Chord Energy Corp (CHRD) Business

Item 1. Business

Overview

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

On May 31, 2024, we acquired Enerplus Corporation, a corporation existing under the laws of the Province of Alberta, Canada (“Enerplus”) in a stock-and-cash transaction (such transaction, the “Arrangement”). The results of operations and reserves data presented herein report the results of legacy Chord from January 1, 2023 through May 30, 2024 and the results of Chord (including legacy Enerplus) from May 31, 2024 through December 31, 2025, unless otherwise noted.

As of December 31, 2025, we had 1,302,921 net leasehold acres in the Williston Basin, approximately all of which is held by production. We are currently exploiting significant resource potential from the Middle Bakken and Three Forks formations, which are present across a substantial portion of our acreage. We believe the locations, size and concentration of our acreage in the Williston Basin creates an opportunity for us to achieve cost, recovery and production efficiencies through the development of our project inventory. Our management team has a proven record of accomplishment in identifying, acquiring and executing large, repeatable development drilling programs and has substantial experience in the Williston Basin.

As of December 31, 2025, we had 5,025 gross (3,937.3 net) operated producing wells. Our working interest for producing wells averaged 78% in the wells we operate. During the year ended December 31, 2025, we had average daily production of 276,620 net Boepd. As of December 31, 2025, Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, estimated our net proved reserves to be 917.5 MMBoe, of which 69% were classified as proved developed and 56% were crude oil.

Business Strategy

Our operational and financial strategy is focused on rigorous capital discipline and generating significant, sustainable free cash flow by executing on the following strategic priorities:

•Maximize returns. We intend to efficiently execute our development program and optimize capital allocation, while evaluating our performance and focusing on continuous improvement. We have established a strong capital allocation framework with the objective of balancing stockholder returns and reinvestment of capital. We are focused on conservative capital allocation, delivering low reinvestment rates and returning significant capital to stockholders at mid-cycle oil prices. Since introducing our return of capital program in 2021, we have declared an aggregate amount of cash dividends to our stockholders of $61.19 per share of common stock and repurchased an aggregate amount of $1.3 billion shares of common stock.

Our scale and high-quality assets in the Williston Basin allow us to generate significant, sustainable cash flow to support maximizing returns at mid-cycle oil prices. We expect that our business strategy will continue to provide sizable cash flow generation which will enable us to return capital to our stockholders and continue to pursue acquisitions that add to or lengthen our inventory, while maintaining a strong balance sheet. We have a return of capital program designed to provide peer-leading, sustainable stockholder returns. The return of capital plan includes a base cash dividend of $1.30 per share per quarter ($5.20 per share annualized) and a $1 billion share repurchase program, which the Board of Directors authorized during the third quarter of 2025.

As of December 31, 2025, we had $952.2 million remaining under this share repurchase program. We plan to return capital through the base dividend payout, supplemented by opportunistic share repurchases and variable dividends.

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We expect to return a certain percentage of adjusted free cash flow (“Adjusted FCF”) each quarter, with the targeted percentage based on free cash flow generated during the previous quarter and projected leverage (defined as the ratio of (i) the sum of our aggregate outstanding debt, less cash and cash equivalents held as of the balance sheet date, to (ii) our estimated earnings before interest, taxes, depreciation and amortization for the next twelve months at $65/Bbl WTI and $3/MMBtu Henry Hub, excluding the impact of commodity derivative instruments) under the following framework:

•Financial strength. Our management team is focused on maintaining a solid risk management process to preserve a strong balance sheet and protect our cash generation capabilities. Recognizing the oil and gas industry is cyclical, our business is designed to navigate challenging environments while preserving sufficient liquidity in an effort to be opportunistic in low commodity price cycles.

As of December 31, 2025, we had $2,156.7 million of liquidity available, including $189.5 million of cash and cash equivalents and $1,967.2 million of unused borrowing base capacity available under the Credit Facility (defined in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”).

•Commitment to excellence. We are focused on creating a durable organization that generates strong financial returns and sustainable free cash flow through commodity cycles. We believe we have an attractive inventory that is resilient to commodity price fluctuations, which supports the sustainable generation of free cash flow. Our management team is focused on the continuous improvement of our operations and overall cost structure and has robust experience in successfully operating cost-efficient development programs. The magnitude and concentration of our acreage within the Williston Basin allows us to capture economies of scale, including the ability to drill longer lateral lengths for developmental wells, the ability to drill multiple wells from a single drilling pad into multiple formations, the ability to utilize centralized production and crude oil, natural gas and water fluid handling facilities and infrastructure, and reduce the time and cost of rig mobilization.

We have extensive engineering, operational, geologic and subsurface technical knowledge. Our technical team has access to an abundance of digital well log, seismic, completion, production and other subsurface information, which is analyzed in order to accurately and efficiently characterize the anticipated performance of our oil and gas reservoirs. We leverage many technologies in support of data gathering, information analysis and production optimization. Data management and reporting practices improve the availability, accuracy and analysis of our information in a cycle of continuous improvement. Emerging technologies are evaluated on a regular basis, ensuring we are implementing the best technologies for our business needs.

Our team is focused on employing leading drilling and completions techniques to optimize overall project economics. We continuously evaluate our internal drilling and completions results and monitor the results of other operators to improve our operating practices. We continue to optimize our completion designs based on geology and well spacing.

We foster a culture of innovation and continuous improvement, constantly looking for ways to strengthen our organizational agility and adaptability. Management, with oversight from the Board of Directors, is focused on enterprise risk management (“ERM”), which seeks to establish guidelines and policies for appropriate risk assessment and risk management, including exposure to safety risk, financial risk, commodity price risk and cybersecurity risk. The Audit and Reserves Committee of our Board of Directors reviews our cybersecurity guidelines and policies and receives updates on cybersecurity matters at least semi-annually. In addition, we have established cybersecurity practices that are guided by the National Institute of Standards and Technology, require quarterly cybersecurity training of our employees and receive an annual audit and penetration assessment by a third party. Our ERM program allows us to have a better enterprise-view of risks, improve our risk response and preparedness and better incorporate risk mitigation around existing and emerging risks into our strategic plans.

