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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

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  ¨

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: $6,340,929,766

Number of shares of registrant’s common stock outstanding as of February 16, 2024: 41,438,134

Portions of the registrant’s definitive proxy statement for its 2024 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2023, are incorporated by reference into Part III of this report for the year ended December 31, 2023.

 

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			58
Item 1C.			Cybersecurity			58
Item 2.			Properties			60
Item 3.			Legal Proceedings			60
Item 4.			Mine Safety Disclosures			60
			PART II
Item 5.			Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			61
Item 6.			[Reserved]			62
Item 7.			Management’s Discussion and Analysis of Financial Condition and Results of Operations			63
Item 7A.			Quantitative and Qualitative Disclosures about Market Risk			76
Item 8.			Financial Statements and Supplementary Data			78
Item 9.			Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			130
Item 9A.			Controls and Procedures			130
Item 9B.			Other Information			130
Item 9C.			Disclosure Regarding Foreign Jurisdictions that Prevent Inspections			131
			PART III
Item 10.			Directors, Executive Officers and Corporate Governance			132
Item 11.			Executive Compensation			132
Item 12.			Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			132
Item 13.			Certain Relationships and Related Transactions, and Director Independence			132
Item 14.			Principal Accountant Fees and Services			132
			PART IV
Item 15.			Exhibits, Financial Statement Schedules			133
Item 16.			Form 10-K Summary			137
Signatures						138

The terms defined in this section are used throughout this Annual Report on Form 10-K:

“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.

“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.

“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.

“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.

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

“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.

“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.

“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.

“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.

“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.

“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.

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 as well as 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;

•general economic conditions;

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

•logistical challenges and supply chain disruptions;

•our business strategy;

•the geographic concentration of our operations;

•estimated future net reserves and present value thereof;

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

•drilling and completion of wells;

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

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

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

•availability of qualified personnel;

•infrastructure for produced and flowback water gathering and disposal;

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

•the possible shutdown of the Dakota Access Pipeline;

•the expected timing and closing of the Arrangement (as defined in the “Overview” section of Item 1 below);

•the possibility that required shareholder approvals related to the Arrangement may not be obtained;

•the risk that a condition to closing the Arrangement may not be satisfied;

•the risk that either party may terminate the Arrangement Agreement (as defined in the “Overview” section of Item 1 below) upon the occurrence of certain circumstances or that the closing of the Arrangement might be delayed or not occur at all;

•property acquisitions, including the Merger (as defined in the “Overview” section of Item 1 below) and 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 Merger and Arrangement;    

•any litigation relating to the Merger or 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 return capital to stockholders;

•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 ESG 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 similar to or caused by a recurrence of the novel COVID-19 pandemic 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 any bank failures, the interest rate environment and the potential for a government shutdown in the absence of Congressional approval of an appropriations bill in March 2024;

•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, inflation, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed 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.

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.”

•The Arrangement is subject to a number of conditions which may delay the Arrangement and could result in additional expenditures of money and resources or reduce the anticipated benefits, or result in the termination of the Arrangement Agreement and us having to pay a termination fee.

•The Arrangement Agreement subjects us to restrictions on our business activities prior to the closing of the Arrangement.

•The synergies attributable to the Arrangement may vary from expectations.

•Our shareholders and Enerplus (as defined in the “Overview” section of Item 1 below) shareholders, in each case as of immediately prior to the Arrangement, will have reduced ownership in the combined company.

•The market price of our common stock may decline if large amounts of our common stock are sold following the Arrangement.

•Litigation relating to the Arrangement could result in an injunction preventing the completion of the Arrangement and/or substantial costs to Chord and Enerplus.

•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 the bank failures, the Federal Reserve’s decision to increase interest rates and the potential for further increases or an extended period of elevated interest rates, as well as the potential for a U.S. government shutdown due to failure to enact debt ceiling legislation, 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 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.

•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.

•Increasing stakeholder and market attention to ESG matters may impact our business and ability to secure financing.

•Our operations are subject to a series of risks arising out of the threat of climate change, energy conservation measures or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, restrictions on drilling and reduced demand for the crude oil and natural gas that we produce.

•Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of crude oil and natural gas wells and adversely affect our production.

•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 Merger, 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.

•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 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.

•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.

•Involvement in legal, governmental and regulatory proceedings could result in substantial liabilities.

•Our profitability may be negatively impacted by inflation 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.

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’s and natural gas with quality and sustainable long-lived assets 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”). Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a rewarding environment for our employees. We aim to enhance return of capital and generate strong free cash flow, while striving to be responsible stewards of the communities and environment where we operate.

As of December 31, 2023, we had 1,029,263 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, 2023, we had 3,760 gross (2,876.0 net) operated producing wells. Our working interest for producing wells averaged 76% in the wells we operate and 51% in total. During the year ended December 31, 2023, we had average daily production of 173,425 net Boepd. As of December 31, 2023, Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, estimated our net proved reserves to be 636.2 MMBoe, of which 71% were classified as proved developed and 58% were crude oil. 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 and reserve estimates as of and 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.

Enerplus is an independent North American oil and gas exploration and production company. We believe that the combination of Chord and Enerplus will provide improving returns, capital efficiency, low-cost inventory and a peer-leading balance sheet, all of which support sustainable free cash flow generation and meaningful shareholder returns. Under the terms of the Arrangement Agreement, Enerplus shareholders will receive 0.10125 shares of Chord common stock and $1.84 in cash in exchange for each common share of Enerplus they own at closing. The transaction is expected to close by mid-year 2024.

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 maximize returns through efficiently executing our development program and optimizing our capital allocation, while evaluating our performance and focusing on continuous improvement. As part of our efforts to maximize returns, 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 $47.79 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 dividend of $1.25 per share per quarter ($5.00 per share annualized) and a $750 million share repurchase program.

As of December 31, 2023, we had $683.0 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:

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, 2023, we had $1.3 billion of liquidity available, including $318.0 million of cash and cash equivalents and $991.1 million of unused borrowing capacity available under the Credit Facility (defined in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”).

•Commitment to excellence. We are focused on creating a durable organization that generates strong financial returns and sustainable free cash flow through commodity cycles. We believe we have an attractive inventory that is resilient to commodity price fluctuations, which supports the sustainable generation of free cash flow. Our management team is focused on the continuous improvement of our operations and overall cost structure and has 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 are committed to our established ESG initiatives and seek to maintain a culture of continuous improvement in ESG practices. We strive to provide reliable, safe and affordable energy in a responsible manner against the backdrop of an evolving energy landscape. The key tenets of our ESG philosophy are to always put safety first, minimize our environmental impact, reduce our emissions intensity, promote an

inclusive 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 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, 2023, 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 89% independent and 56% of our directors are women. As part of our ongoing effort to enhance our ESG practices, the Board of Directors has established the Environmental, Social and Governance 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 2024 Annual Meeting of Stockholders.

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, 2023, we had 1,029,263 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin. Of our 1,029,263 net leasehold acres, 1,024,771 net acres were held by production, and 58% of our 636.2 MMBoe estimated net proved reserves were comprised of crude oil. We believe we have a large project inventory of potential drilling locations that we have not yet drilled, the majority of which are operated by us.

•Operating control over the majority of our portfolio. In order to maintain control over our asset portfolio, we have established a leasehold position comprised primarily of properties that we expect to operate. As of December 31, 2023, 96% of our estimated net proved reserves were attributable to properties that we operate. In 2024, we plan to TIL approximately 103 to 113 gross operated wells with an average working interest of approximately 75%. Controlling operations enables us to optimize capital allocation and control the pace of development of our assets to manage our reinvestment rates in line with our broader strategic objectives. Additionally, operational control allows us to materially benefit from proactively managing our cost structure across our portfolio. We believe that maintaining operational control over the majority of our acreage allows us to better pursue our strategies of enhancing returns through operational, cost and capital efficiencies and allows us to better manage infrastructure investment to drive down operating costs and optimize price realizations.

