | 349,768 |
Production | (25,457) |  |  | (7,026) |  |  | (67,428) |  |  | (43,722) |
Net proved reserves at December 31, 2022 | 381,288 |  |  | 138,451 |  |  | 814,926 |  |  | 655,560 |
Proved developed reserves, December 31, 2022 | 272,529 |  |  | 115,227 |  |  | 689,651 |  |  | 502,698 |
Proved undeveloped reserves, December 31, 2022 | 108,759 |  |  | 23,224 |  |  | 125,275 |  |  | 152,862 |
2023 |  |  |  |  |  |  |
Proved reserves |  |  |  |  |  |  |
Beginning balance | 381,288 |  |  | 138,451 |  |  | 814,926 |  |  | 655,560 |
Revisions of previous estimates | (38,073) |  |  | (5,270) |  |  | (33,308) |  |  | (48,895) |
Extensions, discoveries and other additions | 53,207 |  |  | 15,046 |  |  | 62,273 |  |  | 78,632 |
Sales of reserves in place | (3,999) |  |  | (53) |  |  | (3,067) |  |  | (4,564) |
Purchases of reserves in place | 12,375 |  |  | 3,052 |  |  | 20,060 |  |  | 18,771 |
Production | (36,427) |  |  | (13,047) |  |  | (82,953) |  |  | (63,300) |
Net proved reserves at December 31, 2023 | 368,371 |  |  | 138,179 |  |  | 777,931 |  |  | 636,204 |
Proved developed reserves, December 31, 2023 | 241,362 |  |  | 105,702 |  |  | 640,180 |  |  | 453,762 |
Proved undeveloped reserves, December 31, 2023 | 127,008 |  |  | 32,476 |  |  | 137,751 |  |  | 182,442 |
2024 |  |  |  |  |  |  |
Proved reserves |  |  |  |  |  |  |
Beginning balance | 368,371 |  |  | 138,179 |  |  | 777,931 |  |  | 636,204 |
Revisions of previous estimates | (35,229) |  |  | (3,741) |  |  | (38,294) |  |  | (45,351) |
Extensions, discoveries and other additions | 43,301 |  |  | 10,032 |  |  | 62,013 |  |  | 63,669 |
Sales of reserves in place | (1,264) |  |  | (204) |  |  | (1,071) |  |  | (1,646) |
Purchases of reserves in place | 176,710 |  |  | 39,256 |  |  | 596,287 |  |  | 315,346 |
Production | (48,479) |  |  | (16,338) |  |  | (122,193) |  |  | (85,182) |
Net proved reserves at December 31, 2024 | 503,410 |  |  | 167,184 |  |  | 1,274,673 |  |  | 883,040 |
Proved developed reserves, December 31, 2024 | 317,689 |  |  | 125,824 |  |  | 1,053,288 |  |  | 619,061 |
Proved undeveloped reserves, December 31, 2024 | 185,721 |  |  | 41,360 |  |  | 221,385 |  |  | 263,979 |

__________________
(1)For periods prior to July 1, 2022, we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when reporting reserves. As of July 1, 2022, NGLs are reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented.
(2)Natural gas is converted to barrel of oil equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil.
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.
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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 re-ordering of the Company’s development timing 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 proved undeveloped (“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.
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 Williston Basin Acquisition.
Sales of reserves in place. Proved reserves decreased 4.6 MMBoe primarily as a result of the Non-core Asset Sales.
2022
Proved reserves increased by 404.7 MMBoe during the year ended December 31, 2022 due to the following:
Purchases of reserves in place. The Company added 349.8 MMBoe of proved reserves from the purchase of reserves in place as a result of the Merger.
Extensions, discoveries and other additions. The Company added 51.5 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.
Revisions of previous estimates. The Company had net positive revisions of 47.1 MMBoe attributable to the following:
Increases:
•30.3 MMBoe associated with the change to reporting reserves on a three-stream basis in 2022
•26.1 MMBoe associated with higher crude oil, NGL and natural gas prices
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Table of Conten ts
•2.6 MMBoe associated with tighter differentials and stronger NGL yields
Decreases:
•6.7 MMBoe associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets
•5.2 MMBoe primarily associated with lower working interests as a result of well payouts associated with higher commodity pricing
Production. Production decreased proved reserves by 43.7 MMBoe.
Sales of reserves in place. There were no impacts to proved reserves as a result of the sale of reserves in place.
Changes in Proved Undeveloped Reserves
The following table summarizes the changes in the Company’s estimates of PUD reserves during 2024:

|  | Year Ended December 31, 2024
|  | (MBoe)
Proved undeveloped reserves, beginning of period |  | 182,442 |
Purchases of minerals in place |  | 121,671 |
Extensions, discoveries and other additions |  | 58,287 |
Revisions of previous estimates |  | (25,393) |
Conversion to proved developed reserves |  | (73,028) |
Proved undeveloped reserves, end of period |  | 263,979 |