•Responsible stewards. We seek to maintain a culture of continuous improvement in ESG practices as outlined here in this Annual Report on Form 10-K and in our Sustainability Report. We strive to provide reliable, safe and affordable energy in a responsible manner against the backdrop of an evolving energy landscape. The key tenets of our ESG philosophy are to always put safety first, minimize our environmental impact, reduce our emissions intensity, promote an inclusive, merit-based culture, align executive compensation with long-term value creation and stockholder interests, and support programs that benefit the communities in which we operate.

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From a safety standpoint, our corporate, field and environmental, health and safety teams are continually assessing and enhancing best practices and training to minimize the likelihood and severity of safety incidents among employees and contractors. Our goal is to create an environment where everyone on a Chord location is safe. We work to always put safety first, to be diligent and never complacent. We expect the same of any service provider or partner that works with us.

We continue to make strides in reducing Scope 1 GHG emissions, and in particular methane emissions. To help maintain the trend of continuous improvement, our cross-functional emissions reduction team has developed a more robust process to identify and prioritize emissions reduction opportunities, through the creation of a Marginal Abatement Cost Curve (“MACC”). A MACC is a decision-making tool that ranks emissions reduction options based on their cost-effectiveness and potential impact, allowing us to prioritize the most efficient strategies for potential emissions reduction. We have developed a MACC to help guide our carbon management investments.

We continue to strive to align our Scope 1 and Scope 2 disclosures towards various frameworks, including the Task Force on Climate-related Financial Disclosures (“TCFD”), the Sustainability Accounting Standards Board's (“SASB”) Extractives & Minerals Processing Sector: Oil & Gas - Exploration and Production Standard, the Global Reporting Initiative (“GRI”) Standard for Oil and Gas, and the American Exploration and Production Council (“AXPC”) ESG Metrics Framework. We also are proficient in capturing the natural gas that we produce, and, as of December 31, 2025, we were capturing substantially all of our natural gas production in North Dakota.

We provide leadership training and educational and professional development programs for employees at every level of the organization. We have also made meaningful investments in safety training programs that benefit our employees and contractors. We are deeply involved in the communities in which we work and deploy our financial resources, time and talent to support a number of charitable organizations.

We have a short-tenured and highly capable Board of Directors that is comprised of experienced energy industry professionals with a variety of diverse perspectives and that is 82% independent. In 2024, the Board of Directors established the Safety and Sustainability Committee, which is charged with overseeing our ESG strategies, policies and goals. For more information about our ESG and corporate responsibility efforts, please see the “Sustainability” page of our website and the Proxy Statement that we will file for our 2026 Annual Meeting of Stockholders.

Competitive Strengths

We have a number of competitive strengths that we believe will help us successfully execute our business strategies:

•Substantial leasehold position and existing production in one of North America’s leading unconventional crude oil resource plays. We believe that our Williston Basin acreage represents a premier position in a top oil basin in the United States that will continue to provide significant free cash flow generation. As of December 31, 2025, we had 1,302,921 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin, approximately all of which is held by production. As of December 31, 2025, approximately 56% of our 917.5 MMBoe estimated net proved reserves were comprised of crude oil. We believe we have a large project inventory of potential drilling locations that we have not yet drilled, the majority of which are operated by us.

•Operating control over the majority of our portfolio. In order to maintain control over our asset portfolio, we have established a leasehold position comprised largely of properties that we expect to operate. As of December 31, 2025, 89% of our estimated net proved reserves were attributable to properties that we operate. In 2026, we plan to TIL approximately 135 to 165 gross operated wells with an average working interest of approximately 75%. Controlling operations enables us to optimize capital allocation and control the pace of development of our assets to manage our reinvestment rates in line with our broader strategic objectives. Additionally, operational control allows us to materially benefit from proactively managing our cost structure across our portfolio. We believe that maintaining operational control over the majority of our acreage allows us to better pursue our strategies of enhancing returns through operational, cost and capital efficiencies and allows us to better manage infrastructure investment to drive down operating costs and optimize price realizations.

•Balance sheet among best-in-class. We believe a strong balance sheet provides us flexibility through volatile price environments and allows us to generate significant, sustainable free cash flow and corporate-level returns. We have no near-term debt maturities, are focused on rigorous capital discipline and have a hedging program to minimize downside risk.

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•Incentivized management team with proven operating and acquisition skills. Our senior management team has extensive expertise in the oil and gas industry with an average of 25 years of industry experience. We believe our management and technical team is one of our principal competitive strengths relative to our industry peers due to our team’s proven record of accomplishment in identification, acquisition and execution of large, repeatable development drilling programs. In addition, a substantial majority of our executive officers’ overall compensation is in long-term equity-based incentive awards, and we have implemented leading management compensation practices aligned with stockholders, which we believe provides our executive officers with significant incentives to grow the value of our business and return capital to stockholders.

Exploration and Production Operations

Estimated net proved reserves

Our estimated net proved reserves and related PV-10 at December 31, 2025, 2024 and 2023 are based on reports independently prepared by NSAI, our independent reserve engineers. NSAI evaluated 100% of the reserves and discounted values at December 31, 2025, 2024 and 2023 in accordance with the rules and regulations of the SEC applicable to companies involved in crude oil, NGL and natural gas producing activities. Our estimated net proved reserves and related standardized measure of discounted future net cash flows (“Standardized Measure”) and PV-10 do not include probable or possible reserves and were determined using the preceding 12 month unweighted arithmetic average of the first-day-of-the-month index prices for crude oil and natural gas (the “SEC Price”), which were held constant throughout the life of the properties. See “Item 8. Financial Statements and Supplementary Data—Note 23—Supplemental Oil and Gas Reserve Information — Unaudited” for additional information about our estimated net proved reserves.