•Best-in-class 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 more than 25 years of industry experience. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven record of accomplishment in identification, acquisition and execution of large,

repeatable development drilling programs. In addition, a substantial majority of our executive officers’ overall compensation is in long-term equity-based incentive awards, and we have implemented best-in-class 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.

Our estimated net proved reserves and related PV-10 at December 31, 2023 and 2022 are based on reports independently prepared by NSAI, our independent reserve engineers. Our estimated net proved reserves and related PV-10 at December 31, 2021 were based on reports independently prepared by DeGolyer and MacNaughton, our previous independent reserve engineers. Our current and previous independent reserve engineers evaluated 100% of the reserves and discounted values at December 31, 2023, 2022 and 2021 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,
			2023						2022						2021
Estimated proved reserves:
Crude oil (MMBbls)			368.4						381.3						174.3
NGLs (MMBbls)(1)			138.2						138.5						—
Natural gas (Bcf)			777.9						814.9						459.3
Total estimated proved reserves (MMBoe)			636.2						655.6						250.9
Percent crude oil			58		%				58		%				69		%
Estimated proved developed reserves:
Crude oil (MMBbls)			241.4						272.5						114.0
NGLs (MMBbls)(1)			105.7						115.2						—
Natural gas (Bcf)			640.2						689.7						361.8
Total estimated proved developed reserves (MMBoe)			453.8						502.7						174.3
Percent proved developed			71		%				77		%				69		%
Estimated proved undeveloped reserves:
Crude oil (MMBbls)			127.0						108.8						60.3
NGLs (MMBbls)(1)			32.5						23.2						—
Natural gas (Bcf)			137.8						125.3						97.4
Total estimated proved undeveloped reserves (MMBoe)			182.4						152.9						76.5
Standardized Measure (GAAP) (in millions)(2)			$	6,990.6					$	11,494.5					$	2,696.9
PV-10 (Non-GAAP) (in millions)(3):
Proved developed PV-10			$	6,572.4					$	11,460.3					$	2,474.5
Proved undeveloped PV-10			1,956.1						2,991.9						640.9
Total PV-10 (Non-GAAP)			$	8,528.5					$	14,452.2					$	3,115.4

__________________ 

(1)At December 31, 2023 and 2022, NGL reserves are reported separately from the natural gas stream on a three-stream basis. At December 31, 2021, we reported crude oil and natural gas reserves on a two-stream basis, with NGLs combined with the natural gas stream. This change impacts the comparability of the periods presented.

(2)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.

(3)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.

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,
			2023						2022						2021
									(In millions)
Standardized Measure of discounted future net cash flows			$	6,990.6					$	11,494.5					$	2,696.9
Add: present value of future income taxes discounted at 10%			1,537.9						2,957.7						418.5
PV-10			$	8,528.5					$	14,452.2					$	3,115.4

Our estimated net proved reserves and PV-10 at December 31, 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.

Our estimated net proved reserves and PV-10 at December 31, 2021 were based on reports independently prepared by DeGolyer and MacNaughton, 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 Estimated and Auditing Standards and definitions and current guidelines established by the SEC. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Moscow, Astana, Buenos Aires, Baku and Algiers. The firm’s more than 180 professionals include engineers, geologists, geophysicists, petrophysicists and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer and MacNaughton has provided such services for over 85 years. The Senior Vice President at DeGolyer and MacNaughton that was primarily responsible for overseeing the preparation of the reserve estimates is a Registered Professional Engineer in the State of Texas, is a member of the Society of Petroleum Engineers and has over 10 years of experience in crude oil and natural gas reservoir studies and reserve evaluations.

He graduated with a Bachelor of Science degree in Petroleum Engineering from Istanbul Technical University in 2003, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005 and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any crude oil, natural gas or mineral properties, or securities or notes of clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.

In accordance with rules and regulations of the SEC applicable to companies involved in crude oil and natural gas producing activities, proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” means deterministically, the quantities of crude oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the Estimating and Auditing Standards. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

Based on the current stage of field development, production performance, the development plans provided by us to NSAI and the analyses of areas offsetting existing wells with test or production data, reserves were classified as proved.

A performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for the evaluation of all reserves categories. Performance-based methodology primarily includes (i) production diagnostics, (ii) decline-curve analysis and (iii) model-based analysis (if necessary, based on the availability of data). Production diagnostics include data quality control, identification of flow regimes and characteristic well performance behavior. Analysis was performed for all well groupings (or type-curve areas).

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the impact of dynamic reservoir and fracture parameters on well 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.

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 Managing Director, Corporate Planning & Reserves is responsible for overseeing the preparation of the reserves estimates under the supervision of our Senior Vice President, Planning & Investor Relations. Our Managing Director, Corporate Planning & Reserves has more than 13 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 Financial Officer; Senior Vice President, Planning & Investor Relations and Managing 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.

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.

The Merger was accounted for as of July 1, 2022. Accordingly, the results of operations presented herein report the results of legacy Oasis prior to the closing of the Merger on July 1, 2022 and the results of Chord (including legacy Whiting) from July 1, 2022 through December 31, 2023. 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.”

__________________ 

(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.

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2023. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

Our total net leasehold position shown in the table above includes 1,029,263 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin. At December 31, 2023, our total acreage that is held by production increased to 1,025,375 net acres from 996,187 net acres at December 31, 2022.

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2023 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,
2024			1,713						1,296
2025			1,003						632
2026			2,686						2,087

We have not assigned any PUD reserves to locations scheduled to be drilled after lease expiration.

As of December 31, 2023, we had 6,188 (3,133.4 net) total gross productive wells, of which 3,760 gross (2,876.0 net) productive wells were operated by us. Substantially all of our productive wells as of December 31, 2023 were horizontal wells.

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,
			2023												2022												2021
			Gross						Net						Gross						Net						Gross						Net
Development wells:
Oil			111						66.9						67						41.3						49						23.3
Gas			—						—						—						—						—						—
Dry			—						—						—						—						—						—
Total development wells			111						66.9						67						41.3						49						23.3
Exploratory wells:
Oil			—						—						—						—						—						—
Gas			—						—						—						—						—						—
Dry			—						—						—						—						—						—
Total exploratory wells			—						—						—						—						—						—
Total wells			111						66.9						67						41.3						49						23.3

As of December 31, 2023, we had 64 gross (33.9 net) wells in the process of being drilled or completed, which included 44 gross operated wells waiting on completion and 19 gross non-operated wells drilling or completing.

As of December 31, 2023, we had four operated rigs running, and we expect to run four operated rigs during the majority of 2024.

As of December 31, 2023, 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.

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, 2023, substantially all of our gross operated crude oil and natural gas production was connected to gathering systems. In addition, from time to time we may enter into third-party purchase and sales transactions to, among other things, improve price realizations, optimize transportation costs, blend to meet pipeline specifications or to cover production shortfalls. We also enter into various sales contracts for a portion of our portfolio at fixed differentials. We believe that the loss of any individual purchaser would not have a long-term material adverse impact on our financial position or results of operations, as alternative customers and markets for the sale of our products are readily available in the areas in which we operate.

Our marketing of crude oil, NGL and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For a description of some of these factors, please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business.”