Proved undeveloped reserves increased by 81.5 MMBoe during the year ended December 31, 2024 due to the following:
Purchases of minerals in place. The Company added 121.7 MMBoe of PUD reserves from the purchase of minerals in place as a result of the Arrangement.
Extensions, discoveries and other additions. The Company added 58.3 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 25.4 MMBoe primarily attributable to the following decreases:
•23.8 MMBoe primarily associated with re-ordering of the Company’s development timing plan following the Arrangement
•0.9 MMBoe associated with lower crude oil, NGL and natural gas prices and weaker differentials
•0.7 MMBoe primarily associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets
Conversions to proved developed reserves. The Company incurred $408.4 million in capital expenditures to convert 73.0 MMBoe of PUD reserves to proved developed reserves during 2024. The PUD conversions represented 40% of the Company’s PUD reserves balance at the beginning of 2024. The conversions to proved developed reserves included 28.9 MMBoe of PUD reserves attributable to the Arrangement that were converted to proved developed reserves subsequent to the Arrangement and therefore were not included in the PUD reserves balance at the beginning of 2024.
As of December 31, 2024, 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, 2024 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.
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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 $75.48 per Bbl for crude oil and $2.13 per MMBtu for natural gas, $78.22 per Bbl for crude oil and $2.64 per MMBtu for natural gas and $93.67 per Bbl for crude oil and $6.36 per MMBtu for natural gas for the years ended December 31, 2024, 2023 and 2022, 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.
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, 2024, 2023 and 2022:

| At December 31,
| 2024 |  | 2023 |  | 2022
| (In thousands)
Future cash inflows | $ | 39,474,381 |  |  | $ | 31,882,940 |  |  | $ | 44,544,247 |
Future production costs | (18,255,819) |  |  | (13,815,882) |  |  | (15,879,712) |
Future development costs | (3,928,154) |  |  | (3,055,823) |  |  | (2,553,605) |
Future income tax expense | (3,096,730) |  |  | (2,573,017) |  |  | (5,283,201) |
Future net cash flows | 14,193,678 |  |  | 12,438,218 |  |  | 20,827,729 |
10% annual discount for estimated timing of cash flows | (5,839,500) |  |  | (5,447,578) |  |  | (9,333,254) |
Standardized measure of discounted future net cash flows | $ | 8,354,178 |  |  | $ | 6,990,640 |  |  | $ | 11,494,475 |

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:

| 2024 |  | 2023 |  | 2022
| (In thousands)
January 1 | $ | 6,990,640 |  |  | $ | 11,494,475 |  |  | $ | 2,696,938 |
Net changes in prices and production costs | (2,145,627) |  |  | (6,138,846) |  |  | 3,148,745 |
Net changes in future development costs | 136,608 |  |  | (92,072) |  |  | 35,427 |
Sales of crude oil and natural gas, net | (2,410,774) |  |  | (2,033,251) |  |  | (2,161,708) |
Extensions | 639,614 |  |  | 864,249 |  |  | 958,924 |
Purchases of reserves in place | 3,736,382 |  |  | 373,913 |  |  | 7,441,750 |
Sales of reserves in place | (37,074) |  |  | (75,097) |  |  | — |
Revisions of previous quantity estimates | (493,520) |  |  | (1,142,960) |  |  | 1,434,357 |
Previously estimated development costs incurred | 692,049 |  |  | 574,607 |  |  | 137,534 |
Accretion of discount | 1,088,290 |  |  | 1,445,215 |  |  | 683,631 |
Net change in income taxes | (370,584) |  |  | 1,419,851 |  |  | (2,539,182) |
Changes in timing and other | 528,174 |  |  | 300,556 |  |  | (341,941) |
December 31 | $ | 8,354,178 |  |  | $ | 6,990,640 |  |  | $ | 11,494,475 |