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The following table summarizes our estimated net proved reserves based upon the SEC Price:

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(1)Standardized Measure represents the present value of estimated future net cash flows from proved crude oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows.

(2)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable financial measure under GAAP, because it does not include the effect of income taxes on discounted future net cash flows. See “Reconciliation of Standardized Measure to PV-10” below.

Reconciliation of Standardized Measure to PV-10

PV-10 is derived from Standardized Measure, which is the most directly comparable financial measure under GAAP. PV-10 is equal to Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and gas properties. PV-10, however, is not a substitute for Standardized Measure. Our PV-10 measure and Standardized Measure do not purport to represent the fair value of our crude oil and natural gas reserves.

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

Independent petroleum engineers

Our estimated net proved reserves and PV-10 at December 31, 2025, 2024 and 2023 are based on reports independently prepared by NSAI, our independent reserve engineers, by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revised June 2019) (the “Estimating and Auditing Standards”) and definitions and current guidelines established by the SEC. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699.

Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Richard B. Talley, Jr. and Mr. Edward C. Roy III. Mr. Talley, a Licensed Professional Engineer in the State of Texas (No. 102425), has been practicing as a petroleum engineering consultant at NSAI since 2004 and has over 5 years of prior industry experience. He graduated from University of Oklahoma in 1998 with a Bachelor of Science degree in Mechanical Engineering and from Tulane University in 2001 with a Master of Business Administration degree. Mr. Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 2364), has been practicing as a petroleum geoscience consultant at NSAI since 2008 and has over 11 years of prior industry experience. He graduated from Texas Christian University in 1992 with a Bachelor of Science degree in Geology and from Texas A&M University in 1998 with a Master of Science degree in Geology. Both technical principals meet or exceed the education, training and experience requirements set forth in the Estimating and Auditing Standards. In addition, both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations, as well as applying SEC and other industry reserves definitions and guidelines.

Technology used to establish proved reserves

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

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

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

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

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

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performance and complex situations sourced by the nature of unconventional reservoirs. The methodology used for the analysis was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, production history and appropriate reserves definitions.

Internal controls over reserves estimation process

We employ NSAI as the independent preparer for 100% of our reserves. We maintain an internal staff of petroleum engineers who work closely with the independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished for the reserves estimation process. Our Senior Director, Corporate Planning & Reserves is responsible for overseeing the preparation of the reserves estimates under the supervision of our Executive Vice President and Chief Financial Officer. Our Senior Director, Corporate Planning & Reserves has more than 15 years of broad reservoir engineering experience in the oil and gas industry, focused across conventional and unconventional evaluation and development projects, including corporate reserves estimations. He holds a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines and is a member of the Society of Petroleum Engineers.

Throughout each fiscal year, our technical team meets with the independent reserve engineers to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data into our reserves evaluation software as well as management review, such as, but not limited to the following:

•Comparison of historical expenses from the lease operating statements and workover authorizations for expenditure to the operating costs input in our reserves database;

•Review of working interests and net revenue interests in our reserves database against our well ownership system;

•Review of historical realized prices and differentials from index prices as compared to the differentials used in our reserves database;

•Review of updated capital costs prepared by our operations team;

•Review of internal reserve estimates by well and by area by our internal reservoir engineers;

•Discussion of material reserve variances among our internal reservoir engineers;

•Review of the reserves report by members of our senior management team, including our President & Chief Executive Officer; Executive Vice President & Chief Operating Officer; Executive Vice President, Chief Strategy Officer & Chief Commercial Officer; Executive Vice President & Chief Financial Officer and Senior Director, Corporate Planning & Reserves; and

•Review of our reserves estimation process and the reserves report by our Audit and Reserves Committee and NSAI on an annual basis.

Production, price and cost history

We produce and market crude oil, NGL and natural gas, which are commodities. The prices that we receive for the crude oil, NGL and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, access to markets, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of crude oil, NGL or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. Please see “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business” for additional information on risks associated with commodity prices. Please also see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—Market Conditions” for additional information on market demand.

The following table sets forth information regarding our crude oil, NGL and natural gas production, realized prices and production costs for the periods presented.

The Arrangement was accounted for as of May 31, 2024. Accordingly, the results of operations presented herein report the results of Chord prior to the closing of the Arrangement on May 31, 2024 and the results of Chord (including legacy Enerplus) from May 31, 2024 through December 31, 2025. For additional information on price calculations, please see information set forth in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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

Acreage

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2025. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

Our total net leasehold position shown in the table above includes 1,302,921 net leasehold acres in the Williston Basin, which is the largest acreage position of any operator in the Williston Basin. At December 31, 2025, our total acreage that is held by production increased to 1,324,535 net acres from 1,283,462 net acres at December 31, 2024.

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2025 that will expire over the next three years unless production is established on the acreage prior to the expiration dates:

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

Productive wells

As of December 31, 2025, we had 10,528 (4,415.0 net) total gross productive wells, of which 5,025 gross (3,937.3 net) productive wells were operated by us. Substantially all of our productive wells as of December 31, 2025 were horizontal wells.

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Drilling and completion activity

The following table summarizes the number of gross and net wells completed during the periods presented, regardless of when drilling was initiated.

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(1)All completed oil wells are located in the Williston Basin.

(2)All completed gas wells are located within our non-operated interests in the Marcellus Shale.

During the years ended December 31, 2025, 2024 and 2023, there were no exploratory wells completed.

As of December 31, 2025, we had 105 gross (82.4 net) wells in the process of being drilled or completed, which included 88 gross operated wells waiting on completion and no gross non-operated wells drilling or completing.

As of December 31, 2025, we had four operated rigs running, and we expect to run four to five operated rigs during the majority of 2026.