As of December 31, 2023, we had certain agreements with an aggregate requirement to deliver or transport a minimum quantity of approximately 20.6 MMBbl of crude oil, 12.0 MMBbl of NGLs, 438.7 Bcf of natural gas and 1.6 MMBbl of water, prior to any applicable volume credits, within specified timeframes, the majority of which are five years or less. 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.

On February 1, 2022, we completed the merger of Oasis Midstream Partners LP (“OMP”) and OMP GP LLC, OMP’s general partner (“OMP GP”) with and into a subsidiary of Crestwood Equity Partners LP (“Crestwood”) and, in exchange, received $160.0 million in cash and 20,985,668 common units representing limited partner interests of Crestwood (the “OMP Merger”). 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, terminaling 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.

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 emerging 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.”

As is customary in the oil and gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant title defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with general industry standards. Prior to completing an acquisition of producing crude oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and gas properties are subject to customary royalty and other interests, liens to secure borrowings under our revolving credit facility, and liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect our carrying value of the properties. Please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—Risks related to the oil and gas industry and our business—We may incur losses as a result of title defects in the properties in which we invest.”

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.

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”) and the courts. We cannot predict when or whether any such proposals may be finalized and become effective.

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, 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 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 Producer Price Index plus 0.78%. The Commission received requests for rehearing of its December 17, 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 are permitted to adjust their indexed ceilings annually by Producer Price Index 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 (“Request for Rehearing”). Additionally, during February and March 2022, shippers filed timely petitions for review of the January 2022 Order with the D.C. Circuit and the 5th Circuit. The petitions for review filed with the D.C. Circuit were transferred to the 5th Circuit. On May 6, 2022, FERC issued an order on rehearing in which it denied the Request for Rehearing. On May 11, 2022, the 5th Circuit transferred the challenge to the D.C. Circuit. Additional petitions for review were timely filed with the D.C. Circuit in June 2022. The appeal remains pending before the D.C. Circuit.

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 prorationing 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 decade, 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 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 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.

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 to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by FERC under Order No. 637 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. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to FERC on May 1 of each year for the previous calendar year. Order No. 704 requires certain natural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. Please see below the discussion of “Other federal laws and regulations affecting our industry—FERC market transparency rules.”

Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case by case basis. 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.

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.

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 $1,544,521 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 $1,544,521 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. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes 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 new 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. The anti-manipulation rules and enhanced civil penalty authority increased FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, 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.

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 $1,544,521 per day per violation, adjusted annually for inflation, in addition to any applicable penalty under the Federal Trade Commission Act.

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 have increased or will 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.

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 in the past decade 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.

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. 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 is also developing new requirements for inspection and maintenance obligations when idled pipelines are returned to service and for pipeline class location changes.

These new 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.

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 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.

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.

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 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.

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, 2023, 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, 2023, 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.

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, President Biden highlighted addressing climate change as a priority of his administration, issued several Executive Orders related to climate change, recommitted the United States to long-term international goals to reduce emissions and continues to require 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.

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 takes effect in 2024. 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 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. Several states, though none in the areas where we operate, have implemented, of their own accord or in coordination with their neighbor states, regional initiatives and programs limiting, monitoring or otherwise regulating GHG emissions.

In addition, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules and regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and gas system sources, and impose standards for reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. 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 former 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. These newly adopted final rules are also likely to face immediate legal challenges. 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 depending on 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 has 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, and 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 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-CO2 GHG emissions and increasing the emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration has 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. Other actions adversely affecting the oil and gas industry that may be pursued by the Biden Administration include limiting hydraulic fracturing by banning new oil and gas permitting on federal lands and waters, potentially eliminating certain tax deductions and relief available to the oil and gas industry and imposing restrictions on pipeline infrastructure and liquid natural gas (“LNG”) export facilities. For example, in January 2024 President Biden announced a temporary pause on approvals for new exports of LNG to certain countries, pending a new Department of Energy review of authorization analyses. 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.

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 proposed rules 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. 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. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient. 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 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.

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 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.

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 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 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 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 Biden Administration has issued executive orders, 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.

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 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.

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 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 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 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 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 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 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 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 July 2023, the CEQ proposed 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.

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 8% 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.

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.

Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a 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 16, 2024, we employed 514 full-time employees and we 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.

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 and emergency response preparedness training, protective measures including adequate personal protective equipment, life-saving rules, onboarding processes, contractor safety management, partner surveys, comprehensive audits, semi-annual safety summits, executive-level reviews of incidents and ad-hoc safety stand-downs. In addition, safety training is provided to all employees, and, in order to reinforce accountability, safety performance is integrated into our annual compensation program. We seek to partner only with contractors and vendors who share our commitment to safety.

The goal of our total rewards program is to provide a transparent, thoughtful framework for decisions on employee compensation and benefits. Our total rewards program considers goals in addition to financial benefits and aims to increase employee focus on key performance goals, 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 Life Assistance Program.

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 new 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.

We believe a diverse, equitable and inclusive workforce provides the best opportunity to obtain unique perspectives, experiences and ideas to help our business succeed, and we are committed to creating an environment where every employee is valued and heard. We regularly seek ways to increase the diversity of our workforce, and we embrace an approach to talent attraction and promotion that enables each and every individual to be evaluated based on merit. Our Compensation and Human Resources Committee reviews the Company’s development, implementation and effectiveness of our human resources and 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. Similarly, our Environmental Social and Governance Committee provides oversight, guidance and perspective to management and the Board of Directors regarding the Company’s policies, programs and initiatives related to the promotion of diversity. As of February 16, 2024, approximately 45% 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 16, 2024, 56% 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.

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 sustain and promote a diverse, equitable 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.

Our principal corporate office is located in Houston, Texas at 1001 Fannin Street. We also own field offices in the North Dakota communities of Williston, Ray, New Town and Watford City.

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. 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 and Environmental, Social and Governance 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, 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.

Our obligations and the obligations of Enerplus to consummate the Arrangement are subject to the satisfaction (or waiver by all parties, to the extent permissible under applicable laws) of a number of conditions described in the Arrangement Agreement, including the approval by our shareholders of issuance of shares of the Company’s common stock to Enerplus shareholders in connection with the Arrangement, the approval and adoption of the Arrangement Agreement and the transactions contemplated therein, including the Arrangement, by the Enerplus shareholders and the approval of the Arrangement by the Court of King’s Bench of Alberta on terms consistent with the Arrangement Agreement and otherwise reasonably satisfactory to the parties. Many of the conditions to completion of the Arrangement are not within our control and we cannot predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the Termination Date (as such term is defined in the Arrangement Agreement), it is possible that the Arrangement Agreement may be terminated. The Arrangement Agreement provides that, upon termination of the Arrangement Agreement under certain circumstances, we or Enerplus would be required to pay the other party a termination fee of $240 million and $127 million, respectively.

Although the parties have agreed to use reasonable best efforts, subject to certain limitations, to complete the Arrangement promptly, these and other conditions may fail to be satisfied. In addition, completion of the Arrangement may take longer and could cost more than we expect. The requirements for obtaining the required clearances and approvals could delay the completion of the Arrangement for a significant period of time or prevent them from occurring. Any delay in completing the Arrangement may adversely affect the cost savings and other benefits that we expect to achieve if the Arrangement and the integration of businesses were to be completed within the expected timeframe.

The Arrangement Agreement subjects us to restrictions on our business activities prior to the closing of the Arrangement. The Arrangement Agreement obligates us to generally conduct our businesses in the ordinary course until the closing and to, among other things, use our reasonable best efforts to (i) preserve substantially intact our present business organization, goodwill and assets, (ii) keep available the services of our current officers and employees and (iii) preserve our existing relationships with governmental entities and significant customers, suppliers, licensors, licensees, distributors, lessors and others having significant business dealings with us. These restrictions could prevent us from pursuing certain business opportunities that arise prior to the closing and are outside the ordinary course of business.