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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, 2024. 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, 2024.
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, 2024, 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, 2024. Management’s assessment and conclusion on the effectiveness of our internal control over financial reporting as of December 31, 2024 excludes an assessment of the internal control over financial reporting of Enerplus as it was acquired by the Company in a purchase business combination on May 31, 2024, and the Company is still in the process of aligning and integrating various processes, systems and internal controls related to the business and operations of Enerplus. The total assets of Enerplus represent approximately 46% of the related consolidated financial statement amounts as of December 31, 2024. The total revenues of Enerplus represent approximately 16% of the related consolidated financial statement amounts for the year ended December 31, 2024.
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, 2024 and has issued an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2024. 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
On May 31, 2024, we completed the Arrangement. As part of the ongoing integration, we are in the process of incorporating the controls and related procedures of Enerplus. Other than incorporating Enerplus’ controls, there were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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Item 9B. Other Information
Rule 10b5-1 trading arrangements
During the fiscal quarter ended December 31, 2024, none of our directors or officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
Amendment to Bylaws
Effective as of February 24, 2025, the Board of Directors of the Company adopted the Fifth Amended and Restated Bylaws (the “Bylaws”) of the Company. The amendment and restatement of the Bylaws includes, among other things, the following changes:
•Clarifying that no additional notice need be given for the adjournment of a meeting to address a technical failure to convene or continue a meeting using remote communication;
•Explicitly providing for special meetings of the Board of Directors on less than 24 hour notice;
•Clarifying the definition of “officer” for purposes of Article VII;
•Removing certain obsolete provisions relating to the listing date and the first annual meeting, removing reference to certain information called for in the advance notice provision regarding those acting in concert, and removing a provision regarding the list of stockholders of the Company; and
•Clarifying certain other definitions, renumbering, inapplicable references and section references and added certain references to uncertificated shares.
The foregoing description of the Bylaws is not complete and is qualified in its entirety by reference to the complete text of the Bylaws, a copy of which is filed as Exhibit 3.5 to this Annual Report on Form 10-K and incorporated by reference herein.
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 2025 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 2025 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 2025 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 2025 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 2025 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 |  | Agreement and Plan of Merger, dated as of March 7, 2022 by and among Oasis Petroleum Inc., Ohm Merger Sub Inc., New Ohm LLC and Whiting Petroleum Corporation (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on March 8, 2022, and incorporated herein by reference).
2.2 |  | 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(a) |  | 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.
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(a) |  | Fifth Amended and Restated Bylaws of Chord Energy Corporation
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 as of June 9, 2021, among Chord Energy Corporation (f/k/a Oasis Petroleum Inc.), the Guarantors and Regions Bank, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on June 15, 2021, and incorporated herein by reference).
4.4 |  | First Supplemental Indenture to Indenture dated February 7, 2022, by and among Chord Energy Corporation (f/k/a Oasis Petroleum Inc.), the Guarantors and Regions Bank, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on August 12, 2022, and incorporated herein by reference).
4.5 |  | Second Supplemental Indenture to Indenture dated August 12, 2022, by and among Chord Energy Corporation, the Guarantors and Regions Bank, as trustee (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K on August 12, 2022, and incorporated herein by reference).

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Exhibit No. |  | Description of Exhibit
4.6 |  | Third Supplemental Indenture to Indenture dated June 28, 2024, by and among Chord Energy Corporation, the Guarantors and Regions Bank, as trustee (filed as Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q on August 8, 2024, 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).
10.3 |  | Warrant Agreement, dated as of November 19, 2020, by and between Oasis Petroleum Inc., and Computershare Trust Company, N.A. (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on November 20, 2020, and incorporated herein by reference).
10.4** |  | 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).
10.5** |  | 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).
10.6** |  | 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).
10.7** |  | 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).
10.8** |  | 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).
10.9** |  | 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).
10.10** |  | 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).
10.11** |  | 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).
10.12 |  | 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).
10.13 |  | Purchase Agreement, dated as of May 25, 2021 among Oasis Petroleum Inc., the Guarantors and J.P. Morgan Securities LLC as representative of the several initial purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on May 26, 2021, and incorporated herein by reference).
10.14 |  | Support Agreement, dated October 25, 2021, by and among Crestwood Equity Partners LP, Oasis Midstream Partners LP, Oasis Petroleum Inc., OMP GP LLC and OMS Holdings LLC (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on October 28, 2021, and incorporated herein by reference).