Description of properties

As of December 31, 2025, our operations were focused in the North Dakota and Montana areas of the Williston Basin targeting the Middle Bakken and Three Forks formations. We are the top producer in the Williston Basin, and we have the largest acreage position of any operator in the Williston Basin. We focus our operations in the Williston Basin because of its high oil content, multiple producing horizons, substantial resource potential and management’s previous professional history in the basin. In addition, the Williston Basin provides a unique opportunity to efficiently drill and develop long laterals across large connected blocks that can improve capital efficiency and well-level returns. The Williston Basin also generally has established infrastructure and access to materials and services.

Marketing

We principally sell our crude oil, NGL and natural gas production to refiners, marketers and other purchasers that have access to nearby pipeline and rail facilities. In an effort to improve price realizations, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, NGL and natural gas to a broad array of potential purchasers. We sell a significant amount of our crude oil production through bulk sales at delivery points on crude oil gathering systems to a variety of purchasers at prevailing market prices under short-term contracts that normally provide for us to receive a market-based price, which incorporates regional differentials that include, but are not limited to, transportation costs. These gathering systems, which typically originate at the wellhead and are connected to multiple pipeline and rail facilities, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of December 31, 2025, substantially all of our gross operated crude oil and natural gas production was connected to gathering systems. In addition, from time to time we may enter into third-party purchase and sales transactions to, among other things, improve price realizations, optimize transportation costs, blend to meet pipeline specifications or to cover production shortfalls. We also enter into various sales contracts for a portion of our portfolio at fixed differentials. We believe that the loss of any individual purchaser would not have a long-term material adverse impact on our financial position or results of operations, as alternative customers and markets for the sale of our products are readily available in the areas in which we operate.

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

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Delivery commitments

As of December 31, 2025, we had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 40.6 MMBbl of crude oil, 10.6 MMBbl of NGL, 335.6 Bcf of natural gas and 12.0 MMBbl of water within specified timeframes. We are required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments under certain agreements. We believe that for the substantial majority of these agreements, our future production will be adequate to meet our delivery commitments or that we can purchase sufficient volumes of crude oil, NGL and natural gas from third parties to satisfy our minimum volume commitments.

Competition

There is a high degree of competition in the oil and gas industry for acquiring properties, obtaining investment capital, securing oil field goods and services, marketing crude oil, NGL and natural gas products and attracting and retaining qualified personnel. Certain of our competitors possess and employ financial, technical and personnel resources greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and gas properties and exploratory prospects, better sustain production in periods of low commodity prices and evaluate, bid for and purchase a greater number of properties and prospects than our resources permit. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation or regulation enacted by state, local and U.S. government bodies and their associated agencies, especially with regard to environmental protection and climate-related policies. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or the resultant effects on our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing crude oil, NGL and natural gas and our larger competitors may be able to better absorb the burden of such legislation and regulation, which would also adversely affect our competitive position. See “Regulation” below as well as Item 1A. Risk Factors within this Annual Report on Form 10-K for more information on and the potential associated risks resulting from existing and future legislation and regulation of our industry.

Additionally, the unavailability or high cost of drilling rigs, completion crews or other equipment and services could delay or adversely affect our development and exploration operations. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to obtain necessary capital as well as evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See “Item 1A. Risk Factors—Risks related to the oil and gas industry and our business—Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market crude oil, NGL and natural gas and secure and retain trained personnel.”

In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources, such as wind, solar, nuclear, coal, hydrogen and biofuels as well as the impact of climate change activism, fuel conservation measures and governmental requirements for renewable energy sources, could adversely affect our revenues. See “Item 1A. Risk Factors—Our operations are subject to a series of risks arising out of the threat of climate change, energy conservation measures or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, restrictions on drilling and reduced demand for the crude oil and natural gas that we produce.”

Title to Properties

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

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Seasonality

Winter weather conditions and lease stipulations can limit or temporarily halt our drilling, completion and producing activities and other oil and gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting our drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.

Regulation

Our E&P operations are substantially affected by extensive federal, tribal, regional, state and local laws and regulations. In particular, our operations are subject to laws and regulations related to well permitting, drilling and completion, and to the production, transportation and sale of crude oil, NGL and natural gas. Such laws and regulations are frequently amended or reinterpreted. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, federal agencies, state and local governments and the courts.

The regulatory burden on our industry increases the cost of doing business and affects profitability. Historically, our compliance costs with applicable laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations; however, new laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement may occur and, thus, there can be no assurance that such costs will not be material in the future. We cannot predict when or whether any such proposals may become effective and we are unable to predict the future costs or impact of compliance.

Regulation of production

The production of crude oil, NGL, and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Such statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own and operate properties in North Dakota and Montana, which have regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of crude oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations. The failure to comply with these rules and regulations can result in substantial penalties.

Regulation of transportation of oil

Our sales of oil are affected by the availability, terms and cost of transportation of such oil. The interstate transportation of oil by pipeline is subject to U.S. federal regulation, including regulation of terms, conditions and rates, primarily by the FERC pursuant to the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products, be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. Intrastate oil pipeline transportation rates are generally subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state.

We sell a significant amount of our crude oil production through gathering systems connected to rail facilities. The transportation of Bakken crude oil is subject to extensive federal regulation by the U.S. Pipeline and Hazardous Materials Safety Administration (“PHMSA”). In the past several years, transportation safety regulators have increased scrutiny with respect to crude oil testing, accurate hazard classification and railroad tank car standards. While we do not currently own or operate rail transportation facilities or rail cars, costs incurred by the railroad industry to comply with these enhanced standards may increase our costs of doing business or limit our ability to transport and sell our crude oil at favorable prices.

Regulation of transportation of natural gas

The transportation of natural gas in interstate commerce is regulated by FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. FERC regulates interstate natural gas pipeline transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future. The regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

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Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines. Changes in law and to FERC and state utility commission policies and regulations also may result in increased regulation of our business and operations, and we cannot predict what future action FERC or any state utility commission will take.