We are subject to customary restrictions on our ability to solicit alternative acquisition proposals and to provide information to, or engage in discussions with, third parties regarding such proposals, except that we are permitted in limited circumstances prior to receiving approval from our stockholders of the issuance of new shares of Chord common stock in the Arrangement to provide information to, and engage in discussions with, a party which has made an unsolicited acquisition proposal that our Board of Directors has determined constitutes or would reasonably be expected to constitute a superior proposal. Furthermore, in limited circumstances prior to receiving stockholder approval, our Board of Directors may effect a change of its recommendation in response to an applicable intervening event if our Board of Directors determines in good faith that a failure to effect a change in recommendation would be inconsistent with our Board of Directors’ fiduciary duties.

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 and Enerplus believe that the combination of the companies will provide operational and financial scale, increasing free cash flow, and enhancing 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.

Our shareholders and Enerplus shareholders, in each case as of immediately prior to the Arrangement, will have reduced ownership in the combined company.

We anticipate issuing 0.10125 shares of the Company’s common stock to Enerplus shareholders in exchange for each Enerplus common share, pursuant to the Arrangement Agreement. Following the completion of the Arrangement, it is anticipated that persons who were shareholders of Chord and Enerplus immediately prior to the Arrangement will own approximately 67% and 33% of the combined company, respectively, on a fully diluted basis. As a result, our current shareholders and Enerplus’ current shareholders will have less influence on the policies of the combined company than they currently have on our policies and the polices of Enerplus, respectively.

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. If the Arrangement is consummated, we will issue 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 following completion of the Arrangement. Former Enerplus shareholders may decide not to hold the shares of our common stock that they receive 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. In addition, our financial position after completion of the Arrangement may differ from our financial position before the completion of the Arrangement, and the results of our operations and cash flows after the completion of the Arrangement may be affected by factors different from those currently affecting our financial position or results of operations and cash flows, all of which could adversely affect the market price of our common stock. Accordingly, the market price and performance of our common stock is likely to be different from the performance of our common stock prior to the Arrangement. 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.

Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on Chord’s and Enerplus’ respective liquidity and financial condition.

Lawsuits that may be brought against Chord, Enerplus or their respective directors could also seek, among other things, injunctive relief or other equitable relief, including a request to rescind parts of the Arrangement Agreement already implemented and to otherwise enjoin the parties from consummating the Arrangement. One of the conditions to the closing of the Arrangement is that no injunction by any court or other tribunal of competent jurisdiction has been entered and continues to be in effect and no law has been adopted or is effective, in either case that prohibits or makes illegal the closing of the Arrangement. Consequently, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Arrangement, that injunction may delay or prevent the Arrangement from being completed within the expected timeframe or at all, which may adversely affect Chord’s and Enerplus’ respective business, financial position and results of operations.

There can be no assurance that any of the defendants will be successful in the outcome of any pending or any potential future lawsuits. The defense or settlement of any lawsuit or claim that remains unresolved at the time the Arrangment is completed may adversely affect Chord’s or Enerplus’ business, financial condition, results of operations and cash flows.

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. Although a temporary truce was brokered by Qatar on November 24, 2023, hostilities resumed on December 1, 2023, and the armed conflict is ongoing as of the date of this filing. More recently, Iranian-backed Houthi rebels have conducted several attacks against commercial shipping in the Red Sea, and on January 2, 2024, a senior Hamas leader was killed in a drone strike in Beirut, the capital of Lebanon. Hostilities could continue to escalate and spread into Lebanon and 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.

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. On March 10, 2023, Silicon Valley Bank was closed by the California Department of Financial Protection and Innovation, which appointed the FDIC as receiver. Similarly, on March 8, 2023, Silvergate Capital Corporation announced its intent to wind down and liquidate Silvergate Bank, and on March 12, 2023, Signature Bank was swept into receivership. Although we do 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, as well as the potential for a U.S. government shutdown relating to budget deadlines, 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.

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;

•weather conditions and natural disasters;

•domestic and foreign governmental laws, regulations and policies, including, among others, the IRA, environmental requirements and the discouragement of the use of fuels that emit GHGs and encouragement of the use of alternative energy sources;

•speculation as to future commodity prices and the speculative trading of crude oil, NGL and natural gas futures contracts;

•changing consumer or market preferences, stockholder activism or activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and production of crude oil, 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.

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.

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our crude oil and natural gas E&P activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable crude oil, NGL or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Our estimated net proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves” below. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in planned expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

•shortages of or delays in obtaining equipment and qualified personnel;

•facility or equipment malfunctions and/or failure;

•unexpected operational events, including accidents;

•pressure or irregularities in geological formations;

•adverse weather or climatic conditions, such as blizzards, ice storms, wildfires, floods and prolonged drought conditions;

•reductions in crude oil, NGL and natural gas prices;

•inflation in exploration and drilling costs;

•disruptions in our supply chain for raw materials, chemicals and equipment;

•delays imposed by or resulting from compliance with regulatory requirements, including permits;

•proximity to and capacity of transportation facilities;

•contractual disputes;

•title problems; and

•limitations in the market for crude oil, 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.

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, 2023, 2022 and 2021.

In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by our independent reserve engineers, estimates of crude oil, NGL and natural gas reserves are inherently imprecise.

Actual future production, crude oil, NGL and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. In addition, we may adjust estimates of net proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control. Due to the limited production history of our undeveloped acreage, the estimates of future production associated with such properties may be subject to greater variance to actual production than would be the case with properties having a longer production history.

You should not assume that the present value of future net revenues from our estimated net proved reserves is the current market value of our estimated net crude oil and natural gas reserves. In accordance with SEC requirements, we based the estimated discounted future net revenues from our estimated net proved reserves on the unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months without giving effect to derivative transactions. Actual future net revenues from our oil and gas properties will be affected by factors such as:

•actual prices we receive for crude oil, 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.

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.

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. For example, the NDIC adopted regulations in 2013 that impose more rigorous pipeline development standards on midstream operators, some of whom we rely on to construct and operate pipeline infrastructure to transport the crude oil, NGLs and natural gas we produce.

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.

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.

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. On February 4, 2022, the Department of the Interior 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. 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.

The impact of pending and future legal proceedings on the systems, pipelines and facilities that we rely on can affect our ability to market our products and have a negative impact on realized pricing. In July 2020, the operator of DAPL was ordered by a U.S. District court to halt oil flow and empty the pipeline within 30 days while an environmental impact study (“EIS”) is completed. Also, in July 2020, the U.S. Court of Appeals for the District of Columbia Circuit issued a temporary administrative stay while the court considers the merits of a longer-term emergency stay order through the appeals process. On January 26, 2021, the U.S. Court of Appeals for the District of Columbia Circuit upheld the U.S. District court’s ruling that an EIS is needed and also reaffirmed its earlier decision which allows DAPL to operate through the EIS process. The owners of DAPL appealed the lower court decision to the U.S. Supreme Court in September 2021; however, the appeal was rejected on February 22, 2022. The Corps released its draft EIS on September 8, 2023, which it made available for public comments. The Corps initially established a deadline of November 13, 2023 for public comments and, on October 31, 2023, the deadline for public comments was extended to December 13, 2023. The Corps did not identify a preferred alternative among the five actions analyzed (including granting the requested easement with conditions as originally issued) in the draft EIS. Three of the five alternative actions considered would require the abandonment, removal or reroute of the segment of DAPL at issue. A final EIS and formal decision by the Corps is expected in spring or summer 2024; 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. 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.