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Exhibit No. |  | Description of Exhibit
10.15** |  | 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).
10.16** |  | Executive Employment and Severance Agreement, dated February 2, 2021, by and between Whiting Petroleum Corporation and Lynn A. Peterson (filed as Exhibit 10.1 to Whiting’s Current Report on Form 8-K on February 4, 2021, and incorporated herein by reference).
10.17** |  | Letter Agreement, dated as of March 7, 2022, between Oasis Petroleum Inc. and Lynn A. Peterson (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 8, 2022, and incorporated herein by reference).
10.18** |  | Executive Employment and Severance Agreement by and between Whiting Petroleum Corporation and Charles J. Rimer, effective as of February 2, 2021 (filed as Exhibit 10.3 to Whiting’s Current Report on Form 8-K on February 4, 2021, and incorporated herein by reference).
10.19** |  | First Addendum to Executive Employment and Severance Agreement by and between Whiting Petroleum Corporation and Charles J. Rimer, dated April 13, 2022 (filed as Exhibit 10.1 to Whiting’s Current Report on Form 8-K on April 15, 2022, and incorporated herein by reference).
10.20** |  | Second Addendum to Executive Employment and Severance Agreement by and between Whiting Petroleum Corporation and Charles J. Rimer, effective as of January 1, 2023 (filed as Exhibit 10.40 to the Company’s Annual Report on Form 10-K on February 28, 2023, and incorporated herein by reference).
10.21** |  | Form of Executive Employment Agreement and Severance Agreement for former executive officers of Whiting Petroleum Corporation who served or are serving as executive officers of Chord Energy Corporation other than Lynn A. Peterson, James P. Henderson and Charles J. Rimer (filed as Exhibit 10.20 to Whiting’s Annual Report on Form 10-K on February 24, 2021, and incorporated herein by reference).
10.22** |  | 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).
10.23** |  | 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).
10.24** |  | 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).
10.25** |  | Letter Agreement with Charles J. Rimer, dated December 22, 2023 (filed as Exhibit 10.24 to the Company’s Annual Report on Form 10-K on February 26, 2024, and incorporated herein by reference).
10.26** |  | 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).
10.27** |  | 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).
10.28** |  | 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).
10.29** |  | 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).

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Exhibit No. |  | Description of Exhibit
10.30 |  | Series A Warrant Agreement, dated as of September 1, 2020, by and among Whiting Petroleum Corporation, Computershare Inc. and Computershare Trust Company, N.A. (filed as Exhibit 10.2 to Whiting’s Current Report on Form 8-K12B on September 1, 2020, and incorporated herein by reference).
10.31 |  | Series B Warrant Agreement, dated as of September 1, 2020, by and among Whiting Petroleum Corporation, Computershare Inc. and Computershare Trust Company, N.A. (filed as Exhibit 10.3 to Whiting’s Current Report on Form 8-K12B on September 1, 2020, and incorporated herein by reference).
10.32 |  | Warrant Assignment and Assumption Agreement, dated as of July 1, 2022, by and among Oasis Petroleum Inc., Whiting Petroleum Corporation, Computershare Inc. and Computershare Trust Company, N.A. (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on July 7, 2022, and incorporated herein by reference).
10.33 |  | 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).
10.34 |  | 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).
10.35 |  | 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).
10.36 |  | 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).
10.37 |  | 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).
10.38 |  | 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).
10.39 |  | 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).
19.1(a) |  | Insider Trading Policy.
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.
31.2(a) |  | Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b) |  | Sarbanes-Oxley Section 906 certification of Principal Executive Officer.

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Exhibit No. |  | Description of Exhibit
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 14, 2025.
101(a) |  | The following financial information from Chord’s Annual Report on Form 10-K for the year ended December 31, 2024, 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 27, 2025 | 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 27, 2025
Daniel E. Brown |  |  |
/s/ Richard N. Robuck |  | Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) |  | February 27, 2025
Richard N. Robuck |  |  |
/s/ Susan M. Cunningham |  | Board Chair |  | February 27, 2025
Susan M. Cunningham |  |  |  |
/s/ Douglas E. Brooks |  | Director |  | February 27, 2025
Douglas E. Brooks |  |  |  |
/s/ Ian Dundas |  | Director |  | February 27, 2025
Ian Dundas |  |  |  |
/s/ Hilary Foulkes |  | Director |  | February 27, 2025
Hilary Foulkes |  |  |  |
/s/ Samantha F. Holroyd |  | Director |  | February 27, 2025
Samantha F. Holroyd |  |  |  |
/s/ Kevin S. McCarthy |  | Director |  | February 27, 2025
Kevin S. McCarthy |  |  |  |
/s/ Ward Polzin |  | Director |  | February 27, 2025
Ward Polzin |  |  |  |
/s/ Jeffrey Sheets |  | Director |  | February 27, 2025
Jeffrey Sheets |  |  |  |
/s/ Anne Taylor |  | Director |  | February 27, 2025
Anne Taylor |  |  |  |
/s/ Marguerite N. Woung-Chapman |  | Director |  | February 27, 2025
Marguerite N. Woung-Chapman |  |  |  |

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