Regulation of sales of crude oil, NGL, and natural gas

The prices at which we sell crude oil, NGL, and natural gas are not currently subject to federal regulation and, for the most part, are not subject to state regulation. FERC, however, regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. Similarly, the price we receive from the sale of oil and NGL is affected by the cost of transporting those products to market. In addition, while sales by producers of natural gas and all sales of crude oil, condensate and NGL can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

With regard to our physical sales of energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission (“CFTC”) and the Federal Trade Commission (“FTC”). Should we violate these laws and regulations, we may be subject to civil penalties imposed by regulatory agencies, as well as related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Environmental and occupational health and safety regulation

Our exploration, development and production operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our operations in affected areas. These laws and regulations may restrict the rate of crude oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and affects profitability.

Any new laws or regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement that result in more stringent and costly well construction, drilling, operating conditions, monitoring and reporting obligations, water management or completion activities, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our results of operations and financial position. We may be unable to pass on such increased compliance costs to our customers. We may also experience a delay in obtaining or be unable to obtain required permits, which may interrupt our operations and limit our growth and revenues, which in turn could affect our profitability. Moreover, accidental spills or other releases may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such spills or releases, including any third-party claims for damage to property, natural resources or persons. While, historically, our compliance costs with these laws and regulations have not had a material adverse effect on our financial position, cash flows and results of operations, there can be no assurance that such costs will not be material in the future as a result of such existing laws and regulations or any new laws and regulations, or that such future compliance will not have a material adverse effect on our business and operating results. Some or all of such increased compliance costs may not be recoverable from insurance.

The following is a summary of the more significant existing environmental and occupational health and safety laws, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and wastes

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These classes of persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances released at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We are also subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes that impose strict requirements on the generation, storage, treatment, transportation, disposal and cleanup of hazardous and nonhazardous wastes. Under the authority of the EPA, most states administer some or all of the provisions of RCRA,

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sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate ordinary industrial wastes that may be regulated as hazardous wastes. RCRA currently exempts certain drilling fluids, produced waters and other wastes associated with exploration, development and production of crude oil and natural gas from regulation as hazardous wastes. These wastes are instead regulated under RCRA’s less stringent nonhazardous waste provisions, state laws or other federal laws. There have been efforts from time to time to remove this exclusion, which removal could significantly increase our and our customers operating costs, and it is possible that certain crude oil and natural gas E&P wastes now classified as non-hazardous could be classified as hazardous waste in the future.

We currently own or lease, and have in the past owned or leased, properties that have been used to explore and produce crude oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons, hazardous substances and wastes may have been released on, under or from the properties owned or leased by us or on, under or from, other locations where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons, hazardous substances and wastes were not under our control. These properties and the substances disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes, to clean up contaminated property (including contaminated groundwater) and to perform remedial plugging or pit closure operations to prevent future contamination.

Air emissions

The federal Clean Air Act (the “CAA”) and comparable state laws and regulations restrict the emission of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Obtaining permits has the potential to restrict, delay or cancel the development or expansion of crude oil and natural gas projects. Over the next several years, we may be required to incur capital expenditures for air pollution control equipment or other air emissions-related issues. If the EPA were to adopt more stringent air quality standards, state implementation of the revised standard or any other new legal requirements could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, significantly increase our capital expenditures and operating costs and reduce demand for the crude oil and natural gas that we produce, which could adversely impact our business.

Environmental protection and natural gas flaring initiatives

We recognize the environmental and financial risks associated with air emissions, particularly with respect to flaring of natural gas from our operated well sites and are focused on reducing these emissions, consistent with applicable requirements.

The NDIC has issued orders and pursued other regulatory initiatives to implement legally enforceable “gas capture percentage goals” targeting the capture of natural gas produced in the state, commencing in 2014. As of November 1, 2020, the enforceable gas capture percentage goal is 91%. The NDIC requires operators to develop and implement Gas Capture Plans to maintain consistency with the agency’s gas capture percentage goals, but it maintains the flexibility to exclude certain gas volumes from consideration in calculating compliance with the state’s gas capture percentage goals. Wells must continue to meet or exceed the NDIC’s gas capture percentage goals on a statewide, county, per-field, or per-well basis. Failure of an operator to comply with the applicable goal at maximum efficiency rate may result in the imposition of monetary penalties and restrictions on production from subject wells. In September 2020, the NDIC revised the gas capture policy to allow several additional exceptions for companies that flare natural gas under certain circumstances, such as gas plant outages or delays in securing a right-of-way for pipeline construction. As of December 31, 2025, we were capturing substantially all of our natural gas production in North Dakota. While we were satisfying the applicable gas capture percentage goals as of December 31, 2025, there is no assurance that we will remain in compliance in the future or that such future satisfaction of such goals will not have a material adverse effect on our business and results of operations.

Climate change

The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, climate-related disclosure obligations, and regulations that directly limit GHG emissions. Our operations are subject to a series of regulatory, political, litigation, financial and physical risks associated with the production and processing of fossil fuels and emissions of GHGs. The Trump Administration has indicated that it is not pursuing a climate change policy in line with the Biden Administration and is instead focused on growth in the energy sector. The Trump Administration’s priorities, orders and actions are rapidly evolving and have and likely will continue to place less emphasis on concerns regarding climate change.

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In recent years the U.S. Congress has considered legislation to reduce emissions of GHGs, including methane. For example, the Inflation Reduction Act of 2022 (the “IRA”) appropriated significant federal funding for renewable energy initiatives and, for the first time ever, imposed a fee on methane emissions from certain facilities. The methane emissions fee provision of the IRA took effect in 2024, and the EPA published rules in 2024 to facilitate the determination and payment of this methane charge. However, in March 2025, the Trump Administration implemented a Congressional Review Act disapproval of the methane charge rule, and rescinded many executive orders issued under the Biden Administration concerning climate change initiatives. Several states, though none in the areas where we operate, have implemented, of their own accord or in coordination with their neighbor states, regional initiatives and programs limiting, monitoring or otherwise regulating GHG emissions.