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 West Texas Intermediate (“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, 2023, 2022 and 2021.

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.

Approximately 29% of our estimated net proved reserves were classified as PUD as of December 31, 2023. 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 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.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our E&P activities are subject to all the operating risks associated with drilling for and producing crude oil and natural gas, including the possibility of:

•environmental hazards, such as natural gas leaks, crude oil and produced water spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gas, such as hydrogen sulfide, or other pollutants into the environment;

•abnormally pressured formations;

•shortages of, or delays in, obtaining water for hydraulic fracturing activities;

•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.

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 management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These potential drilling locations, including those without PUD reserves, represent a significant part of our execution strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, crude oil, NGL and natural gas prices, costs and drilling results. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations. See also “Risks related to our financial position—Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our estimated net crude oil, NGL and natural gas reserves.”

Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil, 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, 2023, 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, 2023, we had an aggregate of 1,296 net acres expiring in 2024, 632 net acres expiring in 2025 and 2,087 net acres expiring in 2026 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, 2023, 2022 and 2021.

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. 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 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 impose numerous obligations that are applicable to our operations and services. The trend of more expansive and stringent environmental and occupational health and safety legislation and regulations applied to the oil and gas industry could continue, resulting in material increases in our costs of doing business and consequently affecting profitability. See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on these environmental and occupational health and safety matters. Compliance with existing environmental and occupational safety and health laws, regulations, executive orders and other regulatory initiatives, or any other such new legal requirements, could, among other things, require us or our customers to install new or modified emission controls on equipment or processes, incur longer permitting timelines and incur significantly increased capital or operating expenditures, which costs may be material. One or more of these developments that impact us, our service providers or our customers could have a material adverse effect on our business, results of operations and financial condition and reduce demand for our products.

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 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 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.

Businesses across all industries are facing increasing scrutiny from stakeholders related to their ESG practices. Businesses that do not adapt to or comply with 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 ESG issues, 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. Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG related disclosures, increasing mandatory ESG 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, our Board of Directors has established the Environmental, Social and Governance Committee, which is charged with overseeing our ESG policies. 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 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, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.

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. 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.

Also, institutional lenders may, of their own accord, decide not to provide funding for fossil fuel energy companies or related infrastructure projects based on climate or other ESG-related concerns, which could affect our access to capital for potential growth projects.

See “Item 1. Business—Regulation—Environmental and occupational health and safety regulation” for more discussion on ESG and climate-related concerns.

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.

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. There have been wide-ranging actions taken by international, federal, state and local public health and governmental authorities to contain and combat the outbreak and spread of COVID-19 in regions across the United States and the world. To the extent COVID-19 continues or worsens, governments may impose additional similar restrictions.

In addition, the resurgence of COVID-19 or other 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. There can be no assurance that our personnel will not 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.

Any further impact from COVID-19 will depend on future developments and new information that may emerge regarding the continued severity of COVID-19 and any new variants, 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.

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.

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.

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.

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.

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. The public health concerns posed by COVID-19 could pose a risk to our personnel and may render our personnel unable to work or travel. The extent to which COVID-19 may impact our personnel, and subsequently our business, cannot be predicted at this time. We continue to monitor impacts of COVID-19, have actively implemented policies and practices to address COVID-19, and may adjust our current policies and practices as more information and guidance become available. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

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 periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

•recoverable reserves;

•future crude oil, NGL and natural gas prices and their appropriate differentials;

•development and operating costs;

•potential for future drilling and production;

•validity of the seller’s title to the properties, which may be less than expected at the time of signing the purchase agreement; and

•potential environmental and other liabilities, together with associated litigation of such matters.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities or title defects in excess of the amounts claimed by us before closing and acquire properties on an “as is” basis. Indemnification from the sellers will generally be effective only during a limited time period after the closing and subject to certain dollar limitations and minimums. We may not be able to collect on such indemnification because of disputes with the sellers or their inability to pay. Moreover, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results of operations or cash flows.

Significant acquisitions and other strategic transactions, including the Merger, 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 Merger, 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 Merger, our results of operations and stock price may be adversely affected.

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.

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.

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 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 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.

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 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 $2.7 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.

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;

•the costs of developing and producing our crude oil and natural gas production;

•our ability to acquire, locate and produce new reserves;

•the ability and willingness of our banks to lend; and

•our ability to access the equity and debt capital markets.

If the borrowing base under our revolving credit facility or our revenues decrease as a result of low crude oil, NGL or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves, and could adversely affect our business, financial condition and results of operations.

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.

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, 2023, 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, 2023, we had commodity derivatives in place with nine counterparties and a total net commodity derivative liability of $3.6 million.

From time to time, U.S. federal and state level legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal and state 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. 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 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. In the future, the U.S.

Department of Treasury and the Internal Revenue Service are expected to release regulations and interpretive guidance relating to the CAMT, 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 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 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. Additionally, 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.

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 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.

As of December 31, 2023, we had no outstanding borrowings and $8.9 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.

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.

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, authorizes our Board of Directors to issue preferred stock without stockholder approval. If our Board of Directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

•advance notice provisions for stockholder proposals and nominations for elections to the Board of Directors to be acted upon at meetings of stockholders; and

•limitations on the ability of our stockholders to call special meetings.

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our Board of Directors.

As of December 31, 2023, we had 3,232,654 outstanding warrants to purchase shares of our common stock and 839,039 outstanding stock–based awards. In addition, as of December 31, 2023, a total of 2,201,501 shares of common stock were available for future issuance under our equity incentive plans, including 1,002,681 shares of common stock reserved for future issuance under the Oasis 2020 Long Term Incentive Plan (the “2020 LTIP”) and 1,198,820 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.

In connection with the Merger, we assumed certain pre-petition general unsecured claims of Whiting, which were subject to the jurisdiction of the United States Bankruptcy Court for the Southern District of Texas and had reserved 1,224,840 shares of common stock for potential future distribution to settle such general unsecured claims. As of October 19, 2023, all claims were resolved and we released the previously reserved shares of common stock.

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.

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.

The U.S. economy experienced significant increases in inflation rates beginning in 2021 from, among other things, supply chain disruptions and governmental stimulus or fiscal policies adopted in response to the COVID-19 pandemic. Although U.S. inflation rates have shown signs of moderating, we cannot predict any future trends in the rate of inflation. Elevated interest rates and the state of the general economy have brought uncertainty to the near-term economic outlook. The re-emergence of high levels of inflation would further raise our costs for labor, materials and services, due to a combination of factors, including: (i) global supply chain disruptions resulting in limited availability of certain materials and equipment (including drill pipe, casing and tubing), (ii) increased demand for fuel and steel, (iii) increased demand for services coupled with a limited availability of service providers and (iv) labor shortages, which would negatively impact our profitability and cash flows. We seek to mitigate these inflationary impacts by reviewing our pricing agreements on a regular basis and entering into agreements with our service providers to manage costs and availability of certain services that are utilized in our operations.

It is difficult to predict whether such inflationary pressures will have a materially negative impact to our overall financial and operating results in 2024; 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, 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.

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 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.

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.

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.

None.

We maintain a cybersecurity program overseen by the Managing Director, Information Technology that uses a risk-based methodology to support the security, confidentiality, integrity and availability of our information. The security of our field infrastructure and corporate network is a priority for our business. We recognize the importance of assessing, identifying and managing material risks associated with cybersecurity threats. Our cybersecurity program utilizes a combination of automated tools, manual processes and third-party assessments with the goal of identifying and assessing potential cybersecurity risks. These risks may include, among other things, operational risks, 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 (NIST) 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.

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 information technology (“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.

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 Managing Director, 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 Managing Director, 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 Managing Director, Information Technology, is responsible for overseeing the prevention, mitigation, detection and remediation of cybersecurity incidents. Our Managing Director, Information Technology, has over 16 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 Managing Director, 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 Financial Officer. The Cybersecurity Council is led by the Managing Director, Information Technology, and is comprised of select members of the IT team. 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.

The information required by Item 2. is contained in Item 1. Business.

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.

Market for Registrant’s Common Equity. Our common stock is listed on the Nasdaq under the symbol “CHRD”.

Dividends. In 2023, we paid an aggregate amount of cash dividends of $11.88 per share of common stock, including base dividends of $5.00 per share of common stock and variable dividends of $6.88 per share of common stock. On February 21, 2024, we declared a base-plus-variable dividend of $3.25 per share of common stock. These dividends will be payable on March 19, 2024 to stockholders of record as of March 5, 2024.

In October 2023, we introduced a new $750 million share repurchase program. 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 16, 2024, the number of record holders of our common stock was 285. Based on inquiry, management believes that the number of beneficial owners of our common stock as of February 16, 2024 was approximately 109,816.

On February 16, 2024, the last sale price of our common stock, as reported on the Nasdaq, was $163.71 per share.

Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2023.

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 2024 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, 2023:

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, 2023						117,632						$	164.17					117,632						$	746,489,046
November 1 – November 30, 2023						237,162						161.94						232,359						708,864,811
December 1 – December 31, 2023						160,480						161.15						160,480						683,003,178

___________________ 

(1)During the fourth quarter of 2023, we withheld 4,803 shares of common stock to satisfy tax withholding obligations upon vesting of certain equity-based awards.

(2)During the fourth quarter of 2023, we repurchased 510,471 shares of common stock at a weighted average price of $162.20 per common share for a total cost of $82.8 million, excluding accrued excise tax of $0.2 million, under our publicly announced share repurchase program.

(3)On October 25, 2023, our Board of Directors authorized a new share repurchase program of up to $750 million of our common stock, which resulted in the expiration of the $300 million share repurchase program authorized in August 2022.

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, 2023. 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.

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 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.

Enerplus is an independent North American oil and gas exploration and production company. We believe that the combination of Chord and Enerplus will provide improving returns, capital efficiency, low-cost inventory, and a peer-leading balance sheet, all of which support sustainable free cash flow generation and meaningful shareholder returns. Under the terms of the Arrangement Agreement, Enerplus shareholders will receive 0.10125 shares of Chord common stock and $1.84 in cash in exchange for each common share of Enerplus they own at closing. The transaction is expected to close by mid-year 2024.

During the year ended December 31, 2023, we completed the acquisition of approximately 62,000 net acres in the Williston Basin from XTO Energy Inc. and affiliates, subsidiaries of Exxon Mobil Corporation (collectively, “XTO”), for total cash consideration of $361.6 million, including customary purchase price adjustments (the “2023 Williston Basin Acquisition”). The effective date of the 2023 Williston Basin Acquisition was April 1, 2023. We funded the 2023 Williston Basin Acquisition with cash on hand.

During the year ended December 31, 2023, we entered into separate agreements with multiple buyers to sell a vast majority of our non-core properties located outside of the Williston Basin (the “Non-core Asset Sales”). As of December 31, 2023, we 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.

In addition, during the year ended December 31, 2023, we completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds of $12.1 million.

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 decreased during 2023 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 and continued to raise interest rates during a portion of 2023. Although U.S. inflation rates have shown signs of moderating, higher interest rates generally reduce economic activity levels, which could 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 resulting from the potential economic outcomes of monetary policy decisions of central banks, coupled with the geopolitical risks associated with the continued military conflicts between Russia and Ukraine and between 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 is reasonably likely to occur in the near future at current price levels; however, we would evaluate the recoverability of the carrying value of our oil and gas properties as a result of a future material or extended decline in the price of crude oil, 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” 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:

			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		%

			2022																								Year ended December 31, 2022
			Q1						Q2						Q3						Q4
Average Realized Crude Oil Prices ($/Bbl)(1)			$	95.34					$	111.79					$	93.13					$	83.74					$	92.98
Average Price Differential ($/Bbl)(2)			$	1.22					$	2.82					$	1.63					$	0.99					$	1.52
Average Price Differential Percentage(2)			1.3		%				2.5		%				1.8		%				1.2		%				1.6		%

__________________ 

(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, 2023, 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.

The results of operations presented below relate to the periods ended December 31, 2023 and 2022. On July 1, 2022, we completed the merger of equals transaction with Whiting Petroleum Corporation (“Whiting”) (the “Merger”).

Accordingly, the results of operations presented herein report the results of legacy Oasis prior to the closing of the Merger on July 1, 2022 and the results of Chord (including legacy Whiting) from July 1, 2022 through December 31, 2023, unless otherwise noted.

As of the completion of the Merger on July 1, 2022, we elected to report crude oil, NGLs and natural gas separately on a three-stream basis. For the periods prior to July 1, 2022, we reported crude oil and natural gas, which included NGLs, on a two-stream basis. This change impacts the comparability with prior periods.

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. Prior periods have been recast so that the basis of presentation is consistent with that of the 2022 consolidated financial statements. See “Item 8. Financial Statements and Supplementary Data—Note 11—Discontinued Operations” for additional information.

For discussion related to changes in financial condition and results of operations for the year ended December 31, 2022 compared to the year ended December 31, 2021, 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, 2022, filed with the SEC on February 28, 2023.

•Production volumes averaged 173,425 Boepd (58% oil).

•Lease operating expenses (“LOE”) were $10.41 per Boe.

•E&P and other capital expenditures were $922.3 million.

•Estimated net proved reserves were 636.2 MMBoe as of December 31, 2023, with a Standardized Measure of $7.0 billion and PV-10 of $8.5 billion.

•TIL’d 94 gross (69 net) operated wells.

•Paid $11.88 per share base-plus-variable cash dividend for the year ended December 31, 2023.

•Repurchased $240.9 million of common stock with $683.0 million remaining under our $750 million share repurchase program.

•Declared a base-plus-variable cash dividend of $3.25 per share of common stock. These dividends will be payable on March 19, 2024 to stockholders of record as of March 5, 2024.

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 or changes in commodity prices. 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 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 data and average realized prices for the periods presented:

__________________

(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 revenues, production data and average sales prices. 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)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 but does not include proceeds from derivative liquidations or payments for derivative modifications. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.

Crude oil revenues. Our crude oil revenues increased $469.0 million to $2.8 billion for the year ended December 31, 2023 due to the Merger, which significantly expanded our operations in the Williston Basin. This increase was primarily driven by higher crude oil production volumes sold year-over-year of $854.0 million due to more wells TIL’d. The increase was partially offset by a decrease of $385.0 million driven by lower realized crude oil sales prices year-over-year. Average crude oil sales prices, without derivative settlements, decreased by $15.13 per barrel year-over-year to an average of $77.85 per barrel for the year ended December 31, 2023.

NGL and natural gas revenues. Our NGL and natural gas revenues decreased $312.9 million to $296.4 million for the year ended December 31, 2023. Our NGL and natural gas sales decreased primarily due to lower natural gas and NGL prices year-over-year of $407.8 million, partially offset by an increase of $95.0 million due to higher natural gas and NGL sales volumes year-over-year due to our expanded operations in the Williston Basin as a result of the Merger.