In addition, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules and regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and gas system sources, and impose standards for reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. Recent actions by the Trump Administration seek to eliminate, delay or reduce GHG emissions-related requirements.

In recent years, there has been considerable focus on the regulation of methane emissions from the oil and gas sector. Amendments to the 2016 Subpart OOOO performance standards for methane, volatile organic compound (“VOC”) and sulfur dioxide emissions have resulted in presumptive standards for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring technologies, the capture and control of emissions by 95% through capture and control systems, zero-emission requirements for specific components and equipment, so-called green well completion requirements and the establishment of a “super emitter” response program which would allow certified third parties to report large emission events to the EPA, triggering additional investigation, reporting and repair obligations, among other more stringent operational and maintenance requirements. Fines and penalties for violations of these rules could be substantial. The Company is currently taking steps to comply with requirements that became effective during 2024 and those that phase in over time. In July 2025, the EPA proposed to extend most of the compliance deadlines by 18 months. Litigation is pending concerning these recently adopted final rules. Separately, the Bureau of Land Management (“BLM”) has also proposed rules to limit venting, flaring, and methane leaks for oil and gas operations on federal lands. At this time, we cannot predict the ultimate compliance costs or impact of these regulatory requirements, any such requirements have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows.

At the international level, the United Nations (“UN”) -sponsored Paris agreement (“Paris Agreement”) requires member states to submit non-binding, individually determined reduction goals known as Nationally Determined Contributions every five years after 2020. However, the full impact of, and any legislation or regulation promulgated to fulfill the United States’ commitments thereunder, is uncertain at this time, given President Trump’s decision in January 2025 to again withdraw the United States from the Paris Agreement. It is unclear what additional initiatives may be adopted or implemented that may have adverse effects on our operations.

Any new or proposed federal or state policies eliminating support for or restricting the development activities of the oil and gas sector while incentivizing or subsidizing alternative energy sources could reduce demand for our products, increase our operating costs or otherwise have an adverse impact on our financial performance. Executive orders and other actions by the Trump Administration rescind or call into question the extent to which such policies will proceed.

Litigation risks are also increasing, as a number of states, municipalities and other plaintiffs have sought to bring suit against various oil and gas companies in state or federal court, alleging, among other things, that such energy companies created public nuisances by producing fuels that contributed to climate change and its effects, such as rising sea levels, and therefore, are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. The Company is not currently a defendant in any of these lawsuits, but it could be named in actions in the future making similar allegations. Should the Company be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to causation or contribution to the asserted damage, or to other mitigating factors. Involvement in such a case could have adverse reputational impacts and an unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Additionally, our access to capital may be impacted by climate change policies. Stockholders and bondholders currently invested in fossil fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel energy-related sectors. Certain institutional investors who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and have shifted their investment practices to favor “clean” energy sources, such as wind and solar, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. Additionally, there is also a risk that financial institutions will be pressured or required to adopt policies that have the effect of reducing the capital provided to the

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fossil fuel sector. The SEC issued a rule that would mandate extensive disclosure of climate risks, including financial impacts, physical and transition risks, climate-related governance and strategy, and GHG emissions, for all U.S.-listed public companies. However, the SEC has stayed the final rule pending the resolution of consolidated legal challenges and subsequently voted to withdraw its defense of the litigation. States may also pass laws imposing more expansive disclosure requirements for climate-related risks. For example, the State of California will require large U.S. companies doing business in California to make broad-based climate-related disclosures in 2026, pending certain litigation, and other states are also considering similar measures. Separately, the SEC released its final rule on other climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient. Although these rules are currently stayed pending judicial review, if implemented as previously proposed, these rules would significantly increase our climate-related disclosure obligations. New laws, regulations or enforcement initiatives related to the disclosure of climate-related risks could lead to reputational or other harm with customers, regulators, lenders, investors or other stakeholders and increase litigation risks. Any material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could impact our business and operations.

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical and climatic effects on supply chains, assets or operations through storms, drought, floods, sea level rise, changing meteorological conditions and other events or conditions and our ability to mitigate these events is limited and subject to the effectiveness of our disaster and facility preparedness.

Water discharges

The Federal Water Pollution Control Act (the “CWA”) and analogous state laws impose strict controls on the discharge of pollutants into state waters and waters of the United States (“WOTUS”), including produced water and other oil and gas wastes. The discharge of pollutants is prohibited except in accordance with a permit. The CWA also regulates the discharge of dredge and fill material. The scope of WOTUS is subject to ongoing legal challenges and regulatory changes, including the Supreme Court’s 2023 decision in Sackett v. EPA and a subsequent proposed rule in November 2025. Changes to the scope of CWA jurisdiction could increase our costs, cause delays in obtaining permits, and restrict our operations. Non-compliance can result in significant administrative, civil, and criminal penalties.

The Oil Pollution Act of 1990 (the “OPA”) amends the CWA and sets minimum standards for prevention, containment and cleanup of crude oil spills. The OPA applies to vessels, offshore facilities and onshore facilities, including E&P facilities that may affect WOTUS. Under the OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for crude oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from crude oil spills. The OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of crude oil into WOTUS.

Operations associated with our production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These injection wells are regulated pursuant to the federal Safe Drinking Water Act (the “SDWA”) Underground Injection Control (the “UIC”) program and analogous state laws. The UIC program requires permits from the EPA or analogous state agency for disposal wells that we operate, establishes minimum standards for injection well operations and restricts the types and quantities of fluids that may be injected. Any leakage from the subsurface portions of the injection wells may cause degradation of fresh water, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages and personal injuries. Moreover, any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations, which costs could be material.