Effective July 1, 2022, we elected to report crude oil, NGLs and natural gas separately on a three-stream basis. Prior to this, we reported on a two-stream basis and NGLs were reported with the natural gas stream. Accordingly, the natural gas sales prices for the periods prior to three-stream reporting were higher compared to the periods subsequent to three-stream reporting since the natural gas sales price included the value of NGLs. The conversion to three-stream reporting did not impact our total reported revenues. During the year ended December 31, 2023, average natural gas sales prices, without derivative settlements, were $1.43 per Mcf, and average NGL sales prices, without derivative settlements, were $13.62 per barrel. During the year ended December 31, 2022, average natural gas sales prices, without derivative settlements, were $6.30 per Mcf, and average NGL sales prices, without derivative settlements, were $26.23 per barrel.

Purchased oil and gas sales. Purchased oil and gas sales increased $94.1 million to $764.2 million for the year ended December 31, 2023. This increase was primarily due to an increase in crude oil volumes purchased and then subsequently sold, partially offset by lower crude oil prices year-over-year.

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

			Year Ended December 31,
			2023						2022
			(In thousands, except per Boe of production)
Operating expenses
Lease operating expenses			$	658,938					$	443,560
Gathering, processing and transportation expenses			180,219						141,644
Purchased oil and gas expenses			761,325						671,935
Production taxes			260,002						229,571
Depreciation, depletion and amortization			598,562						369,659
Exploration and impairment			35,330						2,204
General and administrative expenses			126,319						209,299
Total operating expenses			2,620,695						2,067,872
Gain (loss) on sale of assets, net			(2,764)						4,867
Operating income			1,273,182						1,583,789
Other income (expense)
Net gain (loss) on derivative instruments			63,182						(208,128)
Net gain from investment in unconsolidated affiliate			21,330						34,366
Interest expense, net of capitalized interest			(28,630)						(29,349)
Other income			9,964						2,901
Total other expense, net			65,846						(200,210)
Income from continuing operations			1,339,028						1,383,579
Income tax (expense) benefit			(315,249)						46,884
Net income from continuing operations			1,023,779						1,430,463
Income from discontinued operations attributable to Chord, net of income tax			—						425,696
Net income attributable to Chord			$	1,023,779					$	1,856,159
Costs and expenses (per Boe of production)
Lease operating expenses			$	10.41					$	10.14
Gathering, processing and transportation expenses			2.85						3.24
Production taxes			4.11						5.25

Lease operating expenses. Lease operating expenses increased $215.4 million to $658.9 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022 primarily due to the Merger, which significantly expanded our operations in the Williston Basin. The increase in LOE included increases in workover costs of $86.7 million, fixed costs of $75.8 million and variable costs of $28.1 million. LOE per Boe increased $0.27 per Boe to $10.41 per Boe for the year ended December 31, 2023 primarily due to increases in workover costs of $0.58 per Boe, partially offset by decreases in fixed and variable costs of $0.28 per Boe.

Gathering, processing and transportation expenses. Gathering, processing and transportation (“GPT”) expenses increased $38.6 million to $180.2 million for the year ended December 31, 2023 due to the Merger, which significantly expanded our operations in the Williston Basin. This increase is attributable to higher production volumes of $62.1 million, offset by a decrease of $13.2 million due to the change in fair value of certain derivative transportation contracts and a decrease of $10.3 million due to lower rates. Our GPT expenses on a per Boe basis decreased $0.39 per Boe to $2.85 per Boe for the year ended December 31, 2023.

Purchased oil and gas expenses. Purchased oil and gas expenses increased $89.4 million to $761.3 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022 primarily due to an increase in crude oil volumes purchased, offset by lower crude oil prices year-over-year.

Production taxes. Production taxes increased $30.4 million to $260.0 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. This increase is primarily due to an increase in crude oil production taxes as a result of higher oil sales.

The production tax rate as a percentage of crude oil, NGL and natural gas sales was 8.3% for the year ended December 31, 2023 as compared to 7.7% for the year ended December 31, 2022. This increase was primarily due to an increase in natural gas production volumes, coupled with lower average natural gas sales prices.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expenses increased $228.9 million to $598.6 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022 due to the Merger, which significantly expanded our operations in the Williston Basin, and as a result, increased production volumes sold year-over-year due to more wells TIL’d. DD&A expenses increased $176.1 million attributable to increased production volumes and $51.9 million due to a higher depletion rate year-over-year. The depletion rate increased $1.10 per Boe to $9.20 per Boe year-over-year for the year ended December 31, 2023 due to higher costs.

Exploration and impairment expenses. Exploration and impairment expenses increased $33.1 million to $35.3 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. This increase was primarily due to impairment expenses of $29.0 million during the year ended December 31, 2023 and higher exploration expenses year-over-year of $3.8 million. Impairment expenses for the year ended December 31, 2023 included $17.5 million associated with the write-down of the right-of-use asset for our Denver office lease, $5.8 million associated with a lower of average 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.

General and administrative expenses. Our general and administrative (“G&A”) expenses decreased $83.0 million to $126.3 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. This decrease is primarily attributable to a decrease in merger-related costs, partially offset by an increase in compensation and other costs associated with a larger organization after the Merger.

Derivative instruments. We recorded a $63.2 million net gain on derivative instruments for the year ended December 31, 2023, which was primarily comprised of a net gain of $56.4 million associated with our contracts to manage commodity price risk and a net gain of $6.8 million associated with an embedded derivative related to the contingent consideration included within the 2021 agreement to sell our upstream assets in the Permian Basin. 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, partially offset by a realized loss of $256.7 million on settled commodity derivative contracts. During the year ended December 31, 2022, we recorded a $208.1 million net loss on derivative instruments, which included a net loss of $224.2 million associated with our commodity derivatives contracts, partially offset by an unrealized gain of $16.1 million associated with our contract that includes contingent consideration. The net loss of $224.2 million on commodity derivative contracts was comprised of a realized loss of $561.1 million on settled commodity derivative contracts, partially offset by an unrealized gain of $336.9 million related to the change in fair value of our commodity derivative contracts.

Investment in unconsolidated affiliate. On November 3, 2023, Energy Transfer LP (“Energy Transfer”) completed a merger with Crestwood, and holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood unit held. No gain or loss was recorded as a result of this merger. For 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.

Other income, net. For the year ended December 31, 2023, we recognized $10.0 million of other income, net as compared to $2.9 million for the year ended December 31, 2022. The $7.1 million increase was primarily due to an increase in interest income year-over-year associated with higher balances in our money market accounts.

Income tax (expense) benefit. Our income tax expense was recorded at 23.5% of pre-tax income from continuing operations for the year ended December 31, 2023, and our income tax benefit was recorded at (3.4)% of pre-tax income from continuing operations for the year ended December 31, 2022. Our effective tax rate for the year ended December 31, 2023 was higher than the effective tax rate for the year ended December 31, 2022 primarily due to the impact of releasing substantially all of the remaining valuation allowance on our net deferred tax assets in 2022.

Income from discontinued operations attributable to Chord, net of income tax. Income from discontinued operations attributable to Chord, net of income tax for the year ended December 31, 2022 of $425.7 million represents income from OMP from January 1, 2022 to the completion of the OMP Merger on February 1, 2022. This was primarily comprised of a gain on sale of $518.9 million and midstream revenues of $23.3 million, offset by income tax expense of $101.1 million, midstream expenses of $13.2 million and interest expense of $3.7 million. There were no discontinued operations for the year ended December 31, 2023.

As of December 31, 2023, we had $1.3 billion of liquidity available, including $318.0 million in cash and cash equivalents and $991.1 million of aggregate unused borrowing capacity available under our Credit Facility (defined below). Our primary sources of liquidity are from cash on hand, cash flows from operations and available borrowing capacity under our Credit Facility. Our primary liquidity requirements are for capital expenditures for the development of oil and gas properties, dividend payments, share repurchases and working capital requirements. In addition, we completed the 2023 Williston Basin Acquisition on June 30, 2023 for total cash consideration of $361.6 million with cash on hand.