Additionally, federal and state regulators have investigated a purported link between underground injection and seismic activity. This has led to, or could lead to, new requirements or restrictions on the use of disposal wells, potentially increasing our operating costs. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or our customers.

Hydraulic fracturing activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from unconventional formations, including shales. The hydraulic fracturing process is typically regulated by state crude oil and natural gas commissions or similar agencies, but federal agencies have asserted regulatory authority over certain aspects of the process. Regulations imposing more stringent standards on hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, wellbore integrity and handling of flowback water have varied under prior

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administrations, and litigation challenging those rules resulted in rescission in federal courts. Appeals to those decisions are on-going, but with little activity in the last several years.

In addition, some states, including North Dakota and Montana where we primarily operate, have adopted, and other states may adopt, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. For example, both North Dakota and Montana require operators to disclose chemical ingredients and water volumes used in hydraulic fracturing activities, subject to certain trade-secret exceptions. If new or more stringent federal, state or local legal restrictions or bans relating to the hydraulic fracturing process are adopted in areas where we operate, or in the future plan to operate, we could incur potentially significant added costs to comply with such requirements, experience restrictions, delays or curtailment in the pursuit of exploration, development or production activities and may even be limited or precluded from drilling wells or limited in the volume that we are ultimately able to produce from our reserves.

Increased regulation and attention given to hydraulic fracturing may lead to greater opposition to, and litigation concerning, crude oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to added delays, restrictions or cancellations in our operations or increased operating costs in our production of crude oil and natural gas. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Endangered Species Act considerations

The federal Endangered Species Act (the “ESA”) and comparable state laws may restrict exploration, development and production activities that may affect endangered and threatened species or their habitats. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”) and to bald and golden eagles under the Bald and Golden Eagle Protection Act. Some of our operations are located in areas that are designated as habitat for endangered or threatened species, and our development plans have been impacted on occasion by certain endangered or threatened species, including the Dakota Skipper and the Golden Eagle. If endangered or threatened species are located in areas of the underlying properties where we want to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed by seasonal or permanent restrictions or require the performance of extensive studies or implementation of costly mitigation practices.

Moreover, the U.S. Fish and Wildlife Service may make changes to the list of species as endangered or threatened under the ESA and litigation with respect to the listing or non-listing of certain species as endangered or threatened may result in greater protections for non-protected or lesser-protected species. The issuance of more stringent conservation measures or land, water, or resource use restrictions could result in operational delays and decreased production and revenue for us.

Operations on federal lands

Performance of crude oil and natural gas E&P activities on federal lands, including Indian lands and lands administered by the BLM, are subject to detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government. These regulations may result in significant costs associated with the removal of tangible equipment and other restorative actions. Additionally, under certain circumstances, the BLM may require operations on federal leases to be suspended or terminated.

Crude oil, NGL, and natural gas operations on federal lands are subject to increasing regulatory attention. The former Biden Administration has explored various means to curtail oil and natural gas activities on federal lands and the Trump Administration now seeks to increase such activities. Following passage of the IRA, several DOI recommendations, including an increased royalty rate, minimum bid limits and a significant reduction in total available acreage, were required to be implemented as part of the IRA and have been subsequently incorporated in recent lease sales.

Additionally, oil and natural gas operations and related infrastructure projects on federal lands may be impacted by recent changes to the National Environmental Policy Act (“NEPA”) implementing regulations. NEPA requires federal agencies, including the BLM and the federal Bureau of Indian Affairs (“BIA”), to evaluate major agency actions, such as the issuance of permits that have the potential to significantly impact the environment. The Council on Environmental Quality (the “CEQ”) has historically had rules that govern NEPA review. In March 2025, in response to court decisions, CEQ rescinded its NEPA regulations and directed agencies to review and update their NEPA rules and procedures.

Operations on federal lands also face litigation risks. For example, legal challenges have been filed relating to federal leasing decisions, such as for failure to adequately assess the impact of GHG emissions resulting from production on federal lands.

Depending on any mitigation strategies recommended in such environmental assessments or environmental impact statements, we could incur added costs, which could be material, and be subject to delays, limitations or prohibitions in the scope of crude oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt our or our customers’ E&P activities. Approximately 6% of our net acreage position in the Williston Basin is federal mineral acreage, which is spread across our acreage position, and any portion of a well on federal land requires a permit.

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Employee health and safety

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state regulations require that information be maintained concerning hazardous materials used or produced in our operations. Certain of this information must be provided to employees, state and local government authorities, or citizens.

Human Capital Resources

Our mission is to responsibly produce hydrocarbons while exercising capital discipline, operating efficiently, improving continuously and providing a fun and rewarding environment for our employees. We seek to foster a culture of innovation and continuous improvement and are constantly looking for ways to strengthen our organizational agility and adaptability.

To execute our strategy in the highly competitive oil and gas industry we need to attract, develop, and retain a highly effective, talented, and engaged workforce. Our ability to do so depends on a number of factors, including an available pool of qualified talent, compelling compensation and benefits plans, and an energizing environment committed to helping employees develop and grow. As of February 13, 2026, we employed 676 full-time employees and we also utilize independent contractors to perform various field and corporate services as needed. Our current hiring plans focus on advancing talent attraction in our primary operating locations of Houston, Texas and Williston, North Dakota. We believe that the knowledge transfer plans we have in place are appropriate, and that we will continue to have the human capital necessary to operate our business safely while executing on our strategic priorities. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages and consider our relations with our employees to be satisfactory.

Health and safety

We are committed to protecting the health and safety of our employees, contractors on our job sites, and the communities in which we operate. We seek to improve our procedures to maintain our safety culture. For example, our environmental, health and safety teams regularly monitor and update our recommended safety practices with feedback and input from our field personnel under a management of change process framework. We operate our worksites under a stop work authority program pursuant to which every person on our worksites is empowered to halt operations to address a potential safety issue. We have developed a comprehensive safety management system that includes recurring risk assessment, hazard recognition and mitigation training, emergency response preparedness training, protective measures including adequate personal protective equipment, life-saving rules, onboarding processes, contractor safety management, partner surveys, comprehensive audits, semi-annual safety summits, executive-level reviews of incidents and ad-hoc safety stand-downs. In addition, safety training is provided to all employees, and, in order to reinforce accountability, safety performance is integrated into our annual compensation program. We seek to partner only with contractors and vendors who share our commitment to safety.

Compensation and benefits

The goal of our total rewards program is to attract, retain, and motivate employees through a competitive and comprehensive total rewards package. Our total rewards program considers both corporate and personal performance goals and aims to increase employee focus on key performance drivers while also seeking to maintain and improve overall well-being and deepen commitment to our collective success. We do this by ensuring employees at Chord are competitively compensated and rewarded for their performance, which enables us to attract, motivate and retain high level talent while delivering strong performance to achieve our business strategy. Our intent is to ensure the compensation and benefits provided as part of our total rewards program are fair and equitable across positions and locations, market competitive, based on merit, consistent with our values and transparent to our employees.

The core elements of our compensation program include base pay, short-term incentives and long-term incentive opportunities for employees at all levels of the Company. In addition, we offer benefits that include retirement plan dollar matching, health insurance for employees and their families, income protection and disability coverage, paid time off, volunteer time off, parental leave, flexible work schedules, financial wellness tools and resources and emotional well-being services, such as an Employee Assistance Program. We participate in annual peer benchmarking to ensure we remain competitive across all components of our compensation and benefit programs.

Training, development and career opportunities

Our team of talented employees possess a broad set of skills including engineering, geology, production, marketing, land, supply chain, health and human safety, human resources, finance, accounting, information technology and legal. Many of our employees work in disciplines that require highly specialized skills and subject-matter expertise, underpinning our ability to deliver on our strategic priorities. We are committed to the personal and professional development of our employees, with the

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belief that a greater level of knowledge, skill and ability benefits the employee and fosters a more creative, innovative, efficient, and therefore competitive organization. We empower our employees to develop the skills they need to perform in their current jobs while also developing skills and experiences to support their longer-term growth. We provide our employees with programs that support their learning and development, which are designed to build and strengthen employees’ abilities, including leadership trainings, development of professional competencies, safety trainings and information and technology trainings.

Community Involvement

We strive to make a positive impact in the communities where we operate. Our charitable initiatives include sponsoring technical training programs in our local communities, engineering scholarships, environmental and wildlife rehabilitation programs, Habitat for Humanity projects, mental health programs, and educational programs like OneGoal and Junior Achievement. We actively promote and support employee volunteerism and philanthropy as a core part of our community engagement efforts.

Workforce dynamics

We prioritize diversity of thought, constructive debate, and engaged leadership, aiming to attract, develop, and retain a highly effective and engaged workforce. We believe a workforce that brings varied backgrounds and experiences enriches the Company with unique perspectives and ideas. We actively support our workforce through a thorough and merit-based talent identification process.

Our Vice President of Human Resources is responsible for overseeing all human capital management programs. Our Compensation and Human Resources Committee reviews the Company’s development and implementation of our human capital management practices, policies, strategies and goals, including those related to the recruitment, development and retention of personnel, talent management and other employment practices. In addition, the Board of Directors believes it is important for directors to possess a diverse array of backgrounds, skills and achievements. When considering new candidates, the Nominating and Governance Committee, with input from the Board of Directors, takes these factors into account as set forth in its charter and our Corporate Governance Guidelines.

We are an equal opportunity employer and do not discriminate on the basis of any characteristic protected by applicable law, including race, religion, color, national origin, sex, gender, age, marital status, veteran status or disability status. We engage with individuals with disabilities to provide reasonable accommodations that may allow them to participate in the job application or interview process, to perform essential job functions and to receive other benefits and privileges of employment.

In addition, we seek to work with business partners who do not engage in prohibited discrimination in hiring or in their employment practices, and who make decisions about hiring, salary, benefits, training opportunities, work assignments, advancement, discipline, termination, retirement and other employment decisions based on job and business-related criteria. To maintain a diverse and inclusive workforce, we maintain a robust compliance program supported by an annual certification by all employees to our Code of Business Conduct and Ethics Policy.

Offices

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

Available Information

We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. Our filings with the SEC are available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.

We make available on our website at http://www.chordenergy.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. We also use our website as a means of disclosing additional information, including for complying with our disclosure obligations under the SEC’s Regulation FD (Fair Disclosure). Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K.

Other information, such as presentations, the charters of the Audit and Reserves Committee, Compensation and Human Resources Committee, Nominating and Governance Committee, and Safety and Sustainability Committee and the Code of Business Conduct and Ethics Policy, are available on our website, http://www.chordenergy.com, under “Investors — Corporate Governance” and in print to any stockholders who provide a written request to the Corporate Secretary at 1001 Fannin Street, Suite 1500, Houston, Texas 77002.

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Our Code of Business Conduct and Ethics Policy applies to all directors, officers and employees, including the Chief Executive Officer and Chief Financial Officer. Within the time period required by the SEC and The Nasdaq Stock Market LLC (the “Nasdaq”), as applicable, we will post on our website any modification to the Code of Business Conduct and Ethics Policy and any waivers applicable to senior officers who are defined in the Code of Business Conduct and Ethics, as required by the Sarbanes-Oxley Act of 2002.

We also make available Sustainability Reports and other sustainability documents on our website, which contain various performance highlights relating to ESG and human capital measures. Information contained in our Sustainability Reports, and other documents, are not incorporated by reference into, and do not constitute a part of, this Annual Report on Form 10-K.

References to the Company’s website in this Form 10-K are provided as a convenience and do not constitute, and should not be deemed, an incorporation by reference of the information contained on, or available through, the website, and such information should not be considered part of this Form 10-K.