Capital availability will be affected by prevailing conditions in our industry, the global economy, the global banking and financial markets, stakeholder scrutiny of ESG matters and other factors, many of which are beyond our control. While the U.S. bank failures in March 2023 appear to be somewhat contained, risks to the financial sector remain as evidenced by recent publicity regarding New York Community Bancorp Inc. In addition, the Federal Reserve’s increases in interest rates and the potential for such rates to increase further or to remain elevated for an extended period of time have created additional economic uncertainty. Although we do not currently have a business relationship with the failed banking institutions and are unable to predict future interest rates, these disruptions 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.

Our cash flows depend on many factors, including the price of crude oil, NGL and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the impact of changes in crude oil, NGL and natural gas prices on our production, which mitigates our exposure to crude oil, NGL and natural gas price declines; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices.

As of December 31, 2023, our commodity derivative contracts cover 5,762 MBbls of our crude oil production for 2024, as well as 2,457 MBbls of our crude oil production for 2025 and 651,600 MMBtu of our natural gas production for 2025. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” and “Part I, Item 1A. Risk Factors” for additional information.

Subsequent to December 31, 2023, we entered into the following commodity derivative contracts to manage risks related to changes in crude oil prices.

																		Volumes (Bbl)												Weighted Average Prices
Commodity						Settlement Period						Derivative Instrument						Total						Daily						Sub-Floor						Floor						Ceiling
Crude oil						2024						Two-way collars						825,000						3,000												$	66.65					$	81.94
Crude oil						2025						Three-way collars						1,095,000						3,000						$	55.00					$	70.00					$	81.62
Crude oil						2026						Three-way collars						270,000						3,000						$	50.00					$	65.00					$	83.70

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. There were no borrowings outstanding under the Credit Facility (defined below) as of December 31, 2023; however, on a quarterly basis, we pay a commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

We also have contracts which include provisions for the delivery, transport or purchase of a minimum volume of crude oil, 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 (excluding deliveries from future production and applicable volume credits) were $391.6 million as of December 31, 2023. 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.

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.

Senior secured revolving line of credit. We have a senior secured revolving credit facility (the “Credit Facility”) with a borrowing base of $2.5 billion and elected commitments of $1.0 billion that is due July 1, 2027. As of December 31, 2023, we had no borrowings outstanding and $8.9 million of outstanding letters of credit, resulting in an unused borrowing capacity of $991.1 million. On October 31, 2023, we completed the semi-annual borrowing base redetermination, reaffirmed the borrowing base of $2.5 billion and maintained the aggregate amount of elected commitments of $1.0 billion. Additionally, the amendment permits us to incur term loans in addition to the revolving loans provided under the Amended and Restated Credit Agreement.

For the year ended December 31, 2023, the weighted average interest rate incurred on borrowings under the Credit Facility was 7.1%, compared to 4.6% for the year ended December 31, 2022.

We were in compliance with the financial covenants in the Credit Facility at December 31, 2023. See “Item 8. Financial Statements and Supplementary Data—Note 13—Long-Term Debt” for additional information.

Senior unsecured notes. As of December 31, 2023, we had $400.0 million of 6.375% senior unsecured notes (the “Senior Notes”) that mature on June 1, 2026. Interest on the senior unsecured 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.

The Consolidated Statements of Cash Flows have not been recast for discontinued operations, therefore the discussion below concerning cash flows from operating activities, investing activities and financing activities includes the results of both continuing operations and discontinued operations. See “Item 8. Financial Statements and Supplementary Data—Note 11—Discontinued Operations” for disclosure of cash flow impacts attributable to discontinued operations. For a discussion on cash flows for the year ended December 31, 2022 compared to the year ended December 31, 2021, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2022 Annual Report on Form 10-K filed with the SEC on February 28, 2023 under the subheading “Cash flows.”

The following table summarizes our change in cash flows:

			Year Ended December 31,
			2023						2022
			(In thousands)
Net cash provided by operating activities			$	1,819,851					$	1,924,026
Net cash used in investing activities			(1,430,306)						(682,562)
Net cash used in financing activities			(664,698)						(823,096)
Increase (decrease) in cash and cash equivalents			$	(275,153)					$	418,368

Net cash provided by operating activities was $1,819.9 million for the year ended December 31, 2023. The decrease in net cash provided by operating activities of $104.2 million from the year ended December 31, 2022 was primarily due to an increase in operating expenses, partially offset by an increase in revenues from crude oil, NGL and natural gas sales. See “Results of Operations” above for additional information on the impact of volumes and prices on revenues and for additional information on increases and decreases in operating expenses between periods.

Working capital.  Our working capital is primarily impacted due to the factors discussed above, coupled with the timing of cash receipts and disbursements. Changes in working capital (as reflected in the Consolidated Statements of Cash Flows) decreased net cash flows from operating activities by $91.9 million and $46.6 million during the year ended December 31, 2023 and 2022, 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.

Our 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 $991.1 million as of December 31, 2023, and excludes current hedge assets, which were $37.4 million as of December 31, 2023. For purposes of the Current Ratio, the Credit Facility’s definition of total current liabilities excludes current hedge liabilities, which were $14.2 million as of December 31, 2023.

Net cash used in investing activities was $1,430.3 million for the year ended December 31, 2023. The increase in net cash used in investing activities of $747.7 million from the year ended December 31, 2022 was primarily attributable to an increase of $374.3 million in capital expenditures incurred to develop our oil and gas properties and an increase in acquisitions of $213.5 million. During the year ended December 31, 2023, we paid cash consideration of $361.6 million for the 2023 Williston Basin Acquisition as compared to net cash consideration of $148.1 million paid to Whiting stockholders in connection with the Merger in 2022. In addition, we had a decrease in proceeds from the sale of our investment in Crestwood and cash distributions for our ownership of Crestwood’s common units of $420.7 million (see Note 12—Investment in Unconsolidated Affiliate). We had a decrease in proceeds from divestitures of $114.8 million year-over-year, whereby we received net proceeds from divestitures of $160.0 million in connection with the completion of the OMP Merger in February 2022 compared to $54.4 million primarily due to the sale of non-core properties and non-operated wellbore divestitures during year ended December 31, 2023. These increases in net cash used in investing activities were partially offset by a decrease of $364.1 million for cash payments to settle commodity derivative contracts.

For the year ended December 31, 2023, net cash used in financing activities of $664.7 million was primarily attributable to dividends paid to stockholders of $500.3 million and payments made to repurchase common stock of $239.3 million, partially offset by proceeds from the exercise of outstanding warrants of $91.3 million. For the year ended December 31, 2022, net cash used in financing activities of $823.1 million was primarily attributable to dividends paid to stockholders of $654.7 million, payments made to repurchase common stock of $152.0 million and payments for income tax withholdings on vested equity-based compensation awards of $41.8 million, partially offset by proceeds from the exercise of outstanding warrants of $19.8 million.

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,
			2023						2022						2021
			(In thousands)
Capital expenditures
E&P			$	920,841					$	495,947					$	168,189
Other capital expenditures(1)			5,626						11,771						2,277
Total E&P and other capital expenditures(2)			926,467						507,718						170,466
Acquisitions(3)			361,609						(2,275)						586,030
Total capital expenditures from continuing operations			1,288,076						505,443						756,496
Discontinued operations(4)			—						3,396						49,123
Total capital expenditures(5)			$	1,288,076					$	508,839					$	805